Mar-2022

Shell blue hydrogen process

Helping heavy industries, refiners and resource holders to meet their net-zero emission ambitions through the integration of proven technologies for affordable greenfield blue hydrogen production

Nan Liu

Article Summary

A growing number of national governments and energy companies, including Shell¹, have announced net-zero-emission ambitions. Although renewable electricity is expanding rapidly, without low-carbon hydrogen as a clean-burning, long-term-storable, energy-dense fuel, a net-zero goal is difficult to achieve, especially when it comes to decarbonising fertiliser production and hard-to-abate heavy industries such as steel manufacturing and power generation. Hydrogen also has potential as a transport and heating fuel that could repurpose existing gas distribution infrastructure or be introduced into existing natural gas supplies.

Consequently, hydrogen plays an important part in many green strategies. The EU’s hydrogen strategy² published in July 2020 describes it as “essential to support the EU’s commitment to reach carbon neutrality by 2050 and for the global effort to implement the Paris Agreement while working towards zero pollution”.

Momentum is building with a succession of commitments to hydrogen by various companies and governments. For example, in June 2020, Germany announced a €9-billion hydrogen strategy,³ and the International Energy Agency says that “now is the time to scale up technologies and bring down costs to allow hydrogen to become widely used”.⁴ Over the last three years, the number of companies in the international Hydrogen Council, which predicts a tenfold increase in hydrogen demand by 2050,⁵ has jumped from 13 to 81 and includes oil and gas companies, automobile manufacturers, trading companies and banks.

In 2018, global hydrogen production was 70 Mt/y.⁴ Today’s demand is split between being used for upgrading refined hydrocarbon products and as a feedstock for ammonia production for nitrogen fertilisers. Nearly all production comes from fossil fuels: it accounts for 6% of natural gas and 2% of coal consumption, and 830 Mt/y of CO2 emissions⁶ — more than double the UK’s emissions.⁷ “Grey” hydrogen is a major source of CO2 emissions.

If hydrogen is to contribute to carbon neutrality, it needs to be produced on a much larger scale and with far lower emission levels.

Long term, the answer is likely to be “green” hydrogen, which is produced from the electrolysis of water powered by renewable energy. This supports the integration of renewable electricity generation by decoupling production from use. Hydrogen becomes a convertible currency enabling electrical energy to be stored and for use as an emissions-free fuel and chemical feedstock.

Green hydrogen projects are starting. For example, a Shell-led consortium is at the feasibility stage of the NortH2 wind-to-hydrogen project in the North Sea, and a Shell—Eneco consortium secured the right to build the 759-MW Hollandse Kust Noord project at a subsidy-free Dutch offshore wind auction in July 2020; this project will include a green hydrogen technology demonstration.

However, electrolysis alone will not meet the forecast demand. It is currently expensive and there is insufficient renewable energy available to support large-scale green hydrogen production. To put the scale of the task into perspective, meeting today’s hydrogen demand through electrolysis would require 3,600 TWh of electricity, more than the EU’s annual use.⁴ Moreover, using the current EU electricity mix would produce grey hydrogen from electrolysis with 2.2 times the greenhouse gas emissions of producing grey hydrogen from natural gas.⁸

An alternative is blue hydrogen produced from natural gas along with CCUS. Hydrogen production via electrolysis has a similar efficiency to blue hydrogen production, but the levellised cost of production is significantly higher for electrolysis at €66/MWh compared with €47/MWh for SMR—CCUS.⁹

In addition, it is widely acknowledged that scaling up blue hydrogen production will be easier than delivering green hydrogen. For example, the EU strategy² says that “other forms of low carbon hydrogen [i.e., blue] are needed, primarily to rapidly reduce emissions… and support the parallel and future uptake of renewable [green] hydrogen”.

The strategy goes on to say that neither green nor blue hydrogen production is cost-competitive against grey: the hydrogen costs1 estimated for the EU being €1.5/kg for grey, €2.0/kg for blue and up to €5.5/kg for green.⁴

With the cost of CO2 at $25—35/t, blue hydrogen becomes competitive against grey, even with higher capital costs, and green hydrogen may still be more than double the price of blue hydrogen by 2030.⁴ Some forecasts indicate cost parity will occur in about 2045.¹⁰

Greenfield technology options 
This paper considers three technology options for greenfield blue hydrogen projects: SMR,
autothermal reforming (ATR) and Shell gas partial oxidation (SGP) technology (Figure 2).

SMR
SMR, a proven catalytic technology widely applied for grey hydrogen production, uses steam in a multitubular reactor with external firing for indirect heating. Post-combustion carbon capture can be retrofitted to convert grey hydrogen production to blue. For example, the Shell CANSOLV2 CO2 Capture System is proven to capture nearly all the CO2 (99%) from low pressure, post-combustion flue gas.

However, for greenfield blue hydrogen applications, oxygen-based systems such as ATR and SGP technology are more cost-effective than SMR (Figure 3), a conclusion backed by numerous studies and reports.¹¹ Note that the cost of CO2 makes grey hydrogen via SMR more expensive than blue hydrogen from SGP technology. The cost advantage of oxygen-based systems over SMR increases with scale because the relative cost of the air separation unit decreases with increasing capacity. Another advantage is that more than 99.9% of the CO2 can be captured using the lower-cost, pre-combustion Shell ADIP ULTRA solvent technology

ATR
ATR uses oxygen and steam with direct firing in a refractory-lined reactor with a catalyst bed. It is more cost-effective than SMR, but requires a substantial feed gas pretreatment investment and the fired heater produces CO2 emissions (Figure 2).

SGP technology 
SGP technology is also an oxygen-based system with direct firing in a refractory-lined reactor, but it is a noncatalytic process that does not consume steam and has no direct CO² emissions. Compared with SMR, SGP technology saves money by maximising carbon-capture efficiency and simplifying the process line-up, both of which offset the cost of oxygen production (Figure 4).