The case for blue hydrogen

An analysis of the costs and merits of grey, blue, and green hydrogen.

Matheson, a subsidiary of Nippon Sanso Holdings Corporation

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Article Summary

Hydrogen is essential in petroleum refining. It enables the production of clean burning, low sulphur fuels, the hydrotreating of heavy feedstocks to yield more desirable products, and the hydrogenation of vegetable and animal fats for the production of green fuels, among other uses. In the petrochemical industry, hydrogen is the backbone of reactions involved in the production of multiple products of common use that are derived from syngas or from hydrogen itself.

Although hydrogen is a colourless and (odourless) gas, nowadays it is commonly labelled with a colour associated with the way it is produced and the feedstock and the emissions produced in its manufacturing, among other considerations. The spectrum of colours goes from black (hydrogen produced from coal) all the way to green (produced from renewable sources). Table 1 presents a summary of the three most common types (colours) of hydrogen.

Grey, blue, and green hydrogen
Grey hydrogen is mainly produced by reforming of fossil fuels such as natural gas, LPG, or naphtha via steam methane reforming (SMR); it accounts for about 95% of the hydrogen gas that is produced worldwide today. The SMR process generates carbon dioxide (CO2) as co-product, a greenhouse gas that is vented to atmosphere. Grey hydrogen has one of the lowest overall (fixed and variable) costs of production; it requires less equipment and a smaller footprint. Nevertheless, its acceptance is coming under pressure for environmental reasons.

Blue hydrogen is produced similarly to grey hydrogen, from fossil fuels or from non-renewable energy sources, but with a lower carbon intensity. Carbon emissions are lowered by capturing, storing and/or sequestering a portion of the total CO2 produced in the process. Commercial processes can capture up to about 90% of the CO2 produced. The cost of production is mainly influenced by the cost of feedstock, utilities, the incremental cost of CO2 handling (recovery, compression, storage, transport via pipelines, sequestration), and the carbon credits that often subsidise the overall cost of blue hydrogen. Carbon credits vary with geography, region, politics, lobbying, and other factors.

Green hydrogen is produced using renewable energy. It meets the lowest carbon threshold when clean energy sources are used to separate hydrogen from other compounds such as water molecules. Clean sources of energy include wind, solar energy, hydropower, and geothermal. Different factors affect the cost of green hydrogen. The first one is the cost of the process, for example electrolysis where hydrogen is produced from water using renewable energy. The cost of generating green energy has fallen significantly in the past decade. Green hydrogen presents a number of challenges in term of 24/7 availability of green energies for its production, overall production cost, and the limited volume that can be produced. Wind and/or solar energy can be used to produce green hydrogen, which can be temporarily stored during periods when there is low power demand, or can be repurposed.

A more recent addition to the spectrum of colours is turquoise hydrogen, produced by pyrolysis, which breaks down methane into hydrogen and solid carbon. However, turquoise hydrogen is likely to be no more carbon-free than the blue variety in view of emissions from the required process heat.

There can often be a misconception about the production of true green hydrogen. The hydrogen produced is green only if the process uses clean green electricity with zero carbon emissions. If one needs to supply electricity to split a water molecule (electrolysis), and the electricity comes from a power plant fed by fossil fuels (where carbon emissions are produced), then the hydrogen generated via this process is not green.

There have been numerous successful government-backed projects in recent years aimed at fostering the use of clean hydrogen. The International Energy Agency has identified five smart policy actions that are needed.1 1. Establish long term signals to foster investor confidence; 2. Stimulate commercial demand for hydrogen in multiple applications; 3. Help mitigate salient risks, such as value chain complexity; 4. Promote R&D and knowledge sharing; and 5. Harmonise standards and remove barriers.

The number of countries with polices that directly support investment in hydrogen technologies is increasing, with a rising focus on existing and new applications and technologies, but with support for new applications such as road transport as well. Governments have a critical role to play and are working with an increasingly strong and diverse stakeholder community to address key challenges, including high costs, policy and technology uncertainty, value chain complexity and infrastructure requirements, regulations and standards, and public acceptance.

Grey and blue hydrogen production
Figure 1 shows a typical block diagram for a hydrogen production process using a steam reformer with natural gas as feed and a pressure swing adsorption (PSA) unit.

Feed pretreatment and reforming section
Hydrocarbon feedstock — normally natural gas — enters the plant typically at about 350 psig and is pre-heated to about 750°F (400°C). Other hydrocarbons such as LPG or naphtha, either from fossil fuels or renewable sources, can also be used as a feedstock, in which case a pre- reformer is required. Steam as a reactant for the (endothermic) reforming reaction is added at a steam/carbon ratio of about three. This mixed steam/hydrocarbon feed is heated to about 950°F (510°C) prior to entering the reformer tubes. A syngas mixture of hydrogen, CO, CO2, unreacted CH4, and steam exits the reformer’s catalyst-filled tubes at about 1550°F (840°C).

Syngas cooling and waste heat recovery section
The syngas is cooled in a waste heat boiler to about 650°F (340°C) prior to entering the high temperature shift (HTS) reactor. The HTS exit syngas is further cooled to about 100°F (38°C) in a series of heat exchangers prior to entering the PSA unit, which recovers 84-88% hydrogen as product at about 250 psig. The remainder of the syngas is collected in a purge (tail) gas hold vessel at about 3-7 psig as low-Btu fuel gas.

Heat supply to the reformer furnace and convection section
PSA purge gas is the main source of fuel for the reformer furnace which typically equals about 60-80% of the total furnace firing requirement on low heating value basis. Natural gas is used as make-up fuel to supply the remainder of the firing duty. The reformer temperatures are controlled by modulating the natural gas make-up fuel flow to the furnace. The reformer furnace’s combustion flue gases exit the firebox at near atmospheric pressure at about 1750-1850°F (950-1010°C). After heat recovery in the convection section, the flue gases exit the plant at about 300-350°F (150-175°C). Boiler feed water treatment, a deaeration system, and a steam drum are also present to manage steam production.

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