Author:
Morgan Rodwell, P.Eng. (AB/BC), Executive Director – Process Technology, Fluor Canada Ltd.

There are a number of considerations when imagining and defining a blue hydrogen project that can have a significant impact on the optimal configuration and economics. In part one of this series, we covered energy consumption, the valuation of CO₂, CO₂ emissions, markets/customers, and logistics. In this second part, we will cover technology selection and execution knowledge. 

The technology selection economics may be driven by size. If one started with the assumption of a blue hydrogen project achieving 90% carbon capture (excluding external power source emissions), then the point where a steam-methane reformer (SMR) with flue gas carbon capture becomes less attractive than an oxygen-blown autothermal reformer (ATR) is likely in the 80-100 mmscfd (193-241 t/d) range. Obviously, specifics of location, plot space availability, power source carbon footprint and more will come into the equation and may shift the range around somewhat. But if your target capacity is significant outside the range, it should become obvious quickly that SMRs are more viable when small, and ATRs take over when capacities are large. This also applies to blue ammonia projects, because the economics of scale will change the optimum technology selection.

• For an SMR scheme, flue gas carbon capture will be the preferred capture route to achieve 90% capture (or higher, albeit of declining economic viability). Flue gas capture has the downside of needing significant plot space due to the very low pressure and thus large size equipment. 
• For an ATR scheme, process capture will provide the bulk of the capture, and this will be lower cost than flue gas capture. However, the ATR requires an air separation unit, which itself has a significant energy requirement.

Technology selection should be done holistically. Selecting one part of the technology line-up in isolation may not result in the economic optimum. For example, selecting an ATR technology may result in the most economic ATR option (operating pressure, preheat configuration, steam/carbon ratio), but this may limit options for CO₂ capture and product purification with the impact of increasing the cost of hydrogen. For example, there are benefits in the design of an ATR (and for SMRs) to operate at lower pressures (the reforming reaction benefits) and lower steam/carbon ratio (operating cost). However, lower pressures make CO₂ capture more challenging, both from an energy cost and ultimate capacity. It may even be necessary to compress the produced syngas to higher pressures to perform the CO₂ removal (especially if cryogenic or very high recoveries with physical solvents are desired). This may be more expensive than accepting the slightly worse performance of the ATR at higher operating pressures. 

Further, the ATR configuration has impacts on the shift reactor configuration. Two key parameters in the overall configuration are methane-slip through the reformer, and CO-slip beyond the shift reactors. Both of these eventually end up as CO₂ emissions, either on the site or when final H₂ product is burned or further processed. If minimizing CO₂ emissions is economically attractive, then minimizing these slips may appear very desirable; the challenge is that the cost/benefit analysis of reducing these slips and the CO₂ capture technology itself may push in opposite directions, forcing a decision on optimums that is highly sensitive to the valuation of both the H₂ product and CO₂ credits.

Local Execution Knowledge is (at least) as important as technology knowledge. While the technologies involved in blue hydrogen do look somewhat different than those traditionally used in Western Canada, they are not dramatically novel, different or uncommon. For example, while an ATR used pure oxygen, and there are no operating ATR units in Canada today, there are (and have been) gasification units that in many respects are very similar. Further, while there have only been a handful of large ATRs built around the world in the last 15-20 years, most of them were built in regions where the execution model is very different than what needs to happen in Western Canada. Whether it be logistics, modularization, labour relations or weather, B.C., Alberta and Saskatchewan are quite different from the Middle East, Africa, Southeast or Central Asia. The project execution model for a large blue hydrogen project here will not look much like how projects are executed in those jurisdictions.

Don’t assume that knowledge in an adjacent space applies. A key mistake that some have made in assessing technology in the blue hydrogen and carbon capture space is that this is the same as acid gas removal from natural gas. There are two aspects here.

• For flue-gas carbon capture, the problem of amine degradation due to oxygen, SOₓ and NOₓ means that commodity solvents are not a good selection, and that any solvent will see degradation on a single or multi-pass basis and require maintenance. Selecting a proven technology is critical to project success.
• For syngas capture, especially at scale and the high CO₂ partial pressures will generally make physical solvents more attractive than amine processes.  Amine processes will have large energy costs for regeneration, while physical solvent processes will not, but will have higher power costs for refrigeration.  Options include Rectisol® (using methanol, licensed by Linda AG or Air Liquide SA), Selexol® (using dimethyl ethers of polyethylene glycol) licensed by Honeywell) and Fluor Solvent™ (using propylene carbonate, licensed by Fluor). Each has pros and cons depending on the project goals. 

Technology selection should consider the scale-up and novelty risks. Some of the technology options being touted in the industry are not yet proven at scale in the blue hydrogen space. Most have been demonstrated at smaller scale, or in adjacent spaces, so the technology risk is not large. The accuracy of predicted capital and operating costs for some technologies may not be as good as for older technologies because there are no at-scale examples to use as a benchmark.  An example of this is the idea of cryogenic recovery of CO₂ from synthesis gas. While there are demonstrated examples of cryogenic CO₂ removal from natural gas, at scale, the extrapolation to synthesis gas service is slightly more complicated. There is recent scientific literature on the phase behaviour of H₂-CO₂ mixtures at cryogenic conditions, and one of the key aspects that is raised is the ability of commercial simulation software to accurately predict the phase behaviours. It is not difficult to improve the predictions to match this published data, but the datasets are small and inconsistent, and few companies are cognizant of these risks. Predicting the partial pressures and freezing point of CO₂ below its triple point in the presence of high partial pressures of H₂ and using extractive solvents is of particular concern. 

That said, linked to the prior point about not performing technology selections in isolation, there are definite potential benefits of such options because it may provide for the avoidance of other costs, such as large-scale CO₂ compressors because the CO₂ can be recovered as a liquid and pumped.

If you are thinking of a new blue hydrogen application, or of retrofitting existing grey hydrogen facilities to be blue, consider these issues as you begin the feasibility and scoping stages (FEL1-2) of your project. It is never desirable to find you have selected some technology options for a project that locks you into less attractive options and consequences as you define other parts of the project. 

If you have any questions, don’t hesitate to reach out to a knowledgeable engineering contractor that understands both the technical issues and the local environment and economic climate.