Part 1 of this series discussed the process of making blue hydrogen and how using the Fluor Solvent℠ Process can reduce the energy consumption of capturing CO₂ from a hydrogen plant by up to 80% when compared to amine technology. Click here to review Part 1.

In a larger hydrogen production plant, such as those being proposed for Alberta, the selected technology is an Auto-Thermal Reforming (ATR) process, which uses pure oxygen to drive the reaction of methane to synthesis gas without needing a large furnace. This has two advantages over the steam-methane reforming process: (1) it can be scaled to larger capacity in a single equipment line up – world scale ATR plant can produce approximately 450 mmscfd of hydrogen (1080 t/d), compared to 200 mmscfd (480 t/d) for the largest single train SMR in the world; and (2) the ATR operates at higher pressures (30-50 bar), compared to an SMR (20-25 bar). The latter provides an opportunity for lower hydrogen compressor cost and higher partial pressures of CO₂ in the removal step.

Fluor originally developed the Fluor SolventSM Process in the 1950s and built the first unit to remove CO₂ from natural gas at Terrell County, Texas in 1960. That plant is still operating today, 62 years after startup. Subsequent units were installed in syngas and natural gas facilities until 1992. The process uses propylene carbonate as a physical solvent, so it requires higher CO2 partial pressures than does an amine process, but it requires no heat for regeneration. The CO₂ flashes out of the solvent as the pressure is reduced. The only energy requirements are for a small flash gas recycle compressor, the vacuum compressor at the last flash step, and possibly some supplementary refrigeration (the CO2 itself acts as a self-refrigerant in the process). Four examples were installed in syngas applications for hydrogen and ammonia production, located in Belgium, Mississippi, Oklahoma, and Trinidad.

Figure 1: The Fluor Solvent Flowsheet (simplified)

Figure 1 depicts a simplified flowsheet of a Fluor Solvent℠ Process. The inlet gas, dehydrated to <100 ppmw H₂O is cooled and contacted with the propylene carbonate solvent at sub-ambient temperatures (generally above -25°C). The solvent is highly selective towards CO₂ and absorbs only small amounts of hydrogen and light hydrocarbons. The solvent is let down in pressure using a hydraulic turbine. Subsequent flash steps first liberate desired components (like hydrogen), which are recycled to the feed, until the flash gas is primarily CO₂. The last step happens at vacuum to ensure the lean solvent can maximize CO₂ capture. The flash steps occur at low temperatures, sending the solvent back to the absorber at as low a temperature as possible. In an ATR-based hydrogen plant, supplementary refrigeration may not be necessary.

However, Fluor never forgot about propylene carbonate. Further research and development lead to a modern simulation tool with new regressions of the vapour-liquid equilibrium data. This allows better designs and improvements to the schemes that were originally devised over 50 years ago. We are now able to provide a Fluor Solvent design for CO₂ removal from hydrogen plant syngas that is lower cost than an amine unit. It is particularly attractive for higher pressure ATR applications but can be applied to SMR applications.  In a paper presented at the IPTC conference in February 2022 ^[1], Fluor shows that in an ATR hydrogen plant, the process requires just 20% of the energy input of a promoted MDEA technology, and most of that is provided by electricity.  The heat load is just 2% of that of an amine unit.  If the electric power is low emission, the emissions profile can be well under 20% of that of an amine unit in such a service. The result is that the net abated emissions are 96% of the captured CO2, versus just 83% for amine.

One of the key items in the original design manuals was that CO₂ partial pressures over 100 psia (700 kPa) were the target for the process; however, one of the very first units built in California in 1961 functioned with a partial pressure of 57 psia (393 kPa).  New regressions of the data allowed for a certainty that plants can be designed and operated at lower inlet CO₂ levels, with one configuration at just 21 psia CO₂ partial pressure, extending the capability of the Fluor Solvent℠ Process. The development work continues, with recent grants of patents for new variants of the process since 2015.

But the Fluor SolventSM Process doesn’t stop there. Producing all this additional hydrogen for uses beyond the current refining and ammonia applications, means that even if hydrogen displaces natural gas (for instance in home heating), the demand for natural gas will rise. The provincial and federal reports agree on this and predict demand for natural gas production in Canada will rise from 16 bcf/d today to as much as 24 bcf/d by 2050.

In order to produce this additional natural gas, production may expand in plays that have been considered marginal, such as the basins in the far northeast portions of British Columbia. There is also potential for additional production from existing fields. As gas demand itself rises, the dry gas fields are likely to become more economically viable. A downside of these dry fields is that they are often high in CO₂. An example is the Horn River Basin, where the gas can be more than 10% CO₂, but where there are over 75 tcf of reserves. The Cabin Gas Plant was built in this field in 2011, but it is not running today, likely because the economics have been poor for dry gas, and the site would be a significant CO₂ emitter (it was not built with CO₂ sequestration capability).

A Fluor Solvent℠ plant processing Horn River Gas ^[2] could remove the CO₂ from that gas for an energy requirement of up to 20% that of the amine unit that was installed at Cabin, and all of that would be in the form of electric power to drive compressors.  Depending on the source of the electricity, the emissions from the process would be only 30% that of the amine unit (if a natural gas combined cycle power plant was the power source), and possibly as low as 3% if hydroelectric power was the source. 

The Fluor Solvent℠ Process provides the lowest energy and lowest GHG intensity option for CO₂ removal for both hydrogen production and natural gas purification. Our further developments make us even more confident in the design of these units, and the 50+ year operating lives of the existing facilities provide evidence of their reliability. While there is always a desire to chase the latest new technology, sometimes there is as much value (if not more) in looking at those options which are proven and capable of being applied today, and not needing the decade or more required to move from low technology readiness levels to commercialization.

References

1. M. Gilmartin, G. Aljazzar and C. Graham, A Physical Solvent Approach to Blue Hydrogen, “in International Petroleum Technology Conference, Riyadh, 2022
2. M. Rodwell, Fluor Solvent Offers Significantly Lower GHG Intensity that MDEA for CO2 Removal from Natural Gas for Horn River, in Canadian Energy Technology 22, Calgary, 2022.