CO₂ Removal – Modern Application Of Longstanding And Proven Technology

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By Morgan Rodwell, P.Eng. - Executive Director, Process Technology, Fluor Canada Ltd.

Over the last two years, significant interest has been expressed in hydrogen — with various consultancies, agencies and government organizations issuing white papers, reports and strategies. Many of these articles make clear, there exists significant opportunity for hydrogen to play a key role in the energy transition towards Net Zero. The Alberta Hydrogen Roadmap [1] and Hydrogen Strategy for Canada [2] both predict large demand for hydrogen by 2050, and significant penetration into the market by 2030. 

While hydrogen can be made from electrolysis of water or gasification of biomass, these routes will face economic challenges. Electricity remains expensive, and while renewables do offer the potential of low (per kWh) production costs, pricing will be set by whether the grid can accommodate this power. Intermittent production of hydrogen from stranded renewables will not be capital efficient due to low on-stream availability. Biomass availability and handling logistics needed to scale up to the large demand profiles identified in the published strategies will also be challenged. 

Significant developments have emerged in methane pyrolysis, where the production of hydrogen results in a solid carbon byproduct (a.k.a. “carbon black”) instead of CO₂. While this production route would make byproduct handling easier, the cash-cost of hydrogen production is higher than more traditional routes, because the energy contained in the carbon is not recovered. Even the best forecasts of methane pyrolysis performance have energy input costs (feedstock + heat from gas or electricity) of 2.3 GJ per GJ of hydrogen produced. This cash-cost of production may still be attractive over electrolysis (which has an energy input cost of 1.25 GJE / GJ of hydrogen produced) with consideration for (relatively) high power prices in Canada. Additionally, locations where subsurface geology doesn’t accommodate CO₂ sequestration provides additional support to this production route.

Developments are also being pursued regarding technologies to mineralize CO₂, to produce saleable commodities. However, many of these routes are likely years from commercialization at the scale necessary to consume large quantities of CO₂ that world-scale hydrogen production will require.

This leaves producing hydrogen from fossil fuels — primarily natural gas — the most likely route. 

In new large hydrogen production plants (such as those being proposed for Alberta) the selected technology is an Auto-Thermal Reforming (ATR) process. This process uses oxygen to drive the reaction of methane (i.e., natural gas) to synthesis gas. The ATR advantages over the traditional Steam Methane Reforming (SMR) process include:

  1. increased production capacity in a single equipment line up (a.k.a., “train”), with world-scale plant production at approximately 430 mmscfd of hydrogen, compared to 200 mmscfd world-scale SMR
  2. higher operating pressure (30-50 bar), compared to an SMR (20-24 bar). The ATR provides the opportunity for lower hydrogen compression cost, as well as higher partial pressures of CO₂ (making the removal of CO₂ easier).
  3. Reduced utility and plot space requirements (normalized based on hydrogen production) thereby reducing the cash-cost of hydrogen production and CAPEX, respectively.

Based upon internal studies, hydrogen production from natural gas should continue as the lowest cash-cost option, where Carbon Capture and Sequestration (CCS) is possible. Auto-Thermal Reforming of natural gas with CCS to produce hydrogen requires about 1.6 GJ of natural gas (both feedstock + fuel) to produce 1 GJ of hydrogen.

Producing hydrogen from natural gas through commercially proven routes produces CO₂ as a byproduct. At world-scale hydrogen production, this requires a geological formation having available pore space to sequester the CO₂, and either store it indefinitely (e.g., a deep saline aquifer with reliable caprock) or mineralize it (e.g., ultramafic basalts). The latter is not fully developed and is only used in Iceland, to date.

Successful capture and storage of the produced CO₂ is key to producing hydrogen with a low carbon intensity.

An important step in CO₂ removal is capturing the “process CO₂” — the CO2 produced from the oxidation of carbon in the feedstock. Historically, in a steam-methane reforming plant, CO₂ was removed from the syngas following the shift reactors using a hot potassium carbonate process or an amine. For hydrogen plants, in the late 1980s, the use of Pressure Swing Absorption units became common for purification (instead of methanating CO back to CH₄), which also allowed for much higher purities (99.9% instead of 95%). This allowed the CO₂ to be removed with the unconverted CO and methane and routed to the furnace as fuel (the tail gas).  This reduced the energy consumption of the hydrogen plant by taking away the energy cost of the CO₂ removal step and providing a small amount of the fuel demand. For the last 30 years, every hydrogen plant built uses PSA hydrogen purification.

However, in such a configuration, all the CO is in the flue gas at atmospheric pressure. While the concentration of CO₂ in SMR flue gas is higher than most gas-fired furnaces (~15mol%), flue gas capture is still relatively expensive because the equipment is large and the energy requirements are relatively high.

Alternatively, you can choose to return to the older scheme and remove the CO₂ from the synthesis gas. This can capture about 55% of the total emissions of the hydrogen process. This is the scheme that was implemented on the Quest Carbon Capture and Storage project using Shell ADIP-X, a promoted amine process. Like all amine processes, there is a significant heat load to regenerate the solvent and recover the CO₂. For the Quest Carbon Capture and Storage project, the published operating data [3] indicates an average energy requirement of 2.28 GJ/tonne of CO₂ captured.

An alternative exists in the Fluor SolventSM Process, originally developed in the 1950s with the first unit built (to remove CO₂ from natural gas) at Terrell County, Texas in 1960. That plant is still operating today, 62 years after startup. Fluor SolventSM Process provides the lowest energy and lowest carbon intensity option for CO₂ removal in both hydrogen production and natural gas purification, where CO₂ partial pressures exceed 400 kPa (60 psia). Since that time, our further developments have provided additional confidence in the applicability of these units, and the 50+ year operating lives of the existing facilities provide “real world” evidence of their reliability. In a hydrogen plant application, energy requirements using Fluor SolventSM Process are about 20% that of a similar amine technology [4], or less than 0.5 GJ/tonne.

This editorial is the first, in a two-part series. The second editorial will explain the development, range of applicability and exceptional performance characteristics of the Fluor SolventSM Process.

References

[1]

Ministry of Energy, "Alberta Hydrogen Roadmap," Government of Alberta, Edmonton, 2021.

[2]

Natural Resources Canada, "Hydrogen Strategy for Canada," Government of Canada, Ottawa, 2020.

[3]

Shell Canada Energy Ltd., "Quest Carbon Capture and Storage Project Annual Summary Report," Alberta Department of Energy, Edmonton, 2019.

[4]

M. Gilmartin, G. Aljazzar and C. Graham, "A Physical Solvent Approach to Blue Hydrogen," in International Petroleum Technology Conference, Riyadh, 2022.

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