Published December 2021
Hydrogen is one of the most important chemicals manufactured and used globally in key applications like petroleum refining, the fertilizer industry (e.g., ammonia production), methanol manufacture, and others. A unique point about hydrogen is that it can be used as a clean fuel. For example, when used in a fuel cell, hydrogen produces (electric) energy and water without CO2 emissions. Hence, the gas can be used as an energy source in integrated clean energy systems and auto transportation. A remarkable thing about hydrogen is that it has a very high energy density (energy per unit weight) and, like other fuels, can be stored and carried from one place to another as a chemical or energy source. Those qualities make hydrogen an attractive fuel for transportation and electricity generation.
Ironically, this super-clean energy source generates 8 to 10 metric tons of carbon dioxide per ton during its production from the cleanest fossil source: natural gas. Unfortunately, water electrolysis which can produce hydrogen via a carbon-free or low carbon-emitting process, is very costly at the moment due to enormous consumption and high cost of the renewable electricity and electrolysis cells. Coal-based hydrogen production is even more CO2 intensive. For these reasons, attention is being directed to capturing & sequestering of CO2 especially from large-scale hydrogen plants based on reforming of natural gas.
Nevertheless, CO2 capture and its subsequent compression (required for different applications of CO2), is expensive and adds significantly to hydrogen production costs. There is currently an extensive R&D effort to develop new technologies and improve existing ones with the aim of capturing CO2 more economically and more effectively.
The Process Economics Program, in a recent publication (PEP Review 2021-15), has presented a techno-economic analysis of a natural gas-based hydrogen production plant with an integrated CO2 capture facility. That analysis is based on the assumption that process steam and electricity requirements are met from an onsite utilities generation facility. The CO2 is captured from the flue gas stream leaving the plant stack system. The configuration presented captures 90% of the CO2 generated in the process.
In this review, we evaluate the techno-economic of a similar technology, using the same hydrogen plant capacity (90 million standard ft3/day or 100,500 Nm3/h) and the same design criteria/assumptions which we used in the previous review. The major difference in this review is the location of the CO2 capture point which, in our current analysis, is taken from the outlet stream of water-gas shift reactor (just before the pressure swing adsorption unit).
Two cases have been analyzed. In Case 1 (our base case), we assume that the steam and electricity required for the process is purchased. In Case 2 (a supplementary case), both steam and electricity are generated onsite from natural gas.