CHODOROWSKA and M. FARHADI, Wood, Reading, UK
Part 1 of this article, published in the Q3 2021 issue, introduced the study concept and methodology for examining four transportation vectors to convert natural gas from Ras Laffan Industrial City in northeast Qatar into an H2 product at South Hook LNG terminal in Milford Haven, West Wales, UK. The value chain for each option was defined, and CAPEX and OPEX were calculated for each unit within the process. Part 2, published in the Q4 2021 issue, considered H2 production with carbon capture and the LNG value chain. The final part of this article here will consider the ammonia (NH3) and methylcyclohexane (MCH) value chains, safety considerations and the study conclusions.
The NH3 vector consists of the four key process blocks shown in FIG. 10. H2 production and NH3 synthesis take place in Qatar before transportation to the UK. The captured carbon dioxide (CO2) is a product for further processing before reinjection in Qatar. Dehydrogenation of the NH3 takes place in the UK, delivering H2 to the natural gas grid.
FIG. 10. NH3 vector process blocks.
FIG. 11 shows a more detailed block flow diagram of the NH3 vector with the key material balance.
The referenced tables are related to the different process blocks in FIG. 11. Each table shows the capacity of the individual unit, and whether one or more units are required based on the largest capacity references found in the literature.
FIG. 11. NH3 block flow diagram with material balance.
H2 production is the same steam methane reforming (SMR) + carbon capture and storage (CCS) process as that described for the LNG vector, other than a slightly larger capacity due primarily to the loss in the NH3 cracking process. Infrastructure and revenue from byproducts such as natural gas liquids (NGL) and condensate have not been considered.
TABLE 9. NH3 synthesis
NH3 synthesis (TABLE 9) is based on the Haber-Bosch synthesis loop. FIG. 12 shows typical NH3 production processes, including NH3 production from natural gas via an SMR producing H2.
FIG. 12. Ammonia production processes.
Although more information is available on NH3 production using methane gasification and autothermal reforming (ATR) combined with air injection, many NH3 production processes employ SMR-based H2. Natural gas as a feedstock passes through an SMR unit to generate H2, which then enters a Haber-Bosch synthesis system. Nitrogen (N2) is generated from air using an air separation unit (ASU), which involves air compression and a cryogenic separation process.
To maintain a comparative basis for this study, the SMR + CCS route for pure H2 production followed by N2 injection prior to the NH3 synthesis unit was selected.
The pure H2 gas from the SMR after mixing with N2 is fed to a Haber-Bosch synthesis system. NH3 is produced from an exothermic reaction of H2 and N2 over an iron oxide catalyst within this synthesis loop. After a cooling process, the end product liquid NH3 is stored and ready to be loaded onto a ship for transportation.1
The NH3 boil-off gas (BOG) is continuously returned to the liquefaction system where it is cooled through a two-stage refrigeration loop.1
NH3 storage is based on having sufficient storage to service the number of ships and their size. The same storage capacity in Qatar and the UK is assumed based on refrigerated storage spheres of 50,000 m3 capacity with a margin to allow for any delay in ship arrival. A boil-off rate (BOR) of 0.1 vol%/d is assumed and BOG from storage is re-liquefied and returned to the tanks at both the loading terminal and receiving terminal.
NH3 transportation is based on the use of semi-refrigerated liquefied petroleum gas (LPG) tankers. The largest available LPG tanker with a capacity of 85,000 m3 is considered for shipping NH3 from Qatar to the UK.2 NH3 shipping infrastructure and storage is a mature process and in operation worldwide. At atmospheric pressure, the NH3 has a boiling point of –33°C; therefore, it is less expensive and more available to transport NH3 than LH2 or even LNG—safety concerns are associated with NH3 leaks, as it is a highly toxic and flammable chemical that can leak in gaseous form.3 For the purposes of comparison, it is assumed that the LPG carriers are fueled by LNG; however, it can be expected soon that the ships would operate on NH3 as a direct fuel.
TABLE 10. NH3 cracking
NH3 dehydrogenation or cracking (TABLE 10) is the finalprocess to revert the NH3 back to H2. This process is costly (depending on the purity of H2 required), energy intensive, suffers product losses and can be avoided if NH3 was used directly as a fuel. A typical NH3 cracking unit configuration is shown in FIG. 13.
FIG. 13. NH3 cracking.
H2 purification with a PSA at 20 bar has 85% recovery4. This results in a H2 loss of about 15% when cracking NH3 back into H2—some references have even lower recoveries. Catalytic dehydrogenation of NH3 is an endothermic and energy-intensive process, with required high temperatures of 650°C–700°C or greater over a catalyst. Despite the recent interest and importance of NH3 dehydrogenation, limited information exists on the process development with small capacities.4
The total specific value for the whole value chain is $2,020/metric t of H2, split between a CAPEX of $511/metric t of H2 and an OPEX of $1,509/metric t of H2.
The MCH vector consists of the four key process blocks shown in FIG. 14. H2 production and the hydrogenation of toluene into MCH takes place in Qatar before transportation to the UK. The captured CO2 is a product for further processing before reinjection in Qatar. Dehydrogenation of the MCH back to H2 takes place in the UK, delivering H2 to the natural gas grid. FIG. 15 shows a more detailed block flow diagram of the MCH vector with the key material balance. H2 production is the same SMR + CCS process as that described for the LNG vector other than a slightly larger capacity due primarily to the loss in the MCH dehydrogenation process. Infrastructure and revenue from byproducts such as NGL and condensate have not been considered.
FIG. 14. MCH vector process blocks.
FIG. 15. MCH block flow diagram with material balance.
MCH hydrogenation (TABLE 11) is the hydrogenation of toluene into MCH—the process is reversible where toluene is essentially the carrier and reused in the overall process. Toluene feed plus makeup is heated through a vaporizer prior to mixing with H2. The mixture then enters a fixed-bed reactor in which toluene reacts with H2 to produce MCH though an exothermic reaction, which occurs at a temperature of 240°C and pressure of 10 bar in the presence of a catalyst. The released heat is removed using a heat recovery system. The produced MCH from the reactor is cooled and the condensate is separated from the gas.5
TABLE 11. MCH hydrogenation
MCH is a liquid at atmospheric pressure and temperature and contains 6.2 wt% H2 with a volumetric H2 density of 47.4 kg H2/m3 (23.3 mol H2/l). This makes MCH a good option as an H2 carrier, as it has a relatively low safety risk.6
A leading company is pioneering the development of this novel process by providing a proprietary MCH hydrogenation technologya. Although little information is available on this technology, FIG. 16 gives the process flow diagram and (using this technology) suggests MCH is produced for large-scale H2 with low cost and 99% efficiency.
FIG. 16. Toluene hydrogenation to MCH.
MCH and toluene storage is based on having sufficient storage to service the number of ships and their size. The same storage in Qatar and the UK is assumed based on storage tanks of 50,000 m3 capacity, with a margin to allow for any delay in ship arrival. MCH and toluene can be stored in typical industrial chemical storage tanks, such as atmospheric, low-pressure (2.5 psig–15 psig) or high-pressure fixed roof, floating roof, horizontal or vertical cylindrical vessels. From the literature used7, it was not entirely clear what had been selected and it is assumed to be a low-pressure, fixed roof type.
MCH/toluene transportation is based on the use of large typical oil/chemical carriers, which is the main advantage of this vector—the use of conventional chemical and oil transportation infrastructure.7 MCH and toluene are in liquid form at ambient temperature and atmospheric pressure due to a high boiling point. A 45,000-metric t tanker was selected;6,8 however, this is one area of this vector that could be optimized using fewer, but larger, vessels. MCH is transported to the UK and toluene is transported back to Qatar in the same ship. MCH has a slightly lower density and a higher transport volume compared to toluene; therefore, the MCH shipping requirements dictate the shipping operation.
No BOG management is required, and it is assumed the ships are fueled by LNG to keep this option comparable to the other vectors.
MCH dehydrogenation (TABLE 12) is the final process to revert the MCH back to toluene and release the H2. Similarly, to NH3 reconversion, MCH dehydrogenation is a particularly challenging and energy intensive process. MCH reconversion is an endothermic reaction that takes place at a temperature range of 400°C–500°C in the presence of catalyst. The aforementioned company has developed a novel dehydrogenation process as part of the proprietary MCH hydrogenation technology, providing the dehydrogenation process with a reduced operating temperature of 350°C using a recently developed catalyst. The schematic in FIG. 17 indicates a process flow diagram of the dehydrogenation process.
TABLE 12. MCH dehydrogenation
The MCH feed is initially vaporized in the MCH vaporizer and superheated in a heat exchanger before entering the fixed-bed reactor, like that of the hydrogenation unit. The dehydrogenation of the MCH to H2 gas and toluene is the reverse reaction of the hydrogenation and, therefore, is endothermic. In this study, the heat required is supplied by natural gas as the fuel. The reactor product gas is cooled in heat exchangers and the H2 gas is separated from the toluene in a condenser separator. The H2 gas is eventually purified to meet the H2 product specification.
FIG. 17. MCH dehydrogenation.
The total specific value for the whole value chain is $1,956/metric t of H2, split between a CAPEX of $360/metric t of H2 and an OPEX of $1,596/metric t of H2.
The total specific values for each of the four vectors plus the optimistic LH2 future case are plotted in FIG. 18 and tabulated in TABLE 13. It should be remembered these values have been calculated on a comparative basis rather than absolute values for the full well-to-grid value chain.
TABLE 13. Total specific values for each vector
The following should be considered when comparing the different processes:
° LNG, –162°C at atmospheric pressure
° LH2, –253°C at atmospheric pressure
° NH3, –33°C at atmospheric pressure
° MCH, ambient temperature at atmospheric pressure
° CO2, –50°C at 7 barg
FIG. 18. Specific values for each vector.
For the four transport vectors and value chains, maintaining the LNG infrastructure and producing H2 at the point of use is most likely the most economical, since less deep processing of the H2 is required. The conversion and subsequent reconversion required is not to the very low temperature of LH2 and no chemical reactions are associated exothermic/endothermic and product losses, which increases both CAPEX and OPEX. The LNG vector does present the additional processing and transportation of the CO2, but this is not as costly or energy intensive as liquefying H2 or the highly exothermic/endothermic NH3 and MCH processes. The LNG vector does have a higher transportation and storage element compared with NH3 and MCH, but this is counterbalanced by the lower LNG conversion costs. The LNG vector also gains from the fact that the large-scale LNG infrastructure is in place, mature and has achieved significant efficiency savings over time.
Sequestration of the CO2 closer to the import facility also has clear economic benefits, but this may not be an option in some locations.
Not surprisingly, the LH2 vector was the highest value and, solely from the optimistic future trend, it is seen that it will become more economical as more investment in development is made. However, liquefaction of H2 will have a finite cost that is not better than LNG—achieving a temperature of –253°C is substantially different and more energy intensive than achieving –162°C. Further complicated by maintaining these temperatures and reducing boil-off during storage and transportation, these costs are higher than for the other vectors.
Although H2 has a high energy content on a mass basis, the energy density graph (FIG. 19) shows a relatively low energy density on a volumetric basis and, therefore, requires larger and more expensive storage and shipping infrastructure.
FIG. 19. Energy density of different fuels.
NH3 and MCH are comparable based on this study, and the order of position can probably be changed by optimizing shipping and storage sizes. Both processes have complex conversion and reconversion processes that are energy intensive and have product losses of ~12% for the MCH and >15% for the NH3, resulting in higher feedgas costs and lower resource efficiency than the LNG vector.7 Both require additional materials handling—as the carrier, toluene must be transported and stored in both locations for the MCH vector. An ASU to produce nitrogen is required for the NH3 vector. Both have well-established equipment, although NH3 cracking requires further investigation. NH3 synthesis units are relatively small, although most major suppliers claim that units up to 6,000 tpd are in development.
NH3 would have some appreciative benefit over MCH if there were no requirements to convert it back to H2—this would also bring it closer, if not equal, to LNG. The use of NH3 as a direct fuel is gathering momentum—showing it to be competitive and economical for trucks, shipping and aviation would encourage its use as a better option.
Energy efficiency and overall CO2 loss to the atmosphere in these processes have not been analyzed in depth, but it is clear the LH2 vector has the minimum CO2 loss to atmosphere through the process chain, as H2 is used as shipping fuel and the CCS process occurs closest to the source of the hydrocarbon feedgas. However, power production for the LH2 process is high and CO2 losses can be substantial at this point. The method of regasification also needs further development. CO2 loss to atmosphere in the NH3 process would be reduced once NH3 becomes the shipping fuel of choice in the future.
Low-carbon power production, energy recovery and integration in these processes are key areas for optimization. All four processes have aspects where energy recovery would offset the high OPEX costs related to energy usage. Regasification of the LH2 and LNG both require heating, and better “cold” recovery—particularly for the LH2—would improve the energy balance. Both NH3 and MCH have exothermic reactions where energy integration could be better optimized.
FIG. 20 shows that for all four vectors, OPEX is the overriding cost compared with CAPEX. Full financial burdens have not been calculated in this comparison analysis: upstream, CO2 reinjection, jetty and utility infrastructure costs across all options have not been included (except for CO2 shipping berths), all of which would increase CAPEX and OPEX. However, it can be seen that the specific H2 cost is $1,600/metric t–$2,700/metric t, which gives confidence that the results are similar to other published data and are in the targeted range cited in literature for Australia (AUS$2.00/kg H2) and Japan (U.S.$2.50/kg H2).9
LNG should be considered as a comparable H2 vector when designing or retrofitting blue H2 technologies along with NH3 and other LOHCs. The technology is mature, proven and large scale, and infrastructure is already in place—no part of the value chain is unproven at the studied scale. If the captured CO2 can be sequestrated at the import location rather than returned to the export location, then further cost savings can be ~$0.361/kg H2. There does not seem to be a significant advantage between NH3 and MCH other than NH3 may have future advantages if it becomes a directly used fuel and NH3 cracking can be avoided, resulting in significant cost savings.
The main advantage of the LH2 value chain would be the reduction in CO2 emissions throughout the value chain, dependent on the method of power production. This comes at a significant additional cost of $1.10/kg H2 or (optimistically) $0.70/kg H2 if scale-up and energy reduction can be achieved. The technology is unproven at the scale required in this study and, therefore, uncertainty remains in both costs and greater project risks.
a Chiyoda Corp.’s SPERA HydrogenTM
This article was presented at the GPA Europe Virtual Conference on May 25, 2021.
The information and data contained herein is provided by the authors’ company solely for the article itself and should not be considered to have consequence outside this hypothetical study. The authors’ company makes no representation or warranty, express or implied, and assumes no obligation or liability, whatsoever, to any third party with respect to the veracity, adequacy, completeness, accuracy or use of any information contained herein. The information and data contained herein is not, and should not be construed as, a recommendation by the authors’ company that any recipient of this document invest in or provide finance to any similar project. Each recipient should make its own independent evaluation to determine whether to extend credit to projects with which they are involved.
1 Bartels, J. R., “A feasibility study of implementing an ammonia economy,” 2008, online: https://www.semanticscholar.org/paper/A-feasibility-study-of-implementing-an-Ammonia-Bartels/e4a3c0ed04725a4222350f05b9d3a1fcc97f6329
2 Liquefied Gas Carrier, “Fully refrigerated tankers that carry LPG, ammonia and vinyl chloride,” 2021, online: http://www.liquefiedgascarrier.com/Fully-Refrigerated-Ships.html
3 Hydrogen Council, “Path to hydrogen competitiveness: A cost perspective,” 2020, online: https://hydrogencouncil.com/wp-content/uploads/2020/01/Path-to-Hydrogen-Competitiveness_Full-Study-1.pdf
4 International Energy Agency, “IEA G20 Hydrogen report: Assumptions,” 2020, online: https://www.iea.org/reports/the-future-of-hydrogen/data-and-assumptions
5 Advanced Materials and Reactors for Energy Storage Through Ammonia (ARENHA), “D2.2 Public report on industrial requirements,” 2020, online: https://arenha.eu/sites/arenha.drupal.pulsartecnalia.com/files/documents/ARENHA-WP2-D22-DLR-ENGIE_11012020-final.pdf
6 T. Autrey, T., “Hydrogen carriers for bulk storage and transport of hydrogen fuel cell technologies webinar,” 2018, online: https://www.energy.gov/eere/fuelcells/downloads/hydrogen-carriers-bulk-storage-and-transport-hydrogen-webinar
7 Hurskainen, M., “Liquid organic hydrogen carriers (LOHC): Concept evaluation and techno-economics,” Research Report VTT-R-00057-19, 2019, online: https://cris.vtt.fi/en/publications/liquid-organic-hydrogen-carriers-lohc-concept-evaluation-and-tech
8 Teichmann, D., W. Arlt and P. Wasserscheid, “Liquid organic hydrogen carriers as an efficient vector for the transport and storage of renewable energy,” International Journal of Hydrogen Energy,” December 2012.
9 Ishimoto, Y., M. Voldsund, P. Nekså, S. Roussanaly, D. Berstad and S. O. Gardarsdottir, “Large-scale production and transport of hydrogen from Norway to Europe and Japan: Value chain analysis and comparison of liquid hydrogen and ammonia as energy carriers,” International Journal of Hydrogen Energy, November 2020.
NICOLA CHODOROWSKA is a Managing Consultant in the specialist engineering and consulting group at Wood in Reading, UK. She holds a BEng degree in chemical engineering
and is a Fellow of the Institution
of Chemical Engineers.
MARYAM FARHADI is a Process Engineer in process engineering and capital projects at Wood in Reading, UK. She holds an MSc degree in process systems engineering from the University of Surrey.