BILIYOK, M. CZARNECKI and A. DAR, Petrofac, Woking, UK; and S. J. GAULD, Infinity Blue Energy, Perth, Australia
In Q1 2021, the co-authors’ company delivered a front-end engineering design (FEED) for the Arrowsmith Hydrogen Plant (AHP), a staged development by Infinite Blue Energy (IBE) Group. Located in Western Australia, this plant uses wind and solar energy to produce green H2. While Stage 1 of the project is a 25-metric tpd H2 production facility, the design for AHP includes a roadmap for scaling up green H2 production to a capacity of 300 metric tpd by Stage 3.
Several unusual engineering challenges were encountered while designing these processing facilities. This article highlights these design challenges and provides recommendations for successfully dealing with them. Some of the recommendations apply to both blue and green H2 production.1
The deployment of green H2 is also explored to identify the critical factors that will promote or hinder proliferation of this technology.
Part 1 of this article, published in the Q4 2021 issue of H2Tech, discussed the design challenges and solutions for electrolyzer technology selection, the intermittency of renewable power generation and wastewater management.
The original design for the 25-metric tpd H2 facility involved storing the produced H2 as a high-pressure (HP) gas at 370 barg in a 4-d storage system before selling it to the Australian market. This is because H2-fueled buses, vans and trucks require H2 at 350 barg, while passenger vehicles require H2 at 700 barg. It is also cheaper to store H2 as a gas than as a cryogenic liquid. Depending on the storage pressure, only about a third of the energy required for liquefaction is used for compression. However, large-scale storage of H2 gas is more challenging in terms of volume/size and pressure of storage required compared to liquid H2 (LH2), a denser fluid that can be stored at lower pressures. LH2 was initially only considered as an option for further expansion for exports.
HP H2 gas can be stored in pressure vessels, from which it can be loaded onto tube trailers and delivered to the off-takers. However, design stress limitations exist related to the diameter and internal gas pressure for these vessels, and as a result, HP H2 gas is typically stored in composite vessels—this was identified as the preferred solution during the conceptual study. Unfortunately, these vessels are only available on a small scale, with the largest holding less than 1 metric t of H2 at high pressures. Using these to store 100 metric t of HP H2 would be prohibitively expensive; an alternate storage method suitable for such large amounts of H2 was therefore required.
The focus of the 25-metric tpd H2 facility was to produce H2 for immediate consumption in the domestic Australian market as a road fuel. The H2 storage options were therefore limited to HP H2 gas and LH2, as conversion to ammonia (or other chemical storage options) would introduce insurmountable complexities to the off-takers. As a result, LH2 was the first solution implemented. Dry H2 gas can be liquefied and stored in insulated tanks at a temperature of –253°C. Due to the scale of H2 production, liquified natural gas (LNG) and industrial gas design procedures were combined to implement a robust design for a continuous storage (along with boil-off compressors) and loading system.
About 80% of the produced H2 was stored and transported as LH2 to the domestic market. Due to offtake agreements, HP H2 gas storage was still required for the remaining 20%. The diameter limitation of pressure vessels and the prohibitive cost of composite vessels for storing such large volumes of HP H2 gas led to the consideration of unorthodox storage solutions, such as large-diameter, full-welded, stainless-steel piping. This resulted in a few km of piping arranged compactly in a corner of the facility (FIG. 8) with a line packing approach, which was then routed to truck loading stations for loading into tube trailers for delivery to off-takers.
Although H2O electrolysis technology for H2 production has been around for decades, only a handful of companies operate mature and proven electrolyzer units. What was once a niche sector is now experiencing exponential growth. Consequently, some equipment items have long-lead procurement times. Most established vendors are also used to dealing with market requirements for smaller units (up to 5 MW of electrolysis) and are now facing the challenge of scaling up their manufacturing facilities to meet growing demand. As a result, equipment such as an electrolysis package and H2 liquefaction package are long-lead items with procurement challenges.
Plant capacities have also caused challenges for original equipment manufacturers (OEMs) in providing the appropriate solutions for H2 compressors and LH2 loading pumps for this application. The H2 purity requirement of 99.999 vol% has eliminated several compressor options, such as lubricated reciprocating compressors, due to the potential for contamination of the H2 gas product. Centrifugal and rotary-screw compressors were considered unsuitable for the operating ranges of low-pressure (LP) and HP compressors due to the relatively high compression ratio and low H2 flow-rates. In keeping with the production of green H2, compressors driven by electric motors were selected over those with engines or turbines powered by gas.
HP H2 gas storage piping.
A limited pool of OEMs exists for proven green H2 equipment (e.g., electrolyzers, compressors and H2 liquefaction packages) at this scale, which constrains the supply chain in the current active market. Early supplier engagement is critical to the success of projects such as this one. At the start of the project, significant effort was therefore made to build collaborative relationships with OEMs—especially the electrolysis package vendors—and identify preferred suppliers to mitigate this supply chain risk. Such an approach pays off enormously in delivering safe and optimal designs for green H2 production systems at these novel scales.
For the H2 compression example, two suppliers were eventually identified as capable of meeting the LP compressor duty requirement in a single non-lube reciprocating compressor with five stages of compression. One supplier was identified for the HP compressor duty that recommended a single-diaphragm compressor with two stages of compression.
The best source of low-carbon H2 in different regions.
The hazards presented in an H2 facility are well understood and documented within the industrial gases sector. The electrolysis and liquefaction processes primarily produce three hazardous fluids: H2 gas, LH2 and oxygen (O2) gas. Significant work has been done by organizations (e.g., the European Industrial Gases Association) to develop operating and design standards for use on such facilities.
H2 gas is highly flammable, with a flammability envelope of between 4% and 75% in air. Ignition energies are also significantly lower compared to light hydrocarbons. Together, these two properties result in a high probability of ignition on release. Immediate ignition can lead to a jet fire, which burns with an almost invisible flame (visibility is better at night). This is potentially hazardous since there is little visual warning to personnel of an ignited leak.
Cost estimates of blue and green H2 production to 2050.
Late ignition can result in an explosion with a tendency towards detonation in confined volumes. Due to the low molecular weight of H2, a release will rapidly rise. This is particularly hazardous in areas where the gas can accumulate, such as under eaves or in roof spaces or other confined areas.
LH2 has additional hazards relating to the very low temperatures at which it must be stored. Leaks from piping or vessels can lead to the formation of a large vapor cloud with the potential for ignition. O2 gas is a byproduct of the electrolysis process—in this project it was vented to the atmosphere. High concentrations of O2 lead to enhanced combustion with the potential for aggressive O2 fires.
A standard process safety management framework was used during the design stage to identify hazards, determine the extent of the consequences, and identify prevention and mitigation safeguards. A hazard identification (HAZID) process was undertaken to identify the major accident hazards (MAHs) within the facility. Each MAH was modeled using the proprietary consequence modeling packagea. The results were used to identify specific engineering safeguards for inclusion in the design.
Two main preventative barriers were identified for the H2 systems: leak prevention and material selection for piping. Regarding leak protection, the design basis required that all piping be fully welded as much as possible. H2 is an exceptionally small molecule, and leakage through flanges and fittings is common. Material selection for piping was also critical, as some materials are susceptible to H2 embrittlement (depending on the operating envelope).
Mitigation safeguards included careful positioning of fire and gas detection. Upon release of H2 inventory, the gas rises rapidly, so typical placement of detectors would not identify the H2 cloud. Areas where H2 gas could accumulate—especially inside the electrolyzer building—were identified, and fiber optic cables that pick up vibrations were used around the HP H2 storage for leak detection.
For fire detection, ultraviolet flame detection was used, as imaging-based flame detectors were unsuitable due to the invisible nature of the flames. In the event of an ignited H2 leak, the source of H2 would be isolated and the fire allowed to burn out.
Prevention measures for the O2 vents focused on ensuring adequate vent location. The O2 vent from the electrolyzers is extremely low pressure, and typical dispersion models used in software packages—such as proprietary consequence modeling packagea—are not valid within this operating envelope. Further work is required to ensure the vent location is adequate, either by increasing the exit velocity to ensure dispersion, or by using computational fluid dynamic modeling to demonstrate adequate dispersion.
Presently, green H2 costs average between two to three times the cost of blue H2. Blue H2 is produced by reforming natural gas, along with capture and sequestration of the CO2 emissions. Green H2 production costs are primarily influenced by the cost of renewable energy used and the costs of the electrolysis unit (and to a lesser degree, its utilization factor). In a recent report sponsored by the Hydrogen Council,2 McKinsey predicted that the cost of green H2 production will fall by 50%–60% over the next decade due to the declining costs of renewable electricity, the scaling up of electrolyzer manufacturing, and the proliferation of green H2 production and distribution due to favorable government policies.
In an earlier analysis, Wood McKenzie3 also identified 2030 as the year when green H2, produced primarily by solar electrolysis, would reach cost parity with blue H2. According to the consultancy, renewable H2 could reach parity in Australia, Germany and Japan by 2030, based on $30/MWh renewable power cost and a 50% utilization factor of the electrolysis units. The International Energy Agency (IEA) identified similar drivers behind falling costs but was more conservative in its forecast. Its earlier analysis showed that the cost of producing H2 from renewable energy could fall 30% by 2030.4
The cost of H2 production varies significantly across geographical regions, depending on the availability of renewable energy. Regions with complementary profiles of solar irradiance and wind can produce green H2 at the most competitive prices, as highlighted in FIG. 9. Australia, due to its solar and wind profile, is among the countries identified as most favorably placed to contribute to the deployment of green H2 production. This project is located in the coastal region of Western Australia that enjoys extended periods of sunshine and wind (including both land and sea breezes), emphasizing the present economic advantages of deploying an H2 plant in this location.
Several studies have estimated how the cost of green H2 production will evolve globally compared to blue H2, i.e., when the fall in the cost of renewable energy and the cost of the electrolysis units will result in convergence of green H2 costs with that of blue H2. To better formulate a policy regarding H2-based energy, the Scottish government commissioned a report investigating the future of the H2 industry.5 The study report posits that blue H2 will have a lower cost over the next decade or so, with green H2 potentially competing with blue H2 on cost from the mid-2030s onwards (FIG. 10).
In delivering the FEED for a large-scale green H2 development, the engineering team encountered several challenges that are not typical for hydrocarbon gas processing facilities:
It is clear that the location of the plant was a primary enabler for the project. Western Australia possesses consistent winds that blow an average of 18 hr/d, as well as abundant solar irradiance during daytime. As a result, wind turbines are able to generate power at high-capacity factors (hence cheaply), which is then augmented by power generated by solar PV during daytime hours when the wind is not blowing.
Transmission lines located nearby provide access to the Western Australia grid, enabling the plant to export or sell renewable power to the grid in times of excess output and buy back green power whenever the onsite renewable power assets are not generating enough electricity to meet the requirements of the electrolysis units to maintain H2 production.
The cost of renewable power in Western Australia is low compared to regions that may require offshore wind development and locations that do not have the complementing solar irradiance to ensure steady H2 production and may require other renewable sources (e.g., hydro) to compete. Presently, the suitability of green H2 in most other regions is unlikely to be as financially attractive. However, as the cost of green H2 production is forecast to fall globally over the coming decades, green H2 will grow to overtake blue H2 as the dominant H2 source in an emissions-constrained future.
a DNV’s PHAST
1 International Renewable Energy Agency (IRENA), “Hydrogen from renewable power: Technology outlook for the energy transition,” 2018, online: https://www.irena.org/-/media/Files/IRENA/Agency/Publication/2018/Sep/IRENA_Hydrogen_from_renewable_power_2018.pdf
2 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
3 Wood Mackenzie, “Green hydrogen production: Landscape, projects and costs,” 2019, online: https://www.woodmac.com/our-expertise/focus/transition/green-hydrogen-production-2019/
4 International Energy Association (IEA), “The Future of hydrogen: Seizing today’s opportunities,” June 2019.
5 Scottish Government, “Scottish hydrogen: Assessment report,” 2020, online: https://www.gov.scot/publications/scottish-hydrogen-assessment-report/pages/12/
CHET BILIYOK is a Chartered Process Engineer with 16 yr of experience in process design, project execution, technical consultancy and R & D across the energy industry. He has drawn on previous experience working in oil and gas to deliver projects in renewable/low carbon H2, carbon capture, utilization and storage (CCUS) and waste-to-fuels, recently serving as the Process Lead during FEED of the Arrowsmith Green Hydrogen Project. Dr. Biliyok has authored more than 20 peer-reviewed journal articles and presented his work at major international conferences. He is based in Petrofac’s Woking, UK office as the Technical Director of Petrofac’s New Energy Services and seeks to deliver solutions that enable organizations to thrive in a low-carbon energy future.
MICHAEL CZARNECKI is a Chartered Chemical Engineer with 17 yr of experience working in process design and project engineering management across the energy industry. He works as a Study Manager supporting Petrofac’s Engineering & Consultancy services team in Petrofac’s Woking, UK office. Mr. Czarnecki recently project-managed the Arrowsmith Green Hydrogen FEED Project. This project involved the integration of wind turbine and solar PV technology to electrolyze H2 from raw water. He has a keen interest in low-carbon projects and new technologies and is applying his experience of working within the onshore and offshore oil and gas sectors to new energy projects.
AHMED DAR has more than 25 yr of engineering experience in the oil and gas, petrochemicals and sulfur management sectors. He has worked on a variety of international projects for major engineering contractors and operating companies. His experience encompasses all project phases, from project proposals to conceptual design, feasibility studies and FEED to detailed engineering. He is a subject matter expert in sulfur recovery unit design, operations, troubleshooting and performance optimization. Mr. Dar joined Petrofac in 2018 and works as a Consultant Process Engineer supporting Petrofac’s Engineering & Consultancy team in the Woking, UK office. He recently provided process engineering and design support on the Arrowsmith Green Hydrogen FEED project and is interested in renewable energy technologies and carbon capture and sequestration. Mr. Dar earned an MS degree in advanced chemical engineering and is a Chartered Engineer.
STEPHEN J. GAULD is the Managing Director at Infinity Blue Energy, based in Perth, Australia. He has more than 20 yr of experience in the oil and gas sector working for some of the largest global service companies and operators, such as Baker Hughes GE, ENI, ExxonMobil, Chevron, RocOil and Woodside. Mr. Gauld is very experienced in managing project delivery and cash flow and gained a wealth of experience field testing and developing state-of-the-art rotary steerable and logging while drilling technology. In the last 5 yr, he has delivered several renewable energy projects from design, civils and construction through commissioning and now leads Australia’s first commercial-scale green H2 plant north of Perth.
FIG. 8. HP H2 gas storage piping.
FIG. 9. The best source of low-carbon H2 in different regions.5
FIG. 10. Cost estimates of blue and green H2 production to 2050.