Capital Projects

 

S. KRESNYAK, Rocky Mountain GTL Inc., Calgary, Alberta; and J. WAGNER, Wagner Energy Consulting, Calgary, Alberta, Canada

H₂ possesses a greater energy density than natural gas, gasoline or diesel: with the world moving increasingly towards decarbonization, there is little doubt that H₂ has a major role to play. Ultimately, the H₂ economy is expected to rely on electrolytic green H₂, which will provide complete decarbonization; however, green H₂ cannot presently compete economically with H₂ derived from fossil fuels. Because of this, the majority of H₂ production now utilizes a steam methane reforming (SMR) process and a natural gas feedstock.¹ While this is unlikely to change before 2030, pre- and/or post-combustion carbon management systems can reduce the carbon intensity (CI) of this H₂ from 10 kg–12 kg CO₂e/kg H2 to 3 kg–6 kg CO₂e/kg H₂. This transition from high-emissions gray H₂ to low-emissions blue H₂ will provide an interim solution while zero-carbon green H₂ technologies mature. This article showcases a new method for co-generating blue H₂ alongside high-quality synthetic fuels, providing maximized energy output with reduced carbon emissions and need for carbon sequestration.

FIG. 1. Types of H₂.

FIG. 2. Synthesis process flow schematic.

Production of syngas for blue H₂. Syngas (H₂ + CO) feeds are necessary for a number of chemical production processes (e.g., methanol, synthetic fuels, ammonia-based fertilizers).² Any of three technologies can be used to generate syngas from natural gas, depending on the H₂:CO ratio desired. The technologies available for deployment and the syngas compositions they produce are as follows:

• SMR: 3 H2–5 H2 per CO, but has ability to generate a 2.4 H2:CO ratio
• Autothermal reforming (ATR): 1 H₂–2.4 H₂ per 1 CO
• Gasification/partial oxidation reforming (POx): 1 H₂ per 1 CO.

FIG. 3. GTL process concept.

When the desired end product is H₂, the CO portion of the syngas is converted to CO₂ using a water-gas shift (WGS) reaction. The resulting CO₂ is then separated from the H₂ and either released or captured and sequestered. Alternately, the WGS conversion process can be omitted, and the raw syngas synthesized into synthetic methanol, Fischer-Tropsch (FT) diesel or jet fuel. These synthesis conversion processes require a syngas composition of ~2 H₂ per CO mole ratio, meaning that syngas generated via SMR would contain H₂ in excess of need. A membrane separation process can be used to trim the syngas to the desired composition, and the newly separated H₂ used as fuel for the process or removed and utilized in other processing units. This alternate method has significant advantages for blue H₂ production, including: 

• Produces blue H₂ with a CI of 6 kg CO₂e/kg H₂ and without immediate need for post-combustion carbon capture
• Substantially all carbon from the process inlet feed is fully converted or sequestered in useful chemicals, such as FT fuels or methanol, rather than being emitted into the atmosphere as CO₂
• The quantity of blue H₂ produced is flexible and can be varied by changing the steam/carbon ratio (S/C) feeding the SMR
• The combined production of H₂ and synthetic chemicals/fuels is economic at small scale and scalable to meet local market requirements.

FIG. 4. Enhanced GTL process^b flow schematic.

FIG. 5. Carseland GTL plant.

Industrial application: The Carseland GTL plant. A Canadian companya has designed and constructed a new GTL plant near Carseland, Alberta (FIG. 5) that uses a proprietary version of the above process^b to co-generate blue H₂ with synthetic diesel^c. The plant has the capacity to produce 450 bpd of synthetic diesel using 7.4 million cubic feet per day (MMft³d) of natural gas feed with H₂ co-production, or 5.4 MMft³d of natural gas without; its H2 output capacity is 6 MMft³d (16.5 metric tpd). The company plans to immediately increase SMR capacity and maximize synthetic diesel production to 614 bpd with maximum co-production of 12.8 MMft³d (34.9 metric tpd) of blue H₂.

FIG. 6. Blue H₂ co-production economics using new process.

CO₂ management study: Carseland GTL plant vs. conventional blue H₂ plant. A study was commissioned to verify the carbon management comparison between the proprietary process used at the Carseland plant and one already in use elsewhere to produce blue H₂. An operating example of a conventional blue H₂ project using SMR with pre-combustion carbon capture and sequestration (CCS) was located and detailed observations made (TABLE 1).³ The study demonstrated parity between the Carseland GTL Project’s CI and that of its more conventional counterpart: in both cases, the CI was approximately 6 kg CO₂e/kg H₂. The Carseland GTL Project, however, achieved these results without making use of CCS facilities, opting instead for a carbon capture and utilization approach and storing the equivalent carbon in synthetic diesel.

TABLE 1. Carbon management comparison.

Economics of blue H₂ production at the Carseland GTL plant. TABLE 2 describes the current (2021) market commodity pricing used to establish the economic potential of the process used at Carseland. Based on this, as FIG. 6 illustrates, the economic potential of this process is a > 20% internal rate of return (IRR) before tax for a plant producing 500 bpd of synthetic diesel and 16 metric tpd–34 metric tpd co-generated blue H₂. These calculations assume H₂ prices of > CAD $2.00 (U.S. $1.50) per kg.

TABLE 2. Commodity pricing.

Carseland GTL plant: Planned projects leading to net-zero. The following projects are planned for the Carseland GTL plant to establish a path to net-zero emissions by 2025 (FIG. 7): 

1. H2 co-production project to achieve CI = 95 g CO₂e/MJ diesel, which would achieve CI targets for 2022 according to Canada’s low-carbon fuel standards
2. Post-combustion CCUS and/or biomass syngas (25% capacity) to meet and exceed Canada’s and British Columbia’s 2030 low-carbon fuel standard³
3. Raw field gas to achieve CI < 60 g CO₂e/MJ diesel
4. Integration of a renewable hydrotreating diesel plant to achieve CI = 25 or less g CO₂e/MJ diesel.

FIG. 7. Carseland GTL plant path to near-zero future.

Case Study 1: Carseland GTL plant—capacity to decarbonize Alberta natural gas supply. Based on the expansion plans for 2023 of the Carseland plant, blue H₂ will be available in sufficient quantity to support up to 160 MMft³d of 5% blend natural gas. Future plant expansions will bring co-production capacity to 100 metric tpd of blue H₂, which is sufficient to support up to 850 MMft³d of 5% blend natural gas. These volumes of co-generated H₂, as shown by TABLE 3, demonstrate the significant role the Carseland GTL plant can play in supporting the decarbonization of Alberta’s natural gas supply system.

TABLE 3. Carseland GTL plant capacity to support 5% H₂/natural gas blend.

Case Study 2: Carseland GTL plant—capability to integrate with hydrogenation-derived renewable diesel (HDRD) projects. According to a recently completed study, the Carseland GTL plant’s current blue H₂ production capacity of 16 metric tpd could support the integration of a 2,500-bpd–4,000-bpd canola seed oil HDRD plant (FIG. 8), producing a combined site capacity of up to 4,500 bpd of low-carbon diesel with a combined CI of less than 25. The study additionally confirmed that the propane byproduct generated by the HDRD process could be recycled and used as feed for the GTL plant, reducing the plant’s demand for natural gas and further reducing the combined CI.

FIG. 8. Carseland GTL plant integration with HDRD facility.

From Kitimat to California: A blue H₂ market opportunity. H₂ production represents a significant opportunity for Alberta and British Columbia to move beyond satisfying Canadian needs and export H₂ to markets possessing ambitious decarbonization plants but lacking the CCUS capabilities and projected low-cost, sustainable supply of natural gas that make these two regions so well-suited to producing blue H₂. Potentially key export markets for Canadian-produced blue H₂ include Japan, China, South Korea and California; a proposed GTL plant in Kitimat, British Columbia intended to supply the California market provides an illuminating case study.

A workshop was held in March 2021 by two Canadian economic development groups (Edmonton Global and Alberta’s Industrial Heartland Association) to address California’s H₂ market potential. Participants included key California stakeholders, such as the California governor’s office, energy commission and the California Hydrogen Business Council. The key takeaways from the workshop were: 

• California plans a shift to zero-emissions fuels over the next 25 yr, and has ambitious targets to meet
• Low-carbon H₂ will play an important role in this shift
• California’s largest focus area for low-carbon fuels is the transportation sector (TABLE 4), although the state’s power generation sector was also identified as an opportunity
• California’s rapidly growing H₂ market is open to a range of H₂ suppliers from multiple jurisdictions, including Canada
• Decisions on how to meet California’s demand for H₂ will be driven by the market. This includes considerations about how the H₂ is transported (e.g., rail, pipeline, ship) and the form in which it will be distributed, whether as a compressed gas, a cryogenic liquid or using a carrier medium (e.g., ammonia or methanol).^5,6

TABLE 4. California H₂ vehicle market potential.

Based on these findings, a GTL plant located in Kitimat that utilizes the same blue H2 co-production technology as Carseland was proposed. Kitimat, as shown on the map in FIG. 9, is located on Canada’s west coast and provides access to multiple export routes. Beyond that, several synergies confirmed the suitable selection of this location: 

• First Canadian LNG project is located at Kitimat
• Local workforce, infrastructure and expertise available coincidently from above-mentioned project
• Natural gas available from the Western Transmission Gas Line, which has a capacity of 3,500 MMft³d; only a fraction of that amount would be needed
• Marine export through the Douglas Channel has precedent, established by LNG carriers
• Compressed H₂ ships can be fueled with LNG or H₂
• In addition to export possibilities, British Columbia has strong local demand for low-carbon marine FT diesel and FT jet fuel
• The Haisla nation has potential interest in participating.

FIG. 9. Kitimat region map.

The plant, if built, would simultaneously supply blue H₂ to California and GTL products to British Columbia. Using a natural gas feed of between 95 MMft³d and 120 MMft³d, it would have a GTL production capacity of 5,000 bpd–7,000 bpd (3 < S/C < 5 in SMR) and a blue H₂ co-production capacity of 100 MMft³d (240 metric tpd). It should also be noted that all elements of the potential plant’s process are technically proven and commercially available, requiring no further research or technological development. 

The H₂ would be transported by ship as a compressed gas (3,600 psig, or 250 bar), sailing a distance of 1,100 nautical miles (2,035 km) to its destination in California. 

The planned provider for the compressed H₂ ships^f has a range of ship sizes available and has received an approval in principle from the American Bureau of Shipping (ABS) for a container ship design (FIG. 10) that would safely store up to 2,000 metric t of compressed H₂ at ambient temperatures and a pressure of 3,600 psig.⁷ This planned ship would be powered by electric drive engines and onboard fuel cells, using H₂ as fuel. Studies have concluded that the levelized cost of H₂ is quite competitive as a marine transport solution for distances of 2,000 nautical miles (3,700 km) and remains somewhat competitive up to 4,500 nautical miles (8,300 km). The ship will operate as a closed system with no losses or boil-off requirements.⁸ 

FIG. 10. Compressed H₂ ship. Courtesy of Global Energy Ventures Ltd.

The plant’s capital expenditures are estimated at between CAD $800 MM and CAD $1,000 MM with H₂ production cost at < U.S. $2.00/kg and a California retail price for H₂ of U.S. $16.10/kg (CAD $21.50/kg). 

Takeaway. The new co-generation technology being used in Carseland has confirmed the technical and economic feasibility of co-producing blue H₂ and syngas on a small scale and promises to make a valuable contribution to decarbonization in Canada and beyond. Co-generation of this kind provides a strong opportunity to export compressed blue H₂ from Canada to growing H₂ markets in other countries.

NOTES

^a Rocky Mountain GTL Inc. 

^b Enhanced GTL® (EGTL®) 

^c SynDiesel® 

^d The Shell Quest Project (2015), located in Scotford Refinery near Edmonton, Canada. 

^e Eni Econfining process 

^f Global Energy Ventures

LITERATURE CITED

 

1. Ewing, M., et al., “Hydrogen on the path to net-zero emissions—costs and climate benefits,” Pembina Institute, July 2020. 

2. PPHB Energy Investment Banking, “Will hydrogen play a key role in our energy future?” July 2020. 

3. Government of Canada, “Clean fuel regulations,” Canada Gazette, Volume 154, December 2020. 

4. Shell Plc., “Quest carbon capture and storage,” online: https://www.shell.ca/en_ca/about-us/projects-and-sites/quest-carbon-capture-and-storage-project.html 

5. California Energy Commission, Joint Agency Report, 2019. 

6. Bouilama, Sherri, “Event highlights—the California market for hydrogen,” Edmonton Journal, March 2021. 

7. Global Energy Ventures, “Launch of 2022 compressed hydrogen ship program,” December 2021, online: https://gev.com/wp-content/uploads/2021/12/launch-of-2022-compressed-hydrogen-ship-program.pdf 

8. Global Energy Ventures, “Shipping solutions for energy transition,” Macquarie Virtual Conference, March 2021.

STEVE KRESNYAK is VP and chief technology officer for Rocky Mountain GTL Inc. as well as the inventor and engineering director responsible for developing the GTL technology currently installed at the Carseland, Alberta site. He has more than 40 yr EPC/EPCM experience globally and has provided engineering expertise for upstream, downstream and offshore energy projects, primarily pertaining to gas and oil. As a partner with COLT Engineering, Mr. Kresnyak authored and presented several patents and technical papers. 

JAN WAGNER is the president of Wagner Energy Consulting and is a process engineer with more than 45 yr experience. He currently focuses on gas production, gas processing, syngas derivatives and H₂ generation concepts. He received an MS in Process Engineering from Czech Technical University in Prague in 1967 and is a Life Member of the Association of Professional Engineers and Geoscientists of Alberta.