Many advocates for a hydrogen economy believe “green” hydrogen, which is produced through electrolysis using renewable energy, will eliminate the need to curtail wind and solar generation. However, there are many reasons why “blue” hydrogen, which is produced from natural gas while using carbon capture technology to reduce or eliminate greenhouse gas emissions, could be a better long-term option for hydrogen production.
Now is not the first hydrogen (H2) revolution. The promise of hydrogen’s energy density and carbon-free combustion has attracted the attention of innovators for years, with the earliest concepts on the hydrogen fuel cell published in 1801. As large-scale efforts to decarbonize the global economy ramp up in earnest, hydrogen is once more being positioned as a critical solution for numerous sectors.
Hydrogen produced from fossil energy resources is commonly viewed as a bridge in this energy transition, enabling the build-out of midstream infrastructure and downstream demand while the cost of renewably driven electrolysis of water to produce “green” hydrogen continues to fall. However, a 100% green hydrogen economy may fail to deliver on the potential for hydrogen or unnecessarily delay progress. To avoid another missed opportunity, “blue” hydrogen (derived from fossil fuels with carbon capture, utilization, and storage [CCUS]) must comprise a considerable market share of the hydrogen economy.
Hydrogen’s Cost Conundrum
Failures of the hydrogen economy to materialize have centered on the chicken-or-the-egg challenge of a paradigm shift in tightly integrated, capital-intensive industries. Analyses have shown that hydrogen becomes the low-cost, low-carbon solution in a majority of potential end-use markets at $2/kilogram (kg) H 2.
Currently, fossil-based hydrogen without carbon capture, known as “gray” hydrogen, can deliver less than $1.50/kg H 2 costs while carbon capture can add $0.10/kg to $0.30/kg. Green hydrogen currently delivers approximately $5/kg unit costs, although these estimates are dropping sharply with advances in electrolyzer manufacturing and oversupply of renewable power expected to achieve $2.60/kg prices by 2030 and less than $1.50/kg by 2050.
High cost and a lack of carbon pricing limit demand across the end-use sectors where H 2 can be most impactful. Without this demand pull, investment into new production capacity and new or retrofitted transmission, distribution, and storage infrastructure has been unjustifiable.
Commercial consortia, such as the Hydrogen Council; industry first movers, like Air Products in Saudi Arabia; and intergovernmental strategies, including the European Union Hydrogen Backbone project, have initiated the investment needed for the transformation of the hydrogen economy. However, in each case, blue hydrogen is at most a steppingstone to a green hydrogen market: a gray-to-blue-to-green transition. This strategy has three primary limitations that may be resolved through continued utilization of blue hydrogen. They are:
- ■ Geographic variability of resource availability.
- ■ Energy inefficiencies of electrolysis.
- ■ Intermittent supply limiting build-out of constant demand end-uses.
Water and Energy Availability Are Key
Hydrogen production requires abundant, low-cost water or simple hydrocarbons (primarily methane). Green hydrogen consumes at least 9 kg of water per kg of H 2 while gray and blue H 2 requires half as much (when produced via steam methane reforming with a subsequent water-gas shift). Water is increasingly a limited resource, with complex and interdependent uses for energy, agriculture, and sanitation. In many regions across the world, often those with abundant renewable energy, water stress may not allow for production at the scale required to meet local demands.
Conversely, utilization of shale gas reservoirs has dramatically expanded the geographic footprint of natural gas extraction. Suitable geologic carbon dioxide (CO 2) storage capacity is also available and plentiful. Infrastructure availability is also vastly different between blue and green hydrogen. The natural gas value chain is globally mature, and both financial and regulatory stakeholders understand its operation in detail; these “soft” infrastructures require development in an all-green hydrogen scenario.
In addition to higher water consumption, green hydrogen requires approximately 11 times as much energy per unit H 2 produced compared to fossil-based routes (before carbon capture) and it needs to be cheap. Greening the current global gray hydrogen supply would require nearly 3,900 TWh of electricity annually, roughly 60% more than the combined global wind and solar photovoltaic generation in 2020 (2,444 TWh).
|1. Capacity factors of potential electrolyzers running on curtailed renewable power in the California Independent System Operator (CAISO) market. Analysis of the data from 2020 found that only 451 tons (t) of hydrogen could be produced from CAISO’s curtailed renewable energy. Source: National Energy Technology Laboratory (NETL)
At current capital prices, electrolyzers meet the $2/kg threshold only when running on “free” electricity 30% of the time or more, dramatically limiting the hydrogen supply. In 2020, 1.6 TWh of renewables were curtailed by the California Independent System Operator (CAISO), enough for approximately 28.9 kilotons of H 2 production. However, analysis of CAISO data shows that only 50 MW of electrolyzers could achieve a 30% capacity factor on curtailed energy (Figure 1), enough to produce only 451 tons of H 2.
While hydrogen is viewed as a solution to renewable curtailment, converting excess power to hydrogen that can be later reclaimed in a turbine or fuel cell (power-to-gas-to-power) can amount to a 70% energy loss. For most grid storage needs—typically several hours at most—the less than 10% roundtrip losses of battery storage represent a considerable advantage.
Chemical energy storage (including hydrogen) does represent the only technically feasible and widely scalable approach to inter-seasonal storage of renewable energy, but the demand for this duration only becomes meaningful for renewable penetration greater than 70% of demand. Thus, oversupplied renewables are unlikely to catalyze transformational use of hydrogen in a timely fashion.
Weighing Hydrogen Options
Hydrogen is best suited to decarbonize certain difficult-to-abate sectors of the economy, specifically heavy road freight, shipping, aviation, chemicals, cement, and iron and steel manufacturing. These sectors account for a combined 30% of global greenhouse gas emissions and are challenging to electrify. In contrast to load shifting of renewables, each of these sectors would have nearly continuous demand for hydrogen. Thus, those demand centers for which hydrogen has the best value proposition are least served by the capabilities of intermittent, green hydrogen or require additional costs associated with storage.
The simplest “solution” to curtailment would be higher demand on the grid. However, in a business model where the electrolyzer is used to maximize utilization of a renewable resource by avoiding curtailment, the grid will not see increased demand, ensuring supply is intermittent. It is not currently economically feasible for most industries to buy power from the grid to generate green hydrogen continuously. Conversely, blue hydrogen is decoupled from power supply and, in many geographies, leverages low-cost and continuously available natural gas.
Taken together, there is a clear need for blue hydrogen to satisfy growing end-uses at affordable pricing and finance the necessary midstream infrastructure to sustain growth of the hydrogen economy. The ubiquity of shale gas plays, along with growing natural gas infrastructure and CO 2 storage sites, creates an opportunity for a geographically diversified hydrogen economy and rapid decarbonization. However, early leaders in the green hydrogen economy, such as Germany, have left little political room for blue hydrogen. A substantial risk exists that a planned obsolescence of blue hydrogen will limit the participants in this ecosystem and lead to financing difficulties, particularly for new capacity.
Despite current advantages of blue hydrogen, work is still needed to realize a hydrogen transformation. These challenges center on the carbon intensity of existing gray hydrogen production designs and the relative immaturity of the carbon sequestration industry. The predominant mode of gray hydrogen production, steam methane reforming with a water-gas shift reaction, will need to be retrofitted to capture two streams of CO 2: a flue gas from natural gas combustion for heat and a process gas stream under pressure. Alternatively, a shift to auto-thermal reforming would make CO 2 capture considerably simpler, albeit with decreased hydrogen yields, and provide blue hydrogen with lifecycle emissions comparable to those of green hydrogen from wind and solar.
Once captured, from the current state of the art or future production processes, the CO 2 must be stored or utilized. Enhanced oil recovery by CO 2 injection is a mature technology, yet, it is likely to be met with intense scrutiny as it relates to the market requirement of carbon-free hydrogen.
|2. The Department of Energy (DOE) partnered with Air Products Inc. to advance a first-of-a-kind retrofit system to capture carbon from large-scale industrial steam methane reformer plants located at the Valero Port Arthur Refinery in Port Arthur, Texas. The project was funded by the DOE’s Office of Fossil Energy, and co-managed by NETL and Air Products. Courtesy: NETL
The U.S. Department of Energy, Office of Fossil Energy’s National Energy Technology Laboratory (NETL) has unique capabilities and experience to help realize the potential of a transformed hydrogen economy and is making investments across the value chain (Figure 2). NETL is already determining how to address near-term technical gaps with increased use of hydrogen in both pipelines and power plants. NETL’s advanced turbines program is enabling the next generation of turbines to operate efficiently with higher ratios of hydrogen fuel.
Work at NETL is targeting improvements to conventional natural gas reforming methods for hydrogen, as well as exploring more novel hydrogen production technologies, including methane pyrolysis with solid carbon co-production and coal/biomass co-gasification with CCUS for carbon-negative hydrogen. In the mid-term, NETL investment, and research and development (R&D) in carbon capture technology, will enable blue hydrogen to be produced cost-effectively.
NETL is also addressing longer-term R&D challenges, such as hydrogen storage, and working with external partners to assess technical gaps. NETL’s systems analysis capabilities are investigating blue hydrogen production economics, end-use markets, and infrastructure constraints. Finally, realizing the decarbonization potential of hydrogen demands a collaborative ecosystem of technology developers, end-users, and regulators. NETL is well-positioned to support each of these stakeholder groups in rising to this challenge. ■
—Clinton Noack, PhD is a senior consultant focused on research and development, and innovation strategy, for NETL’s Crosscutting Materials, Water Management, and Advanced Energy programs; and Briggs White, PhD is technology manager for High Performance Materials, Water Management, and Energy Storage