Hydrogen is being viewed as the most viable alternative to natural gas in the Power Generation sector. It is already being successfully blended with natural gas in small percentages in several facilities across the U.S. And with funding approved for seven H2Hubs, there will only be an increased focus on mitigating greenhouse gases via hydrogen. As of January 15, 2024, the American Gas Association, reports that "natural gas accounted for 40% of all electricity generation in the lower-48 states," and this hydrogen blending process is a critical first step toward reduced natural gas consumption.
In addition to blending, hydrogen has an even larger role to play in reducing greenhouse gases. While we expect that major adoption of hydrogen as a primary energy source will initially come from some of the more difficult to abate industries like heavy duty trucking and shipping, there is also movement within the utilities space to lean more heavily on hydrogen for power generation. Gas turbine OEMs continue to develop new combustors and other components to facilitate the burning of larger percentages of hydrogen and retrofit existing fleets to be able to run safely and efficiently on hydrogen.
But the transition won’t be easy. Here are five of the top things that utilities need to consider should they wish to introduce hydrogen into the fuel mix.
Start Small
A small amount of hydrogen can be blended with natural gas in existing gas turbine plants without much concern. It won’t materially impact combustion characteristics or require extensive retrofits. Therefore, utilities are advised to start small with perhaps a 5% blend by volume. Refineries, for example, have used hydrogen blends for decades in small gas turbines. By starting with small amounts of hydrogen, utilities will gain the familiarity needed to take their hydrogen ambitions further.
Adding Higher Percentages
Once you venture much beyond 5% to 10% (some OEMs claim existing turbomachinery can operate at up to 20% without modification), there will be a need for new combustors and other retrofits. Several OEMs have combustors in development or testing that are designed to address hydrogen’s higher flame temperature, and its tendency for flashback. The addition of hydrogen leads to faster combustion and accelerated flame propagation. If this exceeds the fluid velocity of the premixed gases, the flame moves upstream in the fluid (flashes back) and can ignite fuel outside the combustion chamber.
Fortunately, such problems are being overcome. Several OEMs have publicly stated they can run their turbines with 50% of more hydrogen blends. Some have achieved 100% in certain models, at least during tests.
The fact remains, though, that further facility modifications will be needed to convert legacy systems to accommodate hydrogen. Hydrogen, after all, is a much lighter molecule than natural gas. Fuel delivery systems will have to be set up and modified to safely bring hydrogen to where it is needed. Piping will also be larger than normal due to a much larger volume of hydrogen gas being required to generate the same amount of power as can be accomplished with unblended natural gas. Seals and valves, too, will need to be changed to enable them to take care of hydrogen without leakage – existing seals and valves can hold natural gas well but not hydrogen. And additional plant safety systems must be incorporated into facilities to detect leaks due to the flammability of hydrogen and the potential dangers that poses.
For combined cycle plants, heat recovery steam generators (HRSGs) may also require extensive modification to accommodate hydrogen. Any utility with hydrogen ambitions that is planning to order a new HRSG or retrofit an old one should collaborate with HRSG engineers to ensure their new gear is capable of dealing with the amount of hydrogen they plan to introduce – otherwise they may find themselves limited in the amount of hydrogen they can easily introduce.
Emissions Compliance
Due to the rise in temperature when hydrogen combustion is compared to natural gas combustion, utilities should expect some increase in the formation of Nitrous Oxide (NOx). This can be mitigated to some degree by more thorough premixing of fuel and air before it enters the combustor. Much research and development is ongoing into the impact of hydrogen on NOx formation. Utilities in areas facing strict emissions mandates are advised to consider this factor carefully before adding hydrogen.
What Color of Hydrogen?
Most current hydrogen supply comes from fossil fuel sources. Blue hydrogen, for example, originates from natural gas using a process known as steam reforming where natural gas and steam react to form hydrogen as well as carbon dioxide. Carbon capture is generally considered to earn the title blue hydrogen, and that adds to the cost. Gray hydrogen is the same as blue hydrogen except that no carbon capture is involved. Black and brown hydrogen are made through partial oxidation gasification from black coal or brown coal (lignite). Red (or pink) hydrogen is generated using electricity from nuclear energy. Green hydrogen is made without producing any greenhouse gas emissions by using electricity from renewable sources to electrolyze water. Electrolyzers use an electrochemical reaction to split water into its components, hydrogen and oxygen.
There are other colors of hydrogen, but these are the principal ones. Most utilities want green hydrogen but very little of it is available and it is currently expensive. Most hydrogen supply right now is used in industrial processes where it makes more economic sense at the moment than burning it for power generation. Even the most optimistic projections about the cost of green hydrogen say it will be many years, perhaps more than a decade before green hydrogen costs come down enough to enable broad usage. Therefore, compromises will probably have to be made such as beginning with blue or gray hydrogen and gradually introducing green hydrogen when it is available.
Hydrogen Availability
Which brings us to the elephant in the room – availability of supply. This is the largest barrier for expanded hydrogen use. Anyone planning to add hydrogen into their operations must seriously evaluate the availability of hydrogen. And while the H2Hubs will certainly increase hydrogen availability in certain areas across the country, organizations that are not near these hubs will need to consider how to source hydrogen if they are serious about implementing it for power generation.
For example, a utility in the south deployed new gas turbines capable of running on 25% hydrogen. However, it has no available supply of hydrogen and does not see any hydrogen becoming available anytime soon.
Even when the hydrogen production problem is resolved, utilities will still need to invest in extensive supporting infrastructure including pipelines and, for some, storage facilities capable of transporting and holding hydrogen without leaking.
The Path Forward
The path forward for utilizing hydrogen in power generation is filled with great challenges, but also great potential rewards. By following these tips, utilities can position themselves to incrementally introduce hydrogen into their operations. This will allow the power generation industry to reduce reliance on natural gas and begin decarbonizing electricity production. The road ahead requires commitment and strategic planning, but hydrogen offers utilities a viable pathway to a cleaner energy future.
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with contribution from Ted Lenart, Vice President of Natural Gas Services, PFES
