The concept of blending hydrogen with natural gas is quickly emerging as a pathway to reduce carbon dioxide emissions while striving to maintain the reliability and affordability provided by the existing fleet of gas-fired power generation facilities.

Just how much hydrogen can be safely mixed with natural gas in simple-cycle, combined-cycle or reciprocating engine units? That is a question the entire power industry is attempting to answer.

The California Public Utilities Commission recently concluded a study that found a blend of up to 5% hydrogen with 95% natural gas is considered to be safe in existing pipelines and will have no detrimental impacts on components, materials and equipment.

Now, the task in California and elsewhere is to identify whether higher percentages of hydrogen are feasible and, if so, what plant modifications may be required as the industry progresses toward a goal of one day using 100% hydrogen as a fuel source for power generation.

Though these questions may sound simple, the process of resolving them is actually quite complex. Burns & McDonnell recently concluded a first-of-its-kind pilot test with EPRI and Wärtsilä at a WEC Energy Group reciprocating engine power plant in the Upper Peninsula of Michigan, a test that involved nearly a full year of planning to execute successfully. Here are eight key rules that came into sharper focus during this exercise.

1. Safety Is Everything

Given the unique chemical characteristics of hydrogen, safety must be the top priority. It is 14 times lighter than air, making it the lightest element in the universe. As a gas, it is difficult to detect because it is colorless, odorless and does not pool near the ground like other fuels. Because of its small molecular size, it is prone to escape from pipelines through valves, flanges or other connection points. Performing leak checks with nitrogen or helium is a prudent safety measure before introducing hydrogen into the system. Hydrogen is also easier to ignite because it has a wide range of flammability and burns with no visible trace of a flame.

Given these factors, it is important to perform upfront safety planning, including Hazard and Operability (HAZOP) and Process Hazard Analysis (PHA) meetings in addition to reviews of applicable codes. Thus, Rule No. 1 is that safety must be the highest priority.

2. Coordinate With the OEM

Whether the test is for a gas turbine or a reciprocating engine, the original equipment manufacturer (OEM) should be involved. Wärtsilä was an essential partner because its team understood the performance characteristics of its equipment better than anyone else.

All of these manufacturers are quickly moving to adapt their units to handle progressively higher percentages of hydrogen. It is essential that their engineers and technicians have an active role in designing test plans they will need for later analysis of test points, blend ratios and durations. In this case, the OEM helped identify the limitations of the equipment that should be considered for a 25% hydrogen blend rate.

3. Determine Type and Source of Hydrogen

There are three main options for hydrogen sourcing:
  • Delivery via truck (most common)
  • On-site generation
  • Delivery via pipeline

For most small-scale, short-duration tests, pipeline deliveries or on-site generation will not be technically or economically feasible.

Once the source is determined, the next task is to determine whether the hydrogen should be transported in liquid or gaseous form. This can be a tricky question because achieving the proper energy density for gaseous hydrogen requires that it be stored at high pressures. Meanwhile, liquid hydrogen must be kept at cryogenic temperatures near absolute zero.

Unless vaporizers, pumps and compressors are available to convert liquid hydrogen into gas, starting with gaseous hydrogen and installing the equipment to reduce and control pressure before mixing with the natural gas supply is likely to be the preferred choice.

4. Secure Hydrogen Supply ASAP

With new use cases quickly emerging for hydrogen, there is no time to waste in securing firm hydrogen supply. Arrangements with industrial gas suppliers need to be made for coordinating large supply volumes of hydrogen for these tests over a short period of time. This can be a contrast with recurring small-volume arrangements over a long period, which are more typical. This is even more evident in demand for green hydrogen (i.e., hydrogen produced from renewable energy sources that power electrolyzers), since the demand is scaling up quickly and there is only a relatively small amount of green hydrogen currently commercially available.

5. Location, Location, Location

Though location has long been recognized for its importance in real estate transactions, it also is an essential consideration for hydrogen testing. The National Fire Protection Association (NFPA) code addressing hydrogen facilities (NFPA 2) specifies minimum setback requirements for liquid and gaseous hydrogen storage, along with spacing between storage facilities and other structures. Site space constraints should be evaluated in addition to the key setback parameters for gaseous hydrogen (storage pressure and pipe size) and liquid hydrogen (storage volume). Sources and types of hydrogen selected for the test affects the location of the unit selected for the test. It should be noted that this is an iterative process and changes to one rule will affect many others.

6. Tie-Ins and Hydrogen Blending

Once types and storage locations have been determined, careful consideration must be given to how the hydrogen supply will be tied into the existing natural gas supply lines. There are two main tie-ins:

  • Hydrogen supply into the existing natural gas system upstream of the blending skid.
  • Blended fuel of hydrogen and natural gas into the existing natural gas line downstream of the blending skids to the units being tested.

Regardless of which approach is chosen, minimizing hydrogen exposure to the existing plant components is imperative, as they are likely rated for natural gas only. It will also be important to place the blended fuel connection as close as possible to the unit that will be doing the test burn. This will reduce any variables that could compromise the data needed for further analysis. The OEM will be an important consultant at this stage to provide input on any equipment that may need to be added or replaced in advance of the test.

For example, it will likely be necessary to have an analyzer installed to monitor any percentage changes in fuel composition while the test is underway. This will provide the insight needed to assess how effective the mixing is happening at various blending levels.

7. Monitor Impacts to Other Plant Operations

In designing the test, a key question to address is whether other units of the plant will continue to operate under normal conditions for the duration of the test. If they can run in isolation due to a separate fuel feed, it is likely they can continue to operate, but if all units are supplied by a common gas fuel header, they will need to be taken offline for the active portion of the test.

In addition, the test design will need to factor in whether the blended hydrogen fuel will be fed near a designated hazardous electrical equipment area. For safety purposes, the ratings of electrical equipment in close proximity to the blended fuel must be examined. It is possible that new electrical ratings will need to be implemented for future exposures to hydrogen fuel. Also possible would be evaluations of any changes to controls that may be needed.

8. Follow-Up

After the pilot is complete, some answers will be clear while others may require additional analysis and evaluation. If it appears feasible that the plant can accommodate some percentage of hydrogen as a fuel source over the long term, hydrogen sourcing will become a priority. Due to the large volume needed over a longer term, trailer and truck deliveries may no longer be a viable option. Will it be possible to tie into an existing pipeline rated for hydrogen? Will it be economically viable to engineer some means of hydrogen production on-site?

Once those questions are answered, existing air quality permits will need to be reevaluated and potentially refiled to meet the expected new emissions profile.

Hydrogen blending has a huge potential to decarbonize the existing fleet of gas generation facilities that today provides approximately 38% of the generation capacity on the U.S. grid.

Identifying answers to the inevitable questions that are emerging over the prospect of blending hydrogen with natural gas will help plant operators maintain historic levels of plant reliability and overall performance while reducing carbon emissions. As the data is assessed, tracked and analyzed, the feasibility of future pathways will inevitably emerge.

All of this points to an exciting future where emissions are reduced while the industry avoids the potential of stranding critical power generation assets at a time when electrical supply is needed most.


As more states enact mandates to achieve zero-carbon emissions, utilities and generation plant owners face more pressure to reduce the carbon intensity of their fossil fleets. Hydrogen blending solutions are gaining increased attention as an option to avoid billions in stranded assets.

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Megan Reusser is a senior development engineer at Burns & McDonnell. With more than a decade of industry experience, she provides clients with technical solutions that optimize process design and reduce energy consumption, with a specialized focus on technologies supporting decarbonization projects.