Hydrogen substitution for natural gas in turbines: Opportunities, issues, and challenges

(Photo courtesy EnergyAustralia)

By Ben Emerson and Tim Lieuwen, Georgia Institute of Technology

Bobby Noble and Neva Espinoza, Electric Power Research Institute

Introduction to hydrogen as an energy carrier

Today’s energy system includes three major subsystems: (A) energy sources (oil, solar, etc.), (B) infrastructure and carriers for moving these energy sources, and (C) energy consumers. 

This article considers issues associated with hydrogen as an energy carrier.  Currently, the energy system is dominated by two largely independent, multi-trillion dollar carrier systems — electricity and  hydrocarbon fuels. In the US today, roughly 40% of energy is carried via electricity and 60% via fuels.  Fuels are chemical-based energy carriers with high energy densities that make long-range transportation possible. Today they are almost completely based on fossil fuels, such as natural gas or crude oil.  These systems leverage millions of miles of pipelines, a significant petrochemical manufacturing base, and serve a global user network, including vehicles, industrial processes, and building heating.   

While many questions remain about the relative roles of electricity and chemical energy carriers in a decarbonized economy, two things seem clear: (1) use of fossil fuels as energy sources and carriers will decrease, although probably not to zero, and (2) use of “manufactured” chemical energy carriers, such as hydrogen that is produced using renewable power, will grow.  These will be used to both move energy from sources to user, as well as to store energy. 

There are three key issues around hydrogen as an energy carrier: (1) generation of hydrogen, (2) logistics, handling, and movement of hydrogen, such as via pipelines, and (3) utilization of hydrogen by a variety of “energy conversion device” — i.e., devices that generate electricity (e.g., fuel cells or gas turbine power plants), or are used to heat water or building spaces.

The primary focus of this article is to address issue (3) —to identify the opportunities and challenges associated with utilizing hydrogen in energy conversion devices. For example, a key opportunity for hydrogen is to store it and then burn it in gas turbines during times of peak demand. This has the benefits of re-purposing existing technology (gas-fired plants and natural gas infrastructure) for combustion-based energy storage with no carbon emissions.  Here we address the following questions:

1. Is hydrogen viable as a fuel? Can hydrogen be used in retrofitted devices or new systems?
2. If so, what are the constraints or issues that must be understood by policymakers, users, and the public?

Can Hydrogen be used in Energy Conversion Devices?

The answer to this question is emphatically yes. There is no fundamental reason why hydrogen cannot be combusted in gas turbines, heaters, boilers, or other energy applications such as generating electricity. It can be used in a blend with natural gas, or as pure hydrogen.

In fact, today hydrogen is used as a dominant fuel source for a number of power generating plants, such as the Fusina hydrogen power station in Italy (100% hydrogen), a petrochemical plant in Daesan, South Korea (95% hydrogen), a steel mill in Wuhan, China (60% hydrogen), and several planned facilities converting to 100% hydrogen such as the Magnum plant in Vattenfall, Netherlands, and the Intermountain Power Agency plant in Utah.   It has been flown in specially designed aircraft by Martin, Tupelov, Boeing, and Skyleader, and airframers have pledged future hydrogen aircraft such as the Airbus ZEROe. 

What are the Constraints Associated with Utilizing Hydrogen in Existing Systems?

While hydrogen combustion offers a promising energy storage and conversion pathway, it is not a “drop-in” fuel for much of today’s natural gas fired energy conversion devices.  In other words, alterations are needed in the fuel handling systems, valves and piping, and combustor hardware.  These alterations are needed to address several issues of concern to stakeholders, including pollutant emissions, operability, and cost.  These issues are highly interdependent.

We will address pollutant emissions first.  In addition to concerns around CO₂ emissions associated with climate change concerns, combustion can generate other pollutants, even zero-CO₂ fuels like hydrogen.  Pollutants most commonly associated with fossil fuel combustion are particulates (e.g., soot), carbon monoxide, and NOx. 

Hydrogen combustion emits no particulate or carbon monoxide emissions, since it contains no carbon atoms – another major benefit of it as a fuel.  However, hydrogen combustion can generate nitrogen oxides (NOx) emissions. In essence, NOx is generated when air is heated to high temperatures and the N₂ and O₂ in air start to react with each other.  NO_x is a regulated criteria pollutant because of its potential to cause adverse respiratory health effects and because it contributes to acid rain.

Neva Espinoza of ERPI will joint GTI to talk about hydrogen and other low-carbon resources in next week’s POWERGEN+ series-Online and Free-Register here

Read about Georgia Tech’s new Microgrid project

Hydrogen holds great promise and formidable challenges. Read about H2 and CHP potential

In situations where NOx emissions are not a concern, many options are available to use hydrogen and hydrogen blends, including the ability to use legacy combustor hardware for a range of hydrogen and natural gas blending levels.  In other words, the key challenges associated with using hydrogen are in low NOx combustion systems.  So called “diffusion combustors” are an older technology that leads to high levels of NOx pollutants.  These systems require water or steam injection to comply with the NOx regulations in modern air permits, which may be unattractive due to the cost and complexity of the water management systems.  These systems need large volumes of clean, de-mineralized water, which introduces additional environmental considerations.  In many places, such as the desert, water injection systems are not practical.  Nevertheless, diffusion combustors have good fuel flexibility.  Many of these systems operate today on fuels with very high hydrogen content, fuels that are naturally produced as biproducts of industrial processes in steel mills and petrochemical plants.  Many of these diffusion combustors are 100% hydrogen capable (see specific site examples above) but their deployment is limited to locations and economies where water/steam injection is viable for NOx control.

So called “lean, premixed combustors” are inherently low NOx systems, and can produce compliant emissions without any water or steam injection because they avoid the high temperature regions that produce NOx.  This is illustrated in Figure 1, which shows the differences of lean premixed combustors relative to non-premixed combustors.  Therefore, lean-premixed systems dominate new electric power plant installations and are the predominant technology in the power generating fleet.  However, legacy systems do not have the operational flexibility or fuel flexibility of diffusion combustors. 

Given these points, we’ll next dig into the details a little further on both operability and emissions in lean, premixed combustors, and what the concerns are and where the issues arise.  Operability refers to the ability to operate the plant reliably without having it shut itself down, damage itself, or have unacceptable performance.  Hydrogen affects operability in several ways.

• Flashback — this is the most severe concern around high H2 levels in systems designed for natural gas, as the flame can propagate upstream and catastrophically damage hardware.  Hydrogen’s flame speed is an order of magnitude higher than that of natural gas.  Therefore, flashback is the dominant issue for modern lean premixed combustors on hydrogen fuel. 
• Blowoff — If you’ve ever tried to light a match outside when its windy, you’ll know what this is.  Similarly, combustors have flow velocities that can exceed 100 MPH and so preventing the flame from flying downstream and out of the system is a major challenge.  Because hydrogen propagates so fast, blowoff challenges are alleviated with hydrogen.  However, this issue is compounded for fuel flexible combustors, which must avoid blow out with slower burning natural gas fuel and simultaneously avoid flashback with high hydrogen fuel.  For these reasons, the highest hydrogen capability marketed for any frame engine with lean premixed combustion is 50% hydrogen by volume, and much lower for most systems.
• Combustion Instabilities- Modern low NOx systems are prone to a variety of damaging oscillations and a great deal of effort is spent on modern systems to develop designs that avoid these issues at the operating conditions of interest.  What this design must look like, however, changes with fuel composition or ambient temperature.  Thus, in cases where the fuel composition can vary widely, it becomes impossible to develop a static design that is stable over all conditions and for all potential fuels.  This has the practical impact of restricting certain operating regimes from operation, depending upon fuel composition.  For example, a plant may not be able to operate at peak power for certain fuel composition ranges.

Finally, lets dig a little further into NOx emissions.  First, we should correct some common errors that are out there.  Since NOx emissions increase exponentially with temperature, and because hydrogen can burn hotter, its sometimes said that hydrogen combustion will produce more NOx.  However, this point needs to be contextualized as to whether the combustor design is a diffusion flame combustion or lean, premixed combustor.  It is true for diffusion flame combustors, which are inherently high NOx devices.  It is not necessarily true for premixed, low NOx systems.  This is because NOx emissions are a function of temperature in these systems and many energy systems run at a fixed temperature or power settings.  To restate — premixed hydrogen powered systems can be designed for near-zero NOx emissions.

Next, it’s important to understand the connection between efficiency of the engine and its NOx emissions.  An approximate rule of thumb is that higher efficiency machines run at higher temperatures and, therefore, emit higher NOx emissions.  For reference, current EPA regulations on NOx for gas turbines is 30 ppm, while in certain areas such as in California with air quality problems, they can be as low as 3 ppm.  The highest thermal efficiency devices on the planet, combined cycle gas turbines, are now designed to operate with NO emissions between 2-25 ppm.  When operating with various H₂ blends, since they are designed to operate at a fixed temperature, hydrogen addition need not adversely impact NOx emissions for premixed, low NOx designs. 

However, H₂ also has additional effects on NOx emissions in low NOx, premixed systems associated with subtle differences in the way it burns which causes it to generate trace increases of NO.  For big, high efficiency engines, these effects are very small.  However, for smaller engines, such as microturbine that might emit 1-3 ppm, the effect could be noticeable — for example, a 1 ppm emission level could become 2 ppm.

To summarize, for lean, premixed combustion systems, increasing hydrogen levels can cause small absolute increases in NO levels, which could be large absolute changes (e.g., in the above example it doubled NOx emissions from 1 to 2 ppm).  However, for larger, high efficiency machines hydrogen effects can be minimal. 

A final point — heat transfer coefficients of combustion products fueled with hydrogen are higher than natural gas.  Because the peak temperature in a gas turbine is controlled by heat transfer to the rotating turbine, this could necessitate a reduction in turbine inlet temperature as hydrogen levels increase.  While high hydrogen fuels can actually benefit cycle efficiency, this can be counteracted by the efficiency reduction from a reduction of the turbine inlet temperature.  Figure 2 illustrates this tradeoff.

Key Future Needs

To summarize, this paper  has shown, first, that hydrogen is certainly an acceptable, very clean fuel.  Second, it has shown that it can be used at low levels in existing fielded systems, and some low NOx gas turbines exist in the field today that can operate with H2 levels of up to 50% , cofired with natural gas.  Furthermore, systems have been developed to operate with pure hydrogen.  The key development challenge for the future is low NOx, fuel flexible systems, that can be readily operated with a range of fuel compositions, ranging from pure H2 to pure natural gas.  Figure 3 below summarizes the hydrogen readiness, R&D needs, and NOx compliance of these various technologies.  All of these will enable the combustion technology of the future — low NOx, wide operability range, fuel flexible combustion systems capable of operating up to 100% hydrogen. 

About the authors:  Tim Lieuwen is the Executive Director of the Strategic Energy Institute at Georgia Institute of Technology.  He is also the founder and CTO of Turbine Logic,  and  a member of the National Academy of Engineering. 

Benjamin Emerson is a Senior Research Engineer in the Ben T. Zinn Combustion Lab at Georgia Tech.  He specializes in combustion testing, development, and engine monitoring solutions. 

Neva Espinoza is vice president-energy supply and low carbon resources, at the Electric Power Research Institute. She has worked for EPRI for the past nine years, including roles as director, senior program manager and senior project manager. Espinoza previously has worked in operations at NRG Energy and at the Oyster Creek Nuclear Generating Station.

Bobby Noble is gas turbine programs manager at EPRI and a Fellow of American Society of Mechanical Engineers. He is a key global leader in hydrogen combustion development and test experience, and has authored a number of EPRI reports on hydrogen utilization case studies

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