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Green Hydrogen and Gas Turbines: An Overview

At the time of writing, after nearly a decade of media blitz and hype, even laypeople are well-versed in hydrogen colors and the wonders they can perform in decarbonizing global economies such as electric power generation, transportation, and the industrial sector (e.g., cement and steel-making).

This article focuses solely on utility or grid-scale electric power generation using gas turbines that burn hydrogen. Other uses of hydrogen of any “color,” including existing and/or planned, e.g., fuel cells for transportation and distributed power generation, at various scales and with associated infrastructure needs, are beyond the scope of this article. This article examines the various processes used to produce hydrogen by referring to the “color” of hydrogen associated with each process, and it provides an analysis of hydrogen strategies that contribute to the goal of decarbonization.

Green Hydrogen

This is where water electrolysis comes into play. It is a “green” technology because no CO2 is produced during the manufacturing process. The underlying chemical reaction is simple, but it requires a lot of energy, which is provided by a battery (in the laboratory) or a power plant (in a commercial-scale application).

It can be demonstrated that the minimum theoretical energy required for water electrolysis is 237.1 kJ/mol of H2O, which translates to approximately 33 kWh/kg of H2. This is the yardstick by which electrolyzer manufacturers’ claims must be measured.

Proton exchange membrane (PEM) electrolyzers, for example, are commercially available today and are quickly gaining market traction because, among other things, they are more flexible and have a smaller footprint than their forerunner technology, the liquid alkaline electrolyzer. Published numbers for PEM and other electrolysis technologies cover a wide range, and verifying them is difficult with little or no commercial-scale experience. A conservative figure for cutting-edge PEM electrolyzers is 55 kWh/kg, which will be used here.

Future developments may (possibly) reduce it to 45 kWh/kg. Interested readers can easily modify the results below by entering the number they believe is “correct.” You can be confident that the proverbial needle will not move significantly.

The goal of green hydrogen production is to use renewable resources, such as solar or wind, to power large electrolyzers that produce H2, which is then stored, transported, and burned in gas turbine combustors. It’s much easier said than done.

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Gray Hydrogen

Let us now turn to hydrogen production via SMR, a more-than-a-century-old technology used around the world to produce H2 for use in the chemical process (for ammonia production) and refining (for hydrocracking and fuel desulfurization) industries.

According to the chemical reaction formulae, each kilogram of H2 produced results in the production of 5.5 kg of CO2. The fuel burned in the reformer must also be included in the actual SMR plant. This can result in a CO2/H2 ratio of around 9.2. (it can be as high as 10 or 11).

Let us apply this to our hypothetical gas turbine (400 MW at 43% LHV) that burns 7.75 kg/s H2. The SMR process would produce 257,000 kg/h of CO2 if the required amount of hydrogen was supplied. On a simple cycle basis, this equates to approximately 642 kg/MWh (1,415 lb/MWh) CO2 production. The combined cycle figure is 438 kg/MWh (966 lb/MWh).

In comparison, the corresponding number for the best field-performer natural gas fired GTCC of 2020, with 60% LHV efficiency instead of 63%, which is the basis of the SMR numbers cited above, is 333 kg/MWh (735 lb/MWh), or more than 30% less than the one fired on 100% gray hydrogen.

Blue Hydrogen (SMR + CCS)

To produce “blue” hydrogen, the SMR plant can be retrofitted with carbon capture and sequestration (CCS). CO2 could be captured in an SMR plant in three ways: I from the tail gas of the pressure swing adsorption (PSA) unit, (ii) from the reformer flue gas with approximately 90% efficiency (45% (v) and 20% (v) concentrations, respectively, and less than one bar partial pressure), or (iii) from the raw H2 at the shift reactor exit with 99+% efficiency (15% (v) concentration and 3.5 bar partial pressure).

Amine-based scrubbing, physical solvents, and membranes are among the available removal technologies, and there is extensive experience in the chemical process industry with CO2 removal from raw H2 at high pressure. CO2 scrubbing from GTCC flue gas at low partial pressures and high volume flows, on the other hand, necessitates larger and more expensive equipment and consumes more parasitic power. In any case, if the SMR plant is equipped with 90% CCS, for our example GTCC firing “blue” hydrogen produced in that plant, CO2 emissions would be 44 kg/MWh (97 lb/MWh) (ignoring everything between the SMR hydrogen delivery point and the gas turbine combustor).

The final figure is quite appealing, but there is no reason why our “best in class” (based on field performance) GTCC cannot also be retrofitted with a 90% post-combustion carbon capture (PCC) system. In that case, CO2 stack emissions would be reduced to 33 kg/MWh (74 lb/MWh), nearly 30% lower than in the blue hydrogen case with SMR plus CCS. (It should be noted that the CO2 output of the SMR producing the required H2 for this plant would be 465 kg/MWh or 46.5 kg/MWh with 90% capture.)

In other words, unless there is a compelling CAPEX/OPEX case for blue hydrogen (via SMR plus CCS), it is impossible to see how it can be a viable alternative to natural gas-fired GTCC with PCC. Even so, 86% capture is sufficient to bring the latter up to par with blue hydrogen in terms of kg of CO2 per MWh of generation (assuming 90% capture), with concomitant savings in PCC block size and CAPEX/OPEX.

Blue Hydrogen (Gasification + CCS)

Globally, approximately 75% of H2 production is from SMR, with the remainder primarily from gasification. The first step in the gasification process is to react coal (or another liquid/solid hydrocarbon feedstock) with oxygen and steam at high pressures and temperatures to produce synthesis gas (syngas), a mixture primarily composed of carbon monoxide (CO) and hydrogen.

Following the removal of impurities from the syngas, the CO in the gas mixture reacts with steam via the water-gas shift reaction to produce additional H2 and CO2. A separation system removes hydrogen, allowing the highly concentrated CO2 stream to be captured and stored.

There is, however, a rationale for producing blue hydrogen by gasifying coal, refinery residue, or other problematic hydrocarbons. Unlike electrolysis or SMR (or its derivatives or close relatives), the feedstock in this case, unlike surplus electric power plus water or natural gas (mostly methane), is not typically regarded as a good candidate for ‘clean’ electric power generation.


The author is unsure what green hydrogen from renewable-powered electrolysis can accomplish in terms of reducing CO2 emissions from grid-scale electric power generation. Even using the entire curtailed wind generation in the United States to produce H2 and burn it in GTCC cannot make a dent in GHG emissions.

The basic idea behind gray hydrogen is to take a perfectly “clean” (relatively speaking) feedstock, such as natural gas, that can be burned in a state-of-the-art GTCC at nearly 60% field-measured efficiency, use it to make H2 while pumping extra CO2 into the atmosphere, and then burn it in the same GTCC. One can certainly imagine a scenario in which an SMR facility’s product, whose existing customers have vanished, can be kept running and producing H2 for use as gas turbine fuel. Even so, one might wonder if it would not be better to retire the facility in the first place to help reduce GHG emissions.

By incorporating a CCS facility into the mix, blue hydrogen eliminates the CO2 disadvantage of gray hydrogen. But the fundamental question remains. A GTCC equipped (or retrofitted) with PCC can burn natural gas directly and still have lower CO2 emissions.

Finally, it should be noted that the concept of a hydrogen economy is not new. It first appeared on the scene half a century ago (e.g., see Chapter 18, p. 117 of Hammond, Metz, and Maugh II’s “Energy and the Future,” AAAS, 1973). There is no doubt that hydrogen has a place in a comprehensive sustainable energy technology portfolio. Increased use of green hydrogen as a storage medium and gas turbine fuel will become a reality as more renewable resources are deployed on a case-by-case basis.

However, unless the world transitions to a fully “distributed generation” mode, expecting it to be the proverbial knight in shining armor for zero-carbon electricity is unrealistic, especially with 500+ MWe super-heavy gas turbines burning exorbitant amounts of manufactured green hydrogen fuel.

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