Roughly speaking, the term “pre-combustion carbon capture” refers to the final step of collecting and disposing of residual carbon (as CO2) resulting from chemical conversion of a “dirty” fossil fuel containing carbon (coal, oil or natural gas) to “clean” carbon-free hydrogen.

Several processes to achieve this fuel conversion are commercially available or in development:

Steam-methane reforming (SMR). Dominates commercial hydrogen production worldwide.

Auto-thermal reforming (ATR). Technology improvement over SMR of growing interest and importance.

Partial oxidation (POX). Oxygen- based process with potential to substantially reduce cost of blue hydrogen.

Pyrolysis. Under development for decomposition of natural gas to produce hydrogen and solid carbon.

Except for pyrolysis, carbon in the original feedstock ends up as CO2 which can be separated (captured), compressed, transported and sequestered in the same way as post-combustion carbon capture.

Steam-methane reforming

Generally, today’s hydrogen production processes involve a string of chemical reactions between water (as steam) and hydrocarbon feedstock. Under the right conditions and occasionally helped by a catalyst, hydrogen in both the water and feedstock is released as essentially pure hydrogen gas.

Steam-methane reforming (SMR) of natural gas, the most common fuel conversion process, involves multiple steps which can be summarized by the following single chemical equation:

CH4+2H2O4H2+CO2 (E=165 kJ/mol)

where E indicates input heat energy required to drive the process.

Introducing respective molecular weights, this equation tells us it takes 1 kg of methane and 2.25 kg of steam to produce 0.5 kg of hydrogen. Unfortunately, the process also generates 2.75 kg of CO2 per kg methane (or 5.5 kg CO2 per kg hydrogen). Almost that same amount of CO2 is produced when burning natural gas feedstock to provide required process heat and steam.

As a rule-of-thumb based on these figures, about 10 kg of CO2 is emitted for each kg of hydrogen produced from natural gas via the SMR process. For it to be considered “low carbon”, a carbon capture unit must be added so CO2 can be captured and compressed for transport to a sequestration site or for utilization.

Improving economy of blue H2

It is widely accepted that large-scale, affordable, blue hydrogen produced from natural gas via SMR plus CCUS is a necessary part of the gas turbine energy transition and for bridging the gap until large-scale production of carbon-free green hydrogen becomes economic.

As pointed out by Shell’s N. Liu in a June, 2021 Hydrocarbon Processing article, Increasing Blue Hydrogen Production Affordability, blue hydrogen may be somewhat more expensive to produce than gray hydrogen (SMR w/o CCUS) — but the difference is largely negated in areas where there is an established cost attached to CO2 emissions (carbon tax, etc.).

In those cases, the cost of blue hydrogen already competes with gray hydrogen. Meanwhile, green hydrogen is expected to remain uncompetitive for some time to come unless there is a steep decline in renewable electricity cost. (See chart.)

Liu also notes that the deployment of an improvement to the industry standard SMR process known as ATR (auto-thermal reforming) has been growing.

And a newly available proprietary process being offered by Shell, O2-based partial oxidation (POX) technology, will further increase the affordability of blue hydrogen produced from natural gas. In all cases for hydrogen to be clean the production process whether it be SMR, ATR or POX must be coupled with an additional process unit to strip CO2 from the product gas stream and the CO2 must be permanently disposed of rather than emitted into the atmosphere.

Why blue H2? According to Liu, a growing number of nations and major companies, including Shell, have announced aggressive net-zero emissions ambitions, pledges, and commitments. Although carbon-free renewable electricity supply is expanding rapidly, a global net-zero goal will be difficult to achieve without availability of both carbon-free (green) and low-carbon (blue) hydrogen as a clean burning, energy-dense and storable fuel.

Although some green hydrogen projects are taking shape, including Shell’s own NortH2 wind-to-H2 project in the North Sea, Liu points out that there will be a need to fill the gap in the growing demand well before large-scale and economic green hydrogen production comes on line. And even in the longer term, he says, electrolysis alone will not meet the forecast growth.

Today, global hydrogen production is on the order of 90 MMt per year, mostly gray hydrogen produced from fossil fuels without carbon capture. Global production of that gray hydrogen is responsible for some 830 MMt per year of CO2 emissions, about 2.5% of the total global emission rate.

If hydrogen is really to contribute to carbon neutrality, says Liu, it must be produced on a much larger scale and with far lower emissions levels. “It is necessary to turn bulk gray hydrogen blue, and it must be done economically.”

Why not blue H2? Recognizing the high level of CO2 emissions via SMR leads to a somewhat surprising dilemma about the strategy of using pre-combustion carbon capture to produce low-carbon blue hydrogen as a substitute gas turbine fuel during the energy transition. According to data supplied to GTW by regular contributor, Bechtel Fellow S. Can (John) Gülen, the CO2 generated by SMR to process natural gas to produce hydrogen fuel will actually exceed the CO2 emitted by just directly using natural gas fuel by over 30%. This clearly puts the blue hydrogen strategy for a “clean” gas turbine fuel in question.

To quantify this, Gülen uses the example of an advanced-class combined cycle plant nominally rated at 460MW and 62% LHV efficiency. Running on natural gas, the rate of plant CO2 emissions would be about 333,000 lb/hr.

However, the SMR process to produce the roughly 50,000 lb/hr of hydrogen needed to fuel the plant would generate about 435,000 lb/hr of CO2 emissions – which is over 30% higher than with natural gas fuel.

Gülen notes the same dilemma arises with the popular idea of using blends of hydrogen and natural gas to lower CO2 emissions when the contribution of the SMR process is properly accounted for. See CO2 curves on the fuel blend emissions rate chart covering the range from 0% to 100% hydrogen.

As shown by the green curve (GTCC+ SMR), the CO2 emissions from an advanced gas turbine plant burning any blend of H2 and natural gas (blue curve) plus the CO2 generated by the SMR process in producing the hydrogen (red curve) exceeds the emissions when burning natural gas alone (i.e., 0% hydrogen).

Post-combustion carbon capture alternative

Based on this analysis, the apparent benefits of blue hydrogen as a potential clean fuel for gas turbine power must be weighed against continued use of natural gas plus post-combustion capture (see post-combustion carbon capture article in the 2022 GTW Handbook).

It might make a lot more sense to add a capture unit at the back end of a gas-fired combined cycle plant rather than adopt the use of blue hydrogen, where one must first convert the natural gas to hydrogen and apply CO2 capture at the front end.

Technically, even with 30% more CO2 to be captured, there still may be sound arguments to support upstream carbon capture since the CO2 would be at higher pressure and higher concentration than it is when comprising only about 4-5% of gas turbine exhaust gases. Ultimately, however, the choice between pre- and post-combustion carbon capture will come down to a trade-off of a plant owner’s preference between higher operating costs vs. additional investment cost.

Since the blue hydrogen is most likely to be supplied “over the fence” by a third party, who would also be responsible for the CO2 disposal, the added capital and operating costs plus profit will show up on the fuel supplier’s book and be reflected in the fuel price. The increase in fuel price, meanwhile, would simply be reflected as an increase in operating costs on the plant owner’s books. Most likely this could readily be passed on to the rate payers.

But, with continued use of cheaper natural gas, the plant owner would face adding post-combustion carbon capture representing a large capital investment. He would also inherit the extra costs for maintenance of the capture unit and CO2 disposal. Depending on a variety of site-specific factors, including the plant owner’s capital and debt structure, regulations governing the rate of capital recovery, tax incentives, etc., this might be the favored option.

Could POX make a difference?

Returning to alternative pre-combustion carbon capture processes, the Shell article cited earlier touts its partial oxidation (POX) process for conversion of natural gas to hydrogen. Author Liu says that a new proprietary Shell Blue Hydrogen Process integrates its own pressurized POX process (known as the Shell Gasification Process or SGP) with its advanced regenerable amine-based CO2 removal process.

With POX, natural gas is partially oxidized in O2 supplied by a cryogenic air separation unit to produce a syngas (H2 + CO). Heat released in the reactor and in the syngas cooler generates high-pressure steam for a downstream CO-shift process (CO+H2OH2+ CO2), and for export to the combined cycle steam turbine.

Compared to conventional SMR and improved ATR technologies, Liu says the Shell system can enable an approximately 20% lower levelized cost of hydrogen, reflecting 17% lower CAPEX and 35% lower OPEX, while removing over 99% of the CO2. Other advantages include being noncatalytic and not requiring process steam (it is a steam exporter). It greatly simplifies the process line-up and increases CO2 capture efficiency, with the bottom line being a substantial reduction in hydrogen production cost, according to Shell’s Liu.

POX for heavy hydrocarbons

Although said to be newly available for hydrogen production from natural gas, the Shell gasification process (SGP) has been used commercially for many years to produce syngas and hydrogen from a wide variety of feedstock, including coal, pet-coke, and residual oil.

For example, at Shell’s Pernis refinery in the Netherlands, an SGP gasifier has been operating since 1997 as part of an Integrated Gasification Combined Cycle (IGCC) plant using heavy refinery residuals as the feedstock.

Most of the syngas, a roughly 50-50 (by volume) mixture of H2 and CO is used to fuel a 120MW combined cycle plant (2×1 GE Frame 6B). The rest is fed to a CO2 removal unit to produce hydrogen for the refinery, while about 3,000 tonnes per day of captured CO2 is sent to local greenhouses for bio-sequestration.

Shell points to the Pernis refinery operation as a long-standing successful demonstration of gasification-based carbon capture and storage. The same can be said of several other refinery- based installations using other gasification technologies for hydrogen production (but mostly without carbon capture). It also highlights the promise this technology may hold for future large-scale production of blue hydrogen from heavy hydrocarbons.

This is also emphasized by Bechtel’s John Gülen and Martin Curtis in their June 2022 ASME Turbo Expo paper, Gas Turbine’s Role in Energy Transition. They see substantial potential for gasification of otherwise “dirty” and unacceptable fuels as a possible route to bulk supply of affordable clean fuel for high efficiency gas turbine combined cycle plants. And they recommend a full-blown FEED study be conducted to confirm engineering and financial feasibility.

Ed. note: Regarding gasification to generate low-carbon fuel for gas turbines, GTW first reported in 2008 on the technical feasibility of adding a CO-shift reactor and a CO2 removal unit to the syngas process line-up to achieve pre-combustion carbon capture in IGCC plants.

Recently, reports from Australia indicate that the feasibility of gasification plus CCS to convert large deposits of Australian brown coal to clean hydrogen and/or ammonia for delivery to Japan is being studied by a consortium of Australian and Japanese companies led by Kawasaki.

The creation of a hydrogen (and/or ammonia) supply chain, which includes marine transportation, is considered essential by the Japanese government for meeting their carbon neutrality commitments. (The South Korean government is also looking into this concept with Doosan Enerbility leading the study.)

Most recently, the government of Indonesia has contracted with Mitsubishi to conduct a similar study of the feasibility of replacing natural gas and LNG used for power generation with ammonia. This may be connected with announced plans for a large-scale coal gasification project in the country to be built by US-based Air Products based on Shell technology, and may be a glimpse of the future.

Turquoise hydrogen on the horizon

With current technology, the energy cost to produce hyrogen by elctrolysis of water ranges from 50 to 60 kWh per kg of hydrogen product. That is the main drawback with green hydrogen.

It turns out that it takes a lot less energy to break down or decompose hydrocarbon molecules in natural gas (mostly CH4) to free the bound hydrogen than it does to break down water molecules.

It also turns out that 60% of the energy in natural gas comes from its bound hydrogen.

The issue then is, how to selectively access the hydrogen in natural gas without producing carbon dioxide byproduct for disposal?

Hydrogen color spectrum

There is a widely accepted, albeit informal, international standard nomenclature, the so-called “colors of hydrogen” which has developed for differentiating various hydrogen production processes and their cleanliness in terms of CO2 emissions abatement.

Generally, blue hydrogen denotes “clean” hydrogen produced from natural gas via steam-methane reforming (SMR) with a large percentage of byproduct CO2 being captured and placed in permanent storage (or productively utilized).

The degree of “clean” depends on the percentage of CO2 captured, usually at least 80%. A dirtier but much more popular cousin is gray hydrogen produced via SMR where the CO2 is simply vented to the atmosphere.

Most of the roughly 90 million metric tonnes of hydrogen produced annually around the world is gray hydrogen, produced from fossil fuels, resulting in the release of about 850 million tonnes of CO2.

Brown hydrogen comes from coal (e.g., by gasification or partial oxidation in the presence of steam) without capture and storage of CO2 produced. Brown hydrogen can be turned “blue” by adding carbon capture and sequestration.

Cleanest of all is green hydrogen, the highly touted game-changer for long-term energy transition, produced by the electrolysis of water using renewable energy to provide required electricity to drive splitting the water (feedstock) into oxygen and hydrogen. Green hydrogen would appear to be the ideal solution, if not for the large amount of electrical energy needed (50-60 kWh/kgH2) to free the hydrogen from its strong bond with oxygen.

Then there is pink hydrogen, where electrolysis of water is driven by nuclear power. Not everyone considers pink hydrogen to be as clean as green, but the idea is to maximize the capacity factor of existing and new nuclear power plants while putting their carbon-free energy to good use. Higher electrolyzer utilization factors possible with steady nuclear power vs. intermittent renewables, or possibly combining the two, is a plus for pink over green.

Last, and newest addition to the color spectrum, is turquoise hydrogen produced by high-temperature pyrolysis of natural gas and promises significantly lower production cost. The pyrolysis process takes place absent of oxygen and water and with much lower energy input than required for electrolysis. Like green and pink hydrogen, turquoise produces no CO2 emissions which mean no carbon capture is required. The co-produced carbon is solid and easily disposed of or recycled.

Enter pyrolysis

The answer lies in pyrolysis, i.e. decomposing the methane and other hydrocarbons in natural gas (or other “dirty” feedstock) at high temperature in an oxygen-free process to produce hydrogen and solid carbon. Perhaps to parlay the combined benefits of both green and blue hydrogen, the hydrogen produced by pyrolysis – when driven by a clean energy source – is called turquoise hydrogen.

The pyrolysis process occurs at high temperature with no oxygencontaining molecules, i.e., no air or water, and thus no carbon dioxide is formed, says Eric McFarland, Chief Technology Officer of C-Zero, an energy technology startup in Santa Barbara, California.

According to McFarland, decomposing methane requires less than about 6 kWh per kg of hydrogen, a fraction of the energy required to produce hydrogen from water.

Compared to state-of-the-art electrolyzers, he maintains, that amounts to only about one-tenth of the energy required to produce green hydrogen. For the same input energy, about 10 times as much hydrogen can be produced by pyrolysis of natural gas as by electrolysis of water.

“As long as (relatively) low-cost natural gas is available, turquoise hydrogen can be much less expensive than green hydrogen”, says McFarland.

Although there are no dedicated turquoise hydrogen commercial facilities up and running, he claims that “many are under development and the projected price of turquoise hydrogen is estimated to be approximately $2/kilogram, depending on the price of natural gas.”

For further reading, see this article which questions the viability of green hydrogen strategies: “Gas Turbines burning green hydrogen: the numbers don’t add up.”