Associate Editor, Turbomachinery International Magazine

Joseph McDonald

In our November issue, we focus on hydrogen compression and how it may represent the foundation of the hydrogen economy. Wanting to explore this market segment further, Turbomachinery International invited Sarah Simons to break down the components and considerations needed for introducing hydrogen to existing compression stations. Simons is a Senior Research Scientist at the Southwest Research Institute and has worked on over 130 compressor installations.

So why should we blend hydrogen? For one, hydrogen is a form of thermochemical energy storage. It can be created by using excess energy from other sources, one of the most popular being ‘green’ hydrogen – or hydrogen created using excess power from renewables. The same result can be achieved via hydrocarbon reformation or coal gasification, which makes ‘blue’ or ‘gray’ hydrogen.

Introducing hydrogen to gas pipelines allows us to make use of the vast existing pipeline network. Pipelines are also a more efficient means of transporting energy compared to power lines. Finally, pipelines will allow for increasingly larger amounts of hydrogen to be introduced to the system over time, keeping pace with the gradual nature of the hydrogen economy.

Many utilities are already running their own hydrogen compression projects. Canadian utility Enbridge is looking to blend up to 2% hydrogen in their natural gas distribution system located in Markham, Ontario. Enbridge wants to evaluate how consumer appliances and the distribution system handles a hydrogen blend. Another project by Hawaii Gas is underway. The company is operating a small steel pipeline with refinery produced syngas containing around 12% hydrogen. The utility even constructed this pipeline with hydrogen blending in mind.

The first thing to consider before introducing hydrogen to a natural gas blend are the differences between the gases. Hydrogen is a much lighter gas, which means that overall mixture density will decrease following its introduction to a natural gas blend. This lower density will result in a higher sound speed /gas flow velocity along with changes to pulsation control design. Hydrogen’s smaller molecules may also raise concerns regarding pipeline embrittlement and leakage.

In addition, blending hydrogen into natural gas will result in changes in viscosity and a lowering of the Joule-Thomson coefficient. Thus, hydrogen blends experience no temperature drop at pressure loss areas (e.g., flow control valves) and show a decreased temperature drop over long distances. There is also an increase in specific heat and compressibility. An important thing to note is that hydrogen blending results in a higher energy density by mass, but a decreased volumetric calorific value. This means that hydrogen blends will require more volume/pressure to transport energy when compared to conventional natural gas.

When calculating the thermophysical properties for a hydrogen blend, note that prior testing is still very limited. Most thermophysical property tests have been performed on binary mixtures, such as hydrogen with methane. Unfortunately, there is little to no testing validation for calculated hydrogen-natural gas mixtures.

Pure hydrogen requires more power to transport the same amount of energy as natural gas – 3 times as much, to be exact. Hence, available power, compressor speed, delivery pressure, and flow velocities must be considered when introducing hydrogen to the pipeline. There could also be an increase in noise, a lack of cooling, and erosional/structural limits.

Simons offered an example of pipeline limitation calculations regarding hydrogen blending. A 2008 study from the Journal of Hydrogen Energy found that if the available power in a pipeline is fixed at a required 5,000 MW and a delivery pressure of 60 bar, then the maximum hydrogen fraction that can be injected for operation is 6.6% on a mass basis. This calculation ensured that the pipeline (and compression station as a whole) did not operate outside of its constraints.

Southwest Research Institute investigated how hydrogen blending interacts with centrifugal compressors. Mass flow and heating value of transported gas decreases as hydrogen content increases. To maintain a compressor’s volumetric energy capacity when using hydrogen, compressor speed, head rise, and power must be increased. One system tested at Southwest Research required a power increase of 20% to facilitate a 10% hydrogen blend.

Luckily, many seals and materials are already compatible with hydrogen. Dry gas seals are typically designed to handle up to 20% hydrogen. O-rings are generally designed with hydrogen-resistant materials. Shaft seals made of PEEK or PTFE are also hydrogen compatible. These materials will usually operate at their recommended hydrogen percentage so long as temperatures stay below 392 degrees Fahrenheit.

Conversely, API 617 dictates that “Materials that have a yield strength in excess of 827 MPa (120 ksi) … are prohibited for use in hydrogen gas service where the partial pressure of hydrogen exceeds 689 kPa (100 psi gauge).” This is most likely to have an impact on the impeller and shaft, since casing and stationary components are typically made of low yield strength carbon steel.

Like centrifugal compressors, many gas turbines can operate with a certain percentage of hydrogen mixed with natural gas. This is usually 5% or less, though some turbines can handle more than 10%. Newer turbines will almost always be able to handle more hydrogen than their older predecessors. Regardless, it’s important to evaluate the entire turbine package for use with hydrogen before proceeding.

A drawback with conventional combustors is that hydrogen’s faster burn and high combustion temperatures result in much higher NOx emissions. There is also increased flashback risk amongst legacy DLE combustors. Higher hydrogen blends (exceeding 4%) also require additional safety measures, such as requiring additional fire and gas detection devices.

Southwest Institute performed a study on hydrogen blending in reciprocating compressors. Blending increasing amounts of hydrogen into a system (while maintaining a fixed speed and pressure ratio) results in minor changes to power and ACFM, but a significant decrease in energy flow. Since reciprocating compressors are rarely designed with speed margins, the best way to maintain a constant energy flow when blending hydrogen is to bring more compressors online.

Reciprocating compressor valves, seals, and materials can handle smaller amounts of hydrogen. Concerns may arise when exceeding 20%. Lubricated compressors can be used if temps are below 350 degrees Fahrenheit and if mole weight is greater than 12 (as per API 618). Non-lubricated machines may require more scrutiny before blending hydrogen.

Most manufacturers find that their gas engines can run on 5-10% hydrogen. Blending hydrogen in gas engines generally results in increased fuel volume consumption due to a decrease in volumetric energy density. Users may need to slow ignition timing to account for this. Flame speed will increase in conditions with less than 20% hydrogen, increasing under in-cylinder peak pressures.

Users should be mindful of increased water from combustion that can become entrained in engine oil. Another cause for concern is increased NOx emissions, which can be managed by adjusting the timing and air-fuel ratio.

One must also consider the effect hydrogen blending has on piping. Introducing hydrogen to a system will result in increased speed of sound and velocity, with more hydrogen resulting a bigger increase. These changes impact acoustic natural frequency and – in the case of centrifugal compressors – create vortex-shedding excitation.

Reciprocating compressors can benefit from the installation of pulsation bottles. These bottles will help reach pulsation attenuation. These bottles will change speed of sound and frequency of a pulsation control system, bringing it in line with the first or second compressor running order.

On the materials front, carbon steels have been used in pressure vessels and piping that have been exposed to hydrogen. These materials general hold up under the conventional temperature/pressure range found during day-to-day operations.

The main cause for concern here is contamination via the hydrogen blending process. If hydrogen is exposed to something like sulfur or phosphorus, it can turn into atomic hydrogen. Atomic hydrogen may enter the pipe crystalline structure, combine with carbons in the piping, and leave pockets of hydrocarbons. These hydrocarbons create gas pockets that weaken materials and make them more susceptible to fractures or cracks.

When considering existing piping, it’s important to establish defect criticality limits to stifle fatigue crack growth. Contamination issues are also present here and can be avoided by providing robust cathodic protection from outside sources. Methods of repair may have to be changed after introducing hydrogen, as piping is often baked. Welds should be pre and post heat treated.

Coolers can run into issues with higher flow velocities brought on by hydrogen blending. They may be under-sized for these increased velocities, and thus unable to cool to desired temperatures. It is also possible that the cooler’s discharge temperature might not be low enough to meet pipeline requirements. Scrubbers, on the other hand, do not have many causes for concern. Like many of the components and materials mentioned before, scrubbers are able to handle up to 20% hydrogen without running into issues.

The most common method for gas analysis is gas chromatography using a helium carrier. In hydrogen applications, however, helium cannot be used. Argon or nitrogen can be used in its place. Keep in mind that the use of these elements can result in longer process times and diminished accuracy compared to helium.

For gas metering, the type of meter used depends on if the hydrogen concentration fluctuates. Systems that do fluctuate in hydrogen percentage can make use of Orifice and Coriolis meters, though they may need resizing. Some concerns regarding gas meters are leakage through polymer membranes, decreased life titanium sensors (in ultrasonic meters), increased leakage through threaded connections, and the life of sealants and lubricants.

Due to hydrogen’s innate properties, its introduction to a compressor station raises some safety concerns. Hydrogen rapidly disperses in air, increases in temperature when it expands, requires a fraction of the ignition energy required by natural gas, and has a high burning velocity. Hydrogen does have the ability to spontaneously combust at pipeline conditions, and it has triple the volumetric leakage of methane.

Despite that, natural gas operations already bring on a slew of safety hazards, many of which are unchanged by introducing small amounts of hydrogen to the system. This is according to an IEA report that assessed risk factors brought on by operating with a 15% hydrogen concentration. Though one should keep in mind that risk assessments for larger blends of hydrogen have yet to be undertaken.

Simons concluded by offering initial steps for evaluation. One should begin by defining the boundaries of the pipeline that will be exposed to hydrogen, based on the hydrogen injection and extraction points. The pipeline’s pressure and energy transport capacity should be determined, and problem points (where contamination and poor cathodic protection may occur) identified.

In addition, a pipeline analysis should be performed to determine compressor and driver limitations. Similarly, gas component and flow measurement constraints should be considered. Users should also re-evaluate the station’s pulsation amplitudes. Gas turbines/engines and piping systems ought to be evaluated and modified (if necessary) for use with hydrogen. Last but not least, there must be a thorough safety review performed in order to account for potential risks brought on by hydrogen’s presence.

Articles

A TMI Editor’s Series webcast discussed what to consider when introducing hydrogen to a compressor station. 

Webcast report: Hydrogen blending at compression stations

Turbomachinery International hosted the “Carbon Capture, Hydrogen, and Achieving a Net Zero Turbomachinery Footprint” webinar on September 9th,2021. The webinar, sponsored by Siemens Energy, Sundyne, and RelaDyne RRS, discussed the viability of hydrogen and carbon capture in decarbonizing industries that rely upon turbomachinery. TMI brought on its resident Myth Busters, Klaus Brun and Rainer Kurz, to educate the audience on the matter. Brun is Director of R&D at Elliott group, while Kurz is Manager of Gas Turbine Engineering at Solar Turbines.

Brun kicked off the discussion by listing the myriad ways in which the energy industry could decarbonize – ranging from employing one of the many colors of hydrogen to implementing carbon capture at existing gas plants. He focused on comparing blue and green hydrogen. Economically speaking, he said blue holds the advantage. As it stands, green hydrogen is expensive to produce due to the high cost of electrolysis. It also has a subpar roundtrip efficiency of less than 40%. Brun believes that blue hydrogen will be the dominant energy source for the foreseeable future, until the cost of electrolysis is reduced. He expects that this could take 30 or more years.

Transitioning to hydrogen also requires one to address the means of transportation. To that effect, Brun offered a couple of options. Option A – blending hydrogen with natural gas in the existing pipeline network. He pointed out, however, that the operational and safety impacts are presently unknown. Option B calls for the development of a pure hydrogen distribution network – through repurposing old oil and gas pipelines and/or building new ones. This would eliminate much of the technical and safety challenges but would come with a high cost to both time and money.

Brun’s “likely hydrogen economy scenario” boils down to the following:

Blue hydrogen will be dominant for at least 25-30 years until electrolysis becomes cheaper.

Natural gas will continue to be transported using existing pipeline infrastructure.

Conversion from natural gas to blue hydrogen will occur near or at end-user, where it is more economical. This could happen at regional hydrogen hubs or via pre-combustion carbon capture.

He also noted that there are three value streams – natural gas, hydrogen, and carbon dioxide. On that last point Brun briefly remarked on how there are plenty of CO2 storage sites, but they do not align geographically with sites of production. He expects that between 50,000 to 100,000 miles of new CO2 transmission pipeline will be required in the US by 2050. Natural gas pipeline capacity will have to be increased to meet hydrogen transportation demand. Hydrogen compression will not be as prevalent in the near-term but will change as green hydrogen becomes more ubiquitous. Carbon dioxide compression, on the other hand, will be extremely common. This will occur during the transfer from source to pipeline pressure, recompression in the pipeline, and finally compressing the CO2 for storage in geological formations.

Brun discussed hydrogen compression, covering some of the difficulties brought on by hydrogen’s characteristics. Design challenges include light gas compression, sealing, materials/coatings, and safety. Pure hydrogen compression requires either a large number of compression stages or high-tip speed impellers. He mentioned that 1

Hydrogen compression is difficult but has historical precedent. Brun remarked that his company, Elliott, has been building hydrogen compressors since 1955 and has produced over 100 hydrogen-rich compressor trains since 2001.

Some materials challenges related to hydrogen compression include higher impeller spin speeds, which calls for the use of materials with a higher strength-to-density ratio. Another challenge is hydrogen embrittlement, which can be remedied via the use of coatings.

Brun believes that natural gas will be in increased demand for its use in creating blue hydrogen. This means that natural gas compression and transportation infrastructure will need to be improved and expanded. He suggested increasing throughput in existing pipelines by installing higher horsepower compressors, increasing pipeline and compressor pressures, and installing more loops. There may also be an increase in electric motor-driven compressors along the pipeline.

Rainer Kurz agreed that blue hydrogen is likely to be a dominant fuel source moving forward, which calls for a means by which the CO2 byproduct could be sequestered.

While hydrogen can be burned in conventional or diffusion flame combustors, lean premixed combustors face challenges using a hydrogen blend. This is due to hydrogen’s high flame speed creating a high risk of flashback in these systems. Higher flame temperatures also come with higher NOx emissions. Compressor packages must be carefully evaluated before use in hydrogen combustion.

One chart showed the increased compressor work required for a hydrogen blend. As hydrogen increases, so does the amount of work required. 100% hydrogen increases compression head by about 1 order of magnitude while power increases by 5. Despite the dramatic increase in power consumption, the efficiency in transporting gas via pipeline prevents a sizeable increase in energy consumption and CO2 emissions. Kurz believes that transporting hydrogen via pipeline is an attractive option overall.

He showed the results of a test simulating a 20% hydrogen blend in a natural gas pipeline. The amount of energy transported in the pipeline remained constant. But there was an increase in both power consumption and energy consumed per energy delivered.

Introducing hydrogen to a natural gas pipelines will require compressors to run faster to meet demand. Kurz stated that once a certain percentage of hydrogen blend is exceeded it will be necessary to restage the compressor or look for alternatives. In an example, a pipeline running up to 20% hydrogen needed three compressor units, whereas only 2 were needed at 10% hydrogen or less. Kurz concluded that hydrogen transport in pipelines is advantageous when compared to other transportation methods.

Turbomachinery International's resident Myth Busters teamed up to discuss the viability of hydrogen and carbon capture in decarbonizing industries that rely upon turbomachinery. 

Webinar discusses carbon capture and the hydrogen economy

The journey towards net-zero is underway. Many nations have made some sort of commitment to eliminating CO2 emissions by the midpoint of the century. How that ought to be achieved, however, is a different story entirely.

 suggests a new tactic for reducing global CO2 emissions – targeting the hyper-polluting power plant. The study, aptly named 

Reducing CO2 emissions by targeting the world’s hyper-polluting power

 found that 17% to 49% of global electricity-based CO2 emissions could be eliminated using this approach.

The study draws its emissions data from an updated version of 2009’s Carbon Monitoring for Action file (CARMA), which tracks CO2 emissions from the world’s power plants. The newest version, created in 2018, “consists of 29,078 fossil-fuel powered plants from 221 countries,” according to the study. CARMA draws from 3 key data sets: plant-level emissions reports, global-plant and company-level data, and country-specific power production data.

In countries like the US, Japan, South Korea, Germany, and Australia, 5% of polluters are responsible for 75% - 89.6% of emissions. This trend scales globally, with the top 5% of the world’s polluters contributing to 73% of all electricity-based CO2 emissions. China’s top 5% is responsible for much less CO2 output – around 24.5% - due to the country’s distribution of emissions evenly amongst different sized plants.

The study goes on to suggest that targeting this top 5% with reforms could significantly reduce global emissions levels. It suggests four key changes along with an estimate of the reduction in CO2. These include lowering intensities to match a national - then international - average, switching to natural gas, and implementing carbon capture technology (with the assumption that 85% of carbon is captured).

The results show that the implementation of all 4 policies could be highly effective in reducing electricity-based CO2 emissions. South Korea, for example, could reduce its electricity-based CO2 emissions by a whopping 76%. Similarly, the US could reduce its carbon output by 63.7%. China, the outlier in this list, would only reduce its CO2 output by 20.7%.

According to the study, implementation of these policies could reduce global electricity-based CO2 emissions by up to 48.9%. Merely switching the world’s plants to natural gas would result in a reduction of 29.5%.

The paper concludes by offering its main takeaway: “Findings suggest that instead of relying on sweeping environmental initiatives, substantial environmental progress can be made through selectively targeting nation’s hyper-polluters – the worst of the worst – that are responsible for the lion’s share of their carbon pollution.”

One key limitation, as the study points out, is the difficulty in enforcing such policy changes at a global scale. Furthermore, some countries benefit much less from such an approach. China may benefit more from targeting 10% of its polluters instead of 5%. This is due to its distribution of emissions across plants.

There is also the issue of data accuracy. The study points out that some plants either do not report their CO2 emissions or they keep them confidential. Thus, the study provides estimates of emissions in the absence of accurate data. The study believes that while some small plants may have been left off the list, the estimates for the largest power plants are reliably accurate. 

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A new study suggests that 5% of the world's power plants are responsible for 73% of all electricity-based CO2 emissions. 

Reducing emissions by targeting hyper-polluting power plants

Is hydrogen the answer to low-emission turbomachinery?

On June 29th, Turbomachinery International jointly hosted a webcast with ETN Global entitled “Is Hydrogen the Answer to Low-Emission Turbomachinery?”. It provided an overview of the various elements of the hydrogen economy, the different types of hydrogen (gray, blue, green), the turbomachinery challenges involved (the design of combustors, pipelines etc.), and the economics of hydrogen. 

Three guest speakers were invited to speak, each an expert in their field.

Pierre Dechamps is an Ambassador at EU Climate Pact and a Senior Advisor at FTI Consulting. He remarked on the state of emissions in Europe, which spurred the creation of the EU’s “Green Deal”. This legislation aims to reduce CO2 emissions to zero by 2050.

Dechamps said changes to Europe’s power generation practices are essential in meeting this goal. Europe aims to transition towards a fully integrated energy system to reduce waste by storing and sharing energy.

In his opinion, hydrogen would be a key player in this new system. Excess energy from renewables would be used to generate hydrogen.

The EU’s “Hydrogen Strategy for Climate Neutral Europe” sets a schedule for at least 6 GW of renewable hydrogen electrolyzers to produce up to 1 million tonnes of renewable hydrogen by 2024; increasing to 40 GW between 2025 and 2030. Beyond 2030, the ambitious plan is to have renewable hydrogen fully integrated into the system, extending to hard-to-decarbonize sectors such as transport.

Geert Laagland, Director of Engineering at Vattenfall and Co-Chairman of ETN Global’s Hydrogen Working Group spoke on the role hydrogen could play in the heat and power sectors. He believes a flexible backup to intermittent renewables is necessary for Europe’s transition from fossil fuels and gas turbines powered by hydrogen would effectively fill this role. 

According to Laagland, hydrogen gas plants are ideal for creating CO2-neutral, flexible dispatchable power. He believes that power generation using blue (and eventually, green) hydrogen can be realized by 2030. Hydrogen plants will also require fewer operating hours, making them more economically attractive compared to current natural gas plants.

Laagland also spoke on heat generation, using district heating in Berlin as an example. He detailed Vattenfall’s plans for transitioning this heating program from coal to low-carbon hydrogen by around 2040.

Laagland provided a graphic showing the development of a hydrogen-based infrastructure in Europe (see figure). Gas turbines and compressors will be required throughout the hydrogen ecosystem. He pointed out that it will be necessary for Europe to import hydrogen from other countries. He also mentioned the importance of storing hydrogen as the “the production and consumption of hydrogen will be out of sync.”

In conclusion, Laagland noted that for hydrogen to be implemented on a large scale, many regulatory and market conditions still have to be met. This includes pricing incentives for hydrogen, converting and building infrastructure, and a sufficient supply of renewable electricity.

Peter Stuttaford, CEO of Thomassen Energy/PSM drew attention to the renewable energy production gap. In his opinion, the gas turbine is poised to fill that gap in a variety of ways. He mentioned flexible fast-load coverage, the fact that natural gas is the cleanest fossil-fuel, and that turbines can run on a variety of fuels.

With certain upgrades, natural gas plants can slowly progress towards using 100% hydrogen. This will allow for a realistic transition away from fossil fuels while still adhering to net-zero goals.

Stuttaford detailed the retrofit process necessary to allow a gas turbine to run on hydrogen. The combustor must be replaced due to increased flame speed and the wider flammability limit of hydrogen. Next, the turbine must be evaluated for heat load due to the higher volumetric flow. Finally, the exhaust must be inspected to ensure an adequate margin.

Additionally, fuel delivery manifolds and fuels line may need to be resized, and controls systems and fuel delivery skids may need to be upgraded.

As an example, Stuttaford showed a site in The Netherlands where Thomassen Energy/PSM had upgraded a plant’s GE 9E turbines to run on up to 35% hydrogen by volume. For the past three years, the plant stably run on up to 25% hydrogen and maintained sub-9ppm NOx.

His company’s FlameSheet technology was described as “a combustor within a combustor” and is used to upgrade existing turbines. Stuttaford said it allows turbines to run on up to 60% hydrogen. It is also being tested when alternating between 100% natural gas and 100% hydrogen.

He advocated a ‘turnkey clean energy package’. It would include an electrolyzer, upgraded gas turbine, and a high-pressure storage vessel for hydrogen.

What opportunities exist for turbomachinery in the evolving energy landscape? 