Any change in operating conditions that causes the operating point to move on the turbocompressor map is known as a disturbance. Disturbances can be categorized depending on their speed. An important factor is the speed of the disturbance relative to the overall speed of the compressor control loop—a disturbance can seem slower to the compressor control main loop if the loop is made faster using a faster controller, instruments/sensors, and actuators. A fast-problematic disturbance for an ordinarily slow-response turbocompressor can be easily managed in an advanced, fast-responsive turbocompressor.

Advanced, fast-responsive digital controllers facilitate great flexibility in compensating for fast changes in operating conditions, nonlinear performance curves, unexpected situations, and complicated control strategies.

A turbocompressor curve or map supplied by the manufacturer is usually an expected performance curve (or a theoretical curve) unless it is verified by a realistic (site) performance test, i.e., a test with final installations and job conditions and not a shop test with shop facilities and alternative gases. The same is true for the surge point/curve: A surge point (or surge curve) tested at the shop is only a rough approximation compared to the real surge point (curve) that is tested at the site with the actual job piping and facilities. In addition, the turbocompressor performance curve shifts with wear, degradation, fouling, etc.

During operation, a turbocompressor is usually affected by fouling due to compressed gas dirt and impurities, which causes its performance to degrade over time. Fouling is defined as degradation of the flow capacity and efficiency caused by contaminants on the gas flow path surfaces, which include both moving and fixed parts in contact with the com-pressed gas. Different kinds of impurities such as dirt, liquid, water, oil, salts, solid particles, etc., could be in the compressed gas.

Another type of fouling is caused by oil leaks. Lubrication oil leaks from the bearings of a turbocompressor or another compressor upstream are a common cause of fouling, especially when combined with dirt ingestion. The most important effect of compressor fouling is a decrease in the gas flowrate and compressor pressure ratio. This can result in some changes in the compressor curves and map and a re-matching of different compressor stages. This re-matching could affect the compressor efficiency and operation unexpectedly. However, in most cases, a decrease in efficiency reduces the performance and global efficiency of the facility. In extreme cases, fouling can also result in surge problems, as it tends to move the compressor surge curve to the right toward the operating points.

Solutions to reduce compressor fouling are offline compressor washing, online compressor washing, and advanced filtration systems. However, if any of these methods cannot be used or are not as effective as they should be, some changes in the operation of the turbocompressor should be expected. For example, the turbocompressor may consume more power when compressing the required volume of gas to the required discharge pressure. A turbocompressor control system should be configured to deal with reasonable fouling and wear on the compressor. The control system’s response to some fouling and degradation should be evaluated and confirmed in the design stage.

Most turbocompressors have a check valve installed on the turbocompressor discharge to prevent backflow during a surge, for example. It should be located as close as possible to the turbocompressor discharge nozzle to minimize the gas volume involved in the surge instability. The check valve is critical for a turbocompressor with a reactor downstream, for example, to prevent the backflow of catalyst (or harmful mixtures) to the turbocompressor. The check valve is also extremely important for turbocompressors in parallel operation.

A possible malfunction could be the failure of a downstream check valve or the downstream control valve. Proper risk assessment and failure scenarios should be defined, and consequences and mitigation methods should be evaluated. Some turbocompressors have two check valves in series.

It is difficult to note a general narrative for how a surge curve may change due to a change in operating conditions. Such changes can be case-dependent and difficult to generalize. The following are based on some observations.

A decrease in suction pressure can lower the surge curve on a turbocompressor map, which moves the operating point closer to the surge.

An increase in the suction temperature can act in the same way and lower the surge curve.

A decrease in molecular weight can lower the surge curve, resulting in a slight movement toward the surge.

A key question is where to locate anti-surge flow measurement—on the suction or discharge? The anti-surge flow measurement could be located at suction or discharge. The suction flow measure-ment is preferred because it measures the flow at the location where it’s needed. However, in some turbocompressors, due to practical or operational reasons, the flow should be measured at the discharge. For example, there may not be sufficient space or pressure at the suction to accommodate the suction flow measurement. It is difficult to make a general rule since both types are in use today. If the flow measurement is on the discharge, the discharge flow should be referenced back to the suction temperature and pressure. For such an anti-surge system, the temperature and pressure at the suction and discharge should be accurately measured. The discharge temperature measurement may not be fast enough to correct the flow signal for transient-operating situations due to heat transfer lags in temperature measurement devices.

Amin Almasi is a Chartered Professional Engineer in Australia and the U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring and reliability.

Articles

Disturbance speed, degradation, the surge curve, and other factors and components affect the efficiency and functionality of a turbocompressor.

Turbo Tips: Key Considerations & Risks in the Operation and Control of Compressors

The aerodynamic centerpiece of a centrifugal compressor is the impeller. That's where the mechanical work is transferred to the gas to increase the pressure. There are two types of centrifugal compressor impellers: closed (shrouded) and open (unshrouded). Since the vanes are essentially the place where the energy transfer happens, why is a shroud necessary? There are a number of considerations that aim to increase efficiency, operating range, head-making capability, manufacturability, and reliability.

A high-tip velocity maximizes the head per impeller. But the tip velocity of any impeller is limited by the allowable stresses. The shroud adds to stress levels that must be carried by the blades. Thus, an open impeller usually allows for higher tip velocities while staying within acceptable stress levels for the material. So why select impellers with a shroud?

Looking at the cross section of an impeller, we recognize that the blade height (or aspect ratio) is relatively small compared to blades in axial compressors. Thus, secondary flows from leakage across the blade from the pressure to the suction side are an issue. In open impellers, it’s imperative to maintain tight clearances between the blade and stationary parts in all operating conditions. Shrouded impellers allow control of leakage flows by using labyrinth seals at the impeller eye between the shroud and stationary parts. That greatly obstructs leakage and enables easier control of clearances. Since leakages affect head-making capability and efficiency, the relative advantages depend on the circumstances.

In high-pressure applications, tip clearance losses may be significant and require tight control on the gap between the blade tip and shroud to maintain acceptable stage performance. In applications with significant axial movement and thermal growth, tip clearance must be increased, which can affect performance and even thrust levels. That’s particularly difficult if multiple impellers sit on a single shaft. In that case, both shrouded and open impellers may be used, with the open impellers usually in the higher flow front stages. On the other hand, the stress caused by the centrifugal forces on the closed impeller blade due to the mass of the shroud necessitates thicker blades and limits maximum allowable tip speeds.

Modern impellers are analyzed for vibration-mode shapes to avoid interference with fluctuating forces, such as those from stationary vanes. Keeping the modal frequency high enough—and outside of the critical range—is usually easier with shrouded impellers. Open impellers typically have lower natural frequencies compared to closed impellers. The absence of a shroud removes an additional motion constraint that raises the natural frequency of the blade. The lower natural frequencies of open impellers can have implications for the compressor’s diffuser vane count selection and general robustness.

If impellers are 5-axis milled or welded, open impellers are easier to manufacture. Shrouded impellers can be milled in one piece, but low-flow impellers in particular require that the shroud be brazed or welded to the vanes. If impellers are cast or additive manufacturing is used, there is no significant difference in manufacturing difficulty, because there are no challenges controlling the fillets among the blades, hub, and shroud. In addition, there are also semi-shrouded impellers, where only part of the flow path (usually near the impeller eye) is shrouded, while the exducer part is unshrouded.

The relative advantages of open and shrouded impellers are reflected in the respective applications they are used for. In-line compressors for high-pressure applications—gas pipelines and other upstream, midstream, and downstream applications—typically use shrouded impellers. In these applications, tip velocities are often limited for reasons other than stress limits, such as operating at acceptable, favorable Mach number ranges, or improving efficiency and range.

On the other hand, air compressors and integral gear-type machines for various applications often take advantage of the high-tip velocities achievable with open impellers. In fact, they’re currently part of the discussion about hydrogen compressors, due to hydrogen’s high speed of sound and the fact that very high enthalpy rises are needed for even moderate pressure increases.

The authors want to thank Karl Wygant and Rob Pelton, both at Elliott Turbo, for their contributions to this article.

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee.

Rainer Kurz is the Manager of Gas Compressor Engineering at Solar Turbines Incorpo-rated in San Diego, CA. He is an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates.

Open and shrouded impellers both offer advantages, which are reflected in the respective applications they are used for.

Myth Busters: Axial Compressors Don't Have Shrouds, So Why Do We Need Them for Centrifugals?

The use of hydrogen as a decarbonized fuel and for long-term energy storage involves various types of hydrogen-based solutions. These solutions must be capable of delivering clean power via hydrogen fuel for the production, transport, storage, and use of hydrogen, with lower overall emissions than alternative decarbonized energy-storage technologies. Thermochemical technologies, including hydrogen as energy storage, provide the only long durations required for seasonal and daily fluctuations in renewables.

Hydrogen is used in a power-to-gas (P2G) approach as energy storage for excess renewable power that can be stored at high pressures and transported via pressurized pipelines, typically up to 1,440 psi. However, compressing hydro-gen is power-intensive due to its energy density being very low on a volumetric basis. Compared to natural gas pipelines, for equivalent energy volumes, hydrogen compression will likely require 5 - 6 times the power 

. This makes efficiency in design and the overall footprint requirement key aspects when evaluating various compressor technologies.

In this value chain, hydrogen compression will be needed for a range of applications, including pipeline transportation, production, storage, transport, fuel boosting, and use at gas-fired power plants, as well as vehicle/aircraft fueling stations. Providing hydrogen-compres-sion solutions for such a broad range of target applications challenges the technologies that are currently available, giving rise to critical questions on how to adapt compression technologies to meet the wide variety of needs.

In the short term, generating hydrogen from fossil fuels with carbon capture and sequestration (CCS) offers lower costs and production closer to the point of use. This pathway to power production from hydrogen-blended gas will likely require less pipeline compression and possibly lower delivery pressures. In the case of gas-fired power plants, volume flows will be scaled to the size of the existing gas turbine and natural gas combined-cycle (NGCC) power plants, so compression technology will need to match the power-plant delivery flow rates. For the transportation sector, smaller modular compressors will be required for vehicle fueling stations. The CO₂ compression requirements for this pathway will be significant and require additional CO₂ pipelines and compression.

While different types of compressors are used in industrial applications and vehicle refueling stations, the larger power applications for storage and pipelines realistically limit the selection to reciprocating and centrifugal compressors. Both have precedence in this area as well as relevant designs, with high reliability in refinery/plastic production processes, albeit at lower ratios and lower overall discharge pressures.

Compression requirements are largely similar from production to transport, requiring booster units to compress into the pipeline at ratios of 2.5 - 3.0 and recompression in the pipeline at ratios of 1.2 - 1.3. Compression ratios for storage applications will be much higher, up to 10.0. Fuel-line-booster compression may require ratios of 2.5 - 3.5 and be most relevant to hydrogen production at the point of use, i.e., the gas turbine power plant. 

Due to hydrogen’s low energy volume density compared to pipeline-quality natural gas volume density, in blending hydrogen with natural gas, appreciable concentrations of hydrogen will be needed to significantly decrease carbon emissions. The Btu/min flow to the turbine must remain constant for the 50 MW combustion gas turbine system shown in 

 for a blended fuel stream, which means that the natural gas flow falls off non-linearly with increasing hydrogen content. Operators will need to blend more than 50% hydrogen to start making an appreciable difference in carbon emissions, and many gas turbine manufacturers are already investigating means of operating at 100% hydrogen fuel. 

The challenge with hydrogen compression is in the large flow rates and the variety of pressure ratios required for the decarbonized energy market compared to compressors used in refinery applications. The higher compression ratios required for the transportation/power sector will require design adaptations for both reciprocating and centrifugal compressors, including enhanced sealing methods, alternative valve selections, and additional staging. 

 displays some of these requirements relative to the head/flow capabilities of existing reciprocating and barrel-style multistage centrifugal compressors for a range of hydrogen flow conditions corresponding to transported fuel energy content from 6-25 GW (500-2,150 MMSCFD natural gas), which correspond to a range of pipeline sizes analyzed in Allison, et al., 2021.

The two lower-left solid rectangles show a comparison of natural gas versus hydrogen compressors for transport at pipeline stations, where compression requirements increase for hydrogen due to the lower volumetric energy density of hydrogen and the thermodynamic properties of hydrogen that require more power to achieve the same pressure ratio when compared with natural gas. The upper-right solid rectangle illustrates compression requirements for boosting hydrogen from its production pressures of 20 - 25 bar to pipeline pressures of 85 - 100 bar. The dashed rectangles show the capabilities of existing technologies for hydrogen compressors. In general, reciprocating compressors may struggle with meeting flow requirements for hydrogen compression, whereas centrifugal compressors will struggle to meet the head requirement for hydrogen compression in a single unit.

In addition, to harness excess renewable power in P2G applications, hydrogen compressors for storage will need to likely deliver at 3,000 psi and above 

 for injection at the top end of the reservoir. 

Initial boosters to take hydrogen from production pressure to pipeline pressures (atmospheric to 100 psi) will require hydrogen compressors capable of a high number of multiple stages due to significant head requirements. Hydrogen compressors will need to move to designs at higher rated motor and engine drivers, likely 10 MW and above, and compression design variability for a range of pressure ratios. The compounded effect of low energy density by volume and high head due to its high specific heat makes hydrogen compression challenging and power-intensive.

Managing the higher head for the larger pressure ratios associated with hydrogen production and pipeline boosters is a key design parameter. Intercooling between stages is crucial to protecting internal components and keeping power consumption low but is complicated by the need to maintain a semi-compact footprint for reciprocating compressor pulsation bottles, lube oil systems, and intercoolers and their associated piping.

 compare the advantages and disadvantages of the various compression options for hydrogen. 

The various hydrogen technologies that are currently available each have distinct applications where the compressor choice may be more apparent. However, in many applications, an overlap of competing technologies can be expected. It is in the best interest of operators to compare these technologies for each application space and to evaluate details of the compressor offerings such as overall physical size, accessibility for operations, capex/opex cost, manufacturer experience, and durability of each technology. 

Operators should also consider how the technology accommodates the following factors for future hydrogen compression applications:

Frequency of starts/stops – seasonal or daily cycling

Hydrogen purity and possible contaminants

Fixed or variable speed for fixed or variable flow/pressures

Criticality of service/reliability/durability of units

Design adaptability to hydrogen content (if blended H

Reciprocating and centrifugal compressors are viable options for hydrogen compression with enhanced and adapted sealing methods, alternative valve selections, and additional staging. Reciprocating compressors are available for hydrogen service in both low- and high-speed options but will struggle to meet larger volume flow requirements for some applications. Centrifugal compressors for pipeline and storage applications will be capable of higher volumetric flow rates but will need to meet the higher head requirements by using adaptable multi-body arrangements. Finally, centrifugal compressor designers are working to achieve higher tip speeds to overcome the high head required in hydrogen service with fewer compressor stages.

Klaus Brun, Ph.D., is the Director of R&D at Elliott Group; Timothy C. Allison, Ph.D., is the Director of R&D at Southwest Research Institute (SwRI); Marybeth McBain is the Principal Rotating Machinery Engineer at Venture Global LNG; Stephen Ross is the Manager of Compressor Development at Elliott Group; and Eugene L. Broerman III is the Principal Engineer of Fluid Machinery Systems at SwRI. 

Allison, T.C., Rimpel, A.M., Smith, N.R., et al. 2022, “Overview of
Long-Duration Energy Storage Systems and Technologies,” Proceedings of ASME Turbo Expo, Tutorial GT2022-83425, Rotterdam, The Netherlands. 

Williams, B., Kurz, R., McBain, M., 2022, SwRI Oil and Gas Machinery Lecture Series, “Role of the Oil and Gas Industry in the Hydrogen Economy.” 

Allison, T., Klaerner, J., Cich, S., et al. 2021, “Power and Compression Analysis of Power to Gas Implementations in Natural Gas Pipelines with up to 100% Hydrogen Concentration,” Proceedings of ASME Turbo Expo, Paper GT2021-59398. 

Hassanpouryouzband, A., Joonaki, E., Edlmann, K., et al. 2020,
“Thermodynamic and transport properties of hydrogen containing streams,” Sci Data 7, 222. https://www.nature.com/articles/s41597-020-0568-6. 

Kurz R., Allison, T., Brun, K., 2021, “Pipeline Compression for the Hydrogen Economy”, DOE Seminar. 

McBain, M., Bauer, Derrick, B., Ross, S., et al. 2022, “Technology Options for Hydrogen Compression,” Proceedings of Gas Machinery Conference 2022: Fort Worth, TX.

Reciprocating and centrifugal compressors are viable options for hydrogen compression with enhanced and adapted sealing methods, alternative valve selections, and additional staging.

Hydrogen Compression - Prospects & Challenges

In the third and final part of our roundtable Q&A on the state of hydrogen in the turbomachinery industry, experts and OEMs talk about how, from a technical standpoint, different types of turbomachinery benefit or become challenged by the integration of hydrogen. And Mark Axford, founder of Axford Turbine Consultants, weighs in on the role ammonia can or does play in the incorporation of less carbon-intensive fuel sources. 

Mark Axford
Founder
Axford Turbine Consultants

Klaus Brun
Global Director of R&D 
Ebara-Elliott Energy Company

Alex Habeder
Head of Business Strategy
Sustainable Energy Systems 
Siemens Energy

Andreas Kramer 
Senior Manager Business Development 
MAN Energy Solutions

Daniel Patrick
Market Manager Hydrogen 
Atlas Copco Gas and Process

Q: HOW, FROM A TECHNICAL STANDPOINT, DO DIFFERENT TYPES OF TURBOMACHINERY BENEFIT OR BECOME CHALLENGED BY THE INTEGRATION OF HYDROGEN?

The turbomachinery types that are affected by the hydrogen discussion are pipeline compressors and combustion gas turbines. There is no benefit provided to these turbomachines by integrating hydrogen, but there are certainly challenges. 

For centrifugal compressors, the molecular weight of the gas being compressed is an essential design criterion for each impeller. Injecting more than a few percent of hydrogen (by volume) into the existing network of interstate pipelines would require replacement rotors for thousands of centrifugal compressors. Interstate pipelines are regulated by FERC, and the additional costs for the rotor rework would have to be passed along to customers.

For gas turbines, most existing makes and models could be operated with a 5-10% hydrogen fuel blend (by volume) without significant modification. But higher percentages create challenges, i.e., flame temperature and NOx emissions. Hydrogen burns at a hotter flame temperature and has a longer flame shape. Plus, more NOx will be produced for the same power output. This can be mitigated by redesigning the gas turbine combustor and/or spending more on the ammonia catalyst system installed on the gas turbine exhaust.

The two primary types of turbomachines that are affected by a conversion to a hydrogen economy are compressors and gas turbines—compressors, since they are used to gather and transport gas in a pipeline; gas turbines, since they are used to convert energy carrying gas into mechanical energy and electricity via a generator. Gas turbines have been utilized for the combustion of natural gas for many years, and although there are some challenges to maintain other criteria pollutants (such as NOx) low when burning hydrogen, the technology challenges to convert gas turbines to hydrogen operation are manageable. Similarly, compression of hydrogen has been demonstrated in refineries and other petrochemical applications for many years. However, for large-scale transport of hydrogen, different types of compressors will be required. Hydrogen is the lightest of all gasses, and to effectively compress hydrogen to the pressure ratios needed for transport and storage requires very high-speed turbomachines with impellers that operate at speeds well above that of conventional compressors. This technology is currently being developed but is not yet commercially available.

The application of hydrogen compression is not a novel concept. There are currently hundreds of centrifugal and positive displacement machines operating in this field, processing either "pure" hydrogen or a blend of gases with significant hydrogen content. Both compressor types can handle a broad range of application sce­narios, with the choice of technology largely coming down to eco­nomic tradeoffs and the facility’s specific requirements, includ­ing required flow rates, pressure ratios, foot­print limitations, use of dry or wet sealing, etc. Minor modifications usually suffice when the process gas contains smaller quantities of hydrogen; however, as this percentage increases, we must pay particular attention to factors such as power consumption, material compatibility, gas leakage, and operational flexibility.

Compressing hydrogen requires 2.5 - 3 times the compression power needed for an equivalent volume of natural gas.

Hydrogen can induce phenomena like hydrogen embrittlement in certain metals, potentially leading to premature failure of compressor components.

Hydrogen molecules are smaller than natural gas molecules, increasing their propensity to leak through seals and gaskets.

Green energy sources generate fluctuating loads and necessitate operational flexibility. Products should have the capability to operate over a more extensive flow range. There's an opportunity to optimize a hybrid solution comprising both centrifugal and positive displacement machines.

Different types of turbomachinery indeed have their advantages and challenges when it comes to integrating hydrogen. For example, when dealing with large effective volume flows, reciprocating compressors would become excessively large and costly. This is where process gas screw compressors, centrifugal inline compressors, and integrally geared compressors come into play. They can be used upstream of reciprocating compressors to reduce the effective volume flow. In cases requiring further compression, reciprocating compressors can be installed downstream, particularly for extremely high-pressure ratios and for pressure requirements beyond 250 bar. In such cases, centrifugal and integrally geared compressors face the challenge of achieving the necessary polytropic head with an acceptable number of stages. For moderate pressure ratios and below 250 bar, centrifugal inline compressors and integrally geared compressors may be the better solution, depending on the specified process data. For compression from low-pressure electrolysis, e.g., atmospheric, oil-free process gas screw compressors can achieve the required pressure ratio at volume flows not suitable for reciprocating compressors. Additionally, there have been advancements in gas turbines specifically designed for hydrogen, and further developments have been announced for use of green ammonia as fuel.

 Hydrogen is a notoriously difficult molecule for turbomachinery due to its low molecular weight. Turbomachinery designed for hydrogen applications requires high speeds and high stage counts to achieve most pressure ratios. This challenge can sometimes make turbomachinery less appealing for hydrogen when compared to other compression technology like positive displacement, especially for lower flow, high-head applications. However, turbomachinery lends itself well to certain hydrogen applications. For example, the cryogenic temperatures of liquid hydrogen applications result in increased gas density, making it favorable for centrifugal technology. This makes applications such as liquid hydrogen boil-off gas a good fit for integrally geared centrifugal compressors. Hydrogen liquefaction is another area where turbomachinery can shine. Cryogenic hydrogen turboexpanders play a crucial role in providing the necessary refrigeration duty to achieve liquid hydrogen temperatures.

Q: WHAT ROLE CAN/DOES AMMONIA PLAY IN THE INCORPORATION OF LESS CARBON-INTENSIVE FUEL SOURCES?

 Hydrogen is difficult to transport. Unlike natural gas, which can be liquefied and transported globally by ship, it is not economically feasible to liquefy hydrogen for bulk transport. An idea to address this problem is to manufacture green hydrogen and then convert it to ammonia by combining hydrogen and nitrogen. This requires additional capital investment to separate nitrogen from air to manufacture green ammonia. It is feasible to transport ammonia, and upon arrival at a power station, convert the ammonia to hydrogen, which can then be utilized as a turbine fuel. 

If you have excess electricity from wind and solar during peak hours, and you utilize this energy to make green ammonia, why not just stop there and use the subsidized green ammonia as fertilizer? Otherwise, an additional manufacturing step is needed to convert the green ammonia back into hydrogen. Each of these “conversion” processes requires capital investment and machinery that uses energy, thus creating additional cost and inefficiency all to address the hydrogen transportation problem. 

Let’s not forget that natural gas is a “less carbon-intensive fuel source” when compared to coal. It is likely less expensive to add carbon capture to natural gas combined-cycle plants than to pay for the extra infrastructure associated with hydrogen. To that point, hydrogen technology must compete not only with batteries but also with carbon capture.

Part 1: Roundtable Q&A: The State of Hydrogen in the Turbomachinery Industry

Part 2: Roundtable Q&A: Obstacles Preventing Large-scale Implementation of Hydrogen

In Part 3 of our roundtable Q&A on the state of hydrogen in the turbomachinery industry, experts and OEMs discuss how different types of turbomachinery are affected by the integration of hydrogen and the role of ammonia.

Part 3: Roundtable Q&A: The Roles of Hydrogen and Ammonia as Less Carbon-Intensive Fuel Sources

In the second part of our three-part roundtable Q&A on the state of hydrogen in the turbomachinery industry, experts and OEMs discuss the various obstacles that are preventing the large-scale implementation of hydrogen, including the costs of manufacturing hydrogen, transporting it to a power station, and providing large-scale storage at the site.

Q: WHAT OBSTACLES ARE PREVENTING THE LARGE-SCALE IMPLEMENTATION OF HYDROGEN?

The main obstacles are the costs of physically manufacturing hydrogen, transporting it to a power station, and providing large-scale storage at the site. Modern gas turbine power plants utilize combined-cycle technology for high efficiency. These plants are designed to run at baseload and typically utilize building blocks of 300 – 600 MW of capacity. Continuous consumption of this much fuel requires an infrastructure of interconnected pipelines fed from numerous fuel sources. Because this infrastructure does not exist for hydrogen, a nearby storage cavern of substantial proportion must be located near the power plant. In terms of green hydrogen, the electrolyzer and renewable energy sources need to be located nearby. These obstacles can be overcome with government subsidies, but only if the cost of green electricity does not matter.

The main obstacles [preventing large-scale implementation of hydrogen] are the costs of physically manufacturing hydrogen, transporting it to a power station, and providing large-scale storage at the site. - Mark Axford

The primary obstacle to the large-scale implementation of hydrogen as an energy carrier is the cost of hydrogen production, transport, and storage. It is difficult to utilize or convert the existing hydro-carbon transport infrastructure to hydrogen transport because of the challenging physical properties of hydrogen. As previously noted, hydrogen is not an easy gas to handle. Thus, to convert our industrial and domestic usage from fossil fuels to hydrogen requires an entirely new infrastructure, which could cost trillions of dollars. This is something that will take time, money, and commitment to implement.

Reasonably priced and affordable electrolyzers are the prerequisite for covering the growing demand and future hydrogen costs. Furthermore, generating green hydrogen requires a significant and accelerated expansion of renewable energy worldwide. This expansion can only accelerate if permitting becomes faster and less complicated. Automated factories for electrolysis on an industrial scale (including the GW scale) must be constructed, and the pipeline and industrial-scale hydrogen storage infrastructure must be implemented for storing and transporting the hydrogen.

If the preconditions described in the first question have not been achieved, and the necessary infrastructure has not been established, large-scale implementation of hydrogen is expected to face significant challenges and may ultimately fail.

 Supply and demand is one of the largest obstacles hydrogen faces today. We are stuck in the classic “chicken-or-the-egg” situation. Hydrogen producers need confidence that there will be eager consumers, while consumers need reassurance there will be a consistent supply of hydrogen to suit their needs. Both sides of the supply chain seem to be looking at the other, waiting to see what will happen next. With the number of hydrogen projects on the horizon and the ever-growing demand sector, this seems to be a short-term issue. Once we get past the supply-and-demand hurdle, the next challenge will be bringing down the cost of hydrogen. Companies and consumers are generally willing to pay a “green” premium, but there are still significant economic gains to be made before hydrogen becomes adopted as a mainstream energy carrier.

Part 3: Roundtable Q&A: Turbomachinery and Hydrogen, Ammonia's Role as a Less Carbon-Intensive Fuel Source

In Part 2 of our roundtable on the state of hydrogen in the turbomachinery industry, experts and OEMs discuss the various obstacles that are preventing the large-scale implementation of hydrogen. 

As hydrogen continues to dominate discussions about energy security and decarbonization, conference agendas, and government climate goals, its role and capacity are often misrepresented and overhyped. According to the International Energy Agency’s (IEA) Global Hydrogen Review 2022, more than 80% of hydrogen is derived from fossil fuels, with some experts placing it higher. Further, the main uses of hydrogen in the industry are to produce ammonia—which accounts for 34 Mt of hydrogen demand—methanol (15 Mt), and direct reduced iron in the steel industry (5 Mt). Most importantly, almost all hydrogen used in the industrial sector is produced from unabated natural gas or coal, which translates to 630 Mt of direct CO

 emissions. These numbers complicate the carbon-neutral image of hydrogen.

While the technology is proven, hydrogen still plays an insignificant role in the power generation sector, accounting for 0.2% of the total generation, according to IEA. Solutions are underway, but most say it will be at least 10 years for green hydrogen to make deep headway in power generation. IEA reported that 2021 was a record year in electrolysis deployment, with more than 200 MW of additional installed capacity, three times more than 2020, bringing the total operational capacity above 500 MW. But carbon capture, utilization, and storage (CCUS) associated with hydrogen production has been largely stagnant. IEA reported in 2021, 0.6 Mt of hydrogen were produced from fossil fuels with CCUS, capturing roughly 10 Mt—the same production and capture level as in 2020, as no new projects started operation.

To elaborate on these numbers, facts, and technologies, Turbomachinery International put together this roundtable of industry insiders to offer their points of view and insights into hydrogen’s current and projected role in the energy sector.

Q: HOW REALISTIC IS IT TO COUNT ON HYDROGEN AS THE “GOLDEN TICKET” TO NET-ZERO EMISSIONS IN TERMS OF COST, SUPPLY, AND IMPLEMENTATION?

Net-zero emissions are normally discussed to be achieved within a timetable—often 2050. I do not see hydrogen as the golden ticket primarily because green hydrogen is far too expensive compared to other competing technologies. In 2022, the worldwide industrial demand for hydrogen was 95 million metric tonnes—almost half of the demand was fulfilled by manufacturing hydrogen by reforming methane gas, i.e., grey hydrogen. 

In the United States, the industrial price of grey hydrogen is $1 per kg delivered. The cost to make green hydrogen utilizing an electrolyzer is $5 per Kg. To encourage the production of green hydrogen, the United States and the European Union have passed legislation to subsidize its production. The U.S. subsidy is a “double dip”. First, $3 per Kg for all the green hydrogen produced plus an additional guaranteed payment for the electricity produced from it as it is put into fuel cells or gas turbines. There is no market for green hydrogen without huge government subsidies. Moreover, there is no way to discern $5 green hydrogen from $1 grey hydrogen; they are physically identical. Safeguards must be put in place to prevent large-scale fraud.

There are also technical issues with hydrogen relating to the cost of storing and transporting it. Most of the large U.S. interstate pipelines could safely transport hydrogen or a blend of hydrogen and natural gas. However, the pipeline compressor stations would require major rework to handle the volumetric changes due to mole weight. A bigger problem exists in the gas distribution pipelines networks and end-user appliances like stoves and furnaces. Much of the smaller diameter piping could suffer embrittlement if exposed to hydrogen. Also, most end-user devices would not operate if the hydrogen component of the fuel was more than a few percent.

Hydrogen is not a golden ticket to net zero. It is one of many enabling technologies that can, if properly applied and deployed, provide a positive contribution toward a net-zero or decarbonized energy economy. Hydrogen is not a fuel source. It is a basic chemical element that can be utilized for energy storage and transport. Since it does not release CO

 in a net-positive energy exothermic reaction, it is a viable energy carrier. However, hydrogen does not occur naturally and, thus, it needs to be produced either through electrolysis or partial oxidation reactions. Both processes are energy-intensive and require expensive equipment and new infrastructure. Hydrogen is not an easy gas to handle in that it is highly explosive, has a wide flammability range, leaks easily, causes embrittlement in many metals, and is hard to compress since it is a very light gas. Thus, the practical usage of hydrogen is limited to those applications where an industrial process requires hydrogen as a precursor product (such as refining or fertilizer production) or to an application where energy cannot be viably stored or transported by other cheaper and safer means, i.e., hydrogen as an energy carrier is only practical when energy that is produced cannot otherwise be transported easily (via an electrical grid), stored in batteries or other energy storage devices, or locally consumed.

While hydrogen holds promise for achieving net-zero emissions, relying solely on it as the “golden ticket” for cost-effective and scalable implementation creates challenges. The two most significant challenges are (1) hydrogen must become a closed commercial business model that enables worthwhile private commercial investments, and (2) at the same time, we must enter series production with supply chains and suppliers—the majority of whom are still manufacturers.

The cost of hydrogen production today, particularly from renewable sources, remains relatively high compared to traditional fossil-fuel alternatives. While new technologies and economies of scale are emerging and expected to drive down costs over time, achieving cost competitiveness with fossil fuels will require substantial investment and innovation. The development of fossil fuel prices also plays a role, especially with regard to the price of CO

Scaling up hydrogen production and ensuring a reliable supply pose logistical challenges and require substantial infrastructure development. Although hydrogen is an established chemical feedstock in the industrial sector, using green hydrogen in the energy sector is relatively new; thus, there’s no established infrastructure for green hydrogen. We will need robust supply chains, production capacities, or transportation networks to promote the use of green hydrogen on a large scale. All of this must be created at a speed that can keep pace with an announced market ramp-up.

"The cost of hydrogen production today remains relatively high compared to traditional fossil-fuel alternatives. While new technologies and economies of scale are expected to drive down costs over time, achieving cost competitiveness with fossil fuels will require substantial investment and innovation."  - Alex Habeder

Transitioning to a hydrogen-based economy necessitates extensive changes across sectors and the widespread adoption of hydrogen technologies. A comprehensive approach integrating it with other decarbonization solutions is crucial to leverage hydrogen effectively. We need large-scale kick-start projects to test the technologies and progress from talking to acting. Speed is also of the essence.

In these areas, there is no doubt that low-carbon hydrogen is the path to decarbonization: replacing grey hydrogen as feedstock in the chemical and fertilizer industry and changing steel production to the direct reduction pathway with low-carbon hydrogen. On the other hand, in terms of mobility, shipping and aviation cannot be easily electrified and need fuels synthesized from clean hydrogen and carbon, such as CO

To produce green hydrogen, there is a need for renewable energy in large and sufficient quantities. Without the establishment of regulatory frameworks, the feasibility of implementation becomes questionable. Moreover, industries require investment security to proceed. Additionally, cost reduction through economies of scale must be achieved. Without meeting these prerequisites, relying on hydrogen as the ultimate solution may not be realistic.

 Hydrogen is an excellent choice to decarbonize certain industries. However, it is just one of the many strategies we will need to deploy to reach net-zero targets. Industries such as material handling, heavy-duty transportation, long-duration energy storage, stationary power generation, and combustion applications (such as green steel) all seem to be attractive sectors for the early implementation of hydrogen.

Q: WHAT ARE SOME OPPORTUNITIES CREATED BY HYDROGEN UTILIZATION IN THE ENERGY INDUSTRY?

Utilizing hydrogen as an energy storage technology requires substantial economic subsidy. Today, the most economical forms of energy storage are coal piles, oil tanks, and LNG tanks. Of course, these are all hydrocarbons and out of favor politically. So, what are the least expensive non-hydrocarbon forms of energy storage? Pumped storage on rivers and lakes has been utilized for decades, but most of the good sites have already been built out. More recently, lithium-ion batteries, similar to automotive battery packs, have become a favorite. Batteries can soak up the excessive quantities of electricity produced by wind turbines and solar panels during peak production hours. Subsidies for battery storage have been generous and batteries can provide instantaneous injection of KW into the grid when needed—a valuable technical feature. 

As I see it, if we set aside hydrocarbon energy storage, hydrogen must compete with battery storage. However, lithium-ion battery technology is expensive and not necessarily the best battery technology for long-term bulk storage. Several other battery technologies that are now being tested could bring about a sharp reduction in the installed cost per MWh of battery storage—companies such as Form Energy, EOS, and Zinc8. Toyota has also recently announced a solid-state battery breakthrough. I anticipate a disruptive battery technology will emerge for bulk-energy storage over the next two years that will cause severe damage to hydrogen storage's economic viability.

 The primary opportunities for hydrogen utilization, with the aim to decarbonize the total energy supply, are in the areas of petrochemical production—the replacement of blue/brown/black hydrogen with green hydrogen—as a transportation fuel, for fertilizer and ammonia production, and for other industrial chemical processes that require hydrogen as a precursor supply. The usage of hydrogen for power generation makes less sense since the cost of converting green electricity to hydrogen and then back to electric power is expensive, and the roundtrip efficiency of this process is well below 40%. It is not logical to use a process that wastes well over 60% of the produced energy to reduce carbon emissions. For curtailed green electricity it makes more sense to try to improve the distribution system to find off-takers for the electricity or to utilize energy storage technologies with higher roundtrip efficiencies, such as pumped hydro, pumped heat, compressed air, liquid air, etc.

Switching from coal to natural gas for power generation and improving efficiency are the first steps to reducing CO

 emissions. Next is substituting sustainable hydrogen for natural gas to enable carbon-neutral power plant operation, since hydrogen combustion does not produce CO

. Combined- and simple-cycle plants provide residual load for periods of low renewable generation and enable large-scale, seasonal storage of renewable electricity. In the long term, hydrogen-fueled gas turbines and combined-cycle plants will enable a fully decarbonized energy system in which renewables form the backbone of all energy consumed.

Currently, hydrogen is predominantly used in refineries and ammonia production via the steam methane reforming process where 1 ton of hydrogen causes 10 tons of CO

 emission. Future advancements aim to replace fossil-fueled power plants with hydrogen-based alternatives, such as power plants utilizing hydrogen, ammonia (produced with green hydrogen), or synthetic fuels (produced with green or blue hydrogen and CO

 from emitting industries like cement). Co-firing of ammonia or methanol in coal-based or combined-cycle gas turbine power plants is also planned. The same applies to large ship engines for ocean-going vessels, which can be fueled by methanol or, in the future, by ammonia (Power-to-X).

The most obvious opportunity for the energy industry is the chance to reduce the carbon footprint of a traditionally carbon-intensive sector and do so by enabling a low-carbon hydrogen economy. Also, the hydrogen economy will create a variety of new jobs, all while leveraging the wealth of knowledge and experience the energy industry has acquired over the decades from working with traditional energy sources.