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.

FIGURE 1. Comparison of Energy-Storage Forms – Discharge Time vs. Rated Power

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. 

FIGURE 2. Calculated Equivalent Fuel Volumes for LM2500 Combustion Gas Turbine Producing 50 MW at ISO Conditions

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.

FIGURE 3. Comparison of Hydrogen Compressor Requirements vs. Capabilities for Pipelines Transporting 6-25 GW (500-2150 MMSCFD)

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.

FIGURE 4. Hydrogen Storage Pressures and Temperatures

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. 

TABLE 1: Comparison of “Mainline Flow” Compressor Options for Hydrogen


Ps = 169 psia, Pd = 1,440 psia, Q = 150 MMSCFD, Ts = 160°F

TABLE 2. Booster Compressor Application Case 2


Ps = 363 psia, Pd = 1,087 psia, Q = 500 MMSCFD, Ts = 68°F

TABLE 3. Comparison of “Mainline Flow” Compressor 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 this episode of the TurboTime podcast, we talk to Carolyn Woeber, the Director of Application Engineering at Cadence Design Systems, about computational fluid dynamics (CFD). Woeber gives a crash course in CFD and how it relates to the turbomachinery industry. She then talks about how CFD streamlines and benefits pump and compressor design and performance, how it improves the design and analysis of aerospace machinery, and what areas CFD could improve in the aerospace industry and the challenges it faces in terms of the turbomachinery industry.

“Engineers use multiple analysis tools to predict the behavior of these fluids to identify the most optimum design for their needs,” Woeber said. “This can range from analytical empirical analyses all the way to experimental setups, to computational fluid dynamics (CFD),” she said, “Most engineers that you talk to are familiar with and they use the analytical and the empirical analyses. They also use experimental setups when they're evaluating potential designs. But increasingly, we see more and more organizations moving toward enhancing their design processes by also incorporating CFD. So how does that work? What does that look like?

“A CFD practitioner begins with a CAD model that serves as a foundation. On that CAD model, they then create a 2D mesh,” she continued. “This 2D mesh adheres to and resolves the model’s geometry to the level of fidelity that's required for numerical simulation. Then we construct a mesh in the 3D space around that model—this is the space you want to conduct the fluid flow analysis. This 3D space can be internal, it can be external, or it could be a combination of both depending on the configuration. Next, we'll make sure that the topology within the mesh.”

In this episode of the TurboTime podcast, we talk with Carolyn Woeber, the Director of Application Engineering at Cadence Design Systems, about 
computational fluid dynamics. 



TurboTime Podcast: Computational Fluid Dynamics with Cadence

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 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.

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

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 we face in hydrogen 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.

A roundtable of experts and OEMs addresses hydrogen’s role in the energy landscape, including supply and demand, opportunities, and obstacles. 

In this episode of the TurboTime podcast, sponsored by Rentech Boilers, 

talks with Shawn Brewer, Director of Business Development and Field Services at Rentech Boilers, about boiler repair and the company's field services. 

Brewer reviews the most common problems his company encounters in the field and the reasons these issues are common. He also discusses the differences between a successful servicing or support job and an unproductive one and provides an overview of the repair/support process. Brewer offers listeners a detailed report of the top challenges of working in field services and some preventive measures operators can take to ensure the longevity of their equipment.

In this episode of the TurboTime podcast, sponsored by Rentech Boilers, Shawn Brewer, Director of Business Development and Field Services at Rentech Boilers, talks about boiler repair and the company's field services. 

TurboTime Podcast: Boiler Repair, Field Services with Rentech

Commissioning is a set of tests, checks, and activities to convert a newly installed package to a full-capacity commercial operation. Commissioning is performed in four phases:

1. Pre-commissioning
2. Core commissioning
3. Start-up
4. Post commissioning


Pre-commissioning is a thorough site inspection that includes verifying design conformity, the status of electrical, mechanical, and instrument installations, running-in of equipment, flushing, cleaning, drying, etc.

Pre-commissioning activities usually start when mechanical completion is achieved. Frequently, however, these two activities overlap. For example, a package can be under pre-commissioning while neighboring units are still under construction. For this reason, a facility can be separated into easily manageable pre-commissioning entities.


Create a pre-commissioning checklist to track the comprehensive site inspection and pending items. Bolts and similar tightening parts should be tightened as required. (This is a common pending item.) Wiring in general and electrical/instrument wiring connections require a lot of attention. All switches, instruments, indicators, and other instruments and devices should be properly installed and prepared to be qualified for further stages, such as a loop test. Grounding is often missed, but this is an important step. Be sure the grounding status of all machinery and equipment is checked—the ground resistance should also be measured and verified. All tubing and networks of piping, conduits, etc., should be checked and verified, e.g., centralized lubricating systems. There should be no leakage, deformation, or damage, and the entire network should be complete and working properly. There should be no blockage as well.

Planning is the key to success in commissioning. Proper planning and sequencing of different construction, completion, pre-commissioning, and commissioning tasks for different units and packages are extremely important to transition from the erection and installation phase to operation. As part of the planning stage, an estimated number of laborers, technicians, and supervisors should be provided for each stage of the commissioning. As a part of pre-commissioning, most flushing, cleaning, etc., is implemented in the shop before delivering the turbomachinery to the job site.


Safety precautions are important in commissioning. Proper risk assessments should be done before any pre-commissioning and commissioning steps. There are many different risks and hazards in many commissioning tasks and activities, such as the risk of fire. Therefore, fire systems should be commissioned before any risky tasks are started, and/or temporary firefighting equipment should be provided.

Issues in previous stages, such as design, construction, etc., often surface during commissioning. A set of deviations may be necessary to facilitate the commissioning. However, there should be no deviations on matters related to safety, reliability, or operational flexibility.

Each phase of commissioning requires a dedicated form—inspections should be supported by the appropriate record/form, and proper forms/reports should be completed and signed upon completion of each stage of commissioning. All measured data from the commissioning stage should be recorded as well as the various technical parameters and measurements.

Troubleshooting is a major task in the commissioning. Complete troubleshooting guides should be prepared in advance for every machine, piece of equipment, or device in the plant to help identify and correct any malfunctions that may occur.


All required items, lubrications, chemicals, tools, spare parts, and bits and pieces for commissioning should be ready in advance. Further, the quantity and grade of lubrication oil should fit the turbomachinery. The incorrect types and grades of oil were frequently used in different machines in previous commissioning exercises, which caused difficulties during this phase, so ensuring the correct oil is being used is critical. Additionally, all required operational data should be supplied in advance, such as alarm descriptions, alarm set points, initial settings for commissioning, etc.

Handover is another critical task that requires details for each handover, as there are different types. For example, the handover from the construction team to the commissioning team—this is the official start of pre-commissioning. Another example is the handover from commissioning to operation.

And finally, a thorough visual inspection should be conducted to ensure there are no defects, obvious deformations, cracks, weld-joint problems, loose bolt connections, etc. The various modes of operation—starting and stopping, full range of part-load, emergency trips, etc.—should be conducted on each turbomachine. All limit devices, sensors, instruments, etc., should be checked for sensitivity and reliability. Also, safety and limiting systems such as brakes should be checked. An electric motor solo test should be done for all onsite motors to verify the motor’s operational characteristics such as vibration, temperature, noise, etc. 

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.

The four phases of commissioning are important developmental stages for any turbomachinery package. 


Turbo Tips: Commissioning Turbomachinery

In Part 2 of this episode of the TurboTime podcast on pumping/compressing CO

, Myth Busters Klaus Brun and Rainer Kurz discuss the impact CO

has on centrifugal compressor performance and carbon sequestration.

The duo talks about how the pressure of CO

 in a pipeline, for example, affects centrifugal compressor performance. They also carbon sequestration challenges and how the industry is optimizing these technologies for emissions control, specifically in terms of gas leakage and losses.

In Part 2 of this episode of the TurboTime podcast, Myth Busters Klaus Brun and Rainer Kurz discuss the impact CO2 has on centrifugal compressor performance and carbon sequestration.

TurboTime Podcast: Part 2 - Compressing CO2

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.

Articles

Siemens Energy is supplying 12 electrolyzers with a total capacity of 200 MW to Air Liquide’s Normand’Hy project in Normandy, France. Air Liquide will operate the electrolyzers at its plant in the Port-Jerome industrial zone, which will produce 28,000 tons of renewable hydrogen for the industrial and mobility sectors, beginning in 2026.

The low-carbon hydrogen produced with Siemens Energy’s electrolyzers will decarbonize the Normandy industrial basin, displacing up to 250,000 tons of CO

"The sustainable decarbonization of industry is difficult without green hydrogen,” said Anne-Laure de Chammard, member of the Executive Board of Siemens Energy. “That is why projects like this are so important. But they can only be a starting point for a sustainable transformation of the industrial landscape. For the development of a European hydrogen economy to succeed, we need reliable support from policymakers and simplified procedures for funding and approving such projects.”

Siemens Energy electrolyzers are built with proton exchange membrane technology (PEM electrolysis), offering a brief ramp-up time and dynamic controllability that enables integration with intermittent renewable energy supplies. The PEM electrolyzers feature a high energy density while leaving a small environmental footprint with minimal material requirements.

Air Liquide’s Normand’Hy project will be supplied with electrolyzers manufactured at Siemens Energy’s production facility in Berlin. Industrial-scale production of stacks—a key component within the PEM design—will begin in November of this year. Siemens Energy projects manufacture to scale up to 3 GW per year by 2025, enabling the company to provide electrolyzer technology to projects internationally.

Siemens Energy will supply 12 electrolyzers with a total capacity of 200 MW for Air Liquide’s Normand’Hy project. 

Siemens Energy Supplying Electrolyzers for Green Hydrogen Production in France

Operation has commenced at New Fortress Energy’s (NFE) second power plant in Puerto Rico on Sept. 27, 2023—established as part of an initiative sponsored by the U.S. government. The facility in San Juan has an installed capacity of 200+ MW of power generation and is subject to a two-year operation contract, similar to NFE’s 150 MW plant in Palo Seco that became operational in June under the same government program. These plants in San Juan and Palo Seco operate under multi-year contracts with the U.S. government, having fuel, logistics, and power infrastructure completely subsidized.

"NFE is at an inflection point as our core infrastructure projects enter service,” said Wes Edens, Chairman and CEO of New Fortress Energy. “Commercial operation date of San Juan power marks a key milestone. The combination of the San Juan plant and the Palo Seco plant contribute significantly to downstream volumes and terminal earnings beginning in size in Q4 2023. Our projects are entering service after years of buildout, and we now look forward to cash generation, deleveraging, and organic growth opportunities.

“We believe these plants provide significant reliable and efficient power to the Puerto Rico power market, helping to ensure better grid reliability," Edens said.

NFE, in addition to operating a second power plant in Puerto Rico, has announced the completion and sail away of its final rig for FLNG 1: Pioneer II. On Sept. 26, the third and final rig of NFE’s FLNG 1 departed the Kiewit shipyard in Texas for Altamira, joining the two additional rigs for installation and commissioning. The targeted commercial operation date is in late October or early November of this year.

Sailaway of Pioneer II LNG rig; Image Credits: New Fortress Energy

New Fortress Energy has placed a 200+ MW power generation facility in Puerto Rico and completed the Pioneer II rig for FLNG 1.

New Fortress Energy Commences Operation at Puerto Rico Plant, Finalizes Rig for FLNG 1

Rolls-Royce entered a joint venture with Zero Petroleum to further develop its power and propulsion systems by integrating fossil-free synthetic fuels in its aviation, marine, and defense engines.

“Rolls-Royce’s gas turbine technology is a strategic national capability and synthetic fuel is how we can continue to support the warfighter in delivering military advantage. Zero is at the cutting-edge of the synthetic fuel industry and we have been impressed by their rapid progress in the short time they have been in existence; we are confident their team can continue that trajectory,” said Dave Gordon, Rolls-Royce Senior Vice President - UK Defense. “We look forward to a long partnership between Rolls-Royce and Zero to develop and demonstrate the future of sustainable energy across our wide range of complex power and propulsion solutions.”

The agreement will demonstrate Rolls-Royce’s engines using Zero’s range of synthetic fuels, including petrol, diesel, and jet fuel. The data collected from engine testing will be used to satisfy the requirements for an international fuel certification standard. Rolls-Royce expects the integration of synthetic fuels into its aviation, marine, and defense engines to reduce carbon emissions associated with non-synthetic burning.

“The world is facing increasingly urgent demands for fossil-fuel alternatives, and it is vital for all companies to develop the solutions to achieve this,” said Paddy Lowe, CEO of Zero Petroleum. “We have proven the genuine capabilities of our fuels in a wide variety of vehicles–including a light aircraft, a supercar and a chainsaw. As we move toward full certification of our fuels, we are starting to put in place the commercial realization of these demonstrations and aim to be running our first large-scale production plant two years from now.”

The synthetic fuel testing agreement between Zero Petroleum and Rolls-Royce will allow for alternative-fuel innovation in transportation and military applications. In addition to providing renewable fuels for engines in these industries, the partnership will promote the transition to net-zero carbon emissions in the Defense sector for end-users of Rolls-Royce engines.

Zero Petroleum will test its synthetic fuels in various Rolls-Royce engine models to achieve fuel certification standards.

Rolls-Royce, Zero Petroleum Partner to Promote Fossil-Free Synthetic Fuels 

Rolls-Royce and easyJet—partners in developing hydrogen combustion engine technology for aircrafts— are working with Loughborough University in the United Kingdom and the German Aerospace Center, Deutsches Zentrum für Luft-und Raumfahrt (DLR), to test a full annular combustor of a Pearl 700 engine running on 100% hydrogen. The team has shown that 100% hydrogen fuel can be combusted at conditions representing maximum take-off thrust.

Hydrogen testing at DLR, Cologne. Credit: Rolls-Royce

“This is an incredible achievement in a short space of time,” said Grazia Vittadini, Chief Technology Rolls-Royce. “Controlling the combustion process is one of the key technology challenges the industry faces in making hydrogen a real aviation fuel of the future. We have achieved that, and it makes us eager to keep moving forward.”

Pivotal of this achievement was the design of fuel spray nozzles that control the combustion process. This involved overcoming engineering challenges, as hydrogen burns hotter and faster than kerosene. The new nozzles control the flame position using a new system that progressively mixes air with hydrogen to manage the fuel’s reactivity. The nozzles were initially tested at intermediate pressure before the final full-pressure combustor tests.

“We believe hydrogen is the future of short-haul aviation and the success of this test and progress being made demonstrates that this is becoming ever closer,” said Johan Lundgren, CEO of easyJet. “We remain optimistic that it will play a critical role in helping us achieve the ambitious goals we set out in our net zero roadmap.”

The technologies tested will be incorporated into the learning from the Boscombe Down tests as Rolls-Royce and easyJet prepare for a full gas hydrogen ground test on a Pearl engine followed by a full ground test on a Pearl engine using liquid hydrogen.

“This is an outstanding success story, and we are more than happy to have contributed our hydrogen testing capabilities,” said Markus Fischer, Divisional Board Member Aeronautics of DLR. “It was very exciting supporting this technology journey and seeing the burner technology mature in various rigs at our Institute of Propulsion Technology. This underlines again DLR’s capabilities in complex applied research and the achievement, at such a high pace, was supported by our experience in real-scale testing of ground-based gas turbines.”

Recent tests support the combustion element of Rolls-Royce’s hydrogen program after running an aircraft combustor on 100% hydrogen. 

Rolls-Royce’s Aero-Hydrogen Research Project Makes Headway 

On day two of Turbomachinery & Pump Symposia (TPS) 2023, industry professionals presented on 

, offering attendees a review of major turbomachinery in LNG plants, focusing on how compressors, pumps, and gas turbines fit into the various LNG plant cycles, including their integration, operation, and application limits. The tutorial also discussed how to best match turbomachinery for optimal service in LNG plants based on the power, speed, and utility needs of the most common LNG cycles.

The session featured folks from the Elliott Group: Derrick Bauer (Manager), Klaus Brun, Director, Brian Hantz (Senior Engineer), Enver Karakas (Manager), and Brian Pettinato (Manager). They were joined by Rainer Kurz, Manager of Gas Compressor Engineering at Solar Turbines.

The worldwide demand for LNG has risen over the last 20 years, and due to geopolitical instability, this trend is expected to continue in the foreseeable future. LNG plants often use a wide range of turbomachines—including centrifugal compressors, gas turbines, steam turbines, cryogenic pumps, and expanders.

Brun led the session with a preliminary explanation of the LNG, defining it as the large-scale refrigeration of natural gas to achieve liquid form. It is typically liquefied at temperatures ranging from -260°F to -280°F, which varies depending on the type of gas chosen for liquefaction. Originally derived from small-scale refrigeration compressors, modern LNG liquefaction converts a feed gas into a finished fuel product for power generation, heavy-duty transport, alternative fuels, etc.

Klaus Burn of Elliott Group kicked off the discussion at TPS 2023 on Turbomachinery in LNG Plants. Credit: Turbomachinery International 

Brun discussed the ever-growing popularity of LNG production through an analysis of plant scale and output over multiple decades: the largest plants in the 60s and 70s produced a maximum of 2,000,000 metric tons per annum (MTPA), while modern, larger LNG facilities push the boundaries upwards of 7,000,000 MTPA. Despite the rapid growth in average LNG production, the output range of modern LNG plants can still range from as low as 5,000 MTPA to the aforementioned 7,000,000 MTPA.

A series of turbomachinery equipment and processes are required to complete the transfer of the raw material into a viable fuel source, namely compressors, expanders, pumps, a variety of seals, and differing refrigerant methods.

Brun introduced an extensive list of compressors used in LNG applications, as well as the purpose of a compressor in an LNG train. Compressors pressurize and refrigerate the gas to prepare it for storage and transportation as a finished product, but the sheer variety of available compressors allows for unique focuses in LNG production. Examples of compressor models commonly used equipment in modern LNG production include:

This machinery, in addition to the rest of the LNG train, processes natural gas so that it is safe for large-scale industrial applications.

Pettinato gave a complete component breakdown, organized by rotating and stationary parts. The rotating parts of a centrifugal compressor include impellers, sleeves, shafts, coupling hubs, and thrust disks. Stationary parts include end walls, diaphragms, casings, nozzles, labyrinth seals, bearings, end seals, and piston lines. Determining the size of a compressor in an LNG train is vital for optimal efficiency.

“The sizing is determined by the flow and available technology: the larger the amount of flow you have to get through, the more you’d tend to scale up the compressor,” Pettinato said.

Pettinato said the various degrees of testing that a compressor arrangement is exposed largely attempt to identify excessive vibration and assess the performance efficiency of the equipment. Operators may use mechanical running tests, performance tests, or full-load full-pressure inert gas string tests—a costly option—to determine inconsistencies and improve the compressor operation guided by speed, inlet vanes, and suction throttling.

Karakas introduced the role of cryogenic pumps and expanders within an LNG application.

“To use a pump, you have to liquefy the gas,” he said, “So while pumps may be more efficient in terms of transporting fuel, there are a lot of processes that need to first take place to be able to use the pump.”

Pumps for LNG processes transfer and pressurize the fluid while it’s in liquid form, while cryogenic liquid expanders disperse the fluid through a Joule-Thomson (JT) valve. Karakas stressed the importance of proper cooling in an LNG train to avoid issues such as high flammability and improve the overall quality of the gas, citing a submerged motor-driven pump design as favorable for this process because “A submerged motor design has a submerged motor inside the LNG so that the OEM doesn’t need to worry about certification for hazardous areas. Putting the motor in fluids means I don’t have to worry about classifications for hazardous areas. Another benefit is the cooling by the LNG fluid,” he said.

Kurz offered a simple overview of gas turbines, electric motors, and steam turbines. A gas turbine is comprised of a compressor, a combustor, and a turbine section, which provides the power to drive the engine compressor, and whatever power is left over is used to drive a compressor,  pump, or generator. 

The two primary methods of combustion in a gas turbine are conventional combustion and low NOx combustion. The available driver power and speed have to be matched to the LNG compressors. For the best efficiency and economy, the gas turbines should run at maximum power.

The types of materials chosen to construct LNG components must be properly heat treated and field tested to ensure operational safety, according to Bauer, as a poorly tempered metal could cause a catastrophic failure when subjected to high pressures, corrosive gas, or extreme temperatures. Metals with high nickel content, low carbon content, cleanliness, proper heat treatment, and small grain size are optimal for inclusion in LNG equipment.

Bauer delved into atomic structure to explain the advantages of a ductile material for compressor casing design and internal components, “The ability of the planes of atom cubes to slide over each other enables a material to be ductile; it allows the planes to move no matter where the temperature is at,” he said.

Having established the optimal atomic structure of an LNG metal and provided a list of sought-after material requirements, Bauer advised the audience to avoid metals with two specific qualities: high carbon content and low alloy content. Carbon steels and low alloy steels are susceptible to the “ductile-to-brittle” transition, in which a material exposed to LNG processes over time begins to weaken, crack, erode, and eventually fail. Testing of the material’s toughness is required prior to its integration into components, so OEMs often conduct Charpy v-notch impact testing to ensure the material can endure massive amounts of stress. The test applies an immediate downward force to the material in an effort to shatter it, then data is collected to determine the resistance of the material in an LNG application. Conducting material testing is perhaps the foremost step in preventing catastrophic failure at LNG plants.

On day two of Turbomachinery & Pump Symposia (TPS) 2023, industry professionals presented on Turbomachinery in LNG Production Plants.

TPS 2023: Turbomachinery in LNG Production Plants

GE Vernova’s Hydro Power business upgraded one of six Kaplan turbines and generator units at the Qairokkum hydropower plant in Tajikistan. The upgrade increased the capacity of the 21 MW unit to 29 MW, and it is now connected to the grid. All five remaining units will have capacity increased from 21 MW to 29 MW, elevating the total capacity of the Kaplan-powered plant to 174 MW.

"The work done in Tajikistan on making hydropower plants climate resilient is essential for our industry's future and the global energy transition that we all support. We are honored to contribute to this project and for the completion of the first unit’s rehabilitation,” said Bodo Mayer, Hydro Power EMEA Leader, GE Vernova. “This boost in capacity sets the stage for even greater clean-energy production as we prepare to bring five more units online."

Qairokkum hydropower plant is a 60-year-old facility located on the Syr Darya River, providing electricity for 500,000 people within the Sughd province. GE Vernova’s refurbishment process will extend the lifetime of Qairokkum and increase capacity for the delivery of clean, sustainable energy to Tajikistan.

In addition to the refurbishment provided by GE, Tajikistan-based power company Barki Tojik has been selected to assist in the upgrading of six Kaplan units at Qairokkum. The refurbishment process entails the upgrade of six turbines and generators, as well as balance plant and site supervision for the delivered equipment. GE Vernova leads the collaboration, along with Barki Tojik and Cobra—a division of Spain’s ACS Group—to refurbish the Qairokkum hydropower plant. Full modernization of the plant is expected to be completed midway through 2025.

GE Vernova’s Hydro Power business began the process of upgrading six Kaplan units at the Qairokkum plant in Tajikistan.

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