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 discusses what areas CFD could improve in the aerospace industry and the challenges it faces in terms of the turbomachinery industry.

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

Over the years, we have seen requests to drive centrifugal compressors with a combination of gas turbines and electric motors in various configurations. These are often referred to as hybrid drives or dual drives, or in many cases, the electric motor is seen as a helper drive. Some of the confusion comes from the fact that these combinations vary and therefore so does the architecture of such drives. The combination of electric motor and gas turbine drivers to power a centrifugal compressor offers opportunities to take advantage of the individual strengths of each drive in a single package.

In these combinations, the gas turbines can be single shaft, offering very little operating-speed flexibility, or two shaft. On the electric side, we see variable speed motors (as variable frequency drives, although variable speed gearboxes are feasible), as well as electric machines that can be operated as motors or generators. The drivers can also be rated for similar or different power. For certain applications, constant-speed electric motors could be used. The architecture of these drives usually, but not always, requires a clutch between the respective drivers and the compressor.

The reasons for employing a dual-drive configuration are just as numerous as the different configurations. Single-shaft gas turbines, when driving compressor trains in LNG applications, for example, require sizeable starter motors because the starter not only has to accelerate the gas turbine but also the entire compressor train. The starter motor needs to have variable speed capability while also using 25% of the driver power. (That does not sound like a lot, but it would be a 25 MW motor for a 100 MW gas turbine) These motors can also be used to augment the gas turbine power on hot days, and a clutch allows the motor to disengage when it’s not needed. In similar applications, with two-shaft gas turbines, an electric motor can augment the power of the gas turbine, or it can be used as a generator to use surplus power for the generation of electricity. This looks attractive, but often the added complexity cannot be justified economically.

Other uses of hybrid trains seek to take advantage of low-cost electricity during certain times, operating the electric motor (with a disengaged gas turbine) when operating costs would be lower than gas-fired operation. Similar arguments can be made if emissions avoidance, together with high supply security in case of electric grid problems, are sought. In cases like this, the electric motor would be sized for similar power as the gas turbine, and the operation would see either the gas turbine or the electric motor but not both in operation. Therefore, one or two clutches are needed. Generally, to avoid tremendous windage losses, the power turbine of a gas turbine should not spin if the gas turbine does not make power. This means a minimum of one clutch is required.

In this circumstance, like in many other applications where the opportunity is to only use one of the drivers at a time, a centrifugal compressor that can be driven from both shaft ends is advantageous.

Economically, the case for dual drives is often difficult to make because essentially the project carries the cost of an extra driver, and the clutches and train become very complex, including control systems, lube oil control, and the torsional train behavior. Creating electricity to feed into a grid is not often financially rewarding. If the train is part of a facility that can consume the extra electricity, the economics change. The goal of supply security for predominantly electric applications can also be met by electric-only drives with a gas turbine-driven generator. This can include mobile, deployable gas-turbine-driven power generation systems.

“For certain applications, constant-speed electric motors could be used. The architecture of these drives usually, but not always, requires a clutch between the respective drivers and the compressor.”

There are other possible turbomachinery train combinations, including steam turbine drivers, but these are usually only employed in applications where excess steam is available, such as refineries or olefin plants. Similarly, combinations of steam turbines with motor drivers have been successfully employed in petrochemical applications where plant steam is abundant.

So, there are potential benefits to dual drives, but the decision needs to be carefully measured about the goals the operator wants to achieve, and how much added complexity is acceptable.

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 Incorporated 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.

Dual drivers—a combination of an electric motor and a gas turbine to power a centrifugal compressor—play on the individual strengths of each driver in a single package.

Myth Busters: Dual Drives Always Work Better!

Speakers from the Elliott Group presented on 

Applications and Technology for Hydrogen Compression and Pumping, 

including benefits, challenges, and solutions. 

Technical sessions at Turbomachinery & Pump Symposia (TPS) 2023 kicked off on Tuesday, Sept. 26. Speakers from the Elliott Group presented on 

Applications and Technology for Hydrogen Compression and Pumping

. The group cycled through a series of benefits, technical challenges, and requirements for compressing hydrogen.

Marybeth McBain, Manager at Elliott Group, started the technical session with a brief description of blue, green, and pink hydrogens and the method used to produce each gas: Green hydrogen utilizes curtailed renewable electric power via electrolysis, while blue and pink hydrogen require carbon sequestration and nuclear power, respectively. These iterations of hydrogen fuel can be stored for longer periods, but issues regarding cost, wear-and-tear on current pipeline assets, and embrittlement require a careful approach to hydrogen.

McBain addressed the cost of hydrogen production, as, as of now, even with tax credits, it’s expensive to produce at scale. However, she cited the initial price hikes of LNG, in which plant operators were worried LNG was too expensive. But “The industry stepped up and started looking at ways to power plants more modular to offset construction costs and to standardize equipment to lower manufacturing costs,” McBain said. After which, the cost of LNG came down. She encouraged attendees to consider this when it comes to the cost of hydrogen, “and how technology can catch up and give us that cost-competitiveness,” she said.

McBain also addressed secondary concerns regarding what percentage of hydrogen would actually make a meaningful difference in carbon emissions, as using 30% hydrogen doesn’t reduce your use of natural gas by 30%; in fact, it would only reduce natural gas by 15%. She also pointed out the impact hydrogen has on carbon-steel blends (U.S. pipelines are made of several different blends) and compressor requirements—each of which must be considered when transitioning the energy economy to a hydrogen-based model.

Karl Wygant, Senior Manager at Elliott Group, tackled the challenges presented by the compression of a light gas such as hydrogen. Hydrogen compression typically encounters issues with sealing, embrittlement of materials and coating, and temperature constraints. Titanium is chosen for compression at high speeds for most gases, but hydrogen’s corrosive properties present challenges for titanium, making it unsuitable for hydrogen applications.

“Titanium is very sensitive to hydrogen embrittlement, so it’s not acceptable for hydrogen applications,” Wygant said. “What does work well is some of the aluminum series; they show good resistance to hydrogen embrittlement.”

Wygant detailed the hydrogen-resistant properties of aluminum as favorable for hydrogen compression applications, although the material encounters issues of high temperature as tip speed increases. Newer impeller designs or advanced material integration may reduce the issues encountered with hydrogen compression, such as gas corrosion or the lack of materials suited for increased tip speed. Wygant offered a series of potential solutions to the hydrogen compression dilemma, including integrally geared compressors for higher tip speed and the introduction of inter/pre-coolers to manage an increase in temperature. Aluminum may be integrated in favor of titanium with a number of coolers to regulate temperature, addressing a primary challenge in compressing hydrogen for industrial-scale operations.

Enver Karakas, Director at Elliott Group, rounded off the technical session with a detailed explanation of pumping hydrogen and ammonia. Hydrogen requires a much lower liquefaction temperature than ammonia, raising the cost of this process in comparison to the liquefaction of other gases. Handling liquid hydrogen presents a host of challenges, as the gas is highly flammable and corrosive, and the minuscule molecular size causes hydrogen to leak from the system into the atmosphere. Karakas offered a number of solutions to counteract the natural properties of hydrogen, such as a submerged motor design and material consistency to minimize stresses on the components within the system.

Liquid ammonia runs into compatibility issues with copper alloys, e.g., bronze bushing, etc. Karakas addresses ammonia leakage by introducing the concept of, although not new, magnetic couplers, “The way we do handle this is through magnetic couplers. The whole idea is to seal the motor side from the hydraulic side, transferring the torque to the hydraulic side with a magnetic coupler to ensure that no ammonia is leaking into the motor section,” said Karakas.

The director closed the technical session with some final remarks about appropriate liquid expanders and pumps for hydrogen liquefaction. Along with considering magnetic couplers for the sealing of a system, Karakas recommended the use of cryogenic expanders to increase liquid production by 3-5%. Liquid expanders for hydrogen liquefaction achieve higher efficiency through improved cooling and energy recovery systems, counteracting the properties of hydrogen and ammonia that would typically make this process dangerous or ineffective.

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TPS 2023: Compressing and Pumping Hydrogen - Applications and Technologies

The 2023 Turbomachinery & Pump Symposia (TPS) in Houston, TX, kicked off with a welcome address delivered by Dr. Michael Webber, professor at the University of Texas at Austin and John J. McKetta Centennial Energy Chair in Engineering. The address set the stage for this year’s display of turbomachinery and pump technology and highlighted the latest trends in the energy landscape and turbomachinery.

Dr. Michael Webber gave the keynote address on opening day of TPS 2023. Credit: Turbomachinery International 

Dr. Eric Petersen, Director of the Turbomachinery Laboratory at Texas A&M University, opened the keynote address with some helpful notes for the audience: keeping up with TPS 2023 through the designated app, attending the end-of-conference banquet, and submitting abstracts for next year’s symposia. Dr. Petersen closed his brief introduction with an outline of the Asia Turbomachinery & Pump Symposia at the Kuala Lumpur Conference Center in Kuala Lumpur, Malaysia, May 13-16, 2024. This extension of TPS is expected to garner over 2,000 attendees and exhibitors, displaying an international focus on the development of turbomachinery for the future.

Dr. Petersen handed the role of lead keynote speaker to Dr. Webber, who discussed the importance of turbomachinery in the modern world, particularly in the energy generation sector. The history of rotating technology and the predecessors to modern gas/steam turbines were laid out by Dr. Webber, citing the efficiency of continuous rotating motion in power generation as superior to back-and-forth batch power generation. He said that the world of turbomachinery, including gas turbines, will remain relevant given the stability it offers to the grid.

Dr. Petersen highlighted a few trends he sees shaping the future:

New designs that include smaller (and simultaneously, larger) turbines

Turbines that support higher temperatures

Turbines that support a wider range of fuels

Fuel flexibility that can support newer fuels such as ammonia and hydrogen as well as blends: bio-methane + hydrogen, for example

Cooling channels inside the blades (difficult, but possible)

Although the industry is buzzing with talks of hydrogen because it burns clean, challenges with handling and leakage, to name a few, complicate matters. Dr. Petersen said using a 20% hydrogen blend is fine, but higher percentages create problems. He also mentioned ammonia, which reduces emissions but increases energy usage.

Dr. Webber detailed a future in which turbomachinery integrates clean-burning fuels at ever-increasing efficiencies, separating itself from antiquated technologies incapable of fuel flexibility and carbon minimization. Gases like hydrogen, ammonia, nitrogen, and methane will go hand-in-hand with carbon sequestration to develop a power generation sector that is cleaner and more efficient than technologies of decades past.

He closed the keynote address with words of encouragement for those in the field of turbomachinery, deconstructing notions of doubt from those who believe that turbines have no place in the future of energy. Dr. Webber advised those in the crowd to keep developing turbomachinery to counter issues in modern energy generation.

The 2023 Turbomachinery & Pump Symposia in Houston, TX, kicked off with the keynote address by Dr. Michael Webber.

TPS 2023 Keynote: Turbines Will Continue to Play a Role in Power Generation, New Energy Landscape

Mitsubishi Power announced Takasago Hydrogen Park, located at Mitsubishi Heavy Industries’ (MHI) Takasago Machinery Works, began full-scale commercial operation. Electrolysis hydrogen production will bolster product reliability through hydrogen co-firing and hydrogen-operated gas turbines and expand its offerings with the introduction of hydrogen production technologies.

The validation of hydrogen-fueled equipment will be conducted at the T-Point 2 combined-cycle power plant facility using a Mitsubishi Power J-series air-cooled (JAC) gas turbine (450 MW class) and small-to-mid-sized H-25 gas turbines (40 MW class). Hydrogen produced at Takasago Hydrogen Park will be used for the validation of 30% hydrogen co-firing at T-Point 2 and is slated for completion by the end of the year. Hydrogen firing at 100% for the H-25 gas turbine will be validated in 2024.

Takasago Hydrogen Park is separated into sections based on the following hydrogen-related functions: hydrogen production, storage, and utilization. The production area is headed by HydrogenPro AS of Norway, manufacturing alkaline electrolyzers with a hydrogen production capacity of 1,100Nm3/h. Processed hydrogen will be stored in equipment with a total capacity of 39,000 Nm3.

Mitsubishi Power is developing hydrogen production technologies such as solid oxide electrolysis cells, anion exchange membrane water electrolyzers, and turquoise-hydrogen production that generates zero CO

 emissions through the pyrolysis of methane into hydrogen and solid carbon. Mitsubishi will conduct verification and validation of these technologies in sequential order. Following the development of these electrolysis technologies at the Nagasaki Carbon Neutral Park, the company intends on validating the hydrogen production of these technologies at Takasago to prepare for commercialization.

Electrolysis hydrogen production has entered full swing at the integrated hydrogen validation facility in the Hyogo Prefecture, Japan.

Mitsubishi Power’s Takasago Hydrogen Park Begins Full-Scale Production

The NextDecade Corporation’s subsidiary, Rio Grande LNG (RGLNG), is subject to a credit agreement with lenders for $356 million in senior loans to fund a portion of Phase 1 at NextDecade’s 27 million tonnes per annum (MTPA) Rio Grande LNG export facility.

A one-time advance for $356 million was granted by the lender group on Sept. 15, 2023, resulting in the reduction of commitments outstanding under RGLNG’s current term loan facilities for Phase 1 from $11.1 billion to below $10.8 billion. The loans will mature in July 2033 and will gather interest at a fixed rate of 6.72%. These loans will be ranked on equal footing to RGLNG’s existing loan facilities—a $500 million working capital facility and $700 million of 10-year senior notes granted during the final investment decision for Phase 1.

NextDecade’s secured funding adheres to the strategy outlined for Phase 1 of RGLNG: extending and staggering debt maturities, diversifying sources of capital, reducing bank capital over time to provide capacity for future LNG expansions, and minimizing exposure to interest rates. Currently, RGLNG’s fixed-rate debt and executed interest rate swaps have limited the exposure to volatile interest rates for more than 80% of the debt expected to be incurred during Phase 1 construction.

The funding will be put toward the financing of NextDecade’s LNG trains at the Rio Grande LNG export facility in Brownsville, TX. 

NextDecade’s Rio Grande LNG to Receive $356M in Senior Loans

This week kicks off the 2023 Turbomachinery & Pump Symposia (TPS) in Houston, TX, held at the George R. Brown Convention Center from Sept. 25 – 28, with short courses starting today, Monday, and the exhibition floor and technical sessions kicking off on Tuesday. Topics for this year’s program include maintenance, new technologies, reliability, troubleshooting and instruction on emerging designs, and best practices supported by case studies.

TPS 2023 is host to more than 270 turbomachinery and pump companies that will be showcasing full-size equipment, new technology, and emerging industry trends. The symposium features a continuing education program that spans the oil and gas, petrochemical, power, aerospace, chemical, and water industries.

A few new events at this year’s show include a social media scavenger hunt, Women in TPS luncheon, a book signing with Dr. Dara Childs, author of 

Turbomachinery Rotordynamics with Case Studies

, and a tour of the Lab at Texas A&M University in College Station on Thursday—attendees can see how the lab is equipped and what research projects are in progress. The conference is also featuring the Innovation Presents Stage, located in the front corner of the exhibit hall, which gives exhibitors a platform to present 20-minute commercial presentations.

Michael Webber, Ph.D., a professor at the University of Texas at Austin and John J. McKetta Centennial Energy Chair in Engineering, will kick off the first day of technical sessions during the keynote address on Tuesday, Sept. 26 at 8 a.m.

Also on Tuesday, folks from the Elliott Group and Aramco are hosting a tutorial on 

. On Wednesday, Sept. 27, speakers from Siemens Energy and two industry consultants are presenting a tutorial on 

Troubleshooting Aero-Performance Issues in Centrifugal Compressors

, which will provide guidance on how to resolve aero-performance-related issues both in the field and on an OEM production test stand. The discussion includes:

establishing effective communications between the parties involved in resolving the issue

understanding the scope and/or history of the problem

accumulating pertinent data, e.g., geometric, process, dates/times, etc.

application of advanced analytical tools to help identify possible root causes and assess solutions

Experts from Elliott Group and Solar Turbines are also presenting on 

Turbomachinery in Liquified Natural Gas Production Plants

. Given that the global demand for LNG has dramatically risen over the last 20 years, this trend is expected to continue in the foreseeable future. The tutorial will review major turbomachines, such as turbines, compressors, pumps, and expanders, in LNG plants, focusing on how compressors, pumps, and gas turbines fit into the various LNG plant cycles and their integration, operation, and application limits. Presenters will also discuss 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 Turbomachinery & Pump Symposia in Houston, TX, held at the George R. Brown Convention Center, runs Sept. 25 – 28, 2023. 

2023 Turbomachinery & Pump Symposia Kicks Off in Houston

Commonwealth LNG and EQT have structured a head of agreement (HOA) for the supply of 1 million tons per annum (MTPA) of LNG on a take-or-pay basis for 15 years. This agreement additionally covers the associated gas supply to Commonwealth LNG’s facility in Cameron, LA.

"We are very pleased to add a US producer of EQT's stature to Commonwealth's customer portfolio,” said Commonwealth LNG Founder and Executive Chairman Paul Varello. "This agreement will connect EQT's vast natural gas assets to Commonwealth's LNG facility, thus creating a value chain from wellhead to water. Accessing EQT's natural gas production, which achieved a 20 percent year-over-year reduction in Scope 1 and Scope 2 greenhouse gas emissions, supports Commonwealth's goal of achieving environmental standards."

A final investment decision for the project is expected to be delivered in Q1 2024, with the initial LNG delivery expected in 2027. The construction schedule will be fast-tracked through a modular approach and the fabrication of major components occurring offsite.

The agreed-upon terms of the HOA would take effect at the start of the facility’s commercial operation. Final terms of the agreement are pending further negotiations between parties.

One million tons per annum of LNG will be supplied by EQT for Commonwealth LNG’s facility in Cameron, LA.

Commonwealth LNG, EQT Enter Heads of Agreement for LNG Supply

Verdagy has announced the opening of new manufacturing facility in Newark, CA, containing more than 100,000 sq. ft. of space to build hydrogen electrolyzer technology.

The Silicon Valley facility will manufacture advanced water electrolyzers in vast quantity, beginning commercial operation in Q1 2024. Verdagy intends on doubling its total number of employees by next summer to support operation at the electrolyzer facility.

"We are focused on building an entire renewable hydrogen ecosystem in California to achieve our climate goals, including the crucial step of manufacturing electrolyzers," said Dee Dee Myers, Senior Advisor to Governor Newsom and Director of the Governor's Office of Business and Economic Development. "Verdagy's decision to expand its footprint here reflects California's strength in creating new markets, enabling the creation of clean-energy jobs while solving our most existential challenges with the technology of the future."

Verdagy's CA electrolyzer production facility; Image Credits: Verdagy 

Verdagy is on track to comply with the DOE’s goal of a $2/kg cost of hydrogen by 2026 through the optimization of manufacture. The development of manufacturing techniques, cost reductions, and product innovations allows Verdagy to implement a scalable manufacturing design to level the cost of hydrogen.

The opening of Verdagy’s California facility aligns with the state’s priority to develop hydrogen and receive federal funding to become a hydrogen hub, as detailed in Governor Newsom’s Hydrogen Market Development Strategy.

Last month, Verdagy partnered with Temasek and Shell Ventures to close a $73 million Series B funding round. Verdagy will utilize the funds for the launch and commercialization of its eDyanmic 20 MW electrolyzer module—the selected unit for systems at 200 MW and beyond.

"Our new Silicon Valley manufacturing facility will accelerate the production and cost reduction of our eDynamic 20 MW electrolyzer module, which is the basic building block for delivering larger, gigawatt-scale plants," said Marty Neese, Verdagy CEO.

Verdagy aims to design a facility that will become the basis for larger production factories built elsewhere, supporting the rapid manufacturing expansion goal set by the company. An existing location in Moss Landing, CA, will continue to conduct R&D and commercial pilot-plant operations to support Verdagy’s customers.

Verdagy’s facility will produce water electrolyzers at increased scale, beginning operations in early 2024.

Verdagy Opens CA Manufacturing Facility for Hydrogen Electrolyzer

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Amprion GmbH, in an effort to kickstart Germany’s energy transition and replace older power assets, has awarded GE Vernova’s Grid Solutions business with a contract for 12 400 kV power transformers. These transformers will be built at GE Vernova’s grid facility in Monchengladbach, Germany.

“As utilities transition to renewable energy sources, electrical transmission grid operators continue to face increasing demand and complexity. Today’s transmission systems are expected to carry bulk power in ways they never originally were designed to accommodate,” said Philippe Piron, President and CEO of GE Vernova’s Grid Solutions business. “We are proud to support Amprion, a long-time valued GE Vernova customer, to reinforce their 400 kV electrical grid. Our power transformers will help them increase capacity and maintain stability on their network.”

GE's 400 kV power transformer; Image Credits: GE Vernova

Equivalent to more than 5,000 MVA, this order of GE power transformers is capable of supplying electricity to the 29 million people living within Amprion’s grid. The high voltage, 11,000 km-long grid stretches from Lower Saxony to the Alps, covering an area that’s responsible for one-third of Germany’s economic output. GE Vernova plans on delivering the power transformers over the course of two years, from 2025-2027.

GE Vernova’s fleet of power transformers will be replacing modules installed in the 1970s, allowing Amprion to take advantage of updated grid technology and the integration of renewables. The advanced transformers will be installed at nine substations along Amprion’s grid, joining a fleet of previously purchased GE grid products such as switchgears, gas-insulated switchgears, mechanically switched capacitors, and additional transformers. GE Vernova has been fulfilling orders from Amprion since 2003.

Amprion has awarded the supply contract to GE Vernova for the production and delivery of 12 400 kV transformers.

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