In this episode of the TurboTime podcast, we talk to Carolyn Weber, the Director of Application Engineering at Cadence Design Systems, about computational fluid dynamics (CFD). Weber 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 Weber, 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.

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

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. 

Part 2: Roundtable Q&A: Obstacles Preventing 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!

 features a roundtable of experts and OEMs to offer their points of view and insights into hydrogen’s current and projected role in the energy sector. To further the discussion on hydrogen, a collection of authors from the Elliott Group, Southwest Research Institute, and Venture Global LNG reviews the prospects and challenges of hydrogen compression: Compared to natural gas pipelines, for equivalent energy volumes, hydrogen compression will likely require 5 - 6 times the power, making efficiency in design and the overall footprint requirement key aspects when evaluating various compressor technologies.

Our fall issue also includes coverage from the American Society of Mechanical Engineers (ASME) Turbomachinery Technical Conference & Exposition 2023, which celebrated its 67th year. Our coverage includes a look at gas turbines’ role in decentralized energy systems, technologies for a sustainable future, the potential of hydrogen, and more.

Key Considerations & Risks in the Operation and Control of Compressors

, discusses the factors and components—such as disturbance speed, degradation, and the surge curve—that affect the efficiency and functionality of a turbocompressor. And the Myth Busters break down the two types of centrifugal compressor impellers—closed (shrouded) and open (unshrouded)—and why a shroud is necessary given that the vanes are essentially where the energy transfer happens.

As hydrogen continues to dominate discussions about decarbonization and energy security, the fall Sept/Oct 2023 issue of Turbomachinery International features insights from a roundtable of experts and OEMs into hydrogen’s current and projected role in the energy sector.



Turbomachinery International: Sept/Oct 2023

Commonwealth LNG and EQT have structured a heads 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.

Articles

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

Podcasts

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.

GE Vernova to Fulfill Amprion’s Bulk Order for Power Transformers

Carbonvert and Castex Carbon Solutions have followed through on an operating agreement with Louisiana’s state government to develop a 24,000-acre plot of land to permanently sequester CO

. Castex will combine its subsurface operational expertise with Carbonvert’s experience in carbon capture and storage (CCS) projects to develop the Cameron Parish CO

“Castex and Carbonvert look forward to developing the first offshore CO

 storage hub in Louisiana,” said Castex EVP & CFO, Aaron Killian. “Our Cameron Parish project combines premier geologic storage attributes with existing midstream infrastructure to provide a range of tailored solutions to the adjacent industrial corridors in need of economically viable CO

Castex has conducted a series of technical and subsurface studies to determine the carbon storage capacity at the Cameron Parish site. The hub will have a storage capacity of more than 250 million metric tons of CO

 and will sequester carbon from local industrial emitters, primarily ammonia and LNG facilities. Carbonvert, or the “JV Partners”, will seek opportunities to repurpose existing pipeline infrastructure to support the CCS hub.

The JV Partners structured a 50/50 joint venture agreement to identify and advance CCS projects within Louisiana in August 2022. Carbonvert, through the development of the Cameron Parish CO

 hub, looks to promote economic and environmental benefits in the Cameron and Calcasieu Parishes. Castex will serve as the primary operator for carbon sequestration at the Cameron Parish hub.

"We firmly believe our Cameron Parish offshore project will help shape Louisiana’s low carbon future,” said Carbonvert CEO, Alex Tiller. “Our CCS project will strengthen the local economy via funds from the newly adopted Louisiana Act No. 378, via the Federal Justice40 requirements, and by attracting new low-carbon focused businesses and related jobs. It will also provide a solution to clean up existing regional CO

 emissions, which is a win for everyone.”

The joint venture executes an operating agreement for offshore carbon capture and storage at the Cameron Parish CO2 hub.

Carbonvert, Castex Execute Agreement for Offshore CO2 Storage

Kathairos Solutions, within the first year of the unit’s commercial availability, has reached a methane reduction milestone with its methane elimination system. The installation of 1,000 Kathairos units has offset methane emissions by 40,000 metric tons of CO

The methane elimination system relies on the use of liquid nitrogen in remote wells to operate pneumatic equipment—citing it as a non-polluting fuel source in comparison to methane. Nitrogen has a gas equivalence ratio (GER) of 1.2764, which means that each unit of nitrogen offsets 1.2764 units of methane that would’ve been vented in its stead. Methane is a greenhouse gas (GHG) with a global warming factor 28 times higher than CO

Kathairos’ solution will allow Alberta to match a target set by the Emissions Reduction and Energy Development Plan: a carbon-neutral economy by 2050. A liquid nitrogen pneumatic power drive system allows methane reduction targets to be satisfied by eliminating the use of methane entirely.

Liquid nitrogen-operated pneumatic venting produces zero onsite emissions, mitigating an issue associated with remote well sites. The system provides a clean, reliable fuel source for pneumatic devices—which comprise up to 40% of upstream oil and gas methane emissions.

Kathairos Solutions has entered pilot and commercial operations with over 60 North American oil and gas producers, spanning gas basins in Colorado, Wyoming, Utah, Texas, New Mexico, Oklahoma, Louisiana, Pennsylvania, West Virginia, Ohio, and the Western Canadian Sedimentary Basin of British Columbia and Alberta.

The methane elimination systems provided by Kathairos have removed 40,000 metric tons of CO2 equivalent across 1,000 units.

Kathairos Solutions Hits Methane Offset Milestone with Sale of Elimination Units

bp has announced the appointment of Kate Thomson as interim Chief Financial Officer (CFO), shortly after last week’s election of Murray Auchinloss to serve as interim Chief Executive Officer (CEO). Kate Thomson is bp’s former senior vice president and oversaw financing for production and operations, as well as commercial partnerships for the business globally.

“Kate’s experience and skills make her ideally suited to take on the role of interim CFO. She brings deep technical knowledge together with a detailed understanding of bp and has a track record of leadership across our finance function. I look forward to working alongside her as we continue to deliver bp’s strategy,” said Murray Auchinloss, interim CEO, bp.

Kate Thomson, interim CFO at bp; Image Credits: LinkedIn

Prior to her appointment as interim CFO, Kate Thomson served 19 years with the company in multiple senior financial positions, including group treasurer and head of group tax.

Thomson, before joining bp in 2004, held tax roles at professional services firms such as Ernst & Young and Charter plc. She has been a board member for Aker BP the past 7 years and serves on the board for numerous bp Group companies, utilizing her skills as a qualified chartered accountant.

Current board member and 19-year veteran of the company, Kate Thomson, has been appointed as bp’s Interim CFO.

bp Elects Kate Thomson to Serve as Interim Chief Financial Officer

GE Vernova’s Digital Business announced a preliminary release of its carbon emissions management software: CERius. The program provides precise data and abatement planning capabilities. CERius is now available as a pilot software for current GE Vernova customers, and full availability is slated for early 2024.

“There are increased expectations from regulatory bodies, investors, and companies that have made public net-zero commitments that require more rigor to disclose accurate emissions data,” said Amy Cravens, research manager, ESG Management and Reporting Technologies at IDC. “Companies look to carbon emissions management technologies like GE Vernova’s CERius software to help improve scope 1, 2, and 3 data accuracy and reporting, in addition to measuring abatement planning strategies.”

GE’s software will measure, manage, and operationalize insights from greenhouse gas (GHG) data collection to help companies track carbon emissions goals. The program is capable of driving carbon reduction by offering scenario analysis, team collaboration, and standardized reporting based on GHG protocols.

CERius performs insight analytics with the assistance of integrated artificial intelligence (AI), enabling companies to establish strategies for:

Decarbonization & Activation: Companies can simulate carbon abatement scenarios to fine-tune management strategies. CERius users can verify the efficacy of management initiatives such as renewable energy integration, energy efficiency measures, and carbon offset projects to identify an optimal pathway for hitting net-zero targets.

Multi-team Collaboration: The program enables transparent cross-functional visibility across executives, managers, and operators to simplify audit preparations, eliminating the barriers of information within departments. Data quality alerts will be provided for the company to resolve.

Emissions Tracking: Collection of data is automated and data retains increased accuracy to measure and monitor carbon emissions across company assets. CERius uses real-time data visualization and reporting capabilities for companies to accurately manage emissions reduction programs. Scope 1 emissions reporting is improved by 33% using gas fuel systems and fuel flow.

Help Compliance Reporting: Compliance management will be simplified through CERius’ automated data collection and analysis of emissions data. Increased data accuracy will help energy companies cooperate with regulatory agencies for adherence to decarbonization programs.

Digital Twin technology allows CERius to abandon estimates in favor of accurate results by calculating an outcome using multiple variables, such as the heat rate, based on a gas turbine at a single point in time. Greater accuracy enables operators and stakeholders to make data-based decisions regarding carbon management initiatives.

“We believe that we are in a unique position to help customers decarbonize their operations, as GE Vernova’s technology helps generate roughly 30% of the world’s electricity,” said Scott Reese, CEO of GE Vernova’s Digital business. “As an OEM, we’ve had the opportunity to directly validate that CERius provides 33% greater accuracy for scope 1 emissions on today’s gas turbines. That direct validation gives us great confidence that we can help utilities in reporting and reducing their emissions.”

The software is engineered to accurately detect, measure, and manage carbon emissions from gas turbine operations. 

GE Vernova Unveils AI-Based Carbon-Tracking Software: CERius

ConocoPhillips has signed a contract to secure more regasification capacity at the Gate LNG terminal at the Port of Rotterdam in the Netherlands. The Gate Terminal B.V.—live for commercial operation in 2011— is an LNG joint venture between Vopak and Gasunie, supplying processed natural gas to the Netherlands and Europe’s northwest region. The 15-year throughput agreement for 1.5 million tonnes per annum (MTPA) begins in 2031.

LNG terminal at the Port of Rotterdam, Netherlands; Image Credits: Port of Rotterdam

“Adding capacity at the Gate LNG terminal fits well with our efforts to deliver reliable, lower-carbon energy into Europe from highly competitive LNG supply,” said Bill Bullock, Executive Vice President and Chief Financial Officer of ConocoPhillips. “Expanding our LNG footprint with agreements like this further enhances a balanced, diversified, and attractive portfolio as we progress our global LNG strategy.”

This agreement expands ConocoPhillips’ portfolio of LNG assets, joining resource locations in Qatar and Australia, offtake and equity in the Port Arthur LNG Phase 1 project, regasification at the German LNG terminal, and offtake from Mexico Pacific’s Saguaro LNG export facility.

The commercial agreement secures additional regasification capacity at the Gate Terminal B.V. LNG hub in the Netherlands.

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