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s spring edition of the year is here: March/April 2025. Maintenance and repair are always hot topics in the turbomachinery industry, and our spring issue highlights this. What’s cool is how data, smart tools, AI, and advanced technologies are impacting this field. In our cover story, Assistant Editor James Cook updates readers on how the field is evolving and improving inspections, providing more valuable data and insights, and enhancing efficiencies.

“Using AI, we’re able to gather, analyze, and act on critical inspection data much faster and at much greater volumes previously impossible,” Nicole Jenkins, Chief MRO Engineer at GE Aerospace, said. “That’s why at GE Aerospace we prioritize scrutinizing and scrubbing the data to ensure it is trusted and fully transparent.”

Along the same lines, Anthony Brough, Principal Consultant of Dora Partners & Company, and associates from Liburdi Turbine Services authored an insightful article on how leveraging visioning systems and rule-based knowledge, while not AI, provides repeatable and reliable repairs for the aerospace and industrial gas turbine industries.

According to the authors: “In a world where the availability of skilled specialists is increasingly sparse, leveraging visioning systems and rule-based knowledge to provide repeatable and reliable repairs is both possible and imperative.”

This issue also includes a short recap of POWERGEN International 2025. Full coverage and highlights are available at 

, where you can check out our video interviews, detailed session coverage, and more.

“Power generation is having its day again. After a couple of decades of flat demand, we’re seeing utilities beef up their projections in response to increased demand from data centers, onshoring from manufacturing, and increased electrification,” said Kevin Clark, Senior Content Director of Clarion Events. “There’s still a mission to decarbonize, but the wrinkle is maintaining reliability.”

What’s most exciting is our latest Turbo Tour of Texas A&M’s Turbomachinery Lab, which takes readers to College Station, Texas, to give them an inside look into the lab’s history, current research, the origin of the Turbomachinery & Pump Symposium, and exclusive interviews and insights from professors and staff.

We’ve already started rolling out our video interviews and exclusive Q&As. 

Dr. Adolfo Delgado, Associate Professor of Mechanical Engineering at the University’s Turbomachinery Laboratory

, speaks about the latest research being conducted on rotating equipment systems and components and relevant trends and changes during our video interview. Our 

Q&A with Dr. Eric Petersen, Professor of Mechanical Engineering and Director of the Turbo Lab

, discusses the facility’s latest research, trends in propulsion and combustion, and the university’s new addition: the Propulsion and Energetics Research Laboratory. Tomorrow another video interview with Greg Gammon, Director of Global and Corporate Partnerships, goes live!

Also in this issue, the Myth Busters debunk the myth that torsional vibrations are “no problem”—although torsional vibrations in turbomachinery trains are usually well-controlled, Klaus Brun and Rainer Kurz urge readers to address issues proactively during the design process to avoid significant damage.

“One of the challenges with torsional vibrations is that they are often difficult to detect,” Brun and Kurz said. “Most turbomachinery trains are not instrumented to monitor torsional vibrations, and typical torque meters used for power measurements cannot resolve them. As a result, torsional issues may remain unnoticed until a shaft or coupling fails, often causing significant damage and disruption.”

Amin Almasi’s Turbo Tips column explains how renovating modern dry gas seals and their systems increases reliability.

The March/April issue focuses on maintenance and repair and how data and AI are impacting the field and highlights our latest Turbo Tour.

Featured

Turbomachinery International: March/April 2025

After experiencing a 12.6% increase in MW capacity and a 3% increase in total units sold in 2023, 2024 numbers shine even brighter: MW reported orders were up 32.4%, and unit orders were up 4.1%.

“Order activity is up significantly in 2024, primarily driven by large jumbo unit orders for the electric power utility segment, but aeroderivative orders remain strong as well,” said Tony Brough, President of Dora Partners & Company.

The industrial gas turbine market is being impacted by several factors, according to Brough, including the price of natural gas, LNG, and, of course, the rapid development of data centers and artificial intelligence (AI), which is driving up power demand. 

2024 marked the highest unit number and MWs (nearly 500 units and almost 60 MW) reported globally since 2002, up from more than 40,000 MW in 2023.

Mark Axford, President of Axford Consulting, estimated an additional 30,000 MW of unreported orders, known as reservation agreements, bringing total orders booked for 2024 to more than 80,000 MW. He predicts gas turbine orders will increase by 7 – 10% in 2025.

The combined sales of GE Vernova and Baker Hughes, featuring gas turbines manufactured by GE Aerospace, place the two industry leaders at the front of the pack with approximately 85% market share for aeroderivative gas turbines.

“GE Vernova’s numbers were solid in 2024 as it regained the no. 1 spot for advanced-frame gas turbines—Mitsubishi was no. 1 in 2022 – 2023,” Axford said. In 2024, GE Vernova booked 22 GW of gas turbine orders and is upping its gas turbine factory capacity in Greenville, South Carolina, from 55 heavy-frame gas turbines to 70 - 80 per year in 2026.

Overall, advanced-frame (> 225 MW) gas turbine orders were approximately 80% of all orders (MWe). The top OEMs were GE Vernova (7F.05, 7H, 9F, and 9H), Mitsubishi (F, G, and J series), Siemens Energy (F and H series), Ansaldo Energia (94.3A), and Doosan (DJT 6; ~ 2.5%).

Packaged gas turbines have increased 12 - 18% over the past five years, while gas turbine components experienced up to 25% increases, according to Dora Partners & Company. Field service labor also increased by 10 - 20% in the past five years.

Brough reported the total value of packaged units—electric power utility (EPU) and oil and gas (O&G) model units—will reach $163 billion over the next 10 years. Aeroderivative engine sets will reach $26.5 billion, and GE Vernova/Baker Hughes aeroderivatives will hit $21 billion. Over the next decade, Siemens Energy, Mitsubishi Heavy Industries (MHI), and GE/Baker Hughes will dominate the 300+ MW market, accounting for more than 30% of the total value of engine-set units. The total aftermarket value will reach $302 billion in the next 10 years.

Brough named five drivers for the industrial gas turbine market, including grid-scale battery storage, coal plant retirements, rapid data center and AI development, grid-scale renewable energy expansion, and natural gas pricing and LNG.

Over 150 GWs of grid-scale battery storage have been installed globally, most in the last eight to nine years. In the next three years, 490 new U.S. plants are planned, adding more than 62 GWs of capacity. He said the market will be impacted by a decline in large power plants and jumbo frame turbines, with reliance shifting to smaller gas turbines and renewables to recharge, with an uptick in 40 – 100-MW gas turbines and recharge/hybrid systems.

Axford noted that solar and batteries are nearing economic feasibility without subsidies, given their short delivery times compared to gas turbine combined-cycle power, and that solar panel and battery prices are falling.

Coal still accounts for 33% of all electricity produced worldwide. In fact, global capacity struck an all-time high of 2,175 GWs but is expected to plateau in 2027, according to the International Energy Agency.

Dora Partners & Company expects large power plants and jumbo-frame turbines—specifically F, G, H, and J technologies—to increase. Gas turbines in the 40 – 100 MW range will also increase. “Mobile power and peaking will see an increase in demand, and, to a lesser degree, < 20 MW demand will be slightly up,” Brough said.

AI and data center buildouts are rocking the power industry and giving gas turbines “sold-out” status. U.S. utilities and developers “are racing to install baseload gas turbine combined-cycle power, but they can’t get it fast enough,” Axford said. Large gas turbine supply is essentially sold out for the next three to four years.

As Axford put it, gas turbines have gone wild. New orders are now shipping in 2027, 2028, and 2029, and gas turbine and engineering, procurement, and construction (EPC) prices are up sharply. According to Brough, pricing is expected to continue increasing by approximately 5 - 10% over the next 12 - 18 months, with lead times for new units up to 36 - 48 months.

Data centers will also continue to boom. The World Economic Outlook (WEO) reports that well over 11,000 data centers are serving digital commerce and AI computing, with each center averaging an electrical load of approximately 4 MWs—and that’s only expected to increase to meet demand. Nearly 1,400 more are planned in the United States alone. Virginia, Texas, and Georgia have the highest potential for data center buildouts, according to S&P Global Market Intelligence.

Brough said data center buildouts and AI will impact the market the same way coal plant retirements will, but with an increase in onsite power, too.

According to Dora Partners & Company, solar PV’s global capacity is now over 1,800 GW, and the WEO forecasts that global capacity will [

] more than double over the next five years.

Brough said this market driver will also increase mobile, onsite, and peaking power, but “large power plant and jumbo-frame turbines will decline with a slight dilution of F, G, H, and J technologies.”

“In 2024, the United States was the no. 1 LNG exporter,” Axford said. By December 2028, the U.S. Energy Information Administration projects U.S. LNG exports will increase by 80%.

In terms of natural gas, the cost per MMBTU is expected to remain largely “affordable” in the United States, according to Brough, which supports the use of gas turbines. Plus, “government policy is expected to keep it that way over the next four years.”

He said large power plants/jumbo-frame turbines and gas turbines in the 40 – 100 MW range will increase.

2024 was a strong year for GE/Baker Hughes’ LM6000 and LM2500+G4.

“GE/Baker Hughes LM2500+ remains one of the most popular models in the world for the last 25 years,” Brough said. It has 1,458 units in fleet and accounted for 44% of the aeroderivative market (EPU and O&G models) over the past five years, growing at a compound annual growth rate (CAGR) of 4.1%. However, he said the Solar Titan 250 has displaced the LM2500 base engine business, and the introduction of the Solar Titan 350 poses a strong challenge to the 35+ MW LM2500+.

In 2024, GE/Baker Hughes LM6000 boasted 45 unit orders, but the LMS100 and LM9000 came up short with zero orders, though it is believed Baker Hughes is entertaining a lot of interest in the LM9000. The LM6000 has 1,235 units in fleet and improved its market share over the past five years to 16.4% with a CAGR of 1.8%.

Brough also noted a resurgence of the MHI FT8 in 2024, with 16 units ordered.

In 2023, GE/Baker Hughes’s five-year market share was 61%; in 2024, it increased to 63.7%. Siemens Energy and Rolls-Royce both held 8.1% and 4.5% in 2023 and 2024, respectively; MHI/PWPS held 3.6% in 2023 and 5.4% in 2024, and UEC (Russian Aero) held 9.5% and 9.3% in 2023 and 2024, respectively, according to Dora Partners & Company. The company predicts $3.6 billion per year will be spent on gas turbine maintenance, repair, and overhaul.

In North America, aeroderivative unit orders saw a 48% increase and a 236% increase in MW orders in 2023 versus 2024, and GE/Baker Hughes’s MW share was 79.6% in 2023. Globally, aeroderivative unit orders were down 14% in 2024, and MW orders were up 10%. GE/Baker Hughes’s global share was 73% in MWs in 2024.

Who is the competition for GE Vernova’s aeroderivative gas turbines? Axford said in 2000, the answer was Rolls-Royce and Pratt & Whitney. In 2024, the answer was solar panels and wind turbines. Now? The Wärtsilä RICE, Siemens SGT800, and Solar Titan 250 and 350 are taking market share from the LM2500 and LM6000. In 2024, Finland-made Wärtsilä won 800 MW of gensets in the United States (+280%) across approximately 85 sites (~ 6,000 MW installed) and already has 700 MW of orders booked for the first quarter in 2025.

“PROENERGY is winning a larger share of the aeroderivative genset business in North America,” Axford said. A total of 37 PROENERGY LM6000s have been sold globally to utilities and independent power producers since 2009, and 50 LM6000 peakers in Texas alone. One of PROENERGY’s advantages is that its LM6000 and PE6000 gensets are built in Missouri. It also offers field service, level 4 repair, operations and maintenance (O&M), and an EPC turnkey approach that includes selective catalytic reduction for 6000 gensets.

Axford reported that in 2024, PROENERGY received 22 unit turnkey orders from Arizona for its LM6000 gas turbine generator sets. In addition, Colorado Springs Utilities ordered eight PE6000 generator sets. PROENERGY Model PE6000 utilizes refurbished aircraft engines (CF6-80C2) originally in service for wide-body jets such as the Boeing 747 and 767. The PE6000 is rated at a 48-MWe output with water-spray injection. Numerous PE6000 engines have accumulated more than 8,000 hours of runtime in Houston, Mexico, and Germany.

The demand for mobile power is expected to grow in the coming years to increase scalability, meet rising energy demands, and accommodate rapid start-up and deployment.

Dynamis’ DT35 mobile turbine boasts a fast setup and disassembly—“no crane, no forklift.” The model is for sale and lease. Dynamis also leases its 5.5-MW trailer-mounted Solar Taurus 60 and 16.5-MW trailer-mounted Solar Titan 130.

Relevant Power Solutions is building new mobile gas turbine gensets, including a 35-MWe M35 genset (GE LM2500+G4) and a 17-MWe dry low emissions M170 genset (Baker Hughes' NovaLT). Relevant has 12 M170s in production for 2025 – 2026 delivery. Axford reported that Relevant will commission five refurbished LM6000 gensets in June and November 2025, three in Texas and two in Arkansas. Relevant offers a full-load factory string test before shipment, economical turnkey installation, and contract O&M services.

Order activity spiked in 2024, as the gas turbine market was driven by data center development and natural gas and LNG. 

Gas Turbine Market Report: 2024 Posts Highest Units, MWs in 22 Years 

Methane, the main component of natural gas, is on the Environmental Protection Agency’s (EPA) hit list, calling it a climate “super pollutant.” Methane has a shorter lifetime in the atmosphere than CO

 but a greater near-term warming potential. According to the EPA, methane is responsible for approximately one-third of the current warming resulting from human activities and is a greenhouse gas (GHG) with a global warming factor 28 times higher than CO

The Agency released its final rule in late 2023 that will sharply cut methane and other GHG emissions from oil and gas operations—the nation’s largest industrial source of methane. The ruling includes revisions to the new source performance standards and emissions guidelines and promotes the use of methane-detection technologies.

The International Energy Agency (IEA) says methane abatement in the oil and gas industry is one of the cheapest options to reduce GHG emissions anywhere in the economy, and the industry has the largest potential for abatement in the near term. The energy sector accounts for nearly 40% of total methane emissions from human activity; oil and gas operations are responsible for 80 million tons of methane emissions.

The solutions and technologies outlined by the EPA will prevent an estimated 58 million tons of methane emissions from 2024 - 2038. The EPA said the rule would achieve a nearly 80% reduction below the future methane emissions expected without the rule.

In IEA’s Net-Zero Emissions by 2050 (NZE) scenario, energy-related methane emissions decrease by around 75% by 2030—two-thirds of which comes from reducing oil and gas operations emissions. Further, more than 40% of the emissions reductions to 2030 in the NZE Scenario can be achieved with measures that would result in overall savings given the value of the captured gas. These measures include mechanisms to detect and immediately tackle large leaks, replacing pneumatics and pumps, and installing recovery systems. According to IEA, they would require just over 10% of the total spending on methane abatement and can produce results quickly, laying the groundwork for further reductions.

Toby Rice, President and CEO of EQT, said at the 2024 Baker Hughes Annual Meeting (AM) that more than 40% of natural gas producers have already signed on to meet zero or near-zero methane emissions by 2030. In addition to other efforts, EQT—the largest U.S. natural gas producer—is partnering to conduct aerial monitoring of an area the size of France to detect methane emissions. 

The Italian energy company Snam is addressing methane abatement throughout its network: instrumentation upgrades to detect leakage and verify pipeline integrity, as well as equipment to capture and recompress methane gas to boost utilization and efficiency, according to Maria Sferruzza, Executive VP of International Engineering, Construction & Solutions at Snam, who also spoke at the Baker Hughes AM.

One of the big ways oil and gas companies such as bp have reduced their methane emissions is by eliminating flaring. bp aims for zero routine flaring by 2025 at its U.S. onshore operations and globally by 2030. 

Saipem, an Italian multinational oilfield services company, also pledged zero methane leakage by 2030. At the Baker Hughes AM, Alessandro Puliti, the CEO and General Manager, talked about the company’s zero-flaring technology for power plants and other areas of the infrastructure to detect fugitive methane emissions.

“All new design and engineering for our new plants is done to ensure zero flaring and zero fugitive emissions while lowering the physical and environmental footprint,” he said.

One Saipem customer found a way to utilize boil-off gas from its LNG storage facility, which was previously flared or vented, thus improving the efficiency of the ecosystem.

From big-picture site design to hand-held detection cameras, actuators, and aerial technologies such as satellites, airplanes, and drones, the industry uses the latest technologies to detect, reduce, and eliminate leaks and methane emissions.

As they say, less is more. And that’s true in the case of Chevron’s production facilities in the Mustang area in Colorado. The design, completed in 2022, only uses 7.5 surface acres versus the 400 surface acres usually required to deliver the same oil and gas production volume—that’s more than a 95% reduction in surface footprint. The minimal design also lowers lifecycle costs by 15 - 20%.

But it eliminates more than space. Because it produces spec oil direct-to-pipeline, there’s no need for big production tanks, flare systems, or further downstream processing facilities. In addition, flowback technology eliminates air emissions. This design can lower Chevron’s GHG by more than 90%.

The company has been using utility electrical power since 2019 to drill 56 wells, and, when possible, uses grid electricity versus onsite generators to power the drilling rig. This step eliminates 100% NOx and other ozone precursor emissions during the summer months, and close to 75% in colder months when operations require boilers for heat. Plus, it eliminates truck traffic—the design cuts down on more than 152 million miles of truck traffic and associated emissions—and noise from the generators.

 that its goal is simple: “Keep methane in the pipe. We believe methane reductions are possible in the energy industry, and in other key sectors, through the adoption of industry best practices, advancement in measurement technologies, carbon pricing, and methane regulations. Our methane strategy is focused on preventing methane emissions and using advanced detection technologies to validate performance, inform repairs, and improve inventories. We believe this approach can scale quickly across a global asset base, provide actionable information for methane emissions reduction, and augment emissions reporting as protocols become available.”

Oil and gas companies like Chevron use high-tech cameras, such as Teledyne FLIR optical gas imaging (OGI) cameras, in upstream and downstream operations to detect leaks proactively and for regulatory compliance. FLIR OGI cameras quickly scan broad sections of equipment and survey difficult-to-reach areas. They can also detect leaks from safe distances and display invisible gases as clouds of smoke.

“OGI cameras’ largest market is the detection of methane (and other hydrocarbons) in the oil and gas industry from upstream (well pads) to downstream (LNG or refineries),” said Craig O’Neill, the Global Director of Business Development at FLIR. “We also have business in renewable methane industries like biogas production, landfill gas-to-energy, and LNG markets.”

O’Neill said the biggest advantage of handheld OGI cameras is the “ground truth” that the technology shows. Once a leak is detected, the camera stores a video so the technician can share it with coworkers, repair personnel, or environmental professionals. “Many other technologies simply provide an ‘alarm’ that methane is present or a single snapshot image showing methane emissions. While these are great, they don’t tell the whole story of what is happening nor provide a true understanding of the emission event—is it a vent or a leak? Was it an intermittent emission event? Exactly what component is leaking rather than a general area where emissions are present?”

FLIR has cameras in almost every mid-to-large oil and gas operator in the upstream industry, ranging from a single unit to dozens.

Plus, OGI cameras also support the new methane-mitigation industry requirement to quantify emissions detected with technology. For example, the Bayernoil refinery complex in southern Germany integrated a gas detection camera into its leak detection and repair programs and used it to minimize hydrocarbon gas discharges from its piping systems, specifically leaks near flange gaskets.

IBS GmbH, headquartered in Bremen, Germany, conducts in-process analysis and detects gas leaks in biogas facilities. For IBS, using the FLIR GF320 camera not only significantly reduced the time it takes to scan a biogas facility compared to conventional gas detection technology, but it also enabled ground access to difficult areas such as where the tank meets the roof and the inner gas membrane. The case studies were similar for both BP Chemicals and Inspectahire, who said they were able to enhance safety and efficiency—the thermal imaging in FLIR’s cameras allows techs to keep a safe distance, when needed, to detect gas leaks and reduce repair downtime, among other benefits.

With the help of the NGIF Accelerator and its Emissions Testing Center (ETC) program, cleantech startups are developing innovations to tackle methane emissions. The program—operated by the not-for-profit arm of NGIF Capital Corp.—offers dedicated spaces via host sites for these companies to develop, test, and validate their solutions. The four-stage program includes access to the entire gas value chain, including a live gas operations environment.

Through the ETC program, Qube Technologies tested its fixed sensor that continuously, versus intermittently, monitors methane emissions. Since testing at the Tourmaline Oil/Perpetual Energy West Wolf Lake Plant—an ETC program host site—it has deployed over 4,000 sensors at over 1,000 sites, including Canadian operators such as Arc Resources, Enhance Energy, and Ember Resources.

Drones, satellites, and other detection technologies have helped many organizations significantly reduce their emissions. In fact, the Environmental Defense Fund reported on March 4, 2024, that MethaneSAT—a satellite designed to detect and quantify methane emissions—detached from SpaceX Transporter-10 into space. It will circle the Earth 15 times a day and measure changes in methane concentrations as small as three parts per billion.

To reduce emissions at its operations in the Permian Basin, ExxonMobil uses airplanes and helicopters to trail airborne technologies outfitted with methane sensors. It then integrates information collected from flyovers with data from ground-based mobile and fixed sensors remotely monitored from Houston. ExxonMobil said it “reduced methane emissions from all operated assets by nearly half as of year-end 2021 when compared to 2016” and eliminated 100% routine flaring in the Permian Basin, as per the World Bank Zero Routine Flaring Initiative.

Pneumatic devices comprise 40 – 50% of upstream oil and gas methane emissions. Rice said that a certain widely used pneumatic device at EQT turned out to be the company’s biggest source of methane emissions. The company replaced all 9,000 of these devices within 18 months, lowering companywide methane emissions by 70%.

Kathairos Solutions developed a system that uses liquid nitrogen, an inert gas, to power pneumatic devices, thereby replacing instrumental gas and eliminating the need for methane venting. It’s designed for smaller remote well sites, and its adaptable set-up is designed to minimize downtime and reduce operational disruptions.

Mitch Jones, Project Engineer at Kathairos Solutions, said the system gives customers the flexibility to set, commission, and fill the tank before tying it into their system, or Kathairos can facilitate this step. Within the first year of the unit’s commercial availability, 1,000 Kathairos units were installed and offset methane emissions by 40,000 metric tons of CO

Jones said one of its customers in the Rockies region had over 140 tanks installed in less than three months, averaging five tanks installed and tied-in per day. This addressed the needs of 2,500+ wells and around 9,000 pneumatic devices, significantly reducing methane emissions from oil site pneumatics.

Another example from ETC program is Kinitics Automation, a Vancouver-based company whose roots are in the automotive and power-generation industries. The company developed an electric valve actuator to replace methane-venting pneumatic actuators. During tests at one of the ETC program host sites—the University of Calgary and its labs—the actuator’s positional performance was evaluated at a variety of temperatures. Outcomes revealed that the actuator reached the target positions within 0.1% at all tested temperatures and responded to motion commands of 0.25%—the smallest commanded value. In a differential pressure test, the actuator maintained a closed-valve state with a 4,000 kPa(g) differential pressure present across the valve. The electric valve actuator met or exceeded the performance of traditional pneumatic actuators. 

Duke Energy developed its Integrated Methane-Monitoring Platform (IMMP) to detect leaks and measure methane emissions on natural gas distribution systems. It uses a satellite with a short-wave infrared sensor to monitor methane emissions and ground-based technologies such as continuous monitoring sensors, gas cloud imaging cameras, and handheld/portable gas-sensing analyzers.

“IMMP started with satellite captures in Greenville, SC, which helped the team refine, improve, and scale the technology and the methane detection algorithms to various types of local distribution company assets with varying terrain and geography,” said Lauren Crowe, Managing Director of Natural Gas Business Transformation at Duke Energy. 

IMMP has reduced recordable leaks in the Carolinas by more than 85% since its inception in 2022. “Duke Energy’s Natural Gas Business Unit is also using cross-compression technology to capture methane,” Crowe said. “We are also making investments in renewable natural gas, which is considered carbon-neutral because it removes methane from the atmosphere and displaces geological gas.”

The cloud platform ingests and calculates high volumes of real-time leakage data and then quantifies and prioritizes findings in graphic dashboards. Crowe explained that because the technology automates leak detection closer to the source, “pipeline management and operations teams can dispatch repair and maintenance crews to targeted sites for remediation based on near real-time information provided on cloud-enabled mobile devices. Using this method and technology enables us to identify and remediate any leaks in our system quicker and more comprehensively.”

The company’s extension program was selected by the U.S. Department of Energy’s Office of Fossil Energy and Carbon Management for nearly $1 million of funding. “As part of our IMMP extension project, we are testing a suite of both top-down and continuous-monitoring technologies with hopes of being able to detect and quantify emissions across all spatial and temporal scales and to evaluate the efficiency and accuracy of the various types of technologies,” Crowe said. The expansion project will include interstate, customer natural gas assets, upstream, and midstream. “The IMMP extension project will help us build a standard admissions, accounting, and reporting framework that will be useful across the entire value chain.”

To hear more about methane emissions in the oil and gas industry, check out our TurboTime podcast episode with the 

From ground-based technologies to site design and aerial innovations, the industry continues to use smart devices to abate methane emissions.

Reducing Methane Emissions in the Oil & Gas Industry

In this episode of the TurboTime podcast, Myth Busters Klaus Brun and Rainer Kurz discuss the design of turbomachines. They describe the typical design process for a turbomachine, outline the required engineering tools, and explain each analytical tool's function: finite element analysis, computational fluid dynamics (CFD), and rotor and blade dynamics. They also discuss how compressors, pumps, and turbomachines were designed before these advanced computational tools existed.

TURBO: Can you describe the typical design process of a turbomachine and what engineering tools are required?

 You begin with what's known as a 1D analysis, then move to a 2D analysis, also called a blade passage flow analysis. After that, you proceed to 3D and conduct some testing before refining your geometry. In essence, that's the aerodynamics part, right? However, there’s an initial step that is often overlooked, which is your own experience. You start your design based on your experience and your existing machinery portfolio. If you’re a turbomachinery manufacturer with 50, 60, or 70 years in the field, you’ve likely worked on various types of machines. Therefore, before designing a new machine, impeller, or expander, you review your existing portfolio; that's usually your starting point. You examine what's closest to your needs within that portfolio to determine if you can build upon it or if you need to start from scratch. Besides the aerodynamic design process, there's also a review of structures and dynamics that runs parallel to your aerodynamic process. You perform aerodynamic design followed by structural checks. Essentially, you assess the solids and dynamics to ensure there’s no risk of failure due to vibration. You conduct these evaluations throughout to avoid potential failures. These are generally well-known considerations. Additionally, a third aspect that often gets overlooked is manufacturability. It’s crucial to ensure that what you're designing can actually be manufactured, as it wouldn’t make sense to design an impeller or a machine that ultimately cannot be produced due to a lack of available technology or machinery. This consideration relates closely to materials, so manufacturability and materials fall into the same category, requiring a review of your materials, coatings, etc., throughout the design process to ensure that your design is feasible for production.

 I’d also like to point out that, as engineers, we don't design these machines out of thin air. There’s usually a use case, a customer, or a market assessment that indicates we need something that fits specific requirements. This could be a gas turbine that produces 20,000 horsepower or a compressor that can deliver more throughput than what my competitors can achieve within a given casing size, and so on. Then, we enter a process where engineering is asked, "Hey, can you guys do that?” Of course, someone also inevitably asks if we can achieve that at a cost that makes the project feasible. Yes, Klaus is absolutely right; this essentially defines the playground we work within. From there, we move from what could be considered a rough draft, using our experience, to increasingly refined concepts. Ultimately, you'll end up with some CFD simulations, and after building the first machine or prototype, there will be some testing to follow.

Do engineers overrely on computational tools? The Myth Busters deep dive into engineering tools, such as CFD and FEA, used to design turbomachines. 

TurboTime Podcast: The Turbomachinery Design Process - Part I

Turbomachinery International spoke with James Montgomery, Chief Design Engineer, Novel Nuclear, and John Mason, Systems Design and Integration Technical Specialist of Rolls-Royce, to take a deep dive into micro-reactors—compact, portable reactors that produce thermal energy for use as heat or electrical power—and give readers an inside look at the company’s innovations, challenges, and design considerations for its micro-reactor and nuclear technology in terrestrial and lunar applications.

Q: What is a micro-reactor, and how does it differ from a small modular reactor (SMR)?

Micro-reactors are very small scale, in the range of 1 MWe - 10 MWe compared to a typical grid-supplying power plant in the gigawatt range and compared to the new generation of SMRs in the 1/2 GW range—micro-reactors are much smaller than that. We have two potential applications for the micro-technology we’re working on in the United Kingdom: The first one is the terrestrial variant for supplying power to different applications on Earth; and the second is the space micro-reactor that has potential applications for the lunar base as part of the space program and, in the longer term, for power and propulsion applications on satellite and deep-space missions.

Q: What goes into designing a micro-reactor, and how are they customized?

At Rolls-Royce, we have a great pedigree in designing complex systems like this, so the first step in that process is to work with potential end users to understand the user requirements and use cases where we can get value from the technology. Then we’ll work through the process of preliminary design and size of the plant, understanding what the technology can do and where the technology gaps might be. That launches us into a technology program to acquire the technologies we need.

The micro-reactor plant is interesting because it’s genuinely a new product for us at Rolls-Royce, as with the rest of the industry. We’ve pieced together some of our pedigree from the nuclear side and the turbomachinery side that we have developed over many years for aerospace and industrial applications.

Across the Rolls-Royce group, we have experience in several different industries and capabilities. We have large civil engines that power airliners. We are engaged in combat aircraft and military transports, and a large element of our business looks at turbomachinery for turbo-compressors— centrifugal machines, turbochargers for yachts, large mining and industrial applications, etc. We can pull from all these capabilities and experiences and apply them to new industries and new technologies.

Q: What advantages do micro-reactors offer, and in what environments/locations do they work best?

In terms of the terrestrial variant of the micro-reactor, imagine a small-scale power plant in a shipping container-sized envelope that can be deployed to a remote location where access to fossil fuels is strained—that’s our vision for the micro-reactor. The great thing about a micro-reactor is, depending on its size and detailed design, it can be fueled for five to 10 years of operation, which means if you are a remote-unit or -running community or a remote military installation, it makes you resilient to the risks surrounding the fossil-fuel supply chain. Also, as a net-zero technology, it eliminates reliance on fossil fuels for communities.

The space micro-reactor is a completely different application. Many different missions are looking to use these kinds of power plants: In particular, NASA’s Fission Surface Power Project, as part of the Artemis Mission, was looking to develop a power plant for use on the lunar base. There, it’s about operating in areas where solar power is limited, particularly around the south part of the moon where we’re looking to explore, so having a nuclear source that can run reliably day and night is a game changer for moon-based operations.

In the long term, nuclear can be used as a source of power for propulsion and space missions, particularly for deeper space missions where solar power become weaker.

The Artemis Mission aims to build an infrastructure to Mars, and this technology could extend to those kinds of missions' demands. 

From a power-conversion viewpoint on our terrestrial applications, we can utilize our knowledge and expertise gained from our naval applications. These are designed and packaged to fit in a confined space envelope, similar to an ISO container, which is needed to transport the system. With an open Brayton Cycle, we are simply replacing the combustion chamber, where normally fuel is burned, with a heat exchanger to the reactor.

Where things get very interesting from a power-conversion point of view is with space applications. We still use Brayton cycles, but operation in space requires a closed cycle—we can’t continue to take air in the front and push it out the back, so we take the exhaust gas out of the back of the turbine and recondition that flow back to where we started before it re-enters the compressor. So, we’re looking at the most efficient way to do that with recuperation intercooling and various other things.

This presents challenges, but it also gives us additional design levers—because it’s a closed cycle, we can change the working fluid, so, for example, we don’t have to use air as we do with the open cycles for civil aircraft. We can also change the start conditions—optimize it by changing the pressures and temperatures at the beginning of the cycle. Depending on the requirements of the system, we can pick and choose where the design point of the turbomachinery sits.

Q: Can you talk about the use of nuclear energy and its role in a sustainable future?

One of the key technologies that enable micro-reactors is the development of coated-particle nuclear fuel, TRistructural ISOtropic (TRISO) fuel: a kernel of uranium fuel coated in different layers of carbon-like material that has different functionalities for protecting the fuel from overheating and for containing fission products within that small particle in a resilient way. This means that we can potentially simplify the design of the rest of the plant and hence enable much smaller plants more than we’ve historically been able to achieve safely. There are other aspects of the plant as well that are being looked at within the industry to enable a passively safe nuclear design—by that we mean it’s effectively fail-safe from the way it responds to different failure modes.

In terms of power conversion, the key impact of the micro-reactor and heat transfer from the reactor into our cycle is the peak temperature that goes with the fuels and technologies of that reactor. They are much lower than the operating temperatures of civil airliners, and the technology in the power conversion and Brayton Cycle is not being pushed by the cycle’s temperature levels. It gives us other headaches in terms of trying to design the cycle for high efficiency to minimize the size of the overall system, the reactor core, and the amount of fuel needed for the lifetime of the application.

One of the interesting applications for terrestrial micro-reactors is the need to safely transport and operate it at a remote site. As part of our concept, we'll have a containerized solution and ship it to the site using conventional transport. That itself poses design challenges to the way that you transport the radioactive and spent fuel when the site has been decommissioned. There's a lot of work in the industry looking at that.

It gives a flexible solution to the customer because you could have multiple nuclear reactor modules to create nuclear heat combined with multiple modules of John's power-conversion technology to scale the plant to different applications, which could also include the supply of heat for chemical and industrial processes.

The primary fluid used in the Brayton Cycle provides the coolant for the reactor as well. So, there are a lot of scenarios that we don't normally face when designing the system that we need to incorporate additional functionalities for and make sure there's the right redundancy to provide the safety case for these reactors. There are cases that in a normal application—for example, a civil airliner in which you would reduce the power or shut the engine down and rely on other engines to complete the flight safely—that may not work for the nuclear side because it needs to flow continuously to cool the reactor, which will have a big impact on how the system is designed.

Another factor is the environment in which these systems will operate. There are opportunities to use these in various conditions, from cold, Arctic conditions to hot, desert-like conditions such as in mining communities, and these intake conditions for terrestrial systems have a very big impact on their performance. We have to account for these factors when designing what the system and turbomachinery look like to ensure good performance and efficiency throughout each case.

Ambient temperature is a huge factor for space conditions in lunar applications—the day-to-night temperature varies between 100° Kelvin - 385° Kelvin, that’s -300° F - +230° F. That will have a huge impact on our ability to reject heat from the system through the radiators to return the fluid to its starting condition before it goes back through the compressor. From a systems-level point of view, there are many things that we need to think about which do we design for? Peak efficiency of power conversion, which minimizes the size of the reactor plant needed to launch and the amount of fuel you need to take with you? Or do we design for the minimum size of radiators that have to be packaged into the rocket to get the reactors there in the first place? There are many things we have to think about that we don’t normally consider.

This is a really interesting product for us because it brings together our aerospace heritage and our knowledge of how to build lightweight aerospace systems with our nuclear heritage. But this is our first nuclear application where weight has been a real concern, both from a transport point of view for the terrestrial reactor and for the spacecraft where the payload mass and volume are key constraints on the system. So, that's giving us a real challenge and driving us to some interesting packaging solutions for the space reactor in particular.

TurboTime Podcast: Micro-Reactors with Rolls-Royce.

Rolls-Royce is using its nuclear and turbomachinery heritage to create micro-reactors for space and terrestrial applications.

Q&A: Micro-Reactors with Rolls-Royce

In this episode of the TurboTime podcast, James Montgomery and John Mason of Rolls-Royce talk about micro-reactors. Microreactors are compact, portable reactors that produce thermal energy, which can be used as heat or converted to electric power. Micro-reactors can be quickly deployed and installed, and when they utilize a responsive design concept, they can prevent overheating and require fewer components, fewer operators, and less maintenance.

Montgomery is the Chief Design Engineer for the Rolls-Royce novel nuclear team in the United Kingdom. He is responsible for the design of the overall micro-reactor plant. Mason is a Systems Design and Integration Technical Specialist working within the Novel Concepts team in Bristol within Future Programs. His responsibilities are around the power-conversion system that goes with micro-reactors—i.e., the turbomachinery that takes heat from the reactor and converts it into usable electrical power.

“Micro-reactors are very small scale, in the range of 1 MW - 10 MW electrical, and that’s compared to a typical grid-supplying power plant that's in the gigawatt range and also with the new generation of small modular reactors that are in the 1/2 GW range, so we're much smaller than that,” Montgomery explained. “We have two potential applications for the microtechnology we're working on in the United Kingdom: The first one is the terrestrial variant for supplying power to different applications on Earth; and the second is the space micro-reactor that has potential applications for the lunar base as part of the space program and, in the longer term, for power and propulsion applications on satellite and deep-space missions.”

Montgomery also explained the process of designing a micro-reactor: “At Rolls Royce, we have a great pedigree in designing complex systems like this, so the first step in that process is to work with potential end users to understand the user requirements and use cases where we can get value from the technology. Then we'll work through the process of preliminary design and size of the plant, understanding what the technology can do and where the technology gaps might be. That then launches us into a technology program to acquire the technologies we need.

“The microreactor plant is really interesting from that point of view because it's genuinely a new product for us at Rolls-Royce as with the rest of the industry,” Montgomery continued. “So, we've pieced together some of our pedigree from the nuclear side and the turbomachinery side that we have developed over many years for aerospace and industrial applications.”

In this episode of the TurboTime podcast, James Montgomery and John Mason of Rolls-Royce talk about micro-reactors. 

timchen@tyconalloy.com

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