LNG plays a long-term role in the energy transition. Recent data from Wood Mackenzie’s 

2024 Global Gas in the 2050 Net Zero World

 report shows that gas demand will be resilient for the next 20 years while LNG demand will grow until near 2050. According to Baker Hughes’ first quarter 2024 results, global gas and LNG demand growth will see a compound annual growth rate through 2040 of around 1% for gas and 3.5% for LNG.

Even considering Wood Mackenzie’s report, a case less favorable to fossil fuels, gas is expected to decline far less than oil and coal. In the long run, global LNG demand is expected to be driven by emerging Asian economies, coupled with a limited domestic gas supply which will call for increased LNG imports. In short, LNG is both a transition and a destination fuel.

While in emerging Asian countries gas demand will be propelled by the transition from coal to gas and challenges with scaling up renewables, in developed economies the increasing speed of electrification and the roll-out of intermittent renewable energy sources will require more low-carbon and dispatchable power generation sources, supporting grid stability and flexibility.

The global LNG market is responding with an unprecedented surge of additional export capacity. According to Baker Hughes, over the next three-year period (2024 - 2026) approximately 100 million metric tons per year (MTPA) of liquefaction capacity is expected to reach a final investment decision.

The Institute for Energy Economics and Financial Analysis forecasted in its 

 report that nameplate LNG liquefaction capacity from projects under construction or approved by financially capable backers could add an estimated 193 MTPA of new supply capacity from 2024 to 2028, taking the total capacity to more than 650 MTPA—a 40% increase in five years.

This robust supply growth will facilitate lower prices, increasing competition between export terminals. The most competitive projects will be those able to deliver the most cost-effective LNG while offering flexibility and a lower carbon footprint, which explains the continuous innovation and investment from the LNG supply chain to respond to and overcome these challenges.

Traditionally, the LNG industry has been a capital-intensive market. With significant upfront investments needed and long design-to-construction schedules, building an LNG export terminal has always been a careful and risky venture. In contrast to traditional large-scale liquefaction plants, mid-scale solutions based on multiple smaller modular trains represent an important innovation for the industry.

Modules are plug-and-play assemblies capable of increasing speed to market—the time needed to achieve the first drop of LNG. As such, projects can be developed in phases and gradually add new liquefaction capacity while managing financial exposure from previous phases.

At the same time, more flexibility versus traditional stick-built projects can be obtained by splitting the required total LNG production capacity across multiple independent modules, which optimizes production and minimizes maintenance costs. Plus, pre-constructed turnkey modules help minimize project risk, enhance the level of control over module fabrication, and reduce construction site costs and potential schedule delays.

Significantly fewer construction personnel and less site time enhance overall project safety—a key aspect of any LNG project. Pre-designed modules lower engineering costs, as project design efforts are dedicated to the elements of the LNG plant, which cannot be standardized upfront.

NMBL LNG (pronounced “nimble”) is Baker Hughes’ modular solution for mid-scale gas liquefaction. It consists of modules with the ability to process from 0.8 up to ~2 MTPA each and is based on the single-mixed refrigerant liquefaction process.

Many LNG reserves around the world, both accessible and remote, are too small to be economically viable with the conventional large-scale, stick-built approach—from engineering to construction and start-up. This is especially true in the current market context where LNG supply and demand is growing rapidly and the ability to exploit stranded gas reserves can be a differentiator for monetization.

To seize the opportunity, energy companies need an even greater level of agility and the flexibility to consider onshore and offshore LNG options. Traditional LNG projects often falter providing this flexibility due to long lead times, significant upfront investments, and an inability to right-size production. NMBL is designed for scalability and pre-constructed fit for purpose.

Each NMBL liquefaction train includes the process module, a turbo or electric motor-compressor for the mixed refrigerant, the surge vessel for refrigeration storage, the cold box of brazed aluminum heat exchanger type, and the e-room. Its mid-sized modular design mitigates the challenges faced with traditional approaches to engineering and construction and can reduce risks and increase control during the execution phase. Upon arrival, final installation is significantly faster and requires fewer on-site personnel depending on the project specifics. These factors, along with simplified interconnections and civil works, can dramatically reduce project costs.

NMBL modules are a “design one, build many” concept. Its design can be easily scaled up to serve the range from 0.8 to ~2 MTPA and has been optimized to reduce weight and footprint. With a production capacity of 1 MTPA range of LNG, each module weighs approximately 3,000 tons and has a total plant footprint of approximately 3,000 square meters.

Rendering of Baker Hughes NMBL LNG modular solution for mid-scale gas liquefaction.

While traditional modular projects have many interfaces among different companies working simultaneously and not always with the same goals, NMBL integrates design, procurement, fabrication, and testing phases to reduce project risk under a single point of responsibility.

Another NMBL feature is the ability to accommodate different mixed refrigerant compressor drivers, either gas turbine or electric motors, without changing module configuration. The liquefaction process produces zero emissions because it is driven by an electric motor compressor.

NMBL also delivers greater project integration with:

a wide range of compact aeroderivative gas turbines, including the LM2500, LM6000, and LM9000 families

a set of electric motors from BRUSH Power Generation, part of the MAX synchronous motors product line, capable of serving a 30 - 95 MW range

mixed-refrigerant centrifugal compressors

With an LM9000 used for the compressor mechanical drive, its high-power engine is coupled with a high level of efficiency (73.5 MW and 44% efficiency, ISO conditions). With the electric motors as prime movers, the eLNG project can instead accommodate a centralized power island working on gas turbines in single- or combined-cycle.

In the latter case, Baker Hughes can supply power blocks with multiple running LM9000s coupled with one SC/type steam turbine. Moving from simple- to combined-cycle alone enables an increase in power generation efficiency by 20% or more, significantly reducing a project’s carbon footprint.

While recommended for both onshore and offshore liquefaction and small- to medium-size operations, NMBL is also suited for remote locations where a reliable power grid may not be available and therefore the power-block concept is a more fitting solution. Because the LM9000 is an aeroderivative gas turbine, its intrinsic ability to accommodate frequent starts and stops is not only compatible with baseload operations but can also compensate for the fluctuations from intermittent sources when the power supply is coming from renewable energy sources.

NMBL modules are also digitally native— that is they can integrate the equipment offering with lifecycle service and software features. The system is fully compatible with commercially available distributed control systems. Modules can be transformed into “smart objects” via the Baker Hughes iCenter digital platform powered by Cordant asset performance management software.

The LNG industry is undergoing a significant transformation driven by the need for cleaner, more flexible, cost-effective solutions. Shaping industry standards and collaborating with partners across the value chain will accelerate the adoption of new, innovative solutions that can drive productivity and deliver emissions reductions at scale.

As the world seeks to balance its growing energy needs with the imperative to decarbonize, modular LNG is poised to play an increasingly important role, and Baker Hughes is well-positioned with NMBL.

Andrea Intieri is the LNG Platform Leader of Gas Technology Equipment, Industrial, and Energy Technology at Baker Hughes.

Baker Hughes’ NMBL LNG delivers flexibility in an increasingly dynamic LNG market. 

Product Spotlight: Baker Hughes' NMBL LNG

In part two of this episode of the TurboTime Podcast, Klaus Burn of Ebara Elliott Energy, and Rainer Kurz of RKSBenergy LLC, discuss surge and choke on a compressor map. They explain where they occur on the map, what happens to the compressor when they operate in these extremes, and about transient operation of a compressor.

Brun explained surge: “On the left side of the map you have surge, and on the right side is choke, overload, or stonewall. The most basic definition of surge is the compressor head cannot overcome the system-imposed pressure, i.e., pressure on the outside on the suction and discharge, and the compressor is not making enough head to overcome that pressure differential. So instead of the flow moving forward through the compressor, the flow suddenly turns around and goes backward through the machine until that pressure balances again, at which point the machine can overcome that head. Then it starts a process again. And that becomes a circular process—you get into these surge cycles, and it's a fairly complex thing.”

Kurz emphasizes that surge is an interaction between the compressor and the system around it, “meaning the compressor by itself doesn't surge,” he said. “If the system forces the compressor to make more pressure ratio than under whatever conditions the compressor is going to make, then the gas thus what it wanted to do in the first place, which is go from the high pressure to low pressure, meaning it goes backward through the compressor. The tricky part with that is on the compressor map, we show what the compressor does. So, the map by itself and that surge line on the map is essentially something you derive from the compressor performance.”

The Myth Busters, Klaus Brun and Rainer Kurz, talk about surge and choke on a compressor map. 

TurboTime Podcast: Part II: Surge and Choke with the Myth Busters 

As the global energy landscape evolves, recent projections and industry updates highlight the dynamic shifts within the global natural gas sector. In April 2024, the U.S. Energy Information Administration (EIA) anticipated a modest increase in U.S. LNG exports for the year (2%) followed by significant growth in 2025 (an additional 18%). This growth is mirrored by expectations for a rise in U.S. natural gas exports by pipeline (3% in 2024, 4% in 2025) and a slight dip and recovery in pipeline imports in 2024 and 2025, respectively. Concurrently, S&P Global Ratings forecasted stable hydrocarbon prices supported by the Organization of the Petroleum Exporting Countries (OPEC), alongside a year-end rebound in gas prices driven by LNG export expansion and infrastructure developments.

“Low U.S. natural gas prices will likely continue for at least the next 10 years, fueling more LNG developments due to the low base price of natural gas,” said Marybeth McBain Product Line Manager - IGC New Apparatus, Global Sales at Ebara Elliott Energy.

This price point will not only bolster further LNG developments but also the construction of natural gas combined-cycle (NGCC) power plants. “The low and cleaner natural gas fuel will propel more NGCC power plants to be constructed, which provide reliable baseload power to supplement a growing renewables portfolio for the U.S. electric grid—eight new NGCC plants since 2022. This favors all gas-fired turbomachinery supporting the natural gas industry in the United States,” McBain said.

In this context, emerging trends such as modularization and the adoption of e-LNG technologies are reshaping the industry. “LNG projects are requiring modularization to eliminate risk in the field, i.e., stick built, in addition to a decline in available field labor,” said Joel Schubert, Director of Business Development LNG at Siemens Energy. “We also see a trend for future LNG projects going forward with e-LNG (electric motor drives) to reduce emissions and their carbon footprint.”

Moreover, the broader shift toward decarbonization and emissions reduction in LNG projects has started to affect LNG new developments. “Operators are considering greenhouse gas emissions, making changes in design accordingly, and moving toward electrification of some, if not all, of the major compression/pumps in the LNG plant,” McBain said.

Furthermore, Christopher Campos, Area Sales Manager, New Apparatus at Ebara Elliott Energy, said, “The offshore LNG market remains strong despite the current slowdown in the market due to pricing and policy shifts.” He said offshore floating LNG (FLNG) units continue to drive investors to look at capacity space with a limited number of shipyards. “In 2023, we saw Petronas invest in its third FLNG unit while 2024 saw a final investment decision (FID) by Cedar LNG for Canada. Golar is looking at re-purposing Golar Hilli Episeyo for its next area of operation in Argentina. Genting FLNG, an investment by Genting Oil & Gas in Indonesia, contracted out the construction of its first FLNG unit in 2024.”

Two trends are poised to send the global LNG markets into oversupply within two years: lackluster demand growth combined with a massive wave of new export capacity, according to a report from the Institute for Energy Economics and Financial Analysis (IEEFA), 

The global LNG market is slated to experience a shift starting in late 2024, as a wave of new liquefaction projects comes online. IEEFA expects global LNG production capacity (only projects under construction or approved by financially capable backers) to grow by roughly 193 MTPA from 2024 - 2028, rising from ~474 MTPA of nameplate capacity at the beginning of 2024 to 666.5 MTPA by the end of 2028—the fastest capacity growth in the history of the global LNG industry, representing a 40% increase in five years.

During 2024, only 12 MTPA of liquefaction capacity is slated to come online in the Republic of Congo, Mexico, Russia, Mauritania/Senegal, Australia, and the United States. Two of these new projects shipped their first cargoes earlier this year. But late 2024/early 2025 will see a new wave of LNG supply: IEEFA expects ~ 37 MTPA of new LNG facilities to start operations in 2025, with 57 MTPA of new capacity in 2026—the most ever built in a single year. IEEFA sees more LNG capacity additions of (

Note, this excludes any proposed global LNG projects that have not reached FID and the several projects that are moving forward but don’t have a completion date until 2029 or later.

Structural LNG demand growth faces challenges, according to IEEFA: economic, political, financial, and logistical. “The global LNG crisis of the last several years heightened those challenges, spurring some Asian nations to reduce the role of LNG in their development plans and accelerate the development of alternative energy sources.”

Combined imports fell in 2023 in Japan, South Korea, and Europe—a trio of countries that account for more than half of the world’s LNG demand—and IEEFA predicts they will likely continue falling through 2030.

Russia’s invasion of Ukraine spurred a decline in Russian gas supply to Europe that led to a spike in European LNG imports. However, prices have retreated from 2022 levels, largely due to falling demand from developed economies.

The United States, Australia, and Qatar produced three-fifths of the world’s LNG in 2023. Now, for the first time, the United States is no. 1 among global LNG exporters—the first U.S. LNG terminal started up on the Gulf Coast in early 2016. Most of the new LNG capacity slated through 2028 will be concentrated in the United States and Qatar, pushing Australia—the world’s top LNG exporter in 2021 and 2022—to third among global suppliers.

Mark Axford, President of Axford Turbine Consultants, cited in his report from CERAWeek 2024 a disrupting event that completely changed the worldwide energy picture and pushed the United States to the top: “The Nord Stream pipeline blowing up in 2022 was the single-most important occurrence in energy markets in decades. Since then, the United States has gone from third in LNG production to no. 1, with 24% share.”

Today, there are seven operating LNG facilities in the continental United States, with a combined nameplate capacity of 92.3 MTPA of LNG, about one-fifth of the world’s total (

IEEFA said the LNG industry’s capacity to export U.S. gas is set to grow from 94 MTPA to 172 MTPA by 2028. Five U.S. LNG projects, totaling more than 71 MTPA in liquefaction capacity, are currently under construction:

An expansion at Corpus Christi LNG (10 MTPA)

A 1.4-MTPA Mexican project sourced with U.S. gas recently shipped its first cargo and an additional 6 MTPA of U.S.-sourced LNG projects are moving forward in Mexico. IEEFA reports:

The development of the North Field complex will boost Qatar’s liquefaction capacity by 64 MTPA through 2030.

The initial phase of the 20-MTPA Arctic LNG 2 project received its first gas in late 2023.

The country’s first commercial-scale LNG plant is slated to start operations in 2025 or 2026.

Five projects have reached FID or are under construction in Africa.

Campos said that additional LNG carrier fleets have been added to the new-build bookings to support new liquefaction terminals coming online in Qatar, the United States, and Canada. Continued investment in bunkering vessels and LNG-as-a-fuel is still contributing to new-build bookings.

The industry continues to move forward with successful deliveries and progress for liquefaction and pipeline projects.

Siemens Energy successfully delivered, commissioned, and commercially operated its hybrid application for Chart Energy and Chemicals: a nitrogen refrigeration compressor STC-GV (20-3-H) package, powered by a STG-300 2S LE gas turbine. It integrates a synchronous motor/generator into a turbine-compressor configuration and includes online changeover capabilities from motor-to-generator modes and vice versa, supporting a transition to low-emission technology in compliance with local environmental regulations. The integration ensures that surplus power generated by Siemens Energy’s equipment contributes to the local power grid.

Siemens Energy has several recent and upcoming shipments and updates regarding Woodfibre LNG, a 2.1 MTPA export facility with 250,000 cubic meters of floating storage capacity being built near Squamish, British Columbia:

Boil-off gas (BOG) compressors 1 & 2 were successfully delivered on July 16.

Feed gas booster (FGB) compressor will be shipped in mid-August—the company is waiting for date/vessel confirmation from MDR.

BOG/FGB Powerhouses will be delivered at the end of September.

All main refrigeration (MF) and propane (C3) compressors have been successfully tested.

MR LP completed unit test preparation. String test is currently planned for the end of August.

Delivery of the LP MR train is planned for mid-October.

MR HP/C3 Complete Unit Test is planned for the end of November.

Delivery of the MR HP/C3 train is planned for January 2025.

Cheniere said it remains full-speed ahead on its current and future expansion projects. It continues to make progress on its Corpus Christi Liquefaction (CCL) Stage 3 Project and remains optimistic that it will achieve first LNG from the first train by the end of the year.

“We are confident we will secure all the regulatory approvals needed for the Midscale Trains 8 & 9 Project at Corpus Christi and the Sabine Pass Liquefaction (SPL) Expansion Project within our expected timelines,” said Bernardo Fallas, Director of Communications at Cheniere. “We recently received our environmental assessment for Midscale Trains 8 & 9, and we are in pre-filing with FERC for the SPL Expansion Project.”

In terms of pipelines, Fallas said the Sabine Crossing Pipeline Project is proposing a 58-mile pipeline extending east from Texas to the proposed SPL Expansion Project in Cameron, Louisiana, to support the natural gas needs of the project. The proposed pipeline would transport up to a maximum of approximately 2.7 billion cubic feet per day (Bcf/d) of natural gas to SPL from receipt points to be developed.

On July 1, the ADCC Pipeline entered commercial service and can provide approximately 1.7 Bcf/d of natural gas transportation capacity to the Cheniere CCL facility from markets on Whistler Pipeline’s Agua Dulce Header in South Texas.

In late July, Texas LNG Brownsville announced that they converted the two heads of agreement (HOA) with EQT Corp. to a definitive tolling agreement for 2.0 MTPA of LNG offtake. The FID is anticipated by late 2024/early 2025.

Also in late July, Woodside Energy purchased Tellurian Driftwood LNG—it is looking to reach FID in the first quarter of 2025; as part of the FID process, Woodside plans to examine equity sell-down options (up to 50%).

In January 2024, the U.S. Department of Energy (DOE) paused new authorizations for LNG exports to non-free trade agreement (NFTA) nations. The industry pushed back heavily on the pause, calling it “the worst energy decision made so far by the current administration,” according to Mike Sommers, President & CEO of the American Petroleum Institute.

Some projects were affected by the pause: Commonwealth LNG was stalled and is costing the project millions due to inflation while it sits still. In late June, Kimmeridge Texas Gas closed a follow-on control investment in Commonwealth LNG, raising its equity ownership to 90%. After selling his control to Kimmeridge, Founder and Executive Chairman of Commonwealth LNG, Paul Varello, announced his retirement. The pause also impacted Venture Global’s Calcasieu Pass 2 (CP2) LNG in Louisiana; however, on June 27, FERC issued a certificate that allowed CP2 to move forward.

But industry agencies said the pause would not alter the short-term trajectory of the U.S. LNG buildout. In April, IEEFA said: “Five new U.S. liquefaction projects, as well as two Mexican projects sourced with U.S. gas, are under construction and have already been cleared to export to NFTA nations. The projects have a collective capacity of 78 MTPA, meaning—pause or no—the U.S. gas industry is preparing for 85% growth in LNG export capacity by 2028.”

McBain said: “There remains a general acknowledgment in the industry that LNG expansions are continuing to move forward with FERC on a case-by-case basis. Also, the sentiment is that more LNG new licenses will be approved once the election is finalized— regardless of which political party wins.”

Relief came on July 1, when U.S. District Judge James Cain in Lake Charles, LA, ordered the Administration to lift the pause until a lawsuit brought on by 16 Republican-led states—who argued that freezing approvals of LNG exports was “completely without reason or logic”—could be resolved.

“We are encouraged by the recent ruling and expect it will facilitate DOE’s continued processing of LNG export applications,” Fallas said. “We previously stated that we did not believe the DOE pause materially impacted the timelines of our overall projects, and we continue to believe that to be true.”

https://www.eia.gov/todayinenergy/detail.php?id=61863#:~:text=We%20forecast%20that%20U.S.%20LNG,and%20by%204%25%20in%202025

https://www.spglobal.com/ratings/en/research/articles/230627-clear-lng-outlook-could-turn-murky-near-end-of-decade-12770037

The global LNG market has been impacted by new liquefaction capacity, price fluctuations, and political intervention yet it is slated to grow at an unprecedented rate through 2028.

The Global LNG Market: The Rise of LNG Production

In this two-part episode of the TurboTime Podcast, Klaus Burn of Ebara Elliott Energy, and Rainer Kurz of RKSBenergy LLC, discuss compressor maps. The duo explains what compressor maps are, what they are useful for, how they fit into the process, and where head, flow, and efficiency islands fit in.

“In its most basic form, a compressor map is a graphical representation of how a centrifugal compressor behaves,” Brun said. “It's somewhat of an oversimplification because more factors play into it; but overall, it gives an accurate representation of what a compressor does within the system that it operates. A standard compressor map has an X and Y axis. The Y axis has something called head—isentropic or polytropic head. Sometimes you also see pressure ratio or a discharge pressure or a fixed section pressure. On the X axis is flow, and most of the time it’s volumetric flow. Sometimes you see mass flow, but that's not very common. Compressor maps also have a surge line on the left and on the right side of the map you have a choke or stonewall area. And finally, you have efficiency islands, and they correspond to the efficiency of the compressor. Not all compressor maps show them.”

Kurz further described efficiency islands: “Efficiency islands refer to the fact that these maps are three-dimensional, but we can only put them in two dimensions on paper. The three axes you want to display are head, flow, and efficiency. You use the efficiency lines in a very similar way to elevation lines. Also, the coordinates of the map that are directly affected by the compressor aerodynamics are head and flow. You can translate head into pressures or pressure ratios, and you can translate actual flow into mass flow, but ultimately what happens aerodynamically in the compressor is described by head and actual flow.”

The Myth Busters, Klaus Brun and Rainer Kurz, talk about compressor maps—what they are, how they are generated, and what they are useful for. 



TurboTime Podcast: Part I: Compressor Maps with the Myth Busters 

ASME’s 2024 Turbomachinery Technical Conference & Exposition in London, held June 24 – 28 at ExCeL London, welcomed more than 111 exhibiting companies from 22 countries, up from 89 exhibitors at the last Europe-based event in 2022. More than 2,500 attendees networked, attended technical presentations, and walked the exhibitor floor.

“ASME's Turbo Expo continues to attract leaders from industry, government agencies, and academia thanks to its strong reputation and program, which includes companies shaping the future of propulsion and power,” said ASME’s Executive Director and CEO Tom Costabile.

GAS TURBINES' INTEGRAL ROLE IN A SUSTAINABLE FUTURE

Day two of Turbo Expo 2024 kicked off with the panel session, 

The Gas Turbine’s Role in the Decarbonized Power Generation Portfolio

. Executives, engineers, technical leaders, and managers from GE Vernova, Mitsubishi Power, Siemens Energy, and Solar Turbines discussed the challenges with production, transport, and storage of lower-carbon fuels; advancements to combustion systems; retrofits, and more.

Moderator Jeffrey Benoit, Vice President – Global Clean Energy Solutions, PSM – a Hanwha Company, broke out the “new” combustion systems into two sections:

newly manufactured gas turbines from OEMs

new technology retrofits for gas turbine fleets currently in operation

Peter Stuttaford, CEO of Thomassen Energy (TEM), a Hanwha Company, talked about the company’s FlameSheet combustion system retrofit that can be installed in most OEM’s gas turbines F-class and below. The platform offers fuel flexibility, operational range improvement, ultra-low NOx emissions, and entitlement lifecycle costs. In a gas turbine power plant—a GE Frame 7E in Daesan Korea—FlameSheet operated up to 60% hydrogen by volume.

The transport, production, and storage of lower-carbon fuels have historically presented many challenges. Robert Schrecengost—Division Director of H2 with Carbon Management at the U.S. Department of Energy’s (DOE) Fossil Energy & Carbon Management—said overall advancement in terms of hydrogen production has been made with electrolyzers, “but storing and/or transportation to the site is a major investment that will be regionally focused,” he said. “Hydrogen hubs should start many of these in motion, but the Gulf region in the United States has the most hydrogen pipelines installed. Repurposing natural gas pipelines is being discussed in various locations but going to 100% hydrogen will still be a hurdle. A typical F-class gas turbine needs roughly 20K kg per hour of hydrogen. Pipelines or massive production and storage on-site will be necessary.”

Panelist Jason Jermark, VP of Global Service Operations at Siemens Energy, said: “Siemens Energy is actively addressing the challenge of ramping up production of alternative fuels and thus ensuring that sustainable hydrogen and its derivatives become available in relevant quantities and at competitive prices. In cooperation with various partners, we have launched projects to achieve this goal. In Chile, for example, Siemens Energy has teamed up with HIF Global, Porsche, and other companies to build ‘Haru Oni,’ an integrated and large-scale commercial plant to produce carbon-neutral fuels from wind power and water.”

However, according to Jermark, the foundation of the market ramp-up is based on the availability of electrolyzers to produce sustainable green hydrogen. “Air Liquide and Siemens Energy operate a multi-gigawatt electrolyzer production facility in Berlin that enables the supply of large-scale projects worldwide. One of the first projects supplied from the new production facility is a collaboration with Orsted to build one of Europe's largest commercial facilities, FlagshipOne, for carbon-neutral marine fuels in Sweden,” he said.

According to Carlos Koeneke, Technical Director at Mitsubishi Power Systems Americas, “the appetite” to produce, store, and co-fire low-carbon fuels is higher in regions of the world where fossil fuels are expensive. “In Asia, for example, most countries import LNG, which is not only more expensive than natural gas in terms of production, but shipping it usually involves long distances across oceans. These circumstances make hydrogen production economically reasonable in the affected countries.”

He said the long transport distances have created an additional incentive to use ammonia as a hydrogen carrier, as it does not require maintaining hydrogen at low temperatures.

“One new trend is co-firing ammonia directly instead of converting it back to hydrogen through the use of cracking,” Koeneke noted. “Several tests are currently being conducted to burn ammonia in conventional boilers and directly in gas turbines.”

Panelists and moderators at Turbo Expo - (left to right) Jeff Benoit (PSM), Bobby Noble (EPRI), Will York (GE Vernova), Robert Schrecengost (DOE), Jason Jermark (Siemens Energy), Carlos Koeneke (Mitsubishi Power), Daniel Reitz (Solar Turbines), and Peter Stuttaford (Thomassen Energy). Photo provided by Jeffrey Benoit

“All OEMs have decades of experience co-firing hydrogen with diffusion combustors,” Koeneke said. “The percentage of hydrogen has been high in cases of refinery by-product gases (in the order of 90% or higher). The current challenge is mainly related to the use of dry-low NOx combustors, where the risk of abnormal combustion, among others, associated with flashback requires testing and combustor modifications.”

Technological innovations are accommodating fuel flexibility. However, how these newer systems work with existing installations depends heavily on the specific gas turbine, according to Jermark, given the “wide range of over 20 different frames currently in operation, as well as the type of fuel being used—which includes options such as hydrogen co-firing, 100% hydrogen, (fully) cracked ammonia, direct ammonia combustion, methanol, HVO, and FAME,” he said. “Working in combination with various partners, we have recent examples of both pilot applications and scalable solutions. The goal for all new fuel-flexibility developments is to be retrofittable to ensure that they can be seamlessly integrated into the existing fleet with minimal modification.”

Panelist Daniel Reitz, Manager of Marketing and Product Strategy at Solar Turbines, said over the years, Solar Turbines has accumulated experience operating on a wide variety of fuels by adapting the combustion and auxiliary hardware—pumps, valves, etc.—to the fuel properties and is continuing to do that for low-carbon fuels.

“The low-carbon fuels such as renewable natural gas, bio-propane, biogas, biodiesel blends, renewable diesel, and hydrogen-natural gas blends have physical and chemical properties similar to the fuels we have experience operating our turbines on already,” Reitz said. “We characterize them as drop-in fuels, which means we have hardware available to burn these fuels. Regarding fuels with properties very different from drop-in fuels, hardware modifications or development is needed to support them.”

Gas turbines are said to become "fully decarbonized, dispatchable energy sources" that could support and balance intermittent power sources.

According to Reitz: “Gas turbines are inherently flexible and allow for easy adaptation to a wide variety of fuels with different characteristics. In addition to providing fuel flexibility, gas turbines provide high efficiency, low emissions, high availability, high reliability, and high-power density.”

With a larger integration of renewables, dispatchable gas turbines will become more necessary. “In future decarbonized energy systems where renewable energy sources play a significant role, there will be a growing need for dispatchable power to bridge longer periods of low renewable energy generation. While current battery technologies may face limitations in terms of storage capacity, gas turbine power plants offer the capability to quickly provide reliable power, as well as heat through combined heat-and-power generation, and deliver essential grid services,” Jermark said.

TURBOMACHINERY STRATEGIES FOR A CLEAN-ENERGY FUTURE

Flexibility and turbine advancements were the focal point of Wednesday’s panel session: 

Turbomachinery Solutions for Decentralized Energy Systems: Addressing Clean, Dispatchable, and Affordable Energy

. The panel—moderated by Giuseppe Tilocca, Scientific Officer, and Christer Björkqvist, Managing Director, at ETN Global—noted three major strategies addressing the challenges with current gas turbines and turbomachinery and a decrease in flexible capacity: fuel flexibility, digitalization, and efficiency improvements.

“Gas turbines and turbomachinery are evolving by pushing the boundaries of their inherent flexibility to provide mature and cost-effective solutions thereby ensuring a reliable and sustainable energy supply during the energy transition and beyond,” Tilocca said.

The flexibility requirements, as noted by organizations such as the Joint Research Center and the Agency for the Cooperation of Energy Regulators, are expected to increase significantly; however, flexible capacity is decreasing. Effectively, Europe is projected to lose 107 GW of flexible capacity by 2030. This decline is driven largely by economic decommissioning.

Tilocca expanded on the strategies addressing these challenges:

 Gas turbines are being designed to operate on a variety of fuels, including hydrogen and biofuels, to ensure they can adapt to different energy sources.

 Advanced digital tools and analytics are being used to optimize operations and maintenance, allowing turbines to perform efficiently under varying conditions.

 Continuous advancements in turbine technology are improving the overall efficiency of these systems, reducing emissions, and lowering operating costs.

These measures are critical for ensuring that gas turbines remain a viable and sustainable option in a cleaner energy future. Moreover, Sean Fitzpatrick, CEO at Pure World Energy and operator of several microgrids, stressed the need to foster education and communication regarding the positive role of turbomachinery in the net-zero transition.

“Turbomachines are flexible solutions that by smart integration with renewables and storage systems will provide flexibility to decentralized systems and reduce the demand on national grids,” he said.

New combustion systems that enhance fuel flexibility are already available and being integrated into existing infrastructure. For example, Tilocca noted that the German Aerospace Center (DLR) has developed a retrofit system for a 100 kWe turbine adapted to run entirely on hydrogen, based on technology from Ansaldo Green Tech. This turbine is ready for commercial deployment in Germany, indicating that the technology is already available.

The main gaps these technologies address include:

By filling these gaps, new combustion technologies help reduce reliance on fossil fuels, decrease emissions, and support the transition to a sustainable energy ecosystem.

How Gas Turbines Support Decentralized Power Generation

Clean and dispatchable technologies are the future, and gas turbines are an essential component for decentralized power generation. Tilocca said that decentralized generation involves producing electricity closer to where it is used, reducing transmission losses, and enhancing grid resilience.

The key roles of gas turbines in decentralized power generation include:

Gas turbines can quickly ramp-up production to meet demand during peak periods or when fluctuating renewable sources are insufficient

 Prof. David Sanchez from the Universidad de Sevilla said gas turbines help maintain grid balance and quality.

 By complementing intermittent renewable energy sources like wind and solar, gas turbines help ensure a stable and reliable power supply.

Several market dynamics and operating conditions must be considered to transform current energy practices and support a cleaner energy future.

To navigate these challenges, it is essential to develop cost-effective, adaptable solutions that can meet evolving market demands while supporting the transition to a sustainable and clean-energy future.

The theme of this year’s show was achievements and needs to unlock a net-zero future in propulsion and power.

Turbo Expo Showcases Gas Turbines as Part of Decarbonized Future

examines the evolution of the global energy landscape and how recent projections and industry updates highlight the dynamic shifts within the natural gas sector. The Institute for Energy Economics and Financial Analysis estimates that LNG production capacity will increase by 40% in the next five years—the fastest capacity growth in the history of the global LNG industry. Our cover story—

—takes a deep dive into the global LNG market, including trends, newsworthy happenings, and commentary from a few industry folks on the market and the recent halt to the Department of Energy’s LNG export pause.

In tandem with our cover story on LNG is a Product Spotlight that introduces Baker Hughes’ modular LNG solution for mid-scale gas liquefaction: NMBL. In contrast to traditional large-scale liquefaction plants, mid-scale solutions based on multiple smaller modular trains represent an important innovation for the industry. Other innovations are discussed in our show report from Turbo Expo 2024. Speakers and panelists weigh in on the role of gas turbines in a sustainable energy future as new fuels are introduced, technology gaps are satisfied, and market dynamics are considered. To look back at our complete coverage, visit 

Also in this issue, Abdullah Sofiany from Aramco lays out several case studies demonstrating how machine learning techniques offer real-time anomaly detection that proactively identifies potential failures in turbomachinery. “The introduction of machine learning algorithms offers a promising solution to enhance predictive maintenance strategies and mitigate the shortcomings of conventional monitoring approaches,” Sofiany said. “By leveraging real-time operational data and advanced analytics, machine learning models can accurately identify subtle deviations in vibration patterns, even below alarm thresholds, enabling early detection of developing anomalies.”

Modernization for Ammonia Syngas Trains with Steam Turbine Drives

, Siemens Energy shares insights into the modernization of syngas trains at ammonia plants. As these plants age—many in the United States are older than 50 years—modernizing syngas trains is vital due to their significant impact on overall plant efficiency, production capacity, and operating expenses.

Amin Almasi tackles compressors with side streams, a challenging class of turbomachines, as he says, in his bi-monthly column 

. And in part one of the Myth Busters’ two-part column on centrifugal compressor maps, the duo covers the basic physics of constant speed head-flow performance lines. I hope you have a great autumn.

Click here to view the September/October 2024 issue

The September/October 2024 issue highlights the dynamic shifts in the global LNG market that are affecting exports, production, capacity growth, and more.

Turbomachinery International: September/October 2024

While the Latin root for the word “super” simply translates to “above,” for those of us who grew up with comics, movies, and cartoons of Superman, the word raises our adrenaline and we become “super” excited. Thus, it is no surprise when we talk about supercritical fluids that the average turbomachinery engineer starts to hyperventilate. As engineers, we also love critical things—albeit it is not totally clear why. There are critical speeds, critical loads, critical Reynolds numbers, etc., and they all separate the normal from the abyss. They also often describe situations that are difficult to calculate and interesting to investigate, which may make them cool … and super is even better than critical.

is often used in its original sense—above or beyond—supercritical is not in the abyss but on the other side. A supercritical speed for a rotor is a speed that is (usually) higher than the first critical speed—we learned how to operate at supercritical speeds about 150 years ago … ergo, nothing to worry about. Now, a load beyond the critical load may cause something to break or buckle, so sometimes bad things do happen beyond critical.

Any gas or gas mixture has a critical point at a critical pressure and temperature. This can be seen on a phase diagram where the fluid’s gas phase line intersects its liquid phase line at the highest gas temperature. For CO

, the critical point is at about 30° C and 74 bar pressure. Water’s critical point, on the other hand, is at about 374° C and 220 bar; Methane is at -83° C and 46 bar. The critical pressure and temperature for CO

, unlike many other substances, are well within pressures and temperatures often encountered in typical gas compression applications, such as heat pumps, carbon sequestration, and sCO

 Rankine power cycles. For any substance, if temperature and pressure exceed the critical point, distinct liquid and gas phases cease existence. (Note: This is only true as long as the pressure stays below solid-forming pressure, which for CO

 is somewhere in the range of several thousands of bar, and for all practical purposes not relevant for this discussion.) A good example is the atmosphere of Venus, which is 96.5% CO

 and 3.5% nitrogen. There the surface pressure is 93 bar, and the surface temperature is 462° C, which is well above the critical points of both major constituents, thus making the surface atmosphere of Venus a supercritical fluid.

Above the critical point, fluids are in their dense phase, characterized by high density (comparable to a liquid) but maintain the low viscosity of a gas. In the dense phase, the fluid does not form a free surface as a liquid would, but the fluid is still somewhat compressible— although the compressibility, i.e., density change with pressure, is relatively low. This is quite advantageous for transport purposes in pipelines since longer-distance transport is possible with a smaller power demand for compressors or pumps than transport as a gas. Thus, most long-distance transport of CO

 for carbon sequestration will likely be performed under dense-phase conditions but will require pipelines rated for 150 bar (2,200 psi) to reliably keep the fluid in the dense phase. It is important to understand that dense-phase conditions do not imply that the fluid is completely incompressible, so depending on pressure and temperature, either pumps or compressors can be used for pipeline transport or injection.

However, for the turbomachinery designer, the critical point of any fluid itself is considered pure unadulterated evil. It is like the juvenile delinquent that lives on your street who you keep your teenage daughter as far away from as possible. We try to avoid operating near the critical point at all costs. The reason is that most physical properties of a fluid, such as density, speed of sound, viscosity, specific heat, etc., change drastically near the critical point, i.e., physical properties have steep gradients with respect to pressure and temperature changes. This makes it nearly impossible to accurately design a compressor or expander for stable and predictable operation near the critical point. Thus, when designing a turbomachine, we usually select operating points at pressures and temperatures far, far away from a fluid’s critical point.

 is supercritical at pressures and temperatures above the critical point, about 30° C and 74 bar. This is well within the normal experience range for turbomachinery. There are interesting things happening in this region. When CO

 is kept above its critical temperature and pressure, it acts like a gas yet has the density of a liquid. In this supercritical state, small changes in temperature or pressure cause dramatic shifts in density, making sCO

 an attractive working fluid to generate power. The high density allows for machines with an extremely high-power density. Since CO

 is readily available, non-flammable, and non-toxic, it lends itself as a working fluid both for power cycles and high-efficiency heat pumps. Closed-loop Brayton cycles using sCO

 allow for increased efficiency and a substantially smaller footprint (both physically and environmentally) compared to air Brayton and steam Rankine cycles. This also applies to bottoming cycles for gas turbine waste-heat recovery. Additionally, because the heater and cooler do not involve evaporation or condensation, the temperature differences between the process fluid and heating/ cooling fluids are minimized, which decreases losses in the heat exchangers and improves achievable cycle efficiencies.

 very attractive for several applications, and indeed many organizations are building heat pumps, power cycles, bottoming cycles, and pipelines that take advantage of the behavior of sCO

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 a recent retiree from Manager of Gas Compressor Engineering at Solar Turbines Inc. in San Diego, CA. He is an ASME Fellow and has published over 200 articles and papers in the turbomachinery field. 

Supercritical CO2 (sCO2) may not have superpowers, but turbomachinery operators try to avoid working near the critical point at all costs.

Myth Busters: What's so Super About Supercritical CO2?

At TPS 2024, folks from Siemens Energy, including Lukas Biyikli, R&D Portfolio Manager of Integrally Geared Compressors, and Mike Welch, Industry Marketing Manager, presented on the

 Capture Plants with Open Cycle Gas Turbines.

The industry is familiar with carbon-capture technologies’ ability to remove CO

 from flue gas streams. Still, the challenges of providing the flue gas in the correct conditions and supplying the energy required for the CO

The speakers addressed these challenges by first reviewing the most common types of carbon-capture technologies, such as solvent- and potassium-carbonate systems, and then explored how open-cycle gas turbines could achieve similar results.

Welch began with a clarification regarding the role of gas turbines in carbon capture: they can achieve decarbonization by firing low-carbon fuels and their plants can be equipped with post-combustion capture technology. Despite these carbon capabilities, users typically favor traditional technologies over gas turbines for capture applications, citing low CO

 concentration in exhaust (3-4%) and high exhaust gas temperatures as the primary challenges.

He outlines several considerations for choosing carbon-capture technologies, including:

Impact of NOx and SOx on solvent life and replacement rate

According to Welch, carbon capture is a difficult process when using gas turbines: “The only certain thing about CO

 capture is that you’ll need a lot of space and it’ll cost you a lot of money—it’s not a cheap solution. Most of the processes are designed to operate at low ambient temperatures, so you become limited to the available technologies when operating with a gas turbine. There are only a few [technologies] that don’t require cooling of the gas turbine exhaust and most of the emerging technologies can’t support large-scale turbines.”

Despite the inherent challenges of running current carbon-capture technologies in conjunction with gas turbines, there are many available systems in use today. The most common are amine-based systems, which utilize proven solvents to absorb CO

 with low toxicity and low energy demand for desorption. However, these solutions have large footprints and long construction times, with higher energy demand for absorption. Welch goes on to list specific systems and their respective benefits and drawbacks.

Mike Welch reviews electroswing adsorption as an electrochemical carbon-capture method.

Often applied to smaller emitters that generate less than 1,000 tons of CO

 per day. With a smaller footprint, towers have shorter construction times and can be used at space-constrained sites, such as offshore platforms.

 adsorption through centrifugal force, but generally lower capture rates at approximately 100 tons per day.

Proven for gas processing and scalable to large CO

 capture volumes. The energy demand is similar to amine towers, but these systems can use hot water for solvent desorption. On the downside, potassium carbonate operates with low flue gas inlet temperatures.

Unlike typical potassium carbonate, it operates at high flue gas temperatures in a pressurized process. It can generate its own electricity and gas turbine supplementary firing can increase CO

These are also proven for gas processing but struggle when applied to gas turbines, as multiple modules are required to achieve the desired capture rate and purity. Membrane contactor modules are a hybrid solution combined with amine solvents.

Electroswing adsorption can be used on gas streams with any CO

 concentration and, according to electrochemical operators, can selectively capture NOx and SOx.

Biyikli continued the discussion by outlining the basics of CO

 compression and utilization processes following capture. Although compression is the primary electricity consumer in carbon-capture plants, it is a critical step for transportation via pipeline—the most economical way to move CO

The industry recognizes two methods of decarbonization with gas turbines: low-carbon fuels and post-combustion carbon capture.

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