Have you traveled in a modern, fuel-efficient midsize passenger plane lately? Given that these planes look rather conventional, you may wonder: Where does the fuel efficiency come from? There is a good possibility you were on a plane with a geared turbofan.

Turbofans with large bypass ratios have an issue. The large fan is difficult to speed match with the low-pressure turbine that drives it. That’s due to large differences in their diameters. The turbine wants to run at a much higher speed than the fan. The solution is to use a gearbox (rated between 16,000 and 32,000 hp with a ratio of 3:1) between the turbine and the fan. This allows both to operate at their optimal speeds, thereby increasing efficiency. It also allows an increase in fan diameter, improving propulsion efficiency.

New aircraft engines of this type can reduce fuel consumption by 15% compared to older engines. While the introduction of this engine, first used in commercial service in 2016, was a bit rocky, none of the teething problems were related to the gearbox.

Full disclosure: Neither author of this article works or has worked for the manufacturer of these aircraft engines. So why are we writing about them? Because there is proof a gearbox can be a good thing, allowing the match of aerodynamic components with different optimum speeds. Without a gearbox, the speed of the components—for example, a power turbine and a high-pressure gas compressor—is a compromise, reducing overall efficiency. Of course, this improvement is, to some extent, compromised by the fact that the gearbox itself creates losses.

We’re not advocating for a gearbox in every possible application. In many instances—for example, gas turbine-driven compressors in pipeline applications—there is no significant speed mismatch. The power turbine of the gas turbine and the pipeline compressor that’s sized to absorb the gas turbine power have their respective best efficiency at about the same speed.

On the other hand, consider the same gas turbine powering a high-pressure, gas-injection compressor. That is an example of a physically small compressor that absorbs a lot of power, and the compressor wants to run significantly faster than the power turbine. It may be possible to design a compressor for the same duty that works as a direct drive, but it would be bigger and most likely less efficient. In this situation, a gearbox may be a better solution.

Properly sized gearboxes rarely cause problems. Still, end users and turbomachinery experts often advocate against their use. This is interesting because gearboxes—either speed-reducing for generators or speed-increasing for electric compressor drives—are the norm rather than the exception for compressors driven by electric motors and generators driven by gas turbines. They operate to the satisfaction of most users.

In fact, the most challenging applications are not parallel shaft gearboxes used as speed increasers in gas compressor drive applications. The most challenging gearbox designs are used for integrally geared compressors where it’s often necessary to reach to the limits of possible pitch line velocity and where multiple pinions run off the same bull gear. Also, since gearboxes for industrial applications require oil lubrication, a properly designed oil supply and cooling system is imperative to achieve high system reliability and avoid forced outages.

There’s another non-intuitive gearbox preference. For compressor trains, parallel shaft gearboxes are the norm, in particular because API does not recognize epicyclic or planetary gearboxes for this duty. Interestingly, they are commonly used for gas turbine-driven generators, as well as in variable-speed hydraulic gearboxes.

For compressor applications, there are advantages to using epicyclic gears. They are more compact and often, especially for higher gearbox ratios, more efficient than parallel shaft gears. They also allow for an inline drive train, which helps significantly in offshore installations where space requirements, weight, and single-lift capability are important.

Rather than avoiding a gearbox on principle, it is a good strategy to consider if its use could lead to better performance, lower costs, and greater flexibility. Gearboxes are proven devices and, if sized and integrated properly, provide high reliability.

Klaus Brun is the Director of R&D at Elliott Group. He is also the past Chair of the Board of Directors of the ASME International Gas Turbine Institute and the IGTI Oil & Gas applications committee.

Rainer Kurz is the Manager of Gas Compressor Engineering at Solar Turbines Incorporated in San Diego, CA. He is an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

Any views or opinions presented in this article are solely those of the authors and do not necessarily represent those of Solar Turbines Incorporated, Elliott Group, or any of their affiliates.

Articles

Debunking the Myth: Embracing Gearboxes for Enhanced Efficiency in Compressor Applications

Myth: Avoid a Gearbox at All Costs for Compressor Applications

In certain operational and environmental scenarios, turbomachinery could be under dynamic loads such as earthquakes, impact/dynamic loadings, or blast loads (blast pressures). Although these might not be normal conditions and may only happen a few times during the life of equipment, they should be considered for overall safety and reliability. Machinery protection requires proper engineering safety and hazard assessment.

Earthquakes, water-hammer, dynamic forces due to the release of fluids, and similar transient cases could happen any time just as error in operation or malfunction could lead to such accidental loading cases. Blasts and explosions, too, must be considered, as well as accidents such as an item dropped from a crane during maintenance or a truck hitting machinery during an overhaul.

How machinery behaves under extreme loads depends on the quality of the design and the engineering/fabrication criteria met. This means going beyond code prescriptions and accurately predicting how equipment will respond during extreme events. Since experimental investigations are invariably limited, alternative approaches should be sought to evaluate the real behaviour and strength under dynamic/impact loads. This requires the use of realistic models or methods that, although may not be entirely accurate, provide some realistic estimates of load-carrying capacity.

The complexity of the response of machinery subjected to large dynamic loads involves many phenomena. These include elastic and plastic wave propagation, material properties, elastic and plastic buckling, fracture, and rupture. Involvements of different kinds of jointing techniques (welding, bolting, etc.) make simulation or assessment challenging. Another difficulty is the time dependency of dynamic loadings and responses.

Machinery protection requires proper engineering safety and hazard assessment.

It might be assumed that dynamic responses resemble corresponding static responses. This is not the case in many applications. For example, the dynamic elastic-plastic buckling of mechanical parts has been different from static cases and can lead to counterintuitive behavior.

Sometimes a simple energy balance using the rigid-plastic method provides guidance on the overall response of machinery and is helpful in selecting dimensions. For instance, a large explosion can be approximated as a uniformly distributed loading.

Piping loads are particularly vulnerable to different dynamic, impact, and blast loads, resulting in serious damage or leaks. Assessments, simulations, and estimates are required for the resistance of pressurized piping to all possible dynamic/impact loadings to ensure their safety and reliability. In many cases, proper protections and barriers should be in place to reduce risk to acceptable levels. Supports and their structures play a major role in the dynamic responses of piping systems.

There could also be different types and modes of failure when studying machinery under dynamic/impact loadings. As examples, three types of defined failures are mentioned here.

The first type is defined as permanent ductile deformation of machinery without any major incident such as leakage, fracture, or rupture. For instance, the thin shell of a machinery casing might be deformed or wrinkle due to an earthquake. This should be regarded as a failure and should be repaired even if there is no leakage or rupture.

A second type of failure is when rupture, tear, or disconnection happens. In other words, this is when the maximum strain reaches the rupture/tear value for the material, usually in a localized area of the machinery. An example is permanent leakage of a flange joint due to large, exerted loads.

The third type of failure is transverse shear failure. This more readily occurs at boundaries and other hard points (or supporting points) of dynamically loaded machinery. For example, anchor bolt(s) of a machinery might be cut due to dynamic loadings. ■

Amin Almasi is a Chartered Professional Engineer in Australia and U.K. (M.Sc. and B.Sc. in mechanical engineering). He is a senior consultant specializing in rotating equipment, condition monitoring and reliability.

Why simple models estimating impact, dynamic, and blast loads provide insight. 

How to Assess Turbomachinery Reliability and Strength

The Baker Hughes Annual Meeting at the end of January 2023 gave voice to oil and gas executives calling for a reevaluation of decarbonization policies they say may be inadvertently worsening emissions while pushing consumer energy bills upwards.

Sheikh Khalid Bin Khalifa Al-Thani, CEO of Qatargas, explained that coal consumption reached an all-time high in 2022. Why? A general shortage of oil and gas was in evidence even before the Russia-Ukraine war. That crisis only heightened the problem, especially in Europe. The Europeans gobbled up any available LNG supplies at top dollar. That left a shortfall in many other areas, and coal became the solution.

“The energy crisis in 2022 highlighted the fragility of global energy markets,” said Al-Thani. “We must balance climate and emissions reduction policy with energy security.”

He believes that while the role of renewables within the energy mix will increase, it is many years before any energy transition can realistically take place.

“Substituting natural gas for coal is the key as we cannot decarbonize immediately,” he said. “Natural gas is a necessary complement to renewables for a robust energy supply and as support for climate mitigation. Natural gas is reliable, affordable, available, and has a low carbon footprint compared to coal. This makes it a destination fuel, not a transition fuel.”

Standing in the way is a policy and financing puzzle that makes it difficult and sometimes impossible to receive investment for natural gas projects. Several speakers at the event laid out how funding for large-scale natural gas and LNG projects is often thwarted as the investment field has been told that natural gas won’t be around by 2030. This idea comes from policy makers who set decarbonization targets without regard to the realities of the situation. When disruption comes, short-term policies are rapidly adjusted to accommodate a sudden switch to LNG, as in Europe in 2022. But long-term work to develop new oil and gas fields and build the infrastructure to support them is in neglect and has been for many years.

Accordingly, Qatargas plans to boost gas production significantly over the next decade. Al-Thani said the company would do so while reducing its carbon footprint. It has already cut greenhouse gas (GHG) emissions by 12% compared to 2013 and CO2 emissions by 70% via injection and reduction of flaring. Methane emissions, he said, are already less than 1% of the company’s GHG profile.

Nasir Al-Naimi, Executive Vice President Upstream of Saudi Aramco (the largest oil and gas producer in the world), called for a return to energy realism.

“The impractical reality that oil and gas must be replaced has fueled chronic underinvestment, down by more than half from 2014 to 2021,” he said. “We must shatter the misleading narrative that oil and gas can be easily and quickly replaced.”

He laid out the statistics: Fossil fuels supplied 82% of the world’s energy needs in 2021 compared to 7% for renewables. The energy transition, he stressed, will happen at different speeds in different regions as they are at varying stages of development and industrialization. With three-quarters of a billion people still without electricity, the priority in these places is to get power by whatever means necessary.

“Each country has its own unique situation, so we must develop more realistic plays for affordable, reliable, and sustainable energy,” Al-Naimi said.

Saudi Aramco plans to boost production from its current level of around 12 million barrels of oil per day (boe/day) to 13 boe/day by 2027 and increase gas production by 50% by the end of the decade. In parallel, the company is investing heavily in carbon capture, renewables, and hydrogen.

“We must convince the world that oil and gas will play a prominent role in our energy future,” said Al-Naimi.

Lorenzo Simonelli, Chairman and CEO of Baker Hughes laid out the energy “trilemma”—how to balance sustainability with affordability and security.

“There is no future without hydrocarbons, just as there is no one climate savior,” said Simonelli. “Instead of focusing on the fuel source, we need to focus on emissions as reliance on hydrocarbons won’t disappear.”

He announced that the annual meeting was attended by more than 1,600 people, with more than 50% attending for the first time. Faced with surging energy bills for consumers and industry across the globe, he laid out three key points:

1) The need to accelerate the development and adoption of technologies to meet net-zero targets. On the turbomachinery side, that means such things as compressors and valves that don’t leak methane and other gases.

2) There is no future without hydrocarbons and there is no one climate savior.

3) There is no path to net zero without partnerships.

According to Baker Hughes surveys of oil and gas users, 57% said they are continuing with commitments to natural gas and LNG. “LNG and natural gas are not transition fuels, they are destination fuels that play a critical role in abundant, secure, and affordable energy,” said Simonelli.

The harsh realities of global energy were driven home by a series of speakers from around the world. Nurul Ichwan, Deputy Minister for Investment Promotion for Indonesia, explained that most energy in Indonesia comes from coal. He dismissed the idea that tens of GW of coal generation can be transitioned to renewables overnight. His country’s plan is to transition gradually from coal to natural gas while adding more wind and solar.

He commented that some countries in the region are promoting their own environmental credentials by reducing coal mining in their own countries while ordering more coal from Indonesia on multi-decade contracts.

“We want help in exploring and exploiting our own natural gas resources to aid in the transition from coal,” said Ichwan.

Farid Al Awlaqi, Executive Director of Generation for TAQA of the United Arab Emirates (UAE) said his nation has a different approach. It has plenty of solar and baseload nuclear but needs a lot more natural gas to meet swings in demand. “We are removing coal slowly out of the system and replacing with gas,” he said. “Our grids are not ready to manage intermittency.”

Helima Croft, Global Head of Commodity Strategy at RBC Capital Markets, said energy security is back as an energy priority. She is deeply concerned about energy supply over the next year, and said nations needed a diversity of sources. She added that Europe got lucky this year due to a milder winter. She complained about policy makers making it so difficult to fund oil and gas projects.

“We need to avoid underinvestment in oil and gas,” said Croft. “A stable supply of hydrocarbons is vital.”

Kazutomo Irie, President of the Asia-Pacific Energy Research Centre, went a stage further. He noted that emerging and developing nations place more importance on the security and affordability of energy supply than they do on decarbonization.

“We need natural gas to carry out coal-to-gas switching while building up renewables,” said Irie.

Octavio Simoes, CEO, Tellurian, said that while the supply of energy from renewable sources will grow massively in the coming years, it is still a long way from replacing fossil fuels. According to International Energy Agency estimates, the world will need at least 20% more gas and 40% more oil by 2050.

“No energy source has gone down in last 200 years except whale oil,” said Simoes. “The EU still gets 81% of its energy from fossil fuels, so replacing it in ten years is a fool’s errand.”

Yet the environmental lobby and the media are constantly vilifying non-renewable fuel sources. Adding to the problem is a big rise in the cost of the materials used in renewable energy.

“We are on the wrong path to decarbonization as we need affordable energy without volatility,” said Simoes. “We have written the first few and last few chapters on the energy transition and forgotten about the rest of the book. There is a big gap between vision and reality that is wide and getting wider.”

Yet investment in oil and gas in certain countries and political sectors is tabu, he added. The EU, for example, resists investment in gas but is spending far more on decarbonization and not getting there.

“Current energy transition Ideas are not executable,” said Simoes.

Onursal Soyer, Deputy Chief Executive Officer, Lambert Energy Advisory, described how Russian sanctions led the EU to buy up all available LNG at inflated prices to get through the winter and keep the wheels of industry running. As a result, a great many countries were denied LNG. That caused them to turn to coal.

“There was a record level of coal burned worldwide in 2022,” said Soyer. “Coal demand is not going away so replacing it with natural gas should be applauded.”

Hardline decarbonization policies, he added, are a major impediment to oil and gas investment. “This is causing coal to be used more and gas to be penalized, which is only making the situation worse,” said Soyer. 

To further worsen a difficult global energy situation, oil and gas consumption this year will be highest ever and 2023 will be, too. But even with prices high, major oil and gas companies are not investing due to policy hurdles. This investment is vitally needed to maintain current supply and create the oil and gas resources needed to take the world through the next 30 years.

It isn’t just oil and gas that faces shortages and high prices. Other materials are in a real supply crunch, said Kathleen Kelley, Founder and CEO, Queen Anne’s Gate Capital.

To meet the decarbonization and renewable energy targets that have been set, nickel production worldwide will have to go from 100,000 tons to 3 million tons a year. That is unfeasible. It is the same story with rare earths. Some point to the fact that Sweden has found new deposits of rare earths that can be used in batteries and other renewable energy. But those mines will take 10 to 15 years to come online.

“There was a record level of coal burned worldwide in 2022,” said Onursal Soyer, Lambert Energy Advisory.

“Investors are not allocating money to mining due to the industry’s poor performance on environmental, social and governance (ESG) metrics,” said Kelley. “We can’t possibly get to any climate goals based on the timescale of mining alone.”

Jessica Roberts, Head of Forecasting at Benchmark Mineral Intelligence, gave further specifics. Lithium batteries provided 700 kWH of power in 2022. By 2035, they are supposed to provide 5.5 TWH. That requires 300 new mines. It takes five to 25 years to open a new mine.

“We went from 100,000 tons of lithium a few years ago to a million tons last year and will need at least 2 million within a few years,” said Roberts.

Energy industry executives flip the script on unrealistic decarbonization goals. 

The Decarbonization Pushback Has Begun

Rotoflow, an Air Products business, is known for technological innovation in the development and production of turbomachinery over the last 65 years. The first Air Products turboexpander was developed in 1952, and the first practical application of radial turboexpanders in hydrocarbon processes by Rotoflow took place shortly thereafter. Its product range encompasses rotating equipment, alongside after-market services and support.

The company’s work is involved in turboexpander technology for the hydrocarbon, LNG, petrochemical, and industrial gas markets. Phillip Schuepbach, Business Development Manager – New Products and Aftermarket at Rotoflow, said, “Rotoflow’s designs have millions of successful hours of operation with over 3,000 units currently worldwide. Our core products include compressor-loaded expanders (companders), generator-loaded expanders, energy dissipative expanders, and specialty turbomachinery.”

Its full-service aftermarket solutions include field service, shop and field repairs, spare parts inventory, upgrades and rerates, performance and reliability assessments, remote monitoring, and training. Rotoflow’s service technicians can service turbomachinery at all phases of equipment lifecycle and plant types.

“Rotoflow equipment is efficient and reliable, which is a huge factor for oil and gas industry customers tasked with maintaining plant onstream availability. Our power recovery expanders are utilized to recover electrical energy from the expansion of the process stream fluid.” Schuepbach said. This recovered power can be used to offset other electrical usage in the plant, increasing the sustainability of a facility. By eliminating the costly gearbox for low power applications under 500 hp (<370 kW), customers can increase the sustainability of their facilities and recover more power, according to Scheupbach.

As an OEM, Rotoflow can provide both machinery solutions and turnkey support. “With service centers and field service technicians around the globe, we can mobilize quickly to safely and efficiently repair your equipment no matter where you are,” said Schuepbach. Rotoflow’s field service technicians and engineers handle everything from expander overhaul and changeouts to pump and compressor work, in addition to construction assistance and start up/commissioning activities.

One example of Rotoflow’s global reach is the Shanghai Solution Center. Rotoflow opened the new center in the Qingpu district of Shanghai, China to better serve the turbomachinery needs of customers throughout Asia, reported Schuepbach. In addition to servicing turboexpanders, centrifugal compressors, reciprocating compressors, cryogenic pumps, small steam turbines, gearboxes, fans, and blowers, the facility will also be used to build new expanders for small nitrogen generation plants. Finally, it will support Air Products equipment for the company’s Hydrogen for Mobility initiative.

Setting up inspection and service schedules can help preemptively identify repairs and overhauls. Onsite assessments serve as one of the best strategies for ensuring the overall performance of rotating equipment, said Schuepbach. Rotoflow’s experience as an owner/operator can be leveraged to get the most out of equipment. Proper training alongside product and operating knowledge minimizes downtime, maximizing safety, productive operations, and reliability.

Rerates and rebuilds also provide an opportunity to improve the longevity of turbomachinery. Rotoflow can identify causes of damage, recommend performance upgrades that reduce wear and tear, and help prevent future problems. “We have immediate access to materials and equipment and can rapidly dispatch a technician to complete your maintenance needs or get you back online as soon as possible,” said Schuepbach. Routine maintenance involving dirt cleaning, dust, debris, relubrication, and others must be considered, even in the cleanest work environments.

Rotoflow delivers design, engineering and production, and custom solutions. The company’s turbomachinery capabilities service the gasification, air separation, helium, LNG, hydrocarbon, petrochemical, and energy market segments. “In addition to broadening our footprint across the United States, we are enlarging our presence in many previously under-served local markets abroad,” said Schuepbach. Turbomachinery operators demand higher levels of reliability and efficiency. OEMs like Rotoflow—with investments in product development, vertical integration, and skilled teams—will subsequently see further growth. Demand in underserved markets like China and India will also be a strong driver for aftermarket turbomachinery service and support. 

Rotoflow, a manufacturer and operator of turbomachinery, is comprehensive in its approach to support the industry and provide machinery solutions. 

Vendor Spotlight: Rotoflow: Putting the Flow in Rotating Machinery

Hydrogen is the most abundant element in the universe. As a carbon-free energy source, it represents one of the paths to a decarbonized energy supply. Flipping the switch to a decarbonized, green tomorrow would be wonderful. The reality is that a number of considerations, technical advancements, socio-economic hurdles, and resource limitations need to be navigated first. This article explores the current state of hydrogen as a fuel supply; what can be accomplished within today’s installed base of power generation; identifies intermediate hydrogen-based carbon reduction solutions; and outlines the advancements necessary to realize the vision of an entirely hydrogen-fueled gas turbine power generation fleet.

When looking for carbon-free energy sources, the most apparent options are solar, wind, hydro, and nuclear. Yet each of these present unique constraints when asked to satisfy the world’s growing demand for electricity. With their fuel flexibility and high efficiencies, gas turbines have increasingly been relied upon to meet the growing global demand for power. Hydrogen represents a means to leverage this installed base to supply car-bon-free electricity in a less disruptive manner than a complete transformation to new power generating technologies. Fueling gas turbines with pure hydrogen produces only water vapor with zero CO

Hydrogen has been successfully blended with the fuel supply in gas turbines for decades. Recent field demonstration tests have shown successful operation at up to a 44% blend of H

 by volume for aeroderivative gas turbines, and up to 20% for large heavy-frame gas turbines. One concern with combusting hydrogen is increased NO

 emissions due to increased flame temperature. Studies have demonstrated negligible change to NO

Gas turbine OEMs are projecting the capability to operate on 100% hydrogen without impacting NO

 formation, primarily through advancements in combustor design and minor if any changes to existing SCR reliance.

The key to unlocking the full potential of hydrogen as a carbon-free energy source is to convert unused solar, wind, hydro, and nuclear energy available during low-demand periods to hydrogen via water electrolysis. The stored hydrogen produced can then be utilized as an alternate fuel by gas turbines to generate carbon-free electricity during high-demand periods.

Today, the United States utilizes approximately 10 quadrillion BTU/yr of natural gas to produce electricity, according to the U.S. Energy Information Administration. Total hydrogen production is approximately 1 quadrillion BTU/yr. Of this, green hydrogen production capability is only 269 trillion BTU/yr. Note that the vast majority of hydrogen produced today is NOT used to generate electricity—nearly all in the United States is used in refining petroleum, treating metals, producing fertilizer, and processing foods. Petroleum refineries use it to lower the sulfur content of fuels. With the introduction of the Inflation Reduction Act (IRA), the hydrogen industry is poised to take the biggest steps seen to date toward closing this production gap, with a $3/kg tax credit available for green hydrogen production and lesser amounts for more carbon-intensive forms of hydrogen production.

As the availability of hydrogen continues to grow, opportunities will arise for power utilities to introduce it as a carbon-free fuel stream for their gas turbine fleets. Making the change from natural gas to 100% hydrogen in a single step may not be feasible in the near term given the required energy consumption and lack of availability of hydrogen. A reasonable approach may be to introduce it in increasing volume in blends aligned to availability in given geographic areas. The following factors should be considered when approaching these blending opportunities: hydro-gen supply and storage, fuel conditioning and blending skid design, gas turbine capability and period of use, and personnel safety and training.

Table 2 provides a mathematical model of a blending application for a 60Hz GE LMS100 PA+ gas turbine genset operating in simple cycle mode. Figures presented are based on published full-load, beginning-of-life performance for the LMS100 PA+, based on data from GE Gas Power. Based on the relative density and LHV differences between natural gas and hydrogen, one can see the total flow more than triples as you approach 100% hydrogen operation. (This model assumes the line pressure does not change across the range of blending %.) An important consideration for retrofit applications is accommodating this increase in volumetric flow once the 75% blending threshold is approached, where total flow is approximately doubled. Existing piping infrastructure supplying the genset, as well as the fuel delivery piping at the combustors, will need to be evaluated for the increased relative pipe velocities this will result in.

Assuming the hydrogen delivered in the Table 2 example is green or pink hydrogen, another interesting point is the amount of water required. These figures represent the theoretic water necessary to produce hydrogen, which are significant in and of themselves, but do not take into consideration any losses encountered during the purification process of the water to meet a given electrolyzer application. For instance, if sea water is considered as the water source, a desalination process is necessary as well as a deionizing process. Considerations and technical advancements in this area will be necessary to introduce green or pink hydrogen at the scale necessary for power industry consumption.

Blue hydrogen, and turquoise hydrogen (further down the road) represent alternate sources of carbon-free hydrogen that are based on the conversion of natural gas with some form of carbon sequestration. For blue hydrogen, carbon capture and sequestration systems are added to the existing grey hydrogen reforming process to eliminate CO

 emissions. For turquoise hydrogen, a pyrolization process produces hydrogen and carbon in the form of carbon black versus CO

. The carbon is immediately sequestered and available for alternate usage points, replacing more carbon intensive sources.

Hydrogen represents a promising way to reduce the carbon footprint of the power industry. Growing advancements in hydrogen production technologies coupled with strong support from the federal government by way of the IRA bring the opportunity to deliver solutions to the forefront. State and local incentives likewise serve as a catalyst for adoption.

Recent in-the-field hydrogen-blending demonstration projects on both aeroderivative and heavy-frame gas turbines indicate the power sector is ready to take the next step. Implementing a gradually increasing hydrogen-blending strategy for the gas turbine fleet represents an opportunity to realize these benefits today while laying the framework to support a carbon-free energy sector of the future. 

Gus Graham is Business Development Manager at Carbon Reduction Systems (CRDX), a technology-based manufacturing company developing products and services for reducing the use of carbon-based fuels and their emissions. Visit www.crdxs.com or call +1 518-765-8329.

Anthony Brough, P.E. provides business development support for CRDX. He can be reached at abrough@CRDXS.com.

Hydrogen plays a significant role in decarbonizing power generation.

Hydrogen Turbines in Power Generation

PowerGen International, held Feb. 21-23, returned to Orlando, Florida, for 2023. The show appears to be regaining its audience again after a long absence due to the pandemic.

Clarion’s Vice President of Content David Wagman kicked things off by emphasizing the theme of the conference: Destination 2050—reaching net zero carbon emissions by 2050 via industry innovation.

Jan Aspuru, the COO of Orlando Utilities Commission, discussed its microgrid lab and the development of a hydrogen energy storage system. He also spoke on the company’s Osceola generating station, which utilizes GE gas turbines. He noted how intermittent solar is a renewable source for the state of Florida, and that natural gas is seen as a more persistent option. Traditional power needs to work in tandem with newer solutions to retain grid reliability.

Alex Glenn, CEO of Duke Energy Florida and Midwest, detailed different areas that impact the plans to reach net zero. These include local and federal government partnerships, maintaining equipment performance, addressing concerns of stakeholders, and supply chain constraints.

“Coal will represent less than 5% of power generation in 2030,” he said. “A diverse generation mix is key to customers.”

An early presentation provided an overview of direct air capture (DAC) technology and the status of developments and deployments to date. It included a discussion on potential applications for coupling DAC technology with existing power assets to lower the carbon footprint.

Eric Ping, Vice President, Technology at Global Thermostat, explained his company’s DAC system. Ambient air comes in from the sides and is heated to 200°F. Then the CO

 is extracted at a rate of 400 ppm. It uses amine chemistry in solid form instead of the usual solvent form.

“Direct contact steam stripping delivers latent heat into the system,” said Ping. “Multibed adsorption removes significant plant capital expense.”

He added that front-end engineering design (FEED) studies are ongoing for sites in Texas, Illinois, and Alabama to identify risks, establish a plan of execution, and develop a budget before projects are approved for funding.

Kevin Lauzze, Vice President & Project Director at Sargent & Lundy, added that a ring-shaped DAC module with 10 segments was the best design. Computational fluid dynamics (CFD) was used to confirm the viability of that size and design and to ensure there were no fatal flaws in the air flow. A fan 15 feet in diameter turned out to be optimal. When larger fans were modeled, the structural design aspects scaled poorly. Thus, little or no economies of scale were realized in process equipment sizing.

DTE Energy’s Dearborn Central Energy Plant (CEP) generates electricity and distributes chilled water, hot water, and steam to buildings at the Ford Dearborn Research and Engineering Campus (REC). The CEP consists of a combined heat and power (CHP) plant and a chilled/hot water plant for combined power and steam generation. The energy produced from the CHP is sent to DTE Electric. Steam, hot water, and chilled water are sent to the REC. The CHP plant can generate 34 MW and produce up to 225 kilo-pounds per hour (KPPH) of 200 PSIG saturated steam. It consists of two 14.5 MW Solar Titan 130 gas turbines, a 5 MW condensing steam turbine from Siemens Energy, and two Rentech Heat Recovery Steam Generators (HRSGs) (370,000 lb/hr).

DTE recently installed a hybrid analytics solution that combines machine learning and advanced pattern recognition (APR) software with a digital twin to monitor and improve the performance and reliability of the plant.

Kevin Siess, Facility Manager at DTE Energy, said the CEP opened on the first day of 2020. COVID-19-inspired lockdowns provided the impetus to innovate in plant monitoring.

“A single person looks after the entire 34 MW, 87,000 square foot facility 76% of the time,” said Siess.

Teething troubles were inevitable. The first year saw nine unit trips, but that fell to five in year two and two in year three. The number of hours also dropped drastically—from 50 hours of unplanned downtime in the first year to four hours in the third year. Siess said 12,000 data points are analyzed from front-end plant controls, sensors in most components and systems, computerized maintenance management systems (CMMS), and MapX software for advanced pattern management (APM) and modeling.

“Our plant operators are also our maintenance staff who can monitor the plant and overall control systems while they are doing their rounds,” said Siess.

Coal-to-gas conversions were covered in several sessions during the show. While some dream of transitioning to renewables in a matter of a few years, reality is beginning to set in. By moving coal resources to natural gas, major emissions reductions can be achieved without causing grid disruption or causing rolling blackouts as has been the case in California of late.

Jonas Hackmann, President of Fossil Power Systems, talked about the many technical and project execution challenges to be considered when planning to convert a tangential fired furnace from coal to natural gas. He gave a rundown of combustion air system modifications, fuel system designs, boiler modeling, and emissions reductions, as well as factors affecting equipment and retrofit cost, operation, maintenance, and performance. He made the point that coal-to-gas conversions can bring about emissions reductions of about 50% in CO

Another session noted strong interest in 100% hydrogen firing or co-firing large utility-class coal, oil, and natural gas boilers to achieve decarbonization goals. While no singular template exists for all retrofits, the session laid out key fac-tors and potential modifications across a range of units, including both wall-fired and tangential fired boilers. What surprised some attendees was the fact that running hydrogen in boilers is nothing new.

“We have had a great many package boilers running nothing but hydrogen for decades,” said Denis Osowski, Development Director, Engineering Technology at Babcock & Wilcox.

He questioned whether the use of hydrogen in boilers made sound economic sense most of the time for the production of power and steam. In situations where there is a hydrogen hub operating and a coal boiler is sitting nearby, it may make sense. But overall, he said hydrogen is a super expensive fuel and the use of it may require expensive system and equipment modifications. It is technically feasible but often won’t make economic sense.

Osowski showed a chart of gaseous fuels and how impurities often present in hydrogen in very small amounts can make a huge difference in the fuel and how the gas moves through the pipes. Further problems mentioned include the need for bigger pipes and valves, safety features to prevent leakage and cope with hydrogen’s wider explosive limit, the need for more fuel nozzles to spread the flame better and improve combustion efficiency, and modifications to igniter systems and flame scanners.

Rethinking data center power was the topic of a session toward the end of the program. Todd Forrest, Senior Project Development Engineer at HDR, briefed that there are already more than 4 GW of data centers in the U.S. in primary and secondary markets, and the market is experiencing 11% year-over-year growth. He doesn’t anticipate that growth rate slowing down any time soon.

The typical 100 MW data center includes a dedicated substation, often has two independent utility feeds for redundancy, and contains a lot of equipment to shift voltages down before feeding current to the equipment.Most of the time, these facilities use diesel generators for backup power.

But more data centers are looking at CHP to enable them to be fully in control of power supply, or to supplement grid power. In some cases, the CHP facility harnesses excess heat to create chilled water for data center consumption, sells excess power back to the grid, and has the option of using that power to keep the data center running in the event of a natural disaster or grid failure.

Carbon capture, utilization, and storage (CCUS) is an important technology for decarbonization goals. A panel of experts focused on point source carbon capture, geological storage, pipeline transportation, monitoring, costs, and other relevant areas. Richard Esposito of Southern Company emphasized the importance of bringing projects in on time and reviewed the basics of CCUS. Jose Figueroa of the National Energy Technology Laboratory (NETL) spoke on the need for an integrated carbon management approach and the importance of developing advanced technology quickly.

Mark McKoy, also of NETL, went over pipeline infrastructure development projections and the expansion of the industry.

“The U.S. Department of Energy (DOE) is working to implement further initiatives for infrastructure changes. This includes providing technical assistance and information for undertaking CCUS projects and arranging co-founding support for carbon storage facility pilot projects,” said McKoy.

Bob Slettehaugh of Kiewit spoke about the costs of CCUS as an emerging market and the importance of strong partnerships for all parties involved in its development.

Sanjay Hingorani, Chief Engineer and Director, Customer Technical Support at Mitsubishi Power Aero, covered aeroderivative gas turbine upgrades. Specifically, for the fleet of FT8 and FT4000 series gas turbines. The presentation covered several areas where aeroderivative on-demand power technology is improving through product upgrades. Examples were FT8 wet compression, FT4000 performance improvements, digital data solutions and remote monitoring.

“Existing engines can implement wet-compression technology, i.e., water injection, which leads to a 12% power increase on an FT8 gas turbine,” he said.

He highlighted the capability of the company’s aeroderivative units to blend hydrogen and natural gas. Hingorani also addressed the topic of hydrogen as a gas turbine fuel option, and Mitsubishi Power Aero’s efforts in preparing for expected technology changes.

Charlie Green from IHI and Jeffrey Goldmeer from GE Gas Power presented on the use of ammonia as a zero-carbon fuel source for gas turbines. A joint study focused on comparing ammonia to hydrogen and/or ammonia converted to hydrogen. The goal of the study was to find an economic and technical solution for reducing global CO

 emissions in coun-tries with net import resource supply chain complications, such as Japan. The advantages and challenges of using ammonia as a fuel source were discussed from technical and economic perspectives.

“Ammonia has an advantage over hydrogen as a net-zero carbon fuel solution due to its capability to persist over long distances with less effort,” according to Green.

Goldmeer reviewed the cost analysis of the study, which included transportation over land, conversion, liquefaction, storage, sea transport, port storage, and reconversion of the ammonia. Three potential pathways were considered: all ammonia, all hydrogen, or converting back to hydrogen for end use. Ammonia was found to have a lower landed cost (cost of shipping) compared to hydrogen. Transportation was noted as the largest cost driver due to fuel prices.

“Liquified natural gas in combination with carbon capture and storage was found to be competitive in terms of carbon reduction due to infrastructure compatibility,” reported Goldmeer.

The next PowerGen International event will take place in New Orleans Jan. 23-25, 2024. Read more of our PowerGen 2023 coverage at turbomachinerymag.com. 

The dominant themes at the show included hydrogen, the evolution of power plant, and CHP. 

PowerGen 2023 Show Report

Securing reliable power can sometimes prove difficult, especially if you want it in a hurry. In this article, major turbomachinery OEMs, working alongside installation and packaging service providers, outline one solution: mobile gas turbine power units (MPUs). The story covers what’s driving demand for MPUs, their various design goals, and examples of different customer requirements. In addition, problems facing the industry as well as practically applied solutions are discussed. For example, demand currently exceeds supply in many areas, with further growth anticipated by manufacturers. Below, we examine the cross section among aeroderivative gas turbines, logistics, hydraulic fracturing (fracking), LNG, remote operations, hydrogen blending, inclement weather events, and more, with mobile power at the focal point.

Power producers who strive to supply reliable and affordable power to their customers require dispatchable assets that can provide power when needed. On-demand, aeroderivative power plants complement the rise in renewables while maintaining grid stability and reliability because of their inherent fast-start and flexible design capability.

Mitsubishi Power Aero offers a 31 MW FT8 MOBILEPAC aeroderivative mobile powerplant.

“The modular design of the FT8 enables faster deliveries, quick installation, and commissioning,” said Harsh Shah, Vice President, Sales and Business Development at Mitsubishi Power Aero.

Trailers can be transported and relocated easily. He added that the MOBILEPAC design eliminates the need for concrete foundations, reduces installation time (less than two weeks), and has a footprint of as little as 4,300 square feet. This design, coupled with the MOBILEPAC’s fuel flexibility (diesel, natural gas, hydrogen, and LPG), has resulted in over 130 gas turbine packages deployed globally.

“MPUs provide reliable power to ensure that schools, hospitals, industries, and other basic infrastructure can remain operational,” said Harsh Shah, Mitsubishi Power Aero.

“In these cases, MPUs provide reliable power to ensure that schools, hospitals, industries, and other basic infrastructure can remain operational,” said Shah.

Rapid deployment and black start capability make the FT8 MOBILEPAC unit ideally suited for emergency power needs arising from weather-related events or other unforeseen situations.

“For some applications —such as distributed power, crypto-mining operations, and e-fracking a—mobile power solution is necessary,” added Shah. “Customers select FT8 MOBILEPAC because of installation ease and relocation capabilities.”

The high reliability and 5-minute fast start capability of these packages provide flexibility when dealing with uncertain load forecasts. Fast relocation allows the FT8 MOBILEPAC to be applied to electric well-stimulation systems powered by natural gas, resulting in less disruptive and safer fracturing operations. “Mitsubishi Power Aero provided three FT8 MOBILEPAC gas turbines on top of eight stationary operating units to Puerto Rico,” said Shah. These gas turbines continue to secure reliable power on the island. The equipment provides power and can be relocated to isolated areas in case of an outage or disaster.

In 2021, Mitsubishi Power Aero completed a turnkey installation and commissioning of five 30 MW mobile units in 120 days from contract to commercial operation prior to peak season in Mexicali, Mexico. An additional three units were added to the same site to support summer 2022 peak requirements and offset the shortfall while optimizing the existing power infrastructure.

For another example, 54 MOBILEPAC packages were installed at 12 sites across Algeria. Since initial installation, almost half of the units have been relocated to support even more remote communities. In one region, a special control system has been implemented to manage output of several mobile units, which has greatly improved grid stability and significantly reduced instances of blackouts. Factors to consider when purchasing an aeroderivative mobile power unit are delivery and installation lead times, fast relocation capability, fast startup, minimal space requirements, high reliability, and minimal maintenance downtime.

Naidu Balachandar, Leader of the Aero Product Management Organization at GE Gas Power, discussed the OEM’s active mobile gas turbine fleet. GE’s trailer-mounted TM2500 gas turbines are derived from jet-engine technology. They can be mounted on a wheeled trailer for enhanced mobility. This provides a baseload bridge to permanent power installations, or for generating backup power in the wake of natural disasters, plant shut-downs, grid instability, or in isolated locations. They can run on natural gas or diesel, as well as sustainable aviation fuel blends. In addition, the TM2500 is hydrogen capable, with the ability to burn up to an 85% H

 blend, ensuring a pathway to help utilities and other stakeholders reduce their carbon emissions.

GE’s LM2500Xpress package is built on LM2500 aeroderivative dry low emissions (DLE) gas turbine technology. It can be installed in two weeks. Its plug-and-play nature provides flexible power efficiently wherever needed. It is available in simple and combined cycle configuration, and is also hydrogen-capable.

“Customers need two things in any mobile power package: the ability to put power on the grid within a short time frame and reliability,” said Naidu Balachandar, GE Gas Power.

“These units can reach production capacity in a short time, which enables power providers to quickly meet peak demand and ramp down units to avoid wasting energy when demand is lower,” said Balachandar.

Balachandar added that customers need two things in any mobile power package: the ability to put power on the grid within a short time frame —TM2500 packages can deliver power within 10 days—and reliability.

“Over 4,000 aero derivative gas turbines have been used in power generation, marine, and oil and gas applications,” said Balachandar.

Solar Turbines has sold a variety of mobile power unit configurations since 2000. Currently, the company offers two solar mobile turbomachinery (SMT) versions. The smaller mobile unit (SMT60) is powered by Solar’s Taurus 60 engine and offers 5.7 MW of power at ISO conditions in a single frame. The dual frame SMT130 offers 16.5 MW ISO of power with the Titan 130 engine at its core.

With more than 35 units shipped, the SMT60 is a popular unit to support emergency power, back-up power applications, and electric fracturing (e-FRAC) operations to name a few, said Jay Mistry, Mobile Turbomachinery & Electric Motor.

“With the continuing need for global power and challenges in grid development and implementation, the need for flexible mobile power will continue to grow,” said Jay Mistry, Solar Turbines. Compressor Business Manager at Solar Turbines.

After hurricane Nicholas hit Houston, Texas, in September 2021, two SMT60s were deployed to provide power for the displaced population. It offers a compact footprint with a 56-foot long trailer that is 8.5-feet wide and 13.5-feet tall that can be setup in less than four hours.

These units are capable of digital load sharing and can be integrated with any solar products. Add-on options for multi-unit power management or microgrid controls are available.

Greek company Mytilineos has expertise in gas turbines including mobile units. It has developed a fast-track approach with trailer-mounted balance of plants. All packages are delivered assembled and pre-commissioned, limiting on-site installation requirements.

“The mobile plants are dual-fuel capable (natural gas or distillate/DFO) with related fuel handling and treatment systems packaged in trailer mounted form for quick delivery,” reported Kostas Horinos, Executive Director of Mobile Power Projects at Mytilineos.

Mytilineos undertakes the engineering, procurement, and construction (EPC) activities through to project completion. It supplies solutions based on the needs of the client. “Our portable MPUs using aeroderivative gas turbine equipment generate up to 32 MW per unit,” said Horinos.

“Mytilineos undertakes EPC activities through to project completion, supplying customized, fast-track solutions,” said Kostas Horinos, Mytilineos.

One project was in Takoradi, Ghana. Operation and maintenance for 10 GE TM2500+ mobile gas turbine power generating sets. And in Algeria, Mytilineos provided EPC for 38 mobile gas turbine power generating sets with a total output of 775 MW.

For over 20 years, USP&E has specialized in the supply of new and surplus power plants, EPC, and managing the reliable operations of the plant. The company specializes in the mobile power market. “Building a new power plant from scratch can take years, and this time is not always available”, said Will Gruver, Founder and Group CEO at USP&E. “Production lead times with major OEM’s can be as long as two years, while we have the same equipment ready to dispatch in a matter of weeks.”

For immediate power, USP&E has a large number of GE TM2500 mobile turbines available and is currently seeing high demand. These trailer-mounted units offer 26 MW.

“Building a new power plant from scratch can take years, and this time is not always available,” said Will Gruver, USP&E.

USP&E is sending six TM2500’s to crypto mining projects where the client moves them every couple of months to new gas sources. Another client is using 10 TM2500’s to solve a utility crisis. The company is also involved in hydrogen generation projects.

LifeCycle Power provides 5 MW to 35 MW mobile packages for utility and oil and gas applications in the United States. Its fleet utilizes Solar SMT60, Solar SMT130, Mitsubishi FT8, and GE 2500 machines. “Many current applications require fast deployment and movability,” said Geoff Bland, Director of Engineering & Operations, LifeCycle Power. Emissions and fuel variety is increasingly important.

Lifecycle Power’s turbines generate as little as 0.15g/bhp-hr (grams per brake-horsepower hour) NO

. There is little to no methane slip, and they can run on diesel and untreated gas. Another benefit is that installation only takes a few hours. Being able to start on diesel and transition to natural gas is a major factor for many customers. The market for natural gas MPUs is gaining ground due to regulatory mandates around NO

 and particulate matter at low load that reciprocating engines find difficult to achieve.

“Many current applications require fast deployment and movability,” said Geoff Bland, LifeCycle Power.

“Natural gas isn’t available for every location, although the shortage of high horsepower diesel engines has driven an increased market in virtual pipeline transport of CNG and LNG and an increase in natural gas engine sales,” stated Bland. “Turbine solutions that can meet the demands of the market are maxed out and held back by build speed and supply chain restrictions.”

Dynamis Power Solutions offers a variety of mobile turbine generator packages, ranging from 5 MW to 35 MW. The kits are Department of Transportation (DOT) compliant and are easily transported and installed. “Dynamis uses technologies such as GE’s LM2500+ G4, rated at 35 MW, coupled to Brush generator technology,” said Travis Simmering, Vice President of Sales & Marketing at Dynamis.

“Dynamis units can operate in numerous locations and applications, providing reliable and efficient power,” said Travis Simmering, Dynamis.

Dynamis integrates power generation assets onto a hyper-mobile trailer system, with additional ancillary support and an optional control trailer. The packages go from parked to power in 6 to 8 hours. An auto leveling system enables site-to-site transport without a concrete mounting pad. The turbine assembly has an automatic transfer switch, allowing the package to operate in island mode post startup. Simmering said features such as an integrated gas filter and air pre-filter maximize uptime increase the span between maintenance intervals. Recently, Dynamis supplied DT35’s (based upon the GE LM2500+ G4 prime mover) to rental customers in the oil and gas market. “Dynamis units can operate in numerous locations and applications, providing reliable and efficient power,” said Simmering.

Dynamis has seen a steady rise in demand for natural gas mobile power, larger turbine power blocks, and non-detrimental emission reduction solutions.

Over the last decade, the market has had an in-flux of natural gas power, replacing older diesel technology with cleaner, more sustainable fuel, reported Simmering. The growing demand for cleaner technology and larger power continues to challenge the mobile power market to innovate mobile turbine modularization design and production.

Mobile power gas turbines can be up and running in a matter of hours to effectively get power where it’s needed.