Drew Robb

The first PowerGen since 2019 happened in Dallas in May of 2022.

PowerGen 2022 represented elements of both joy and sadness. Joy at once again seeing our friends and the many vendors that are the lifeblood of the industry. Sadness as the show feels like the former capital of a once mighty empire that has been relegated to a peripheral and decidedly provincial role.

But at least there was some fighting talk during the Monday morning keynotes. Sandwiched among those advocating a hydrogen-powered and renewable future, former U.S. Secretary of Energy Rick Perry offered a reality check. He questioned the feasibility of achieving the net-zero targets for 2050 and defended fossil fuels and nuclear power.

He campaigned for a balanced approach, saying we need all sources of generation to power the nation. He made it clear that regardless of the plans for wind, solar, batteries, and hydrogen, we are going to need fossil fuels for a long time into the future. He also called for more attention to be paid to areas such as carbon capture, utilization, and storage (CCUS) and small modular reactors (SMRs) for nuclear power.

"Does anybody think that we're going to be able to address all of the needs of the United States by 2035, with just renewables?” said Perry. “ And if the world went to net zero by 2050, it would be one of the most apocalyptic loss of life in the world's history.”

The Siemens Energy VIA mobile unit was one of the few pieces of turbomachinery in evidence at PowerGen.

Siemens Energy SGT-300 inside a massive VIA mobile trailer.

A session on the future of gas turbines focused on hydrogen. Adam Foust, Gas Turbine Proposal Manager at Siemens Energy, began with a history lesson. Advances in thermal barrier coatings (TBC), aerodynamics, manufacturing techniques such as additive manufacturing (AM or 3D printing), and combustion had led to steady gains in efficiency and MW capacity. He expected the industry to continue to make progress in raising efficiency and performance.

“AM is a key part of those improvements as it has led to increased firing temperatures, greater fuel flexibility and higher efficiency,” said Foust.

3D printing has enabled component and system designs with more complex geometries, improved cooling flows and greater rates of heat transfer. Better mixing of fuel and air in the combustion system means higher firing tempereates as well as lowered emissions and better fuel flexibility.

“In 1985, we were at 90 ppm NOx and that also needed dilution,” said Foust. “Now, we are at 5 ppm NOx.”

By introducing some hydrogen into the natural gas, he added, the amount of carbon dioxide can be lowered. Siemens Energy gas turbines have been tested to operate at 30% hydrogen or more. One has run successfully with 100% hydrogen.

The future of gas turbines, he said, is focused on improving efficiency, increasing hydrogen fuel flexibility, and bringing more AM into GT parts and even blades, while integrating renewables and energy storage. To manage flashback risk in hydrogen combustion, Foust noted in answer to a question that there is a derate with current combustion technology. But new approaches are addressing that.

Ajay Gupta, Director of Product Line Management at Mitsubishi Power, also outlined his company’s pathway to 100% hydrogen generation.

“Gas turbines are vital to the future energy mix but they need greater flexibility,” he said. “Combustor modifications are needed to combust hydrogen.”

Gupta also touted hydrogen as a good form of long duration storage and batteries as short duration storage. And he covered his company’s

Takasago Hydrogen Park in Tokyo that is scheduled to begin operating next year. It will produce onsite in electrolyzers and stored it. Beginning with the smaller H25 gas turbines, the plan is then to then have H100 turbine run on 100% hydrogen and validate them site. With that achieved, larger Mitsubishi turbines can then be tested and validated.

Richard Saab of Siemens Energy discussed HRSGs and hydrogen.

Most attention on hydrogen has centered upon the impact on the combustor. But what about the heat recovery steam generator (HRSG)?

Another session took up this subject. Richard Saab, a Sales Manager at Siemens Energy, made it clear that a great deal of the global gas turbine fleet is connected with HRSGs. He offered some insight into the main impacts are of firing H2 in gas turbines on HRSGs.

For example, the combustion of hydrogen will occur at higher flame temperatures than natural gas. One of the side effects of that fact is the production of more nitrogen oxides (NOx). Secondly, the water dew point of the flue gas increases when firing hydrogen in the GT. This means that cold parts which are in contact with flue gas will form condensation quicker. Thirdly, firing H2 adds extra volume to the exhaust gas flow compared to firing natural gas. Last, but certainly not least, he discussed the various safety aspects that apply when firing hydrogen in the gas turbine.

Many of these impacts are due to the characteristics of hydrogen. It has a high mass related heating value of 51,600 BTU/pound, as well as a density that is eight times lower than methane. Despite that, its benefits are attractive.

“Natural gas generation with 30% hydrogen by volume delivers an 11% reduction in CO2,” said Saab

Hydrogen’s wider explosion range and lower ignition energy compared to natural gas presents some safety concerns for HRSGs. However, he said the hydrogen will accumulate in the same areas of the HRSG as natural has such as the attic. Current safety procedures already take this into account and should be sufficient.

On the exhaust side, hydrogen requires a much higher volume of gas be passed through the turbine due to its density. Thus, the HRSG needs to be engineered to avoid exceeding the casing’s design pressure. Increased pressure drop, too, can cause derated performance.

As emissions of NOX will go up as more hydrogen is added, he recommended leaving space in designs for new HRSGs where an SCR could be added in the future if needed.

“Those wanting to burn hydrogen in future should set it up the HRSG for it upfront,” said Saab. “Those that do receive a hydrogen-ready stamp that can help with financing and will minimize costs. It is far more difficult to do afterwards.”

Retrofitting an SCR into existing HRSGs would be extremely challenging. If HRSG needs a LOT of modification, might need a new HRSG if it is older.

Other impacts: Condensation increases in the back end of the HRSG due to Hydrogen. Above 50% by volume, a lot more water accumulates and this can cause more moisture in the HRSG tubes. Finally, he touched on supplementary duct firing. Hydrogen can be fired in duct burners. He suggested that separate valve trains and firing elements be installed due to differences in heating value and supply pressure.

“Keep different trains of duct burners with different design each for natural gas and hydrogen,” said Saab.

With all the talk about green hydrogen, why not all in green steam? That was the question posed by Paul Brown, Vice President Custom Systems, Industrial Watertube Boilers at Cleaver Brooks. Hydrogen, it turns out is a viable fuel source whether a packaged boiler serves as a back-up to the CHP system, if it is used for heating steam, or is producing steam to generate power in a steam turbine.

“The technology needed to facilitate hydrogen firing and eliminate CO emissions from the system is not new and does not increase risks associated with packaged boiler or burner design and operation,” said Brown

He focused on packaged water tube boilers used as auxiliary boilers in plants. When steam is down, they are called upon to be used as processboilers, for district heat and for cogeneration. But there are design factors in both the boiler and combustion system that must be considered. The good news is that current boilers are conservatively designed so they are in good shape to accommodate the burning of hydrogen.

“The flame temperature is higher with hydrogen so there is a slight possibility of overheating,” said Brown. “But as most furnaces today have a membrane wall construction with water-cooled surfaces, they can usually handle higher temperatures without changes.”

As far as unburned hydrogen collecting in pockets at the top of the boiler due to low molecular weight, once again there is little risk. Brown said D, O, and A style boilers leave very little space for accumulated hydrogen. 

“Purge cycles will be mandated and they will get rid of any unburned hydrogen along with any worries about explosion,” said Brown.

He gave the example of a 100,000 lbs per hour boiler running at 600 PSIG and 750F.Operating on natural gas its efficiency is 84%, which drops to 79.5% at high heating value (HHV) for hydrogen. At a low heating value (LHV), hydrogen has 94.1% efficiency, higher than natural gas’ 93%.

“Pay attention to LHV and HHV numbers and know which one is being referred to and design to deal with it,” said Brown.

Superheated steam from hydrogen would have a lower steam temperature (730F) compared to 750F for natural gas due to hydrogen’s lower mass flow. This calls for minor design tweaks like adding more heating surface to the boiler.

A forced draft fan in an auxiliary boiler running natural gas would need to be 350 hp compared to 250 hp when fired by hydrogen. The reason a less powerful fan would be needed for hydrogen is that less combustion air is needed in combustion.”

Further pointers: hydrogen’s typically low supply pressure requires larger fuel piping than natural gas to obtain the same BTU input to the boiler. Overall hydrogen components are likely to larger and more expensive. And to cope with higher NOx, hydrogen systems need flue gas recirculation (FGR) and/or SCR.

Above 5% hydrogen will push NOx over the limit so need to do something to compensate,” said Brown.

All hydrogen sessions at PowerGen were standing room only.

Day 2 of PowerGen again featured plenty of hydrogen sessions. All were standing room only. Matt Ballew, Technology Strategist for Vista, said hydrogen can either be viewed as a threat or as an opportunity.He sees plenty of opportunity for hydrogen as a baseload fuel as well as in energy storage. When wind is strong at night, turn that power into hydrogen via electrolyzers and then sell later when prices are high.

The most surprising statement was about cost. Ballew said that the most optimistic projection is a dollar a kg or 7.45 cents per mm btu, which is twice that of gas – and he’s talking about hydrogen reaching that level of cost by 2050. That means hydrogen must rely on a tax on carbon or other incentives to make progress in markets.

“The markets don’t make sense right now,” said Ballew.

Hydrogen panelists from left to right: Ballew, Ettlinger, Subramanya, and Emerson

Dr. Ben Emerson from Georgia Tech covered how a retrofittable combustion system is needed to make hydrogen combustion work properly and to avoid flashback – the flame propagating upstream into the nozzle and igniting.

He called into question the idea that hydrogen resulted in higher NOx. His argument centered around the use of Dry Low NOx combustors for natural gas making it difficult to do an apples-o-apples comparison as hydrogen combustion has more moisture content. He said he was discussing this with the EPA. He ended by saying that it may be possible to design a combustor for hydrogen that lowers NOx significantly.

Alan Ettlinger, Senior Director of Research Technology Development at New York Power Authority (NYPA), delivered a teaser about testing being done in conjunction with EPRI. He gave no real concrete details but said a peaker plant on Long island is being run on “more than 5% hydrogen.” I got the idea it was a lot more than 5% but he wouldn’t say. Ettlinger said we would be surprised at the findings of a study being released in the fall.

He did comment on some of the challenges with hydrogen. NYPA trucked in the hydrogen, which he said was a flawed approach.

“The largest hydrogen storage facility in the USA is at NASA and it would only run our plant for three days,” he said. “The hydrogen supply problem needs addressed either by large-scale electrolysis or pipelines.”

Nethra Subramanya from GE laid out GE Gas Power’s capabilities for hydrogen blends in gas turbines. She felt that it makes most sense to blend with natural gas rather than seek to operate at 100% hydrogen.

There is no substitute for in-person networking and face-to-face interaction at industry events.

The second day ended with a dose of reality on hydrogen.

John Gulen, Bechtel Fellow for Bechtel Infrastructure and Power, began his talk by noting the hydrogen “hullabaloo.”

“I’m at PowerGen but where is the power and where are the turbines?” he said. “This is not the PowerGen I remember.”

He revealed some research findings on the optimum size and type of gas turbine to operate hydrogen. This will be covered in more detail in an article in the next issue. But it revealed that larger turbines would be far less efficient due to the amount of hydrogen that would have to be produced via electrolysis to power a combined cycle plant. The sweet spot, Gullen said, was around 200 MW.

“The smaller the GT, the better the chance of burning meaningful amounts of hydrogen,” said Gullen.

He was followed by Ammar Moosa, Commercial Manager for ProEnergy. Moosa addressed the need to design resiliency into aeroderivative turbine peaking facilities.

“Resilience is a function of time and how fast you can respond to any disruption,” he said.

Part of the problem is that no two gas or coal plants are the same. This is quite different from other industries such as oil & gas and data centers. In these fields, repeatability is everything and that greatly improves resilience.

“Aging baseload retirements mean there is more pressure on peaking plants,” said Moosa. “Peakers are operating more than they were designed to these days.”

In addition, extreme weather conditions cause devastation with renewable output. With more wind and solar on the grid, standby peakers are needed more than ever.

ProEnergy subsidiary WattBridge aims to help bridge the gap. It has installed 1824 MW of peaking power in the Houston area and aims to add 4 GW of new power generation in Texas by 2025. All LM6000P units can run at 30% hydrogen fuel with plans to reach 50% by year end.

The company’s strategy is to find the perfect location for peakers which has high pressure firm gas supply nearby as well as transmission, and water.All facilities are owned by WattBridge and standardized in design.

The H.O. Clearke Power Station, for example, has 6 LM6000Ps. That machine was chosen due to its low turnkey $ per kW, fast start within 10 minutes, rapid ramp and low turndown, and no maintenance penalty for frequent starts. WattBridge includes various cooling methods including fogging to augment power output on hot days. 

During the big Texas story of February 2021, the company’ units remained 100% available, oprerating for 141 hours over a 6 day period – at a time when 60% of ERCOT capacity was unavailable.

Articles

HYDROGEN GENERATION, DECARBONIZATION, AND DIGITALIZATION DOMINATE

PowerGen 2022

Bucket inspection of high-pressure steam turbine

Many OEMs are moving away from supporting legacy generating fleets. Yet the service needs of this equipment have not dissipated.In fact, that equipment continues to provide grid stability and is being asked to operate in conditions for which it was not designed.

Large generating equipment, for example, is being dispatched in a load-following manner with peak demands filled by machines designed for baseload. As wind and solar generation wind down in the evening due to natural conditions, and power demand increases as a result of people arriving home, these units are asked to pick up that load. As a result, utilities are asking for different solutions to make equipment dispatchable. Maintenance remains vital so their equipment doesn’t become unsafe to operate.

“The investment to maintain reliability is different than the investment to maintain efficiency,” said Jay Eldridge, Vice President of Sales & Marketing at MD&A. “Our role as a full-service provider is to help customers make good reliability and dispatchability maintenance decisions at a competitive cost.”

When equipment is old and nearing end of life, users need help in extending the life of their machines by an additional cycle until future technologies grow to the point of displacing their assets. Accordingly, Mechanical Dynamics & Analysis (MD&A) aligns itself with customer requirements and their long-term plans for assets. It provides power generators around the globe with a full-service, OEM-alternative for services, parts, and repairs for gas turbines, steam turbines, and generators. Over the last 40 years, its engineers have developed time-tested principles that produce quality repair solutions for gas and steam turbine-generator rotors and components.

“We make repair recommendations based upon the owner’s intended operating plans for the unit,” said Eldridge. “Our capabilities range from steam turbine rotor and stationary component repair to liquid-cooled generator rewinds, gas turbine rotor life extension, and high-speed balance.”

MD&A provides clients with the labor, engineering, and technical experts necessary to address both planned and forced outages of most types of turbines and generators. Its capabilities range from alignment to performance testing and analysis, including control and excitation field engineering, consulting, and training. The company also supplies replacement gas and steam turbine-generator parts and components that address reliability, life extension, and capacity demands by providing retrofit and part solutions. Capabilities range from gas turbine capital parts to packing and spill strips to drop-in valve solutions.

250,000 square foot MD&A turbine-generator repair facility located in St. Louis Missouri USA

The bulk of this work is done at the 250,000 square foot MD&A turbine-generator repair facility in St. Louis, Missouri. This includes gas turbine repair, steam turbine repair, generator, machining, and high-pressure valve repair. The company also has a high-speed balance facility located at the same facility in St. Louis, as well as several parts supply facilities and sites specializing in controls and fuel nozzles.

MD&A manufactures a wide range of parts and components for GE, Siemens, Alstom steam turbines, GE 7FA & 7EA gas turbines, and 7FA and 7EA discs and wheels to support its own rotor life extension program. It can also perform reverse engineering to support turbine owners with short cycle, high quality, aftermarket parts.

“Our reverse engineering experts support everything from small consumable parts needs to full turbine section or generator replacements,” said Eldridge. “Recently, we have added to our inventory to include stator bar components, generator field retaining ring forgings and complete generator field spares to allow us to respond immediately to forced outage needs.”

With so many turbines going through its shops, Eldridge noted several trends such as speed of outage execution becoming more vital. But the demands of the current operational climate are showing up, too, in areas such as steam turbines exhibiting eroded last stage buckets.

“Gas turbine operators have migrated from utilizing new capital components to running with brown (repaired) components,” he said.“Our engineers have observed that gas and steam turbine generators are failing more regularly, requiring both stator and field repairs/replacements to allow the units to be returned to service.”

In response to these trends, the company has developed an inventory plan that enables it to respond to emergent needs during planned and forced outages. In addition, it has developed solutions to expedite outage execution. In particular, MD&A offers “drop in” valve solutions for many types of steam turbines to allow an owner to install a valve cartridge during an outage and have a rotating spare repaired off outage/off critical path.

“We stock inventory of brown hot gas path components for GE gas turbines to support the growing trend of utilizing repaired parts rather than new,” said Eldridge. “We also stock replacement components for generators to include GE 7FH2 and 7A6 to support stator rewinds and field swaps.”

He urged owners to consult with their service providers well in advance of an outage to discuss options to respond to unexpected needs during the outage. A detailed spare parts review and stocking program should be done ahead of the outage with particular focus on any parts or equipment with long-lead items.

7FA unstack for rotor life extension at our MD&A repair.

Rotors in gas turbines produced in the late 20th and early 21st century are approaching the number of starts and hours defined by the OEM as the design service life. This recommended service life is based on many factors including: duty cycle, ambient environment, maintenance practices, and material properties. In reality, rotor end-of-life is usually governed by only a few weak-link components. The remaining components may have additional maintenance intervals of useful life remaining, either as-is or with minor refurbishment.

“A comprehensive rotor inspection and end-of-life assessment can help turbine owner/operators determine what course of action to take to ensure that their rotors continue to operate safely and reliably,” said Eldridge.

MD&A rotor life extensions for GE Frame 7FA and 7EA turbines are compatible with OEM rotors and offer high performance and durability. Information needed for a rotor end-of-life assessment can be broken down into two categories: general design information and user-specific information. In the former category are such items as material properties, accurate dimensional characterization, and an understanding of failure modes.The latter category includes operating history, site conditions, location, and extent of any defects (as determined by a complete non-destructive inspection), and the expected profile of future operation. As rotor life is defined by both hours and starts, an understanding of the detrimental effects not just of cyclic operation but of extended high-temperature operation is critical to success.

“To maximize the probability of continued safe and reliable operation, weak-link components should be carefully evaluated and, if necessary, replaced,” said Eldridge. “Improvements can be made in any of several areas: materials, thermal management, manufacturing processes, and mechanical design. Any approach must balance expected effectiveness and practical considerations.” For more information, visit www.mdaturbines.com

Servicing Turbines and Generators in the Load-Following Era

Vendor Spotlight: MD&A

The turbine marketplace is undergoing a rapid transformation. The boom days of peaking and combined cycle plants fueled by natural gas appear to be over. Lobbying against natural gas is pushing it to the back of the queue behind wind, solar, energy storage, and other sources. Total MW orders per year are down 50% from a decade ago.

In response, turbine OEMs are investing heavily in areas such as hydrogen-based turbines and carbon capture, utilization, and storage (CCUS) to prepare their businesses for a cleaner energy future. Several of the big ones, too, are hedging their bets by adding divisions devoted to renewables, energy storage, and alternative energy.

Yet despite prophesies of doom, many believe there is plenty of life left in the turbine business. Tony Brough, an analyst with Dora Partners, believes gas turbines have a strong role to play over the long term. He noted all the attention on hydrogen and said this market will experience slow but steady progress.

“It is unwise to dismiss hydrogen, but a lot of challenges have yet to be overcome in its utilization,” said Brough.

To gauge the state of the market and the latest in gas turbine trends, we interviewed experts at GE, Siemens Energy, Mitsubishi, MAN, Baker Hughes, Triveni, Solar Turbines, Ansaldo, and Elliott. They lay out turbine trends, what is driving them, and how they are responding. They discuss their strategies with regard to hydrogen, sCO2, and other alternative fuels, and what they are doing in the carbon capture field. And they provide an overview of the different models they offer and their capabilities.

Triveni Turbine Limited (TTL) is a manufacturer of steam turbines up to 100 MW with more than 5,000 machines in over 75 countries across more than 20 industries generating more than 13,000 MW power. Arun Mote, Executive Director & CEO at TTL, said some of the key factors driving demand for steam turbines are reduced operating cost, self-sufficiency (in terms of captive power generation and consumption), and gaining carbon credits across segments such as: waste-to-energy (waste from municipal/industrial landfills); biomass (waste from forest/wood residues); and in steel (utilizing waste heat from processes, as well as gas engines/turbines) through combined heat and power (CHP) in applications such as district heating and combined cycle. Nonetheless, efficiency of power generation has gained utmost importance, which has induced the demand for high-efficiency steam turbines based on reaction steam designs.


"Efficient steam turbines based on reaction steam designs have gained popularity over traditional impulse designs for smaller-and-medium-size ranges of up to 100 MW," Arun Mote, Triveni Turbine.

“Traditional impulse turbines will still continue to find a place for steam turbines smaller than 3 MW for power generation, small-scale CHP, and industrial mechanical drive applications,” said Mote.

TTL has developed efficient reaction type designs from 3 MW to 100 MW. They incorporate upgrades for higher pressure and temperature steam cycles, blade redesigns to improve internal efficiency of energy conversion. They undertake programs to reduce the turbine footprint, and retrofit solutions for aging turbines to improve performance. In countries like Central and South America as well as Southeast Asia, especially in the palm oil segment, TTL has replaced single-stage with multi-stage machines to enhance efficiency. They comply with American Petroleum Institute (API) 611 and 612 specifications in refineries, chemicals, petrochemicals and fertilizers.

The CHP market is showing promise in the Americas. TTL received an order for an 18.25 MW extraction backpressure steam turbine generator from a Colombian paper producer. It will provide steam and generate power.

In cold countries like Europe, the district heating system is a promising segment. TTL can provide competitive steam turbine solutions for district heating plants. It has already established its references in Europe for this application. Additionally, the company provides renewable-based power solutions for sugar, palm oil, biomass,and waste-to-energy using low-pressure steam. The company is developing sCO2 steam turbines leveraging in-house R&D expertise and through association with technical institutes and domain experts.

Elliott Group has seen many changes in the turbine markets throughout the past decade. Two of the more significant trends are the premium on operating efficiency as well as transitioning from fossil technologies to alternative sources. Users were previously focused on reducing upfront capital costs while accepting some sacrifice in operating efficiency. As fossil energy costs continued to climb, there was closer evaluation of capital investment versus operating efficiency. Higher efficiency provided a faster return on investment.

"We have developed turbine solutions that include an optimized aerodynamic flow path based on the required operating conditins and various options of working fluids, beyond steam," said Adam Neil, Elliot.


In response, Elliott has developed flexibility into its turbine designs to provide efficiency and accommodate alternative energy sources and working fluids at a wide range of operating conditions. The company has also added more automation in design tools, application sizing programs, and manufacturing processes.

Elliott Group base turbine and expander equipment offerings include:

MVMS – Multi-Valve Multi-Stage Turbines


Standard frame sizes: J/K-line, R-line, Q-line, N-line

SVMS – Single-Valve Single-Stage Turbines

SVSS – Single-Valve Single-Stage Turbines (YR Family)


Common standard frame sizes: PYR, AYR, BYR, CYR, DYR, MYR


Standard frame sizes: TH85, TH100,
TH120, TH140

Large frame MVMS turbines, for example, are customized with extractions which export steam part way through the turbine to provide high efficiency usage. The steam being extracted supports additional plant processes that would otherwise be let down through a valve. After extracting some of the energy from the high-pressure steam, the lower-pressure extraction steam is used for plant process needs or in smaller horsepower steam turbines driving pumps. This demand for extraction steam may change over such that the turbine needs to balance the primary driven equipment with the required steam being exported.

“Each user has different requirements based upon the steam balance of the plant,” said Adam Neil, Manager, Turbine and Expander Product Development, Elliott. “Customizing the turbine flow path to meet the specific customer requirements or plant processes can greatly improve operating efficiency of the steam turbine.”

The pursuit of decarbonization targets presents several challenges. The shutdown of coal-based power supply creates a gap in baseload supply, especially in winter periods, and increases grid imbalance. This situation is accompanied by an escalation in energy prices, resulting in a compulsion to reduce energy costs and increasing desire for self-sufficiency in energy supply for companies in the manufacturing sector.

“Modern, decentralized, low-emission gas turbines offer a sensible solution to this problem,” said Dr. Sven-Hendrik Wiers, Vice President Gas Turbines, Large Compressors & Screws and Head of Oberhausen Site at MAN Energy Solutions SE.

He noted another trend – the transition towards less CO2 emissions, which impacts steam turbine manufacturers via requirements such as the utilization of waste thermal energy. For steam turbines deployed as mechanical drive, there is growing demand for turbomachinery trains with higher efficiency. Part of the process steam is admitted into the turbine, and the remainder is expanded in the turbine up to the required pressure and extracted – similar to waste-to-energy applications in power generation.

“The socio-economic commitment to accelerated decarbonization requires a rapid phase-out of coal-fired power generation,” said Dr. Sven-Hendrik Wiers, MAN Energy Solutions

MAN Energy Solutions is responding on many fronts. This includes electrolyzers and power-to-X solutions, industrial-scale heat pumps as well as CCUS, LAES (Liquid Air Energy Storage), CAES (Compressed Air Energy Storage), and the further development of gas turbines and reciprocating engines). All MAN gas turbines can burn 20% hydrogen standard (up to 40% as an option). Depending on market requirements, they will be capable of burning up to 100% hydrogen either new or as retrofits.

“We are improving our gas turbines to make them more robust in terms of cyclic operation modes, while also improving hot start capability,” said Wiers. “Stable, low-emission part-load behavior also characterizes our gas turbine family.”

MAN supplies utilities, compressor stations, and industrial production sites with MGT series gas turbine packages. Single-shaft engines for power generation feature a range from 6.6 to 8.9 MW electrical. As twin-shafts, the MGTs drive compressors and pumps (6.8 - 8.3 MW mech).


The MGT single-shaft engine is suited to simple cycle and CHP applications. With efficiencies of up to 34.7% and exhaust temperatures of up to 520°C, service intervals are up to 40.000 EOH. A recent project in Germany involved replacing an aging gas turbine with a new one to fulfil current and projected emission standards. In addition, it needed the capability to burn 20% hydrogen blends and a commitment to extend to 100% by 2030. A similar Brownfield project in Germany is currently in the commissioning phase.

The company’s steam turbines are usually configured to meet customer and market requirements and thus are not “off-the-shelf” products. In the power range of 1 to 180 MW, it can scale the turbine within its modular system and equip it with the required admission extraction. This approach allows steam turbine configuration regardless of the application. MAN steam turbines can be flexibly adapted in regard to volume flow, admissions and extractions.

MAN’s MST series steam turbines can be used for power generation and mechanical drive applications and cover the 1 MW to 180 MW range. Models include MST 010, 020, 040, 050, 060, 080, 100, and 120. Each can be equipped with a condensing or a back pressure module, and can contain an extraction or an admission, or a few of them. The exhaust module can be axial or radial downwards, also the whole inlet module depends on the inlet temperature and pressure of the steam. Up to the power range of 10 MW, the blading can be either impulse or reaction.

They are in high demand. Last year, MAN received many steam turbine orders for applications such as PTA, FCC, air separation, nitric acid, blast furnace, paper IPP, distillery, and sugar. Mechanical testing of steam turbines as well as string tests of the entire train are part of MAN’s capabilities.

The company is developing a low-emission combustor for 100% hydrogen, which will be available in 2025. The Wobbe index of hydrogen fuel is similar to natural gas and, thus, the sizing of the fuel system and other components will not require significant changes in terms of volume.

To preparae for future demands, Mitsubishi Power is expanding and integrating its T-Point 2 facility with Hydrogen Park, a new facility for systematic validation of the entire hydrogen value chain from production to power generation. Mitsubishi Power has announced its 30% hydrogen co-firing for large frame gas turbines and will use Takasago Hydrogen Park to commercialize small and large frame gas turbines on a path to 100% hydrogen firing starting in 2025. Its Hydaptive green hydrogen packages augment renewables with on-demand power from gas turbines and lithium-ion battery storage, and green hydrogen production and storage.

“Aeroderivative gas turbines fulfill urgent requirements, including disaster relief and emergency power,” said Bill Newsome, Mitsubishi Power Americas

The company is developing partnerships to create hydrogen hubs and infrastructure throughout North America. The first hub, a joint venture with Magnum Development, is the Advanced Clean Energy Storage hub in Delta, Utah. The utility-scale hub will use renewable power to produce green hydrogen through electrolysis. Hydrogen will be stored in a salt dome at the site, using technology that has operated for 30 years in the U.S. Gulf Coast. Stored renewable hydrogen can be used for intra-day power when wind and solar availability are limited, as well as providing seasonal energy storage. Another hydrogen hub is being developed in North Dakota in partnership with Bakken Energy. This hub will include facilities that produce, store, transport, and consume clean hydrogen. It will be connected by pipeline to other clean hydrogen hubs being developed throughout North America.

Bill Newsom, President and CEO, Mitsubishi Power Americas, noted that many customers now require power generation equipment to deliver power in extremely short lead times, sometimes from contract to commercial operation less than four months. In these cases, compact, lightweight, aeroderivative packages can be an ideal solution. These units are capable of running on natural gas, liquid fuel, LPG, and in the future, hydrogen blends. The company addresses such needs with its MobilePac units, which are modular and can be delivered and installed quickly. For example, it supplied a five-unit turnkey project in early 2021 that entered commercial operation 110 days after the contract was signed.

The FT8 MobilePac gas turbine is offered as a 31 MW mobile generation package and a 30 or 60 MW stationary package. The design enables fast-track installation and commissioning, as well as demobilization and relocation with minimal crew.

The FT4000 SwiftPac gas turbine combines the open cycle efficiency of an aeroderivative engine and design robustness. It offers greater than 41% simple-cycle efficiency with package output up to 144 MW. Utilizing the core technology derived from the Pratt & Whitney PW4000 turbo-fan engine, the SwiftPac can provide peaking and baseload power with a compact footprint.

Beyond aeroderivatives, Mitsubishi Power provides a wide range of gas turbines ranging from 31 to 574 MW in both the 60 and 50 Hz markets. Here is a summary:

H-25 Series gas turbines (41 MW) were developed for utility customers and industrial customers in both 50 Hz and 60 Hz regions. The first unit entered into commercial operation in 1988.

The H-100 Series two-shaft gas turbines first entered commercial operation in 2010 (105.8 MW, 60 Hz; 16.4 MW, 50 Hz).

The 1,500°C M501G gas turbine for 60 Hz power generation uses steam for cooling combustors. The GAC Series, which is the current model, adopts air-cooled combustors in place of conventional steam-cooled combustors. It uses compressor discharge air for cooling combustors to add operational flexibility by eliminating the need for steam for cooling from the bottoming cycle.

J Series gas turbines are an integration of the G Series and technologies for temperature increase as a result of the Japanese national project for the development of 1,700°C class gas turbines. They operate at a turbine inlet temperature of 1,600°C. M501JAC Series gas turbines adopt air cooling for combustors instead of steam cooling. With a performance equivalent to the M501J, they produce a high level of operability including a shorter start-up time. The M501JAC offers efficiency greater than 64% and reliability of 99.5%. It emits low levels of NOx, CO2, UHC and VOC. The JAC starts up and shuts down quickly. The installed fleet of J-Series gas turbines has accumulated more than 1.6 million hours of operating experience with 47 units in operation.

“With the increased emphasis on decarbonization, power producers are choosing hydrogen pathways to support their clean energy transition,” said Newsom. “At commercial operation, the gas turbine is capable of operating on a mixture of 30% hydrogen and 70% natural gas, which can be increased to 100% hydrogen in the future with minimal infrastructure modification.”

To achieve 100% hydrogen, a new multi-cluster combustor technology derived from Mitsubishi Heavy Industries’ (MHI) heavy launch rocket division is in development. With higher hydrogen concentrations, the risk of flashback rises, as does the concentration of NOx. Because the combustor must enable efficient mixing of hydrogen and air as well as provide stable combustion, the distributed lean-burning combustor incorporates multiple upgraded fuel delivery nozzles with smaller openings. It mixes injected air and hydrogen, without using a swirler nozzle, making the mixing possible on a small scale and allowing for low-NOx combustion. Several multi-cluster combustors, each consisting of multiple cluster burners in a can-type cylindrical liner and casing, are radially mounted at an angle to the compressor section casting to provide a dry low-NOx (DLN) combustion solution for hydrogen-rich fuels.

Siemens Energy thinks that the world is shifting towards a more diverse energy landscape consisting of many small, decentralized power providers, consumers and prosumers looking for reliable and affordable operations with less emissions closer to where the energy is used.

“Interest in fossil-free fuels from customers is high,” said Hans Holmström, Siemens Energy.

Many customers in the industry operate aged assets, some coal-fired. For them the first step is to increase their energy efficiency. This can be achieved by switching to the latest generation of turbines, as well as modifying and upgrading existing assets or better utilization of waste heat and optimization of plant performance.

Hans Holmström, Head of the Industrial Gas Turbine business at Siemens Energy, cites the International Energy Agency prediction that renewables will meet 80% of global electricity demand growth during the next decade. That will require energy storage complemented by gas turbines.

“GTs will be a cornerstone of the grid infrastructure but with a new role as backup power instead of peaking units, and as flexible mid-merit combined cycle plants instead of baseload plants,” said Holmström.

He added that gas turbine generator sets, whether in open cycle, combined cycle or cogeneration configuration, offer some of the highest efficiencies possible across a wide range of power outputs. With natural gas, the fossil fuel with the lowest carbon content, they produce among the lowest CO2 emissions per kWh generated. To decarbonize power generation further, green fuels such as hydrogen or biofuels can fully or partially displace natural gas.

Holmström also touts the efficiency and flexibility of CHP technology. When a CHP plant is combined with heat storage, the possibility to transition to green hydrogen with gas turbines such as the SGT-700 and SGT-800 enables further decarbonization of thermal energy use and at the same time provides renewable balancing power to the grid to allow a large share of wind and solar, he said.

Siemens Energy has released a hydrogen blending capability with natural gas with DLE (dry low emissions) technology between 30 and 75% by volume, depending on the gas turbine model. The company has set out a roadmap for achieving a 100% hydrogen with DLE by 2030 at the latest. It has sold an H2 upgrade to an existing customer, a chemical plant in Brazil, and is installing a new H2-ready SGT-800 gas turbine to the city of Leipzig, Germany. At the Braskem ABC petrochemical complex in São Paulo, the company has designed a CHP plant fueled with residual process gas (up to 60% hydrogen) that allows the petrochemical giant to reduce water use and carbon dioxide emissions. Two SGT-600 gas turbines will generate 38 MW and provide 160 tons of steam per hour.

The Siemens Energy SGT-800 is a single-shaft gas turbine for power and heat generation, where the performance/efficiency has been optimized for combined cycle applications. Over the 25 years that the unit has been on the market, more than 460 units have been sold to all continents. It is suitable for baseload, intermediate load, peak load, and grid support thanks to high inertia. It’s also designed for future upgrade possibilities in regard toefficiency, power, and fuels as they become available. The SGT-800 can be offered as a package, power island, power block, or a turnkey power plant. It’s designed for frequent starts and stops. It can already operate with up to 75 % hydrogen with a roadmap to reach 100%. It offers 15 ppm NOx on natural gas fuel and about 60% combined cycle efficiency. The latest 62 MW package offers 2-pole generator with sound screens, acoustic generator enclosure as optional, single-sided air intake system as standard, and a sliding door arrangement.

Baker Hughes stresses several trends impacting the industry. On the one hand, there is the ever-increasing use of data coupled with digital tools, machine learning, and artificial intelligence to improvediagnostics and inspection technologies. This allows higher reliability and availability, lower maintenance, and overall lower cost of ownership. Additionally, there is the drive for the reduction in harmful emissions and decarbonization. This has led to breakthroughs in combustion, fuel flexibility, carbon sequestration, and increased efficiency.

“As part of our decarbonization efforts, we are focused on the fuel flexibility of our turbomachinery portfolio, including our NovaLT and other aeroderivative turbines,” said Christ Barkey, Baker Hughes.

The NovaLT family of gas turbines for the 5-20 MW range is suitable for power generation and mechanical drive applications. They can reach over 37% efficiency in simple-cycle configuration, and up to 85% in cogeneration, thanks to the high exhaust temperature. Carbon emissions for NovaLT16 and NovaLT12 gas turbines have been reduced by 50% due to material and testing optimization and machining time minimized by design optimization.

The NovaLT family accommodates hydrogen as well as other lower-carbon fuels such as ammonia. These turbines can burn methane gas and hydrogen blends with as little as 5% to as much as 100% hydrogen. The company is working with a range of customers, from gas network providers in Italy and Greece to leverage their existing infrastructure to allow up to 10% hydrogen. Baker Hughes also has a relationship with to Air Products for whom it is providing 100% hydrogen fueled NovaLT16 turbines for a net-zero hydrogen energy complex in Alberta, Canada.

Baker Hughes’ portfolio approach to CCUS aims to design optimized solutions by application, recognizing there is no single approach. It recently joined a strategic partnership with and invested in NET Power to advance the technical and commercial deployment of NET Power’s low-cost, electric power system that generates no atmospheric emissions and inherently captures all carbon dioxide. The development of supercritical CO2 turboexpanders is part of the arrangement.

“We are investing in a portfolio of carbon capture technologies including chilled ammonia, compact carbon capture, and the mixed salt process,” said Chris Barkey, Chief Technology Officer, Turbomachinery & Process Solutions, Baker Hughes.

GE Gas Power is bullish about the gas generation market through the rest of the decade. Beyond that, Brian Gutknecht, Chief Marketing Officer for GE Gas Power, believes scenarios will diverge depending on which combination of technologies drive longer-term reduction of CO2 emissions.

“In any event, we see gas generation playing a valuable, but changing role as it is relied upon more and more to balance supply from renewables,” said Gutknecht. “Developments in hydrogen-based power generation and carbon capture and sequestration (CCS) solutions mean that gas turbines can be a destination technology and not just a bridging technology.”

“Gas generation will grow through at least 2030,” said Brian Gutknecht, GE Gas Power.

The company provides a broad range of turbines as follows:

GE’s 7HA.03 at 430 MW, for example, is capable of more than 1,280 MW and 64% efficiency (5,331 Btu/kWh LHV net plant heat rate) in a 2-on-1 combined cycle configuration with a ramp rate of 150 MW/minute and turndown to 15% load. The combined cycle plant can start up in less than 30 minutes (rapid response hot start). The gas turbine is capable of up to a 50% blend of hydrogen today, with a technology pathway to enable 100% capability within the decade.

OEMs Adapt to Hydrogen, Carbon Capture, Decarbonization, and Renewable-Support Trends

Gas and Steam Turbines Adapt

Turbomachinery International recently toured the Tampa Big Bend power station on Tampa Bay, Florida. Owned and operated by Tampa Electric Company (TECO), Big Bend Units 5 & 6 at Apollo Beach, Florida, recently began commercial operation..

The Big Bend power station on Tampa Bay consists of a new combined cycle plant (right) and the original coal fired steam turbine plant (top left).

This facility has operated for decades as a coal plant. With its coal boilers and steam turbines aging, TECO carefully reviewed the best course for the long term. Project Director Kris Stryker said the price tag to upgrade the boilers and steam turbines would have been too high. And in any case, the legislative trajectory is such that heavy investment in coal equipment might not recoup its investment.

In any case, TECO already had a retirement schedule in place. Unit 2 was retired at the end of 2021. Unit 3 is scheduled for closure at the end of 2023. Of the other two units: Unit 4 will remain in service and is able to run either on coal or natural gas. Unit 1 is undergoing extensive refurbishment as part of a modernization effort. Parts of that old Westinghouse steam turbine will remain but large sections of it are currently being replaced with GE components.

The Big Bend modernization project includes two GE HA gas turbines and two HRSGs from Vogt. Steam lines (foreground on the left) reach 4000 feet from the HRSGs across a water channel to a steam turbine which in the final stages of being repowered.

Unit 1 is destined to be the final element of a new combined cycle facility that has been erected on site. Two GE 7HA.02 gas turbines, two GE H65 generators and two Vogt Heat Recovery Steam Generators (HRSGs) have already been installed. The turbines are running in simple cycle mode for the moment. They can potentially burn between 15-20% hydrogen by volume in the gas stream. However, TECO does not plan to use hydrogen in these units at this time.

By September, the work on the Unit 1 steam turbine will be completed and the facility will transition to combined cycle mode. But this is no ordinary combined cycle. It takes about 4,000 feet of steam lines from the HRSGs to reach across an inlet to Unit 1. Stryker said engineers looked at many options and this was the best plan based on TECO’s need to maintain the power supply to the local area.

When completed, the gas turbines within the 1,090 MW combined cycle power plant at Big Bend will be monitored by GE’s integrated Mark* VIe control system. Data collected from sensors throughout the facility will be fed to GE’s Monitoring & Diagnostics (M&D) Center in Atlanta, GA. In addition, the GE controls feed data to an Emerson Ovation system in the central control room near Unit 1, which oversees the entire facility.

“In theory, we are losing capacity by going from 1,200 MW to 1,090 MW,” said Stryker. “But due to much higher efficiency, we will actually produce more MW hours.”

Coal-fired plants have a maximum efficiency of about 47%, and older plants tend to register a much lower number. Combined cycle power plants have surpassed 60% efficiency and some of the most modern facilities claim close to 67% efficiency. Besides efficiency gains and carbon reduction, the gas-fired plants reduce the emissions of mercury, nitrogen oxides, sulfur oxides, and other pollutants, while also using less water than coal plants. Greenhouse gas emissions from units 1 and 2 will be reduced by more than 60%.The amount of coal used at the site will be reduced by 50% – with similar reductions in the amount of dust, byproducts and traffic related to coal.

TECO has been working to lower its emissions since 1999. Since then, Tampa Electric has reduced coal usage by more than 90% and has cut carbon dioxide emissions in half. The Big Bend modernization project is another step towards lower emissions and reducing the overall carbon footprint. The site also holds about 30 MW of solar panels, a small part of TECO’s 800 MW solar portfolio. It has also installed about 10 MW of energy storage on site. The company has set a net-zero carbon emissions target for 2050.

“Decommissioning two of our coal units and replacing them with clean-burning natural gas is another step along the path we have set to achieving net zero across all our operations,” said Stryker.

Swapping coal for gas 

With the potential threat looming of the termination of gas supplies from Russia or EU sanctions being extended from oil to natural gas, Germany is fast tracking new liquefied natural gas (LNG) import facilities. In essence, the government plans to eliminate years of red tape to enable the deployment of four floating terminals. When in place, it will be capable of replacing more than two thirds of current Russian-supplied gas. This represents a potential boon for U.S. LNG exporters.

A statement from the German Ministry of the Economy said: “Gas supply interruptions cannot be ruled out in the current situation, so precautionary measures must be taken. The immediate and fastest possible development of more independent sources of gas is urgent.

This marks a major U-turn in German policy. Previously, they made it difficult to import US LNG due to the use of fracking, while supporting cheaper supplies from Russia. Those days are over. Once finalized, several environmental and permitting hurdles would be removed. Instead of up to five years, it might take less than a year to build the LNG terminals. As they floating terminals, the entire process is fast as they only need to charter an existing vessel, and make some infrastructure modifications to link the supply to the pipeline network. As a sign that final approvals are a formality, contracts have already been signed with utilities RWE and Uniper.

Germany fast tracks LNG 

Design and engineering software lies back of every aspect of turbomachinery and facility layout. These tools are used to figure out how to increase efficiency, heighten performance, lower costs, decrease emissions, and find the best way to arrange and integrate equipment and systems. 

There are a great many trends and influences impacting this slice of the market. And the vendor community has risen to the challenge. Let’s hear from the experts: 

Concepts NREC offers a suite of software tools starting from preliminary design through full 3D computational fluid dynamics (CFD), finite element analysis (FEA) and 5-axis machining of turbomachinery. Together, the software is called the Agile Engineering Design System. New for 2022 is CyCAL, which allows the design of turbomachinery within a larger system and includes thermodynamic cycle analysis. CyCAL will be a new platform to bring together all tools in a single user environment.

“Engineers need to look at many aspects of a design in addition to the aero/hydrodynamic performance of the primary flow path,” said Peter Weitzman, President, Software Division of Concepts NREC. “A successful designer needs to simultaneously consider off-design performance, secondary (leakage, bleed, injection) flow, rotordy-namics, and product life.” 

In addition, it is not enough to look at the turbo components in isolation. Every piece of turbomachinery sits inside some larger system to accomplish a specific thermodynamic cycle. If the cycle/system layout is decided first and imposed on the turbomachinery designer, then optimal system performance may not be achieved. The turbomachinery needs to be designed concur-rently with the cycle/system to achieve competitive product performance.

Design trends are receiving a lot of impetus lately from the launch industry. The most critical part of a rocket engine is the turbopump, and designers of engines needs to design the engine cycle and turbopumps as a single system. Customers in the rocket industry want better software to accommodate engine cycle and turbopump design, and these improvements are becoming available to anyone designing turbomachinery.

“Our latest software releases have really been about moving beyond design point performance of the primary flow path,” said Weitzman. “We have added capabilities to design and analyze secondary flow in leakage paths for all classes of turbomachinery. CyCAL provides optimized cycle/system design and analysis capability.” 

The SoftInWay AxSTREAM platform is a fully integrated design, analysis, and optimization soft-ware solution for turbomachinery propulsion and power generation systems. The software includes advanced meanline/streamline, CFD, and FEA solvers, as well as thermodynamic cycle and hydraulic network modeling, rotor dynamics analysis and AI capabilities. Additionally, users can do true clean-sheet design through its generative design solver which can automatically create a design space and narrow down the design intent without introducing too much designer bias into the equation. This can help engineers make decisions about how many stages a machine should have, what the optimal configuration is, and other key thermodynamic and geometric decisions before having to go through meanline analysis or later stages in the design process. 

Valentine Moroz. Chief Operating Officer, SoftInWay has observed some definite trends on the simulation side. “We’re seeing a push towards integrated end-to-end solutions both by means of internal development and through partnerships/acquisitions between small software venders and large companies,” he said. “We’re also seeing the industry trend towards use of digital twins, AI, and high-performance computing (HPC).” 

Within the turbomachinery industry, Moroz added, there are three main development strategies: 

1. Complete clean-sheet design for novel applications (especially in areas such as hydrogen, fuel cells, electric vehicles, etc.) where there is no in-house expertise.

2. Trimming and scaling to adjust existing designs to fit into a new design application (the focus here being a reduction in development time, cost, and risk). 

3. Throwing as much computing power as possible at older designs to try and maximize optimization.It is important to fully understand the objec-tives of a design project before beginning.

“When a project kicks off without a clear understanding of the engineering intent across all teams, it often will lead to conflicting ideas about the project requirements across management, the technical team, and the financial team,” said Moroz. “It is important to establish the engi-neering intent early on to understand what tools you actually need to make your project a success.” 

The TURBOdesign Suite by ADT is an integrated platform for the development of turbomachinery systems, starting from meanline design and covering 3D blade design using inverse design technology with automatic optimization capabili-ties. Inverse design is a unique design method to:

• Satisfy the turbomachinery requirements from the first iterations (e.g., compressors pressure ratio, head in pumps or pressure rise in fans);

• To rapidly develop high efficiency blades, using blade loading as an aerodynamic design input parameters which correlates with performances;

• Accurate surrogate models with small design matrix, requiring up to two orders of magni-tude less computational costs compared to conventional direct optimization methods;

• Develop general design know-how by under-standing the blade loading requirements for product series and similar applications;