Guatam Marwaha,  Gas Turbine Product Manager at Camfil Power Systems

Gas turbines are sensitive equipment that rely on good air quality to deliver reliable output. Since 98% of the input is air, a properly designed air inlet system is essential for maintaining efficiency, reliability, and availability. With 60 years of experience, Camfil Power Systems is a data-driven organization that specializes in air inlet filtration and acoustical solutions for gas turbines, generators, industrial air compressors, and diesel engines. Our engineers design products that help customers operate assets profitably while maintaining peak performance. Our customer base includes original equipment manufacturers (OEMs), engineering procurement construction companies (EPCs), operators, and end users. Camfil supports a green energy future by engineering filtration technologies that reduce carbon footprints and are manufactured sustainably.

What products and services do you offer to the turbomachinery market?

We offer a complete range of solutions including: Filter elements such as bag filters, panel filters, cartridge (pulse) filters, and compact (static) filters; air intake filter housing for static, pulse, combined static & pulse; air treatment for heating & cooling systems; ducting & expansion joints, inlet silencers, inlet dampers, enclosures & ventilation; & weather hoods, louvers/mist eliminators, and screens.

On the services front, we offer: Site surveys such as air quality analysis, noise measurements, and filter house assessment; 3-6 months on-site filter testing and comparison (CamLab); filter laboratory testing, filter management, and filter installation; life cycle cost analysis (total cost of ownership); retrofit service; PowerEye predictive analytics services to predict gas turbine power output, maintenance optimization, and turbine performance data; and gas turbine air inlet filtration training at the Test & Learn Event.

How have filters changed over the last ten or so years?

Turbomachinery technology has evolved tremendously over the last decades. Studies of thermodynamics, computerized fluid dynamics, and the use of more innovative materials and technologies have boosted equipment efficiency to a higher level. These developments made turbomachinery more susceptible to fine particulates that cause fouling and corrosion, leading to more rapid degradation of performance. At the same time, stricter emissions regulations require more efficient technologies on the filtration side adapted to changing environmental conditions.

These requirements call for filtration systems of increasingly high efficiency. To ensure the optimum design, our global R&D centers offer dedicated test rigs for turbomachinery applications. Here, tests are conducted to develop new filters matching customer demands. No matter where on the globe you have a turbomachinery application, Camfil Power Systems provides the knowledge, expertise, and R&D facilities to assess, analyze and recommend solutions.

Camfil introduced its PowerEye predictive analytics service for both air intake filters and gas turbines. It was developed with the understanding that ambient and operational conditions can have a major impact on the performance of engines and the entire operation. PowerEye helps you make faster and smarter decisions that will improve power output across your fleet, improve maintenance practices, and help increase profits.

PowerEye’s algorithms combined with real-world filter data predict how different filters and changing atmospheric conditions affect turbine performance. It provides insights and information to maximize the performance of engines, relative to optimizing filter change-outs, improving capacity forecasting, and increasing uptime.

CamGT filters are engineered for environments where large turbomachinery is threatened by high humidity, salt-laden air, and heavy pollution or particulate. They are optimized with low and stable drop features, long service life, and high filtration efficiency to increase availability and reliability.

The latest generation includes three models. The CamGT 4V-300 (12” depth), the New CamGT 3V-440 (17”), and the CamGT 3V-600 (24”). CamGT filters are offered from T7 - T13 efficiency per ISO 29461-1:2021, and fulfill standards for efficiency, burst strength, and water repellency. There is also a Value Rating feature to help evaluate real-life filtration effectiveness and economics based on test data.

What trends have you observed related to turbomachinery filters?

There has been a shift to higher efficiency filters in recent years. Efficiencies that were considered too high a decade ago are becoming more commonplace today, especially for newer installations. This ties in well with the industry’s focus on a clean energy future, where higher efficiency filtration helps to reduce carbon emissions. Another step in this direction has been the introduction of the new air filtration efficiency test standard known as ISO 29461-1:2021. For the first time, the ISO 29461 family of specifications was written with turbomachinery in mind. Following the initial release of ISO 29461-1 for filter efficiency, several additional sections will be issued with test methods designed to rate the pulsability, burst strength, water resistance, and salt resistance of filters.

Camfil Power Systems will be introducing new filtration solutions and services later this year that have been adapted to the changing environmental conditions and technological advancements in the industry. In addition, Test & Learn Events, a 2-day course on the topic of gas turbines and air inlet filtration, are now scheduled to take place in Malaysia, Canada, and Sweden. The training includes hands on experiments, and will cover topics such as the theory of gas turbines and filtration, filter & system design, total cost of ownership, and more.

Gautam Marwaha of Camfil Power Systems discusses filtration trends

Filtration Adapts to Turbomachinery Demands

Plant McDonough-Atkinson natural gas power plant, Georgia Power.

The Supreme Court of the United States (SCOTUS) found in early July that the Environmental Protection Agency (EPA) requires direct congressional authorization to adopt regulations on CO2 emissions, which effectively diminished the 1970 Clean Air Act. The takeaway is that fossil-fuel burning plants will be under less pressure to address greenhouse gasses (GHG).

According to a U.S. Energy Information Administration report titled “Power Plant Operations Report”, from 2005 to 2019, the amount of coal used in power generation dropped by more than 20%. Simultaneously, natural gas doubled from 19% to 38%. The SCOTUS ruling will likely not impact the current carbon-reduction trend, what will be affected is how energy is handled regionally.

Efficiency of different fuel sources. National Academies of Sciences, Engineering, and Medicine.



Areas neglecting balance in power generation sources have issues. The North American Electric Reliability Corporation (NERC) recently published a report titled “2022 Summer Reliability Assessment”, which details anticipated outages this summer. What it shows is that a large percentage of the United States and some parts of Canada will experience power drops. Analyzing the data reveals that areas where power outages happen typically have an unbalanced energy diet.

Report of summer 2022 power outage risk levels in the US and Canada. NERC.



Take for instance California. In June, lawmakers passed 

, which drew on California’s energy problems. The state struggles to provide power, and the bill bets that relaxing regulations and investing into carbon will help subsidize times when renewables struggle to meet demand. They hope to find a solution by walking center between reducing carbon emissions and providing reliable power.

The opposite is happening in Indiana. According to the Indiana Department of Natural Resources (DNR), Indiana is one of the top coal-reliant states. Its Rust Belt position has led to overreliance, to the detriment of power generation efficiency and sustainability. They are making efforts towards decarbonization. Without EPA regulation, the transition is simplified.

The effect of the SCOTUS ruling means further localization of the energy industry. Plant operators have more leeway in using natural gas, so states have more choice over their energy mix, which may help alleviate ongoing power supply issues.

SCOTUS finds EPA lacks authority to restrict GHG

Ruling Depressurizes Gas

During the summer, when temperatures soar, we often hear reports of power plants reducing output and curtailing the amount of electricity available to the grid. Is this a ruse by electricity providers to extract higher fees when the heat rises and we all need to run our air conditioners? Maybe the answer is not that simple.

Approximately 40% of U.S. electricity comes from natural gas thermal power plants. The remaining 60% is more or less equally split between coal, nuclear and alternative sources. Because of market and environmental drivers, most modern thermal power plants use natural gas as the fuel of choice. It reduces the amount of carbon emissions significantly when compared to other fossil fuels — especially coal.

The general layout of a natural gas thermal plant is usually a primary gas turbine cycle (Brayton Cycle) combined with a bottoming cycle that uses exhaust heat from gas turbines as a heat source. This arrangement is also called a combined cycle plant. The bottoming cycle most often utilizes a Rankine steam turbine cycle, but it can also use an Organic Rankine Cycle or a supercritical CO2 Brayton cycle. Both the primary gas turbine and the turbomachinery employed for the bottoming cycle drive electric generators.

Combining the two cycles allows thermal efficiencies in excess of 60% for most modern plants. In other words, 60% of the energy contained in the fuel is converted to electricity — exceptionally high efficiency compared to all other industrial-scale power plants. Combined heat and power plants do boast even higher efficiencies, but that’s due to the fact that output from these cycles is a combination of electricity as well as lower grade usable heat.

Why does this matter to the electricity consumer? Some explanation is required. The gas turbine cycle is an open cycle where inlet pressure and temperature and exit pressure are essentially fixed. The inlet pressure is atmospheric, and the ambient temperature sets the gas turbine inlet temperature (along with key temperatures for the bottoming cycle). The ambient temperature affects both the amount of energy that can be extracted from the gas turbine exhaust and the lowest achievable temperature of the bottoming cycle.

The gas turbine cycle requires compression of air and the subsequent heating of that air by injecting, mixing, and burning a fuel without a change in pressure. That’s followed by the expansion of the hot, pressurized mixture through a turbine section. The compression process consumes power while the expansion process extracts power from the hot, high-pressure gas. Most of the power from expansion drives the compressor; the remaining power is effectively the gas turbine net output power. If compression and expansion are performed efficiently, the process produces usable electric power. This Brayton cycle process differs from a Rankine steam turbine cycle, which does not require compression and derives the pressure increase from pumping and external fixed-volume heating.

The useful net output of a gas turbine is the difference between the compressor-absorbed power and the expansion turbine-generated power. Several variables affect these two critical values. The mass flow through the compression process and turbine process is practically identical, neglecting the small impact of fuel addition. From basic thermodynamics we know that power output is proportional to mass flow. But the design of the compressor defines the volumetric flow. Therefore, air density and mass flow are reduced when inlet air gets warmer. That’s the first reason why a gas turbine’s power output is reduced at rising temperatures.

The second reason relates to the second law of thermodynamics. Specifically, the pressure differential used for the turbine is determined by the discharge pressure of the compressor. The amount of work the turbine can extract is driven by this pressure ratio and the temperature of the gas leaving the gas turbine combustor. The maximum or firing temperature is fixed by the design blade metal and cooling limits of the gas turbine. For a fixed-pressure ratio, turbine power per mass flow (i.e., the work) is independent of the ambient temperature.

However, the power per mass flow absorbed by the compressor increases (for a fixed discharge pressure) when the inlet air is hotter, as dictated by increased entropy creation. That’s another reason why the power output of the gas turbine is reduced. Also, the amount of heat available in the gas turbine exhaust is affected by the ambient temperature — and it’s affected to a degree by gas turbine efficiency, which is also impacted by ambient temperature.

Finally, the energy extraction by the bottoming Rankine cycle — usually a closed cycle — is affected by the temperature of the temperature sink. Say ambient air is used to remove the cycle excess heat and entropy. The higher the ambient temperature, the less work that can be extracted by the cycle. Since closed cycles rely on heat exchangers to reject heat, the total amount of heat rejected is lower at higher ambient temperatures. Therefore, the total cycle output power is lower when the heat input temperature stays constant.

The laws of thermodynamics cause a reduction in power output from a thermal power plant when ambient temperatures rise — not a ruse by power companies to make more money. These basic laws of physics have nothing to do with price gouging.

Klaus Brun and Rainer Kurz talk about summer electricity price gouging assumptions

Myth: Curtailed Output is Price Gouging

Promotional artwork for the Editor's Series webcast

On the 13th of July at 11:00 am, a Webcast was hosted with industry experts Klaus Brun of Elliott Group and Rainer Kurz of Solar Turbines, entitled 

Key Considerations in the Compression and Transportation of CO2

. The two are experts in the field of turbomachinery and longtime contributors to the Turbomachinery International Magazine 

Brun’s main focus was viewing CO2 in its supercritical state as supercritical carbon dioxide (SCO2) and how this state effects the transportation, compressibility, and storage of the gas.

He stated that there are a limited number of pathways towards carbon-free or decarbonized energy in a Hydrogen Economy. The two main ones include green Hydrogen (GH) – which encompasses wind, solar, hydro, geothermal, wave, and nuclear electricity. The other is blue hydrogen (BH), derived from natural gas or coal. In effect, the most realistic options are ones that utilize carbon capture and sequestration (CCS) in some form.

Delving further into the hydrogen economy, the contrasts between GH and BH were put on center stage. The main problem with GH is the cost. Electrolysis at the moment is a very expensive process. There is also the point of efficiency, with GH maintaining a roundtrip efficiency of less than 40%. Large-scale implementation would either require the retrofitting of hydrogen into a natural gas pipeline or the construction of brand-new hydrogen transportation infrastructure.

At the moment, BH appears to be the better option. It uses methane steam reforming processes (SMR) or partial oxidation gasification (POG). Roughly 10 kg of CO2 is created for every 1 kg of hydrogen produced. This method requires the uses of fossil fuels and requires carbon sequestration.

50,000 – 100,000 miles of new CO2 transmission pipeline will be required in the US for a decarbonized energy economy, and there will need to be an increase in the natural gas pipeline capacity as well in order to meet hydrogen transportation demands.

On the storage side of things, it’s a much more cut-and-dry affair. There are plenty of sites in the US and around the world where the gas can be stored. The main issue is that geographical misalignment of storage and production sites means that major transportation networks are needed to dispose of it.

Many long-distance pipelines are likely to run the gas in a supercritical state, which in this case is above 1200 psi but more probably 1500 to 2100 psi. In this state, the CO2 acts much like liquid water, having a high density and low viscosity. Recompressing at this point is essentially pumping. Design considerations need to account for the purity of the CO2 in order to keep energy costs down.

The factors to consider when designing a compressor for the transportation of SCO2 are high compression ratios, low viscosity and high-pressure state, multi-phase behavior, and solubility in elastomeric materials to name a few.

Integrally geared centrifugal compressor (IGC), centrifugal barrel compressors (CBC), or reciprocating compressors (RC), are all options for pipeline compression, depending on the intended use case. For example, an RC would be better suited for low-flow operations than an IGC due to the changes in gas pressure ratios (PR). An IGC may be more efficient due to the increased cooling, but a CBC would be more reliable over longer distances.

Kurz spoke of CO2 applications - carbon capture, carbon transport, and carbon sequestration.

He pointed out multiple options for carbon avoidance. One is in transporting hydrogen to a power plant and burning it on site. The other is transporting natural gas to a power plant and either making BH using (SMR) or using natural gas as a fuel and capturing the CO2 in the exhaust.

A simple compressor with one or two impellers will have the same pressure ratio as a large hydrogen compressor with a significant number of impellers or multiple compressors working in tandem. From an energy standpoint, hydrogen transportation is expensive, while natural gas and CO2 are cheaper options.

Kurz emphasized the importance of knowing and understanding the hydrogen generation process, how it’s used, and where it’s going. BH is best generated near a power plant. GH will generally need to be transported over pipelines.

A recording of the Webcast can be found here: 

https://www.linkedin.com/events/editor-sseries-compressionandtr6945457095689342976/

Key Considerations with Klaus Brun and Rainer Kurz 

CO2’s Future in a Hydrogen Economy

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


LNG around the globe is in high demand. Prices have soared and shipments are being diverted to the highest bidder. But the industry is facing difficulties related to unprecedented demand, problems at LNG export terminals, and overall supply constraints. What has become clear is that LNG is not the answer to the world’s energy problems. Nations can’t rely on it being available or affordable. They will need to find other energy sources to provide their populations with a reliable supply.

In February, Shell released its 2022 LNG Outlook, giving a summation for the previous year and a projection for the future. It spoke of rising LNG demand in 2021, and subsequent price volatility. Gas and oil prices have hit record levels over the last year. The outbreak of war in Ukraine, compounded by recovery from a global pandemic are two primary contributing factors.


Russia follows the US as the global supplier of natural gas. According to the BP Statistical Review of World Energy, the top five pipeline consumers of Russian LNG are Germany, Italy, Belarus, Turkey, and the Netherlands. Russian natural gas imports made up nearly 40% of EU consumption last year, sanctions have complicated that relationship.

The US LNG industry has been a major beneficiary of the growing need for LNG in Europe. But with export terminals operating at or near full capacity, problems were inevitable. A few weeks ago, for example, the Freeport LNG terminal in Texas exploded. Supply was disrupted for three weeks. The result was a 10% reduction in the total natural gas imports in Europe. Since roughly 40% of European gas imports ended abruptly this year due to sanctions, global importers are tightening their belts. Another incident occurred at Shell’s Prelude floating facility in Australia. The workers sought better pay, which led to two weeks of downtime.

One proposition made by US Secretary of Energy Jennifer Granholm is to simply ramp up production. That’s easy for a country like the US, that leads the world in natural gas exports, but not for others. Other options are to delve more into combined cycle gas turbine technology, renewables, and hydrogen blends. Finland, for example, recently announced plans to develop a national hydrogen pipeline network.

The current problems present in the global LNG supply chain are significant. Prices will remain high while parties in Asia and Europe fight over limited shipments. Diversification of energy portfolio’s is required to ease strain on supply lines.

This highlights fundamental issues with LNG as an energy resource. While the surge in imports has been required due to the war, it still meanders around the main problem that LNG is trying to solve. LNG’s success ultimately relies on the premise that local and regional energy production is lacking. In other words, many places where energy production is unable to meet demand have turned to LNG.

More investment into locally sourced energy is key to avoiding these troubles. Otherwise, LNG supply can dry up rapidly due to problems with export terminals, lack of ships to carry the LNG, political considerations, or regional conflicts.

Bottom line: LNG can and should be used to supplement energy shortfalls around the globe, but is no replacement for secure and reliable domestic energy.

A perspective on current LNG supply issues

LNG Won’t Solve World’s Energy Shortage



Every compressor is connected via two or more nozzles with flanges to its suction, discharge, and side-load piping. These pipes, due to flange misalignment or thermal pipe expansion/contraction, can exert significant loads on the compressor flanges. Flange loads, in the form of directly acting static and dynamic multi-directional forces and moments, can cause excessive strain on the nozzles, deflection of the casing, shaft misalignment, and even excessive stress on the equipment and foundation bolts.

For very stiff compressor casings, excessive flange loads usually result in shaft misalignment between the compressor and the driver since the loads ultimately must be carried by the skid bolting – the less stiff interface between the foundation and the dynamic equipment. For lighter compressor casings with lower stiffness, critical internal clearances between rotating and stationary components can be affected. In these cases, flange loads on the nozzles can lead to internal casing or bundle deformation and failure of single-digit-mil clearance components such as dry gas seals and bearings. They may even result in impeller rub.

Compressor vendors often use multiple times the allowable NEMA or API requirements as their design standard. These requirements include NEMA SM-21, the subsequent NEMA SM-24 and the calculation method published in Appendix E of American Petroleum Institute 617. A common multiplier is 3.0 times API 617 (equal to 5.55 times NEMA) as allowable load limits. Similarly, API flange load limits are equal to 1.85 times NEMA. Although NEMA is a steam turbine standard, it is commonly used for flange load calculations on other rotating machinery.

Alternatively, rather than relying on the somewhat arbitrary use of fixed multiples of API or NEMA, many vendors ask the equipment end user to supply pipe flange loads for review and approval prior to design and fabrication of the equipment. However, it is often difficult to accurately predict flange loads before final construction of the compression piping system. Though good pipe design software is commercially available, as-built construction errors and pipe installation misalignments are common.

Regardless, the aim of both the vendor and the user of rotating machinery should be to design equipment and piping that reduces the actual load on the compressor nozzles and casing. The compressor should not be an anchor point for poorly designed piping. Compressors are expensive and complex dynamic machines that are not intended to take the function of relatively inexpensive pipe supports/loops or correct for piping system design errors. API 617 states, “The design of each compressor body must allow for limited piping loads on the various casing nozzles. For maximum system reliability, nozzle loads imposed by piping should be as low as possible regardless of the compressor’s machines’ load-carrying capability.”




The compressor should not be an anchor point for poorly designed piping






Rather than imposing unreasonable flange load requirements, the piping designer should either fix the piping to reduce unnecessary weights and thermal expansion loads or include additional pipe support structural members or thermal loops. The compressor is a finely aligned machine already subject to a range of internal dynamic loads. Any excessive external static loads from pipe misalignment have the potential to lead to operational/maintenance problems and long-term damage.

But reality in the field is often unpredictable and does not always follow the wishes of the compressor and piping layout designer. We have seen cases where the piping was so poorly aligned with the compressor flange that a large bulldozer was required to pull the pipe to get the flange bolt holes to align.

These static loads – and any further thermal expansion/contraction loads – imposed on the nozzle should be corrected by fixing the piping system rather than forcing the compressor to become a static structural node of the system. In other words, instead of imposing expensive flange load requirements on the compressor vendor, piping design and installation should aim to reduce these loads. It is generally cheaper to build pipe supports, structures and loops than to redesign a compressor or hope that stress on the compressor casing doesn’t affect alignment and internals. Remember that the more stress applied on the nozzles, the more difficult alignment with the driver becomes, and the more stress the skid and foundation bolts must carry.

Obviously, there are some cases where minimizing flange loads is difficult – in space-limited plants or where the foundation is flexible. On an offshore platform or marine vessel, for example, it is often difficult to eliminate all relative movement between the compressor and the interconnected piping. But even in these cases, good engineering practices, such as three-point mounts and sub-skids for added stiffness, should be used to minimize skid deflections and associated nozzle loads.

Compressors will always be required to handle significant nozzle flange loads. That is the nature of fitting and interconnecting pressurized machines into a complex piping system. However, the current industry trend of asking manufacturers to design compressors with higher and higher flange loading capabilities runs counter to good engineering practices. It is more efficient and less costly to focus on the proper design of the piping to reduce flange loads than making the compressor a pipe anchor. 



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.

Myth: A Compressor is a Pipe Anchor

For nearly all turbomachinery applications, operators prefer to utilize a direct-driven configuration and avoid gear units. But there are special cases where gear units should be used.

Following an initial evaluation such as a driver speed match analysis, vendors or consultants sometimes inform operators or purchasers that there is no way to avoid the use of a gear unit in a specific turbomachinery train. In high-speed turbomachinery applications, some vendors offer a conventional electric motor with a gear unit. This has been the case particularly for high-speed centrifugal compressors. This is considered by some as an unjustified bias against high-speed, direct-drive electric motors. The use of such motors should be evaluated more closely. The risk and possible operational issues of modern high-speed, direct-drive electric motors are usually less than the problems and issues associated with gear units.

For low-speed turbomachinery trains, the use for a gear unit can easily be avoided. Proper driver types could be selected for machinery options to avoid high-speed drivers for low-speed driven equipment. Steam turbine drivers, though, should usually be limited to direct drive applications. For example, a high-speed steam turbine driver for a low-speed compressor or pump using a gear unit for speed-match is usually a poor decision. Such a complicated configuration can potentially cause many torsional, dynamic and operational issues.

Gas turbine models should be selected to facilitate the direct drive turbomachinery arrangement. Aeroderivative gas turbines usually offer direct-drive trains compared to frame type gas turbines which could only be used in limited speed ranges.

There are tens of thousands of gear units that operate over long periods of time in a wide range of sizes and power-ratings. There are also many gear units for high-gear ratios (above 10), and high-speed applications such as high-speed drivers. Risks, operational issues, and high capital/operational costs associated with gear units have been accepted as fact in many plants. But operators have experienced operational issues, painful installation/commissioning procedures, delays in commission/start-up, numerous unscheduled shutdowns, high cost, and other risks associated with gear units. Because of these issues, there is a growing feeling that gear units should be avoided, if possible.

What is the optimum turbomachinery configuration? It is always best to minimize the number of machinery pieces mounted on a turbomachinery train. That means, eliminating gear units if possible. Doing so, reduces capital, operational, and maintenance costs.

Some gear-unit manufacturers and supporters blame poor application engineering or inadequate maintenance as the reason operators have problems with their gear units. But this does little to lower the relatively high failure rates and issues being experienced with gear units.

Here are a couple of examples from my own experience. They concern integrally geared compressors driven by high-speed steam turbines using intermediate gear units for speed reduction. In such a train, the speed of high-speed steam turbine is first reduced in the intermediate gear reduction. This is used to drive the main input shaft of the compressor. The speed is then increased in the integrally geared train for each compressor casing.

Such a configuration presents inefficient and problematic operation. The speed reduction followed by a speed increase presents considerable losses in the train. It also leads to constant wear and other problems. Such a configuration mandates fixed speed operation of the steam turbine. Instead, this arrangement can be replaced with a more efficient variable-speed steam turbine, direct-driven compressor configuration. This raises the efficiency, reliability, and operational flexibility of the train.

It is true that gear units are needed for many turbomachinery trains. They should be used in cases where other options are not available. But the risks and potential problems associated with gear units should always be considered. Gear units can be eliminated in many turbomachinery trains. Gear units should only be used in turbomachinery trains that other direct drive solutions cannot be employed. 

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.

Should Gear Units Be Used Or Avoided?

Siemens Energy is the single solution supplier for the all-electric Woodfibre LNG project near Squamish, in British Columbia, Canada. The LNG facility will be sized for 2.1 million tonnes per year and utilize renewable hydroelectricity for an 80% reduction in greenhouse gas (GHG) emissions.

Woodfibre LNG will be powered by renewable hydroelectricity.

Siemens Energy’s is including all equipment associated with the main refrigeration trains, compressors, synchronous motors, variable speed drives, converter transformers, harmonic filters, and numerous powerhouses. The main refrigeration compressor trains are one of the components of the liquefaction process that produces the LNG that will eventually be stored in tanks and then transported to LNG tankers for shipping abroad. The project is expected to reach completion in 2027 and begin commercial operation by September of that year.

Articles

World’s Lowest Emission LNG Facility

Howden is coming out with a new single-stage impulse turbine capable of up to 1000 kW of power generation. The machine, titled BASE, is a turbine designed as a generator drive for the 75-1000 kW power range. Its primary use case is in small Combined Heat and Power (CHP) plants, in decentralized solar facilities, as well as for waste-heat recovery. For example, for use in bottoming cycles attached to gas engines and biogas engines, or for utilization of residual process steam.

The BASE has an inlet pressure of up to 40 bar(a) or 580 psi, with an inlet temperature for dry saturated steam up to 400°c (750°f). The generator can run in either 50 Hz or 60 Hz modes. The backpressure for the unit is up to 7bar(a) or 160 psi or vacuum. The dimensions of the unit are 2.5 m (8.2 ft) length, 1.5 m (4.9 ft) width, and 2 m (6.5 ft) height.

The BASE can either be a backpressure or condensing type. It has an oil unit integrated in the base frame. It is a small and compact design, with only minimal foundational work required. It showcases quick-start technology, which does not require preheating of the turbine.

Howden 1000 kW Turbogenerator

Indeck Energy Services, Inc. is staring commercial operation of the Indeck Niles Energy Center in Niles, Michigan. GE is providing H-Class combined cycle plant equipment to Indeck Niles and will provide parts, repairs, and maintenance services for 25 years.

The plant features two GE 7HA.02 gas turbines powering two H65 generators, an STF-D600 steam turbine powering an H84 generator, and two Heat Recovery Steam Generators (HRSG), along with a Mark VIe Distributed Control System (DCS) software solution to support the plant. Auxiliary equipment installed includes dry low-NOx burners using selective catalytic reduction technology to control NOx levels.

The plant delivers approximately 1.1 GW of electricity, the equivalent output needed to power approximately 635,000 US homes and businesses.

In 2020, the EIA reported that natural gas generated the largest amount of Michigan’s electricity for the first time, surpassing coal, which fell to third after nuclear power. Natural gas accounted for 33% of the state’s net generation, while coal’s share declined to 27%.

Plant capable of delivering 1.1 GW of electricity

Indeck Energy Center Operations

Turbomachinery Blog features postings from experts in all areas of turbomachinery, such as: gas turbines, machine diagnostics, materials, repairs, and aftermarket parts, and encourages users to participate, with reader engagement and interaction as its primary purpose.

Machinery and Energy Systems for the Hydrogen Economy cover


Publisher Elsevier is releasing a new book titled 

Machinery and Energy Systems for the Hydrogen Economy

, edited by Klaus Brun and Tim Allison, available at all major booksellers. This book provides engineers, scientists, and technical leaders with a breadth of knowledge to design and build the infrastructure of a hydrogen economy.

With over 40 individual expert contributors, the manuscript in general covers all major machinery, heat engine types, designs, production, storage, distribution, and consumption for a hydrogen economy. Its primary focus is on machinery and heat engine design implementation within various production, transport, and storage use cases

More nuancedly, the use of hydrogen in pipeline transport, energy storage, and as fuel are covered. It also discusses hydrogen machinery applications, their selection criteria, economics, safety aspects, and operational limitations in different hydrogen economy sectors.



Guide on how turbomachinery fits with hydrogen

Elsevier Turbo-Hydrogen Book

Ostroleka C combined cycle power plant. Credit: GE Gas Power.

GE Gas Power is providing Polish energy company Energa SA with an 9HA.02 for its Ostroleka C combined cycle power plant. This project will enhance the reliability and stability of the national energy grid, which is currently facing difficulties. Operations will commence in 2025, with an installed capacity of 745 MW.

The plant will be powered by a GE 9HA.02 50hz gas turbine, an STF-D650 steam turbine, a W88 generator, a Heat Recovery Steam Generator (HRSG) and GE's Mark VIe Distributed Control System (DCS). The turbine features a ramp-up rate of 88 MW per minute, which will permit quick response to grid fluctuations. As part of the agreement, GE will provide full engineering, procurement, and construction (EPC) of this combined cycle power plant.

The 9HA gas turbine that will be installed contains the Dry Low NOx (DLN) 2.6e combustion system, capable of burning up to 50% by volume of hydrogen when blended with natural gas.

The steam turbine will be manufactured locally in GE’s steam turbine factory in Elblag, Poland, while the manufacturing of the generator will take place in GE’s generator factory in Wroclaw, Poland. The gas turbine will be manufactured at GE’s Manufacturing Excellence Center in Belfort, France.

Natural gas fired plant expands Polish power supply 

GE Energa 9HA.02 Plant

Atlas Copco has been busy. The first Atlas Copco integration is Les pompes à vide TECHNI-V-AC Inc.TECHNI-V-AC is a privately owned vacuum equipment and service provider with 10 employees. It will become part of the Vacuum Technique Service Division within the Vacuum Technique Area.

Secondly is Ceres Technologies, Inc., a manufacturer and designer of gas and vapor delivery equipment for the semiconductor industry.The acquisition includes the assets of two affiliates, North Park Metalworkers, Inc. and Peak Precision Technologies, Inc. Their revenue last year was $41 million, and their 185 employees will become part of the Semiconductor division within the Vacuum Technique Area.

Ceres Technologies, Inc. provides gas and vapor delivery equipment. They also contract manufacturing of process tools for OEMs and research organizations, and engineering services for semiconductor and industrial customers.North Park Metalworkers, Inc. produces welded enclosures, frames, and machined parts. Peak Precision Technologies, Inc. supplies precision welded and brazed fabrications.

The third company of July was Glaston Compressor Services Ltd. (Glaston), a British compressed air distributor and service provider. The 26-employee company will join the Service division within the Compressor Technique Area. Customers range from small to larger size manufacturing industry companies.

Fourth and finally is Compressed Air Products, Inc. (CAP). CAP sells to a broad range of industrial customer segments and has 20 employees. It also has a service business.CAP will enter into the Service division of the Compressor Technique Area.

The purchase price of these acquisitions has not been revealed.

Four Atlas Acquisitions

GE AC4400CW diesel-electric locomotive, Creative Commons.

Delivery of oversized transformers for transmission & distribution, natural gas turbine and power generators, as well as renewable technology such as wind tower sections and blades, rely on the US rail systems. Transporting such cargo takes months of planning and rail engineering resources to identify available specialized rail assets with the right axle spread and deck height to achieve railroad clearance. Should a national rail strike occur, we could see a knock-on effect on railcar availability with, overwhelming delays in delivery. The brief strike of 1992 saw oversized cargoes reach the “back of the line” in delivery priority by management.

Global supply chain disruption and global energy crisis challenges with 9/11, the COVID global pandemic, and the Russia-Ukraine war cause debate on whether these were black swan moments or predictable and hedged with proper risk management. Conventional wisdom leads us to believe a rail strike is unlikely, as it has been decades since the last one.

On July 17th, the White House established a Presidential Emergency Board (PEB) and a 30-day “cooling-off” period as part of the negotiating process under the Railway Labor Act, avoiding an all but certain strike for now. But what if that fails? Will hindsight suggest that the elements of a national transportation crisis and the impact of delays for North American utilities were inevitable? With the US supply chain already in crisis, how would that impact electric utilities and the national grid?

Class I freight railroads and rail unions have been tensely negotiating contract adjustments for nearly 115,000 workers since January 2020. At the crux of the negotiations are working conditions and wage increases, amid ongoing supply chain challenges and record-high inflation. The National Mediation Board recently released the parties from mediation, resulting in a mandated 30-day cooling-off period before self-help by the parties would be permissible. On July 12th, a major rail union voted 99.5% in favor of striking when the cooling-off period ended, which was to begin as early as 00:01 on July 18th.

Overall, the next 60 days will be critical to determining a path forward. After 30 days, the PEB will issue a report with recommendations for a collective bargaining agreement, followed by an additional 30-day cooling-off period. If no agreement is reached by the end of the 60 days, all restrictions are removed. This could result in either a rail union strike or Congress taking action to mandate the PEB recommendations, such as in the 1991 NCCC/Union dispute. For those who remember the 1991 dispute, rail shipping was very difficult, with railcars not moving for weeks at a time.

This all comes on the heels of Surface Transportation Board (STB) service orders stemming from an April hearing regarding the current rail service crisis, where the four major Class I railroads were required to be in attendance. As the STB noted, the railroads have shed nearly 29% of their employees since 2018. The STB has also issued orders to improve and meet service requirements for customers that continue to experience service failures. The STB reported the four railroads submitted inadequate service recovery plans in response to its order, after a hearing that lacked detail and omitted specific recovery plan information required to implement the plans. The STB ordered them to resubmit more detailed plans.

The last time a PEB was initiated nationwide was 2011, and before that in 1991. The most recent of which resulted in continued negotiations between both parties resulting in an increase in pay and meal benefits. A best-case scenario would be a compromise between the two, as railroads are pushing for one-person crews and better financial returns in response to the cost of their employees.

The environment is different than it was in 2011 or 1991, before the Union Pacific and Southern Pacific merger, and what the unions are looking to do is also different. Due to the Precision Scheduled Railroading (PSR) initiatives that have swept the industry and slashed employee numbers, the unions are looking at solidifying the crews per train and attendance policies, whereas the previous disputes were more about pay and benefits.

With the railroads having shown such degradation in service, it is entirely possible additional oversight and regulation will come either via the STB or Congress. Additional regulation would be a major blow to railroads, just as CN-KCS look to merge, creating the first north-south route between Canada, the US, and Mexico. In any case, it means shippers must pay more attention to their decisions on how they ship freight and work with rail providers who can navigate the environment of an increasingly ineffective rail network.

Regardless of whether a strike is initiated or not – PSR has changed the Specialized Rail environment going forward. Scheduling of trains for Specialized Cargo has increased due to the transport configuration of the new trains and the length of trains currently being run. Tracks have been removed or abandoned, resulting in fewer locations to offload. On top of all this are locomotive and crew shortages already hurting transit times and availability. With all these unprecedented variables at play in the rail industry, it will be important to be strategic when planning the movement of Turbomachinery.

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