Fans have been widely used in many facilities and plants to move gases. Supply and exhaust fans have also been used in different systems to avoid excessive pressure build-up in the equipment or service being served. Forced and induced-draft fans, too, have been used to maintain a specified draft over the intended application. A fan should be selected to match its downstream and upstream systems to provide a proper flow of gas.


Although one operating fan and another standby configuration has been used, multiple parallel operation is discouraged. Many experts have recommended using just one operating fan at a time (one operating and another standby) on each system, avoiding parallel operating fans. This is to reduce complexity and operational problems as parallel operation has always been complicated and is usually problematic. On the other hand, there have been various reasons for using multiple fans in parallel operation on some special systems. In some specific cases, such as some revamp and renovation projects two fans may be provided to working in parallel. Capacity control by various fan combinations may be more economical than other control methods in some specific cases. Multistage fans may be necessary when pressure requirements exceed the capabilities of a single-stage fan.


When two fans are used in parallel, they may be located quite remote from each other or close together. Sometime two parallel side-by-side fans are close enough to share some items such as lubrication system, shaft, bearings, and casing. Double-width, double-inlet fans are essentially two fans in parallel in a common housing. However, the above-mentioned sharing of items or parts should be avoided as it reduces the overall reliability. Two completely independent fans have always been preferred.


Parallel operation of identical fans has been studied and employed in many plants and facilities. The parallel operation of different fans is far more challenging. Parallel fans may have almost any amount of their operating resistance in common. At one extreme, the fans may have common inlet and discharge plenums. At the other extreme, they may both have considerable individual ductwork of equal or unequal resistance. Fans in parallel should all develop sufficient pressure to overcome the losses in any individual ductwork, as well as the losses in the common portions of the system.

A fan should be selected to match its downstream and upstream systems to provide a proper flow of gas.

When the fans do have individual ducts but are of equal resistance and joined together at equal velocities, they should be selected for the same fan total pressure. If fan velocity pressures are equal, static pressures will be equal. If the two streams join together at unequal velocities, there will be a transfer of momentum from the high-er-velocity stream to the lower velocity stream.


Fans may also be in series but usually at opposite ends of a system. Those in series should handle the same amount of gas by weight measurements, assuming no losses or gains between fans. The combined total pressure will be the sum of the total pressures of individual fans. The volumetric capacities will differ whenever the inlet densities vary from one fan to another. In other words, because of compressibility, the volumetric capacities of the second fan will not equal the volumetric capacities of the first fan. With any fan, the pressure capabilities are also influenced by density.


The case study is for no-load test of a large, critical 2.3 MW fan. This no-load test was part of commissioning to observe and verify if operation and functionality of the fan was suitable for the next stage (load test). The fan was a fixed speed 1,485 rpm turbomachinery which was fed by 11 kV AC power electricity. The rated current was about 140 A and the estimated start-up current was around 750 A.

There were initially different trips on high vibration and some other issues. After resolution of different problems, the test started and operation was sustained. The first problem afterward was a relatively high vibration at the NDE (non-drive end) bearing. The recorded vibration was around 45 microns. This was still below limits published by the manufacturer. However, full investigations were done. Another concern was that this was about two or three times more than other measured vibrations on different bearings.


To start the investigation, the composition of this high vibration (amplitude vs. frequency) was checked. Details of balancing and alignment were also verified. The main part of vibration was related to the operating frequency (1,485 rpm). Therefore, it was assessed as harmless. The manufacturer confirmed that the provisions for rebalancing at site were provided. The key-phasor was provided for this fan and a contractor specialist provided a comprehensive vibration measurement and report that showed no developing problems and no concerning issues.


Relatively high axial vibrations were recorded by handheld vibration measurementdevices on this large, critical fan. Permanent, axial vibration sensors should have been provided for such a large fan. The manufacturer, therefore, was required to install an axial velocity meter.


Another issue was the access to an inspection point of the lubrication oil return line. Sight glass for lubrication oil return piping lines of DE (drive end) side was not easily visible. An additional platform was provided to enable maintenance people to easily check these lines.


The lubrication oil was then found to be dirty. The source of dirt and debris was the system itself due to poor flushing. A complete lubrication oil flushing was done again and verified that all internal parts in contact with the lubrication oil were fully cleaned. ■

Articles

Turbo Tips: Large Fans

hen installing or resetting a piece of equipment, grouts play a crucial role in the long-term performance of the pump, motor, or other type of machinery. Improper grouting can cause premature failure of expensive equipment.


Grouts are generally divided into one of two types, cementitious based grouts or epoxy grouts. Cementitious grouts are used in applications where the loads are static. Equipment generally has vibrations and other non-static loads, so they require epoxy grouts. We will focus on epoxy grouts here.


Other than vibration, there are other reasons epoxy grouts are ideal for making equipment and its foundation function as one unit:

•	Develop a greater bond to steel than cement-based grouts.
•	Form a higher bond to concrete than the concrete’s tensile strength.
•	Higher compressive strengths than the concrete they are attached to, generally within 24-48 hours.

When properly mixed and applied, they provide a bearing area greater than 90%.

They come prepacked so proper proportioning should always be correct.

Accommodate many chemicals that would react with cement-based materials.

Epoxy grouts come in a number of “flavors” to meet different needs. Flowable grouts are made to flow at a rate that they can fill a void. This property is required for almost any project. All epoxy grouts are sensitive to temperature differences. Flow rates slow and cure times extend based on the ambient temperature. Note that grout should not be stored in the cold or hot just prior to installation as a temperature difference of as little as 10 degrees can make a significant difference.

Deep pour grouts are formulated to create less heat when setting so they can be applied in bigger lifts and deeper sections. There are also high-strength or extreme grouts that produce much higher ultimate strength when needed. Lastly, there are highly chemical-resistant grouts for use in the most demanding, harsh environments.


Installing grouts is straightforward. Concrete foundations or bases should be 28 days old so they have achieved strength and drying shrinkage has taken place. Surface preparation should conform to a surface profile of 5-7 according to ICRI (International Concrete Repair Institute) Guideline 310.2, exposing the coarse aggregate of the concrete. Clean any residue with a vacuum, pressure wash, vacuum the water, and let it dry completely.

Forms must be tight, and the metal surface being attached should receive a suitable primer. Once this is complete, mix the epoxy. If there is a significant amount of epoxy, care should be taken to have a mixing process in place so there is a constant stream of material available until the void is filled. Place the epoxy by pouring it through the openings in the base. This is an abbreviated set of instructions to understand the process. Confirm the process with your specific grout manufacturer.


One aspect of grouting that is receiving more attention of late is how the choice of grouting material impacts personnel and plant safety. During the mixing of grout materials, a great deal of dust thrown in the air. This presents a hazard and adequate safety precautions must be followed.


In recent years, however, new epoxy grouts have been developed which create very little dust. This safety advancement is a boon for installers and anyone else in the proximity of the project. DL (dustless) technology grouts are the future of the grouting industry. With a greater emphasis in most plants and jobsites on safety, dust limiting grout is finding wider application within the turbomachinery industry. ■

How to correctly apply grouting and enhance plant safety

Grouts for Turbomachinery

One of the greatest limitations of centrifugal compressors and pumps is that they prefer to operate at a specific revolution speed. Any move away from the best efficiency point (BEP) has a cost due to inefficiencies of a mismatch in the angles of incidence in the main flow, as well as limitations imposed by the growing imbalances in the secondary flows that potentially excite the rotor.


Leakage flowing through the impeller front and the back side cavities is referred to as secondary flow vs. the main flow through the impeller itself. Side cavities provide an alternate flow pathway (back to suction) through gaps at the impeller tip and eye/shaft seals. Ignoring flow reversals in the main flow, aggregate radial flow through the front cavity is always from periphery to eye seal. Aggregate flow through the back cavity can be in either direction, depending on operating conditions and whether it is a mid or final-stage of the machine. In any event, given the much larger pressure differential from periphery to hub in the front side cavity vs. the back, together with its associated higher leakage rate, forces acting on the rotor and generated in the front cavity are much more responsible for rotor self-excitation. Only front side cavity effects will be discussed further.


Self-excitation refers to the phenomenon where impeller rotation induces swirl in the front side cavity, and in turn, this energy (momentum) contained in the fluid (pre-swirl) drives self-excitation. The rotating shroud induces fluid rotation in the front side cavity. Bulk swirl velocity in a front side cavity having no leakage flow is steady at ~.45x. Swirl velocity of leakage flow entering through the impeller tip gap is ~1.0x. Therefore, the rate (and dynamic nature) of transit leakage flowing through the impeller front side cavity is responsible for the extent and dynamic nature of swirl velocity in the cavity. In turn, these changes in the leakage rate impact the magnitude of radial oscillations of the rotor and the level of axial thrust forces produced in the cavity.


The level of axial thrust generated in the front side cavity is a product of the bulk pressure in the cavity and the shroud area/ profile. In a front side cavity having no leakage flow, the rotating shroud centrifuges fluid, inducing a bulk fluid swirl velocity of ~.45x. A pressure decline toward the hub is established to recirculate the centrifuged fluid. Increasing the bulk swirl velocity reduces the pressure near the hub even more, reducing axial thrust forces generated in the cavity, therefore increasing residual axial thrust toward the thrust bearing at front. Leakage entering through the impeller tip gap has a high swirl component (~1.0x). Commonly during extreme operating conditions, the leakage rate increases dramatically and has a highly-variable/dynamic/chaotic character. This translates directly into the extent and dynamic nature of the level of axial thrust generated.


Radial displacement of the rotor is impacted by changes in the swirl velocity in the front side cavity in two ways. First, fluid in the front cavity imposes viscous drag forces on the rotating shroud, so the level of radial damping provided by the shroud is affected by the bulk swirl velocity in the cavity. These viscous damping effects on the shroud have been found to exceed those imposed at the eye seal by two times or more in high-pressure applications. Therefore, increasing swirl velocity via increased leakage will reduce damping, which increases the rotor orbit. Second, increasing bulk swirl velocity increases cross-coupled stiffness (k) at the eye seal and along rotating shroud, and increasing k increases the range of positive whirl where tangential forces are destabilizing. The result is a sub-synchronous resonance at whirl speed (inducing whirl, and potentially whip).


Leakage increases with eye seal wear or damage. As noted, increasing leakage reduces radial damping, increasing the rotor orbit. Also, increasing leakage increases the swirl velocity in the cavity, reducing pressure near the eye seal, and therefore increasing residual axial thrust toward the front. The thrust bearing must accommodate the full range of anticipated axial thrust forces generated in the cavity over the life of the eye seals. Seal wear is a major determinant regarding mean time-between-service intervals.


As revolution speed declines below BEP and the machine approaches stall, the leakage rate grows dramatically and becomes increasingly volatile and circumferentially non-uniform. Stall is characterized by partial to full flow reversals in the main flow, and these conditions migrate into the front cavity through the impeller tip gap and heavily impact pre-swirl in the front cavity. Given their linkage to the leakage rate, the radial orbit and axial thrust generation are directly affected. The forces generated can be violent and destructive, especially when compounded by increased leakage associated with worn or damaged eye seals. Given startups and shutdowns, operating within stall cannot be fully avoided.


To address the negative consequences of high or variable swirl velocity in the front side cavity, the primary tool has been circumferential protrusions/ fins affixed to the casing that oppose tangential flow, destroying the swirling flow structure. They are often employed near the eye seal entrance (so-called swirl breaks) to improve entrance conditions to increase damping and reduce cross coupling.


In higher-pressure applications where self-excitation is of greater concern, protruding fins are sometimes employed in the periphery of the cavity (thrust breaks). They reduce bulk swirl velocity in the cavity to reduce residual axial thrust, to increase damping and to mute excitation sources. Thrust breaks are avoided whenever possible because of their not small efficiency penalty. They waste the energy contained in swirl; and eddy structures formed in the wake of thrust breaks evolve with rotating speed, making their performance not as uniform/ predictable as would be desired along the full radial length of the shroud and at the eye seal entrance. Their benefits plateau at high revolution speeds.


To summarize, transit leakage through the front side cavity is the greatest contributor to the self-excitation phenomenon in centrifugal compressors and pumps, having a significant impact on both radial displacement and residual axial thrust generation.


One possible solution is a peripheral diffuser and return channel for secondary flow in the front side cavity. The front cavity is enlarged, and an annular disc with de-swirl vanes (on the casing side) is attached to the casing wall. A ring is press fit into the periphery of the front side cavity (see diagram on previous page).


Fluid circulates radially around an annular disc, and flow is circumferentially diffused at the periphery. Fluid is centrifuged out by the rotating shroud and flows into peripheral diffuser. Leakage enters through impeller tip gap and flows into peripheral diffuser. The peripheral diffuser promotes circumferential equalization of fluid. Fluid exits the peripheral diffuser at its inner radius, flowing into a side cavity adjacent to casing having de-swirl vanes that efficiently remove swirl and redirects flow to eye seal. The swirl velocity of the fluid at the exit of the vanes near the eye seal is circumferentially uniform, as is pressure, which is slightly above impeller tip pressure. Its design and function are similar to part of the main flow in a mid-stage section (an open diffuser, 180° bend and return channel to hub).


This front side cavity design creates a tortuous pathway to protect areas most susceptible to excitation (eye seal entrance and along rotating front shroud) from the primary excitation source (impeller tip leakage). It provides near-optimal conditions at the eye seal entrance (no swirl and circumferentially uniform in pressure) as well as along the rotating shroud (no swirl, circumferentially uniform in pressure, and an outward-only radial flow (inward transit leakage flow is shunted to the hub separately). Changes in the leakage rate are now de-linked from affecting the radial orbit of rotor or the level of axial thrust forces generated in the front cavity. In effect, there is no potential for self-excitation due to forces generated in the front side cavity.


By eliminating the potential for self-excitation, a number of rotordynamic limitations are removed, expanding the operating envelope. Rotordynamic imbalances occurring during stall and surge are caused primarily by the effects of leakage flowing through the front side cavity. Now that leakage is shunted away and conditioned separate from areas susceptible to excitation, it is likely that the instability thresholds encountered on either side of BEP will be pushed out if not eliminated. Given that swirl velocity in the front cavity is de-linked from leakage rate changes, there is no potential for whirl or whip, so these operating regions need not be avoided. Additionally, as the flow pattern in the side cavity with rotating shroud is similar to that of a pressurized spindle bearing (circumferentially-uniform pressurized fluid fed at hub, and outward-only radial flow with no pre-swirl), significantly higher revolution speeds may be attainable.


Compared to thrust breaks, this design provides a better solution to pre-swirl in the cavity and self-excitation, including the potential for higher revolution speeds. Importantly, the efficiency penalty is much less than with thrust breaks, if any at all. ■

Impeller Design

Environmental contaminants affect gas turbine performance. Sand, dust, salt, and other elements present in the huge volumes of air consumed by turbines can impact aerodynamic performance, corrode metal parts inside the machine, and lead to failure. The local environment can contain high volumes of sand, salt if near to the coast, excessive rainfall, elevated levels of moisture from mist, fog, or high humidity levels, or a combination of any of these with seasonal variations.


Inlet filtration houses are installed to protect the machines from contaminants. Their design needs to be specific to the environmental conditions of each installation. But how do we know how filters will perform against real-world conditions? To gain an in-depth understanding, mobile test rigs (MTRs) were deployed across the globe to review the performance of filters in four different environmental conditions: Coastal sites in the northeast of the United States (MTR4) and west coast of the Kingdom of Saudi Arabia (MTR3), as well as inland sites in the Midwest of the United States (MTR2) near its geographic center, and a desert plateau in the center of the Kingdom of Saudi Arabia (MTR1). These provided a range of conditions, namely coastal low dust (MTR4), coastal high dust (MTR3), inland low dust (MTR2), and inland high dust (MTR1). All equipment, flow rates, and filters were standardized.


The study ran for 6,000 fired and instrument hours, covering all four seasons. Performance data and weather conditions were recorded to identify any abnormalities. Each MTR can run multiple stages of filtration, including a coalescer stage in the weather hoods, pulsing cartridge filters, and downstream vCells stage. Each rig is built to run two independent, identical wind tunnels side by side with multiple filters in each stage, enabling direct performance comparisons. At the high-efficiency cartridge stage, it is possible to run six filter sets per wind tunnel, all capable of being pulse cleaned.


As well as comparing known filters in the industry, having two wind tunnels in each MTR provides the capability to develop and try new filter types without putting a gas turbine at operational risk if it was to be tested at a larger scale. Weather conditions that can affect filtration performance are measured, including rain, mist, fog, snow, ice, dust and sand, and wind speed. Each is measured and rated, including droplet size, particle size, relative humidity, and temperature.


Coalescers are usually installed near large bodies of water, such as oceans, lakes, and rivers. However, one of the larger reactions seen in the MTRs on the pulse filters came from MTR2, an inland low dust test site. Normally such an environment would be classified as benign. But results confirmed that coalescers are beneficial in areas that experience high levels of humidity and fog even where no large body of water exists. As opposed to rain or snow, moisture is formed of tiny water droplets that can become trapped in the matrix of the filter media and cause blockages (Figure 1).


At the MTR3 coastal high-dust installation, the impact of high winds created minor differential pressure increases across the inlet and coalescer stage (Figure 2). Such observations help in the selection and design of filtration systems and GT placement for new power plants.


The importance of being able to test multiple high efficiency products at the same time can be seen from a trial completed in MTR2 (inland high dust). The test rig had two different filtration product types running, one in each wind tunnel with identical test parameters. After six months of operation, a distinct shift in their effectiveness became evident (Figure 3). As current industry testing standards utilize accelerated test methods using a known type of test dust, they produce radically different results. Thus, such standards may not provide a true comparison of products.

The effect of snow, ice and moisture can be seen at the MTR4 (coastal low dust site) (Figure 4). The results showed sharply different reactions to moisture over time that produced differential pressure spikes.

The industry standard filter experienced a greater reaction to moisture over time, producing differential pressure spikes. Such events could lead to de-loading of the gas turbine.


In what appears to be low-moisture risk (inland low dust) regions, there was a consistent reaction to moisture, showing the benefits of installing coalescers. Without coalescers, the inland low dust site’s reaction to moisture is more pronounced than coastal sites in similar conditions with coalescers. The impact of winds on the coalescer stage was also a notable learning from the data set. The measured wind and associated increase in differential pressure was significant enough that OEMs should consider this when installing new gas turbines.


Ultimately, a filtration solution needs to protect high-performance gas turbines from different contaminants, seasonal variants, and distinctive environmental conditions. While lab testing provides some guidance, it does not replace testing in real-world conditions. ■

Gas Turbine Filtration

Many OEMs are moving away from supporting legacy generating fleets. Yet the service needs of this equipment havenot 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 pro-vider 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.


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 manufacturers 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.


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 asis 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

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

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.

These basic laws of physicshave nothing to dowith price gouging.

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 t her mody nam ics. 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 t he gas t urbi ne combustor. T he 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 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

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

Myth: Curtailed Output is Price Gouging

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

May/June 2022