I (Klaus) often joke that turbomachinery aerodynamicists and rotordynamicists hate each other and are natural enemies. The aerodynamicist wants a tiny thin shaft with gigantic, long blades while the rotordynamicist doesn’t even care about the existence of blades and is only happy when the shaft is fat enough. While this may be a slight exaggeration, there is some truth to this, especially when discussing certain topics of rotordynamics such a cross-coupled forces, i.e., when mentioning cross-coupled forces to average turbomachinery designers, their facial expression become terrified, their demeanor transitions to dread, and any meeting becomes a doomsday atmosphere. So, what are these cross-coupled forces that we are so scared of, and how scared should we really be? Some basic discussion may be beneficial.

The functional explanation of cross-coupling is that a force acting on an object in one coordinate direction causes a reacting force of the object in a different coordinate direction. This sounds weird but is quite normal in most complex mechanical systems. For example, if you ride a bike and press with your foot on the pedal in the downward direction, the resulting force transmission leads to a stabilizing forward force and motion via the gear, chain, and wheel. At the same time, since the foot pedal force is applied off the vertical center of the bike, the force creates a destabilizing sideward force that can result in the bike falling over if there is no stabilizing forward motion. For example, if you push down on the pedal but the bike is not moving forward, you usually lose balance. This type of cross-coupling and associated instability happens in all mechanical systems where forces are not just transmitted linearly—which are basically all practical everyday dynamic systems.

There are many causes for cross-coupled forces in rotating machinery, but the most common one is that of cross-coupling in fluid film bearings. In a fluid film bearing specifically, a force in any radial direction will create a cross-coupled force if the shaft is not perfectly centered and/or the pressure profile of the hydrostatic support system is not symmetrical to the bi-normal force vector. Again, sounds a bit complicated but basically all journal bearings can produce cross-coupled forces, and the magnitude of these forces usually increases with the radius of the rotor orbit inside the bearing. Other items in a turbomachine that can produce cross-coupling effects are gear boxes, seals, balance pistons, impeller aerodynamics, etc.—basically everything that is connected or creates a force on the shaft.

From a classical dynamic analysis perspective, we treat a rotor system just like any other mechanical system: We must solve Newton’s first law in two or three dimensions based on mass, stiffness, damping, and applied forces (ma+cv+kx=f). Cross-coupled forces within this analysis then appear as cross-coupled stiffness and damping. This is also the best and easiest way to assess the impact of cross-coupled forces on the stability of the rotor, and this is where the evil magic of the rotordynamicist comes in (Did I mention I am an aerodynamicist?). Unfortunately, I have to work with rotordynamcists on a daily basis, so I will refrain from further adjectives, but rest assured that the field of rotordynamics is basically witchcraft, sorcery, and skullduggery.

In general, you don’t need a rotordynamicist to get a subcritical turbomachine to work, and you don’t need a very good rotordynamicist to get a machine to work that operates between 120% and 200% of the first critical speed. However, as we push above two times the first critical speed, we start encroaching upon the second critical speed and start getting into stability problems that become increasingly difficult. Serious rotordyanmic capabilities and skill are required at this level of witchcraft.

So, when dealing with a rotordynamicist, here are a couple of tips on how to respond to the assertion that there are cross-coupled forces and that you therefore need a thicker shaft:

All turbomachinery rotor systems have some cross-coupled forces, but that does not automatically mean that the system is unstable. As with any other dynamic system, the damping, c, is usually beneficial and enhances stability while low shaft stiffness, k, can lead to instability. Large cross-coupled stiffness (kxy/kyx) can drive instabilities while cross-coupled damping (cxy/cyx) is usually benign with a large uncertainty in magnitude. The potentially destabilizing cross-coupled stiffness kxy/kyx results from the fluid behavior in bearings, gas (or liquid) seals, and/or aerodynamic flow paths.

As noted, not all cross-coupling is destabilizing. When the stiffness terms kxy and kyx have different signs, they drive instability. If that cross-coupled stiffness is occurring at or near a resonance mode shape, then that particular mode is not strongly influenced by the cross-coupling. Or if the cross-coupled stiffness is located near an anti-node of a mode shape, then the effect on stability can be pronounced.

But there are cases where kxy and kyx are of the same sign, and the system is usually stable even if the stiffness is of different magnitudes. One potential source of kxy and kyx being the same sign can come from coordinate transformations. For example, a tilting pad bearing may have no apparent cross-coupled stiffness. But when translating the dynamic coefficients to a different coordinate system, cross-coupled stiffness of both kxy and kyx becomes evident. This can be misleading, but it is not a rare phenomenon, especially with geared systems.

Ultimately, cross-coupled forces and stiffness are poor parameters to judge rotor system stability. They are simply one of the many inputs required for the analysis. As difficult as this is to admit for an aerodynamicist, a full (evil magic) rotordynamic stability analysis should be performed, and the predicted outputs, such as the log-dec or rotor orbits, are much better indicators whether a turbomachine will be stable over its desired operating range.

(Karl Wygant and Brian Pettinato—both rotordynamicists and masters of the dark arts—contributed to this article.)

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 has been an ASME Fellow since 2003 and the past chair of the IGTI Oil and Gas Applications Committee.

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

Articles

What are cross-coupling forces really, and should I judge my rotor system stability on them?

Myth: The End is Near … I Have Rotordynamic Cross-Coupled Forces

Mechanical variable speed drives (mVSDs) are sometimes used for turbomachinery, particularly in the medium-power rating range. And although the use of mVSDs is not widespread in the industry, knowing whether to select an mVSD or more accepted variable speed options, such as electrical VSD or steam turbine drivers, is important.

An mVSD could be a cost-effective and compact alternative to an electric VSD system (or similar) depending on the application and should be determined on a case-by-case basis. However, mVSD systems can be difficult to properly model and predict. mVSD systems are often looked at as unknowns and black boxes by engineers and operators—even some machinery experts are unfamiliar with them.

The majority of mVSDs have been based on hydraulic concepts or use devices based on hydraulic concepts. The fluid-coupling, or hydraulic-coupling, section is a hydrodynamic device used to transmit mechanical power using properly selected oil as a medium. This device is usually responsible for the soft start, speed variation, and damping of mVSDs. Therefore, it plays a major role in its performance. In fact, many mVSDs consist of two parts: a fluid coupling (or hydraulic coupling) and a gear unit; the gear unit only increases the speed (fixed ratio), and the fluid coupling acts as soft starter, damping device, and speed adjuster. This duo increases and adjusts the speed of a fixed speed driver (usually a fixed speed electric motor) to match the high speed needed for turbomachinery, such as a turbocompressor or pump. In other words, the fluid coupling is the device that actually changes or adjusts the speed as the gear unit, often a planetary gear unit, is just a fixed ratio gear system.

The housing in a fluid coupling is an oil-tight compartment that contains oil, an oil pumping impeller, and an oil turbine wheel. There are seals around the input and outlet shafts that are connected to the oil pumping impeller and oil turbine wheel, respectively.

The oil pumping impeller is a driving impeller that is rotated by the input shaft; depending on the design of the device, this shaft is directly driven by the driver or driven through a gear unit. The impeller’s motion imparts both outwards linear and rotational motion to the oil. The oil, which is a carefully selected hydraulic oil, is directed by the pumping impeller. This impeller forces the flow of oil in the direction of the turbine wheel. This mechanism provides a soft-start capability because the input and output shafts are only related to each other through the hydrodynamic action of the oil. Also, by regulating and changing the direction and flow of the oil, load and speed variation can be achieved. In this way, the mVSD starts the operation at small loads regardless of the heavy load on the driven side, such as heavy inertia of the driven turbomachinery.

There are two critical facts: First, a fluid coupling cannot achieve 100% power transmission efficiency because of slippage and losses that occur. Some power is always lost in fluid friction and turbulence, and some is dissipated as heat. Like other hydrodynamic devices, the efficiency tends to increase gradually with increasing scale, as measured by Reynolds number. In other words, small-scale fluid couplings offer relatively low efficiencies.

Second, a relatively low efficiency should be expected when operating at part-load because some adjustments in oil flow and direction are involved, resulting in more losses in turbulence, friction, etc. In fact, more work is wasted in a fluid coupling when the turbomachinery is operating at lower loads or below rated speeds. At part-load, efficiency is relatively low compared to other VSD technologies, such as electrical VSDs, or variable speed drivers such as steam turbines.

As a fluid coupling operates kinetically, low viscosity fluids may be preferred, but other practical aspects should also be considered. Increasing the density of the fluid increases the amount of torque that can be transmitted at a given input speed. Also, these fluids, much like other oils, are subject to changes in viscosity with temperature changes. This leads to a change in power transmission performance. Therefore, oil with optimum viscosity and a high viscosity index should be used. Generally, oil for any mVSD or fluid coupling should be selected after careful analysis and after considering all aspects of operation, reliability, and performance.

There are some unique alignment procedures for some mVSDs, as many systems use complex gear units such as planetary gears. Even for a simple gear unit, alignment is a challenge, and even more so with a complex mVSD system.

mVSD systems, particularly hydrodynamic torque converters, require a large amount of oil for commissioning and operation. As such, the mVSD manufacturer should provide special oil. Further, the main oil pump is often shaft-driven and should be sized properly to handle operational situations such as start-up, emergency shutdown, possible faults, etc. There should also be a full-sized second start-up and stand-by oil pump. Sometimes, a rundown tank or an (third) emergency DC electric motor-driven backup oil pump system could be required.

A combined oil system with other equipment in the train is a compact option for some applications and is facilitated between the mVSD manufacturer and other turbomachinery vendors.

Overall, mVSDs are a good solution.A careful evaluation is the key to selecting the best variable speed drive system for each turbomachine.

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

Knowing how and when to select an mVSD is important in the turbomachinery industry. 

Turbo Tips: Advantages & Disadvantages of mVSDs for Turbomachinery

When selecting a centrifugal compressor for a project, settle-out pressure (SOP) defines two major requirements: driver torque for startup at SOP and compressor shaft-sealing pressure. But first, what is SOP?

In gas compression, pressurized and unpressurized are the two major scenarios associated with compressor shutdown.

An unpressurized compressor shutdown is usually triggered by severe events in the plant—the extreme being a loss of containment and possibly a fire when the gas within the compressor’s isolatable section is vented to a pressure lower than the compressor discharge pressure. However, venting the gas, which results in flaring or safe release to the atmosphere, causes environmental impacts and revenue loss (due to refrigerant or feedstock loss) and therefore is not preferred unless necessary. For this reason, pressurized shutdown is more common and preferred over unpressurized shutdown whenever allowed by safe design.

In a pressurized shutdown, the isolatable section is kept pressurized for restart, which results in pressure equalization across the compressor to SOP. This SOP is usually higher than the design inlet pressure and can reach values higher than the discharge pressure of lower or intermediate pressure sections, for example, of refrigeration compressors in LNG plants. FIGURE 1 is a conceptual schematic depicting SOP and its overly simplified calculation without considering the impact of temperatures.

Let’s discuss why this SOP under unpressurized shutdown affects the above stated two requirements.

Compressor absorbed torque can be considerable if restarted under high SOP. Compressors are typically started with the inlet and discharge isolation valves closed and the recycle (surge control) valve fully open. In the design stage, one of the compressor driver requirements is to meet power and torque requirements under all operating conditions—start-up, including restart at SOP, and normal running. API 617 requires motor driver’s power to be 10% higher than the compressor’s maximum absorbed power for any specified operating case. In some applications, plant operators usually specify to size the motor to deliver the required torque at reduced voltage (80%).

Do note, the starting torque discussed here is not the locked-rotor torque, but the torque required to accelerate the driven equipment from zero to its rated speed.

At restart, if the SOP is considerably higher than the design inlet pressure, the gas density and hence mass flow rate with full recycle through compressor are also high, requiring consider-ably high absorbed torque as in the equation below:

This is especially a concern as driver-produced torque is lower at reduced speeds. As the driver speed increases, it can pick up more load.

When plotted on a compressor map, these high-mass flow rates will show that the compressor runs in overload conditions that require high starting torque. In some cases, the driver torque may fall short of meeting the compressor-absorbed torque, which would impose reducing the SOP. Therefore, restart from SOP becomes an important design criterion while selecting the driver.

If the starting torque at settle-out condition is causing oversizing of the driver, or if the driver is already selected and the project is in the advanced stage of engineering, alternative start-up procedures, including release/venting the SOP, change in recycle valve controls, throttling the inlet flow (if possible) etc., may be considered.

Dry gas sealing pressure is maintained at least 50 psi higher than the process side gas pressure (in beam-type compressors) and impeller back pressure (in overhung compressors). A standard check (also required by API 617) mandates that the available sealing pressure should consider the SOP. The primary sealing gas source is typically taken from the compressor’s discharge with a provision of a high-pressure clean gas for startup (when the compressor discharge is not available). The maximum shaft-sealing pressure and its source should thus be selected to account for the effect of SOP.

For these reasons, the SOP becomes an important parameter in a centrifugal compressor design project.

Sudhindra Tiwari works in Bechtel Energy’s Houston office and has more than 30 years of experience in rotating/package equipment engineering. Email Sudhindra at stiwari2@Bechtel.com.

SOP is an important parameter in centrifugal compressor design.

How Settle-Out Pressure Impacts Compressors 

Accurate hole measuring in turbomachinery components is crucial for safety and performance, ensuring adequate pressure and flow throughout the system. An inaccurate measurement could lead to scrapping the component(s) and material, which is costly.

Turbomachinery applications that have holes include discharge nozzles, eye of an impeller, shaft, shaft sleeve, intake valve, and suction flange, which have hole diameters that range from tapered and straight to through hole and blind. To guarantee accuracy, each of these examples necessitate using the correct bore gage.

When selecting a bore gage, the following factors play a role:

It is useful to review the types of gages available to select one that best suits the application. Bore gage types include telescoping, dial, electronic, and small-hole tool gaging: two- or three-point anvil contact, with a choice between a vernier or electronic readout type, including wireless data transmission for SPC on many electronic types.

The choice between two- or three-point contact is important. A two-point contact rod-type inside micrometer is usually lighter, easier to handle, and more versatile over long ranges—from approximately 6 – 107 inches (150 – 2,700 mm). Any two-point contact gage, regardless of range, can probe a hole better than a three-point contact gage.

Most three-point contact tools have setting rings to ensure accuracy. If you require close tolerance work with a two-point contact inside micrometer, set the tool to a ring gage or an outside micrometer. A three-point contact gage can be seated in position more quickly than a two-point gage.

Usually, the three-point gages can also be read to a finer accuracy. The three-point gage will tell the maximum true diameter that can enter the hole faster than a two-point contact gage.

Three-point gages are accurate to 0.0001 inch (0.002 mm), but overall, accuracy depends on best practices and technique. To ensure accuracy, these practices should be followed:

Make sure that there are no specks of dirt between the clamping surfaces of the tool rods or

Tighten all rods uniformly—not too tightly, not too loosely, but a

Assembling long sections should be done vertically or horizontally with support.

Because temperature can affect long rods used in these gages, they should be assembled in the same environment in which they will be used.

Telescopic bore gages are used for determining the true size of holes, slots, and recesses with a limited measuring range, usually up to 6 inches (150 mm).The ends of both contacts are hardened and ground to a radius to allow proper clearance on the smallest hole that the gage will enter. These tools must be slightly rocked in the hole being measured to ensure that the tool is on the proper diameter before it is locked and with-drawn. The final hole size is obtained by measuring over the gage contacts with a micrometer.

Dial bore gages are available in two- or three-point contact with a choice of dial reading, imperial, metric, or fractional graduations. Measurements are taken by comparison, so some type of setting master should be used as a reference standard. Set the gage as close to the hole being measured as possible to maximize the hole measurement.

Vernier bore gages require the combined ability to read and add fine graduations to obtain a measurement, whereas electronic digital bore gages feature an LCD numerical display for fast-go/no-go visibility measurement results.

As previously mentioned, electronic gages enable measurement data collection and documentation for SPC purposes, which is an advantage over dial or vernier gages. In addition, some electronic gages are IP67-rated for protection against harsh ambient shop environments with coolant, dust/dirt, etc. There are also unique pistol grip gages with trigger activation that allow for fast access to the hole being measured. Both vernier and electronic gages are available in two- or three-point contact styles.

Small-hole gages are well-balanced tools that are ideal for accurately measuring small holes, slots, grooves, and recesses in all kinds of turbine parts. Popular features include a hardend-ball measuring surface with two-point contact. Having a radius on each gage that is less than the minimum diameter that will be measured provides the two-point contact necessary for maximum accuracy. Smooth, sensitive adjustment for a better feel also provides more accurate measurements. Most of these gages have a safety stop that prevents the gage from going beyond its measuring range to avoid any breakage.

When machining bores, challenges with fit and out-of-roundness may result in lobing. Out-of-roundness can be caused by centerless grinding (5-lobing), a worn or out-of-balance spindle (irregular-lobing), work holding with a three-jaw chuck (3-lobing), and other issues. In an internal roundness scenario, lobing often occurs when applied forces on a limited wall thickness surpasses the material’s yield limits. The result impacts the roundness of the internal diameter.

Conversely, external roundness can be impacted when machining a material where its strength is inconsistent through the workpiece, for example, coatings. Out-of-roundness can be identified by irregular travel of an indicator or parts not fitting properly and is either asymmetrical (irregular lobing) or symmetrical (regular lobing). Empirically discovering that the fit is incorrect can be too late and very costly to rework.

Selecting the most appropriate bore gage for the turbine components being made will significantly minimize these challenges. Sometimes, roundness geometries are important enough to utilize metrology equipment that is specially designed to measure it. This is a costly but a very effective way to profile the specific roundness of a part. If parameters are established for the finished part, specific operations can then be monitored in-line with a bore gage. This can reduce the expertise required, empower operators, and improve the end results of the finished parts.

Roundness or ovality (a basic subset of roundness) is typically not specified. But understanding the character of an internal diameter can build confidence when qualifying your work. An effective internal diameter requirement with an overall tolerance is more typical. Bore gages can improve measurement confidence compared to using a slide caliper or other two-point instruments, including greater resolution, accessibility to depth, and ease-of-use.

Sometimes custom gaging solutions are available to solve specific turbomachinery application challenges. For example, a dovetail slot gage can accurately measure internal and external holes in gas turbines and aerospace engines. Fan blade gage versions provide internal measurements of the dovetail seat face width and bottom lobe width. A turbine blade version offers internal single-side measurement for setup, and symmetry and internal double-side measurement for overall width. An external dovetail gage offers measurement of the dovetail slot with ball contacts as well as on machine measurement.

For challenging perpendicular bore holes, a valve cavity-seat pocket gage is helpful. Using a one-piece right-angle adaptor, measurements can be made at 90 degrees to the entry of the core. Optimized anvil form and guide pieces assist the entry and correctly position the measuring head for higher accuracy and ease-of-use.

Overall, gages determine the quality and accuracy of the machined hole or bore and optimize hole measuring.

Tim Cucchi is the Continuous Improvement Manager for Assembly at The L.S. Starrett Co. Founded in 1880 and headquartered in Athol, MA, The L.S. Starrett Co. (www.starrett.com) is a global manufacturer of precision-measuring tools and gages, optical comparators and vision systems, force, and hardness testing solutions, and more.

With a variety of bore gages to choose from, understanding the types of gages available is key to selecting the best fit for each application.

Maximizing Hole Measuring with Bore Gages 

Compressor lube oil systems are often viewed by operators as a necessary evil in that they are crucial to maintaining continuous operation of the main rotating equipment—compressor, driver, and gearbox when required—but can sometimes be a significant contributor to maintenance and operating expenses.

Advances in lube oil units for centrifugal and integrally geared compression trains have helped to address some of the pain points with current systems, including the use of variable speed and electric motor-driven pumps in lieu of fixed speed pumps.

While the design and configuration of a lube oil system can vary greatly depending on the type of driver and driven equipment, capacity, operating profile, site conditions, etc., there are certain components that are common across all applications.

A standard API-compliant pressurized lube oil system consists of a reservoir, pump(s), cooler, heater, filter, control valves, relief valves, pressure and temperature switches, gauges, and piping. In some cases, the main pump can be mechanically driven and operated as a function of the main equipment driver speed. More commonly, a fixed-speed AC-motor-driven main pump is provided in these applications. For either of these configurations, an auxiliary/standby fixed speed pump, usually electrically/AC driven, is also installed to provide redundancy in the event of a main pump failure (2 x 100% configuration). In the case of failure of both the main and auxiliary pump or an electrical blackout, a rundown tank is installed, which supplies oil to the compressor until shaft rotation comes to a stop.

Fixed-speed lube oil system designs offer high reliability and familiarity to operators; however, they do come with drawbacks, such as reduced efficiency, increased power consumption and associated carbon emissions, weight, footprint, and maintenance, as well as the need to stock several spare parts.

The oil requirements of the compressor train can fluctuate during operation and are impacted by several variables, including compressor speed, oil temperature/viscosity, etc. Fixed speed pumps must be designed to meet the maximum required flow rate, plus a margin of safety. This means that a large portion of the time, when the compression train is in operation, more oil is being pumped than is required by the equipment train, resulting in wasted energy.

Fixed-speed lube oil system designs offer high reliability and familiarity to operators; however, they do come with drawbacks, such as reduced efficiency and increased power consumption.

The excess oil must be diverted using a regulating/bypass valve that redirects flow back to the reservoir. Often, this results in the need for additional piping, which can increase the lube oil skid’s weight and footprint and can cause maintenance accessibility issues when the envelope boundary is fixed.

DRIVING IMPROVEMENTS THROUGH ENGINEERING INNOVATION

Over the years, new developments have optimized lube oil system designs to meet evolving industry and customer demands. Conventional designs utilize two fixed speed pumps—a main and auxiliary—each considering at least 120% of the equipment required oil flow. Newer units feature three variable-speed, electrically driven positive displacement pumps that provide 50% of the required flow capacity. Variable speed drives (VSD) enable controlled adjustment of pump operating characteristics to ensure optimized power consumption. Additionally, pump speed can easily be adjusted online to handle variations in the lube oil system, which eliminates the need to oversize the driver and pump.

In a three-pump configuration, during times of normal compressor operation, two of the pumps work in parallel while the third pump is connected to both a normal power supply and an uninterrupted power supply (UPS). It acts as both an auxiliary/standby pump in the event of pump failure and an emergency pump in case of an electrical blackout.

The use of VSDs provides several advantages over fixed speed systems, including a reduction in overall power consumed by the unit. This is primarily due to the elimination of over pumping, as the VSDs can be turned down to match the rotating equipment’s demand for oil.

Comparisons were drawn between a conventional three-inch API lube oil system (786 LPM) versus a three-inch three-pump system (i.e., Dynamic Lube Oil Unit (800 LPM) as seen in FIGURE 1) to evaluate power-consumption values. The conventional unit would require two fixed-speed AC pumps, each with a nominal nameplate rating of 25 kW, which is required to account for:

capability to direct online start under very cold oil conditions, and

necessity to handle higher equipment flowrates (20% margin).

When the conventional system operates under normal conditions, the lube oil system would consume a reduced load of roughly 15 kW.

The latest system design has three VSD pumps, each with a rating of 11 kW. With two pumps running, power consumption would be about 10 kW, which represents a power savings of roughly 33%. The power savings would be 50% when compared to a mechanical-driven lube oil pump since the pump flowrate is highly dependent on the main equipment driver speed. Considering a variable speed main equipment driver, the shaft-driven lube oil pump would provide 120% flow at minimum operating train speed and would then provide 150% flowrate at normal design speed. This oversizing of the shaft-driven pump causes a substantial increase in power consumption for the oil system.

Having the third VSD pump connected to a UPS can eliminate the need for a rundown tank, which removes the need to accommodate rundown oil and interconnected pipe volume in the lube oil reservoir, saving both space and weight on the skid. Furthermore, the support structure for the rundown tank itself is removed, and indoor building height can be reduced. The overall volume of oil in the system is reduced by 40%—from 8,600 L in a conventional system to 5,200 L. The safety valve can also be incorporated directly into the VSD pump itself. The pressure regulating valve, spillback back regulating valve, associated piping loop, and manual hand valves can be eliminated since the VSD adjusts pump speed to maintain the required flow. Eliminating the piping and valving further reduces the weight of the system and minimizes the footprint of the reservoir. FIGURE 2 shows that the overall weight and footprint is reduced by 35% compared to the conventional API unit.

The VSD-driven pumps facilitate the implementation of a battery backup option as an alternative to the rundown tank. This is a result of lower motor name plate ratings for the oil pump and reduced starting currents that are controlled by programmed starting ramps. These factors positively affect the sizing of the required UPS. Furthermore, each pump provides 50% capacity, hence restarting the pumps after a blackout becomes easier when compared to a full-capacity AC direct-on-line (DOL)-started oil pump.

It is also important to note that the use of an electric-based backup system can eventually allow for the integration of solar energy via photovoltaic power cells, which could potentially allow running the oil system on a renewable source during the day.

INCREASED OPPORTUNITIES FOR DIGITALIZATION

The use of VSDs allow the end-user to gather additional operating data (speed, power, hours of operation, flow, operating current, torque, motor temperature, etc.), which further enables monitoring and diagnostics of the pump and motor health. Comparisons to the main drive train equipment parameters and data trends can facilitate the implementation of predictive maintenance programs.Capturing additional energy consumption data helps to evaluate the current component or system condition and can support more accurate assessment in quantifying environmental targets or meeting future legislative requirements.

The use of VSDs allow the end-user to gather additional operating data, which further enables monitoring and diagnostics of the pump and motor health.

Lube oil systems are cited by operators as one of the most problematic components of compressor packages. By addressing many of the issues experienced with conventional designs and better aligning with operator objectives to reduce power consumption and decarbonize through electrification, these challenges are being addressed. While the design philosophy of the lube oil system is novel, the technologies it leverages are often widely used by operators in other areas of their operations.

Peter Rupprecht is the Fluid Systems Application Engineer at Siemens Energy. Firozkhan Shaik is the System Architect Engineer at Siemens Energy. Hunter Banister and Justin Malpiedi are Research & Development Engineers at Siemens Energy.

Newer lube oil units offer advantages over conventional systems via lower power consumption and associated carbon emissions.

Ushering in the Next Generation of Compressor Lube Oil Systems 

Carbon capture, utilization, and storage (CCUS)—which aims to reduce carbon emissions while simultaneously contributing to the development of a circular carbon economy—is set to play a diverse role in meeting global climate goals. With green initiatives on the rise and regulatory bodies becoming more imposing on emitters, curtailing emissions is now a top concern for carbon-producing entities. To solve this problem, innovative solutions are entering the industry. Fueled by direct support from world leaders and governments, CCUS technologies are one pathway to achieving net-zero emissions. So, what role is the turbomachinery industry playing?

HOW DOES TURBOMACHINERY PLAY A ROLE IN CCUS?

) compression can be seen as a critical element in carbon-capture storage applications, which makes it an essential building block in the larger picture of global decarbonization.

“Among compression methods, integrally geared centrifugal compressors are a preferred rotating hardware because of the special behavior of CO

 applications,” said Ulrich Schmitz, Vice President Marketing at Atlas Copco Gas and Process.

, like other high mole-weight gases, increases its temperature during compression, making the interstage cooling provided by integrally geared compressors an energy-efficient and cost-effective characteristic, Schmitz explained. Turbomachinery plays an important role in CCUS processes, for example enabling the transportation of the gas by compressing it. Without this essential component, handling CO

 in the long term would be much more difficult. Compressors also come into play later in the value chain with the creation of aftermarket products. Thus, compressors can be seen as the crux of carbon-capture value generation.

Large-scale adoption is a challenge in both the United States and Europe. One way to increase adoption is through regulatory avenues. The United States passed the Inflation Reduction Act (IRA), which includes $369 billion in green energy grants and subsidies to accelerate the reduction of carbon. In March, Europe proposed the Net-Zero Industry Act, which aims to establish a framework of measures for strengthening Europe’s development of net-zero technologies.

Following the passage of the IRA, Aniruddha Sharma, Chair and CEO of Carbon Clean, a UK-based company focused on carbon capture solutions, said: “Carbon Clean has experienced a 64% leap in inquiries, and we expect the United States to become one of our largest markets,” Sharma said. “In March, we announced a significant expansion in North America to meet this booming demand. [We opened] a U.S. headquarters in Houston and are currently developing a local supply chain.”

Sharma said government support is needed to push CCUS at a significant scale, including policies to economically support these endeavors. This includes setting financial rewards, simplifying the permitting and planning process, ensuring storage sites are developed quickly, and putting a focus on regulation that supports the growth of CO

The U.S. Department of Energy (DOE), through the National Energy Technology Laboratory (NETL), is working on promoting and developing carbon capture and storage (CCS) technologies. In a recent panel at PowerGen 2023, representatives from the governmental body spoke on the role CCS plays in promoting carbon neutrality.

Jose Figueroa, Carbon Capture Team Supervisor at NETL, informed attendees about the capture technologies his department is helping to develop, such as direct air capture. He said that technologies such as CCS and collaboration across different sectors—government, academia, industry, and research organizations—will help support the goal of achieving net zero by 2050 seem more attainable.

Currently, geological storage is the most mature technological option for storing CO

 and offers significant capacity for sequestering CO

 storage in geologic formations includes oil and gas reservoirs, unmineable coal seams, and deep saline reservoirs.

However, the Clean Air Task Force (CATF) said among the carbon capture, transport, and storage value chain, storage is the key bottleneck impeding the development of carbon capture and storage in Europe. According to the authors of Europe’s Net-Zero Industry Act: What does it mean for carbon capture and storage, “As CATF determined last year, Europe could face up to a 50% shortfall in storage capacity available to capture projects in 2030.” However, the Net-Zero Industry Act is creating better conditions and opportunities for clean-energy technologies in Europe.

In the United States, according to the Congressional Research Service, the DOE estimates the country’s total storage capacity to range between about 2.6 trillion and 22 trillion metric tons of CO

Dr. Marcus Brücher, Senior Vice President of Compression at Siemens Energy, said the company is focusing on storage rather than utilization. “The amount of CO

 produced from one large power plant is more than the entire beverage industry could consume per year,” Dr. Brücher said. “This example furthers the assertation that the viability of such products has yet to find a clear pathway when stress testing a business plan from a financial perspective. Theoretically and scientifically, many products are achievable; storage of CO

 can provide source points later when economics and financial returns are more favorable for products derived from CO

The “store-for-later” idea runs in tandem with what has been seen in the past with enhanced oil recovery (EOR) production, which, according to an article published in Reservoir Engineering, are processes that are “implemented to increase the ability of oil to flow to a well by injecting water, chemicals, or gases [such as CO

] into the reservoir or by changing the physical properties of the oil.”

Daniela Abate, Vice President of CCUS at Baker Hughes, explained that CO

-EOR has demonstrated its effectiveness, particularly in the United States where it has been adopted in several projects. According to the CCS Institute’s Global Status of CCS 2022 report, 11 out of 13 operating CCS projects in the United States are based on EOR.

The type of carbon-capture technology employed is what determines the role that turbomachinery plays. “Its role becomes critical for membrane-based, cryogenic, and hot potassium carbonate-based capture technologies, since they are operated with gas streams at medium/high pressures,” Abate said.

According to Office of Scientific and Technical Information, membrane-based capture uses semi-permeable membranes to separate CO

 from a gas stream. Cryogenic capture cools the gas stream to very low temperatures (around -100°C or lower) to distinguish the CO

 from other gases. Hot potassium capture uses a hot potassium carbonate solution to absorb CO

Further considerations when determining which turbomachinery to use include “whether it is a retrofit project with limited available space and whether the site already has sufficient energy to run compression or if a new power generation unit will be needed,” Abate said.

In these installations, operating profiles are often challenging to manage (largely due to turndown), which can lead to the need for parallel units. However, these obstacles create opportunities, such as developing modular solutions to address plot availability issues and creating more efficient machinery equipped with energy-recovery solutions.

Managing the operating profile is directly tied into the efficiency, reliability, and overall performance of both carbon-capture systems and the associated power generation or industrial process equipment. Here, it’s important to compensate for load fluctuations through advanced control strategies or the use of variable speed drives.

Further, beyond turbomachinery considerations, the CO

 capture method must also be determined. CCUS technologies can remove CO

 a few ways, including pre-combustion and post-combustion methods.

“Pre-combustion capture has high efficiency, and the increased CO

 concentration in the syngas significantly enhances absorption efficiency,” Dr. Brücher said. “However, the overall capital cost of the base gasification process is high.”

He said it comes down to evaluating which technology is fit for a specific application based on the management of the mass from the emitting and capture device. The capital cost can be attributed to the complexity of the process, the need for specialized equipment, the high operating temperatures and pressures found, and the challenges associated with feedstock handling and gas cleanup.

One advantage of post-combustion carbon-capture technology—such as absorption, adsorption, and membranes—is its maturity compared to other carbon-capture alternatives.

“It’s viable to retrofit the technology into new and existing plants,” Dr. Brücher said.

The downside of post-combustion carbon capture is that it has a low carbon-capture efficiency due to low CO

 concentration in the flue gas, as well as large parasitic loads of thermal and electrical duties. However, Abate said that “Once the CO

-rich flue gas has been compressed and has the CO

-lean flue gas stream (which typically accounts for more than 80% of the flue gas volume initially compressed) can be expanded to recover energy, which can partially offset the energy required by the CO

As an example, energy recovery devices, such as turbo-expanders or gas expansion turbines, can convert the pressure energy of the aforementioned gas into useful work, such as electricity generation. This recovered energy can then be used to power the compression process or other parts of the carbon-capture system.

Dr. Brücher concluded: “There is no ‘one-size-fits-all’ in these technologies. Each has its own strengths and weaknesses that must be considered. Siemens Energy is developing strategies in each technology area to design and provide products that contribute efficiency gains to each carbon-capture technology.”

OVERCOMING INEFFIENCIES AND INDUSTRY COLLABORATIONS

Implementing carbon-capture tools can impact the overall efficiency of turbomachinery. There’s also further value that can be extracted from the process.

 capture requires both heat and power, and CO

 compression requires power which, if supplied directly by the power plant, will reduce its overall efficiency,” Sharma said.

Some ways of mitigating this inefficiency include using solvents such as CDRMax, which reduce the amount of heat required for CO

 is being used in a down-stream process, e.g., methanol or other fuel/chemical products, there are opportunities to integrate with the CO2 capture plant to meet a large portion of its heat requirement,” he said.

 can be used in the downstream process is through collaborations such as the Flue2Chem project (

). Carbon Clean is collaborating with 14 other organizations, including BASF, Proctor & Gamble, and Unliever, on the Flue2Chem project in the UK: a two-year project that aims to convert industrial waste gases to more sustainable consumer products. The project could result in a saving of 15-20 million tons of CO

 emissions a year in the UK. As part of the project, Carbon Clean’s CycloneCC carbon-capture technology will capture 10 tons per day of CO

“Collaboration among OEM; CCS technology provider; engineering, procurement, and construction (EPC); and end users to maximize process efficiency is essential to the success of carbon-capture projects,” Dr. Brücher said. “OEMs can provide performance finesse by leveraging machine design details which are then tightly aligned to process performance.”

All parties can bring unique expertise and capabilities to the table, and their collaboration could lead to innovations, optimized designs, reduced costs, and more efficient implementation of these technologies.

Efficiency here is created at the machine level, which means reviewing the continuity of that efficiency at the carbon-capture level and then confirming that efficiency at the global facility level.

Dr. Brücher calls it a “create-review-confirm” approach, which can help keep carbon emissions at the lowest GJ/ton possible.

To further emphasize the importance of collaboration, Abate said how partnering with project developers from an OEM perspective, including CO

 transport infrastructure developers, will help in defining a cost-effective solution. Baker Hughes was recently awarded a contract with Malaysia Marine and Heavy Engineering to supply CO

 compression equipment to PETRONAS’s Kasawari offshore CCS project in Sarawak, Malaysia.

“The project is expected to be [one of] the largest offshore CCS facilities, with a capacity to reduce CO emissions by 3.3 MTPA,” she said.

This case shows the benefits of supporting projects in the CCUS space via collaboration. While the industry can reap the rewards associated with regulatory compliance, it also demonstrates its capability of promoting market and technological growth.

Carbon capture, utilization, and storage technologies are set to play a diverse role in net-zero emissions goals.

The ‘Green New Era’ for Turbomachinery?

Western Turbine Users Inc. (WTUI) began in the 80s with a small gathering of owners and operators of gas turbines for power generation in California. It has since evolved into a global network, helping its membership grapple with worldwide changes, including the decommissioning of large baseload units as more power is supplied by newer, renewable energy sources, said Ed Jackson, WTUI president.

More than 1,000 people from 25 countries and 46 U.S. states gathered in San Diego, CA, March 12–15, 2023 for WTUI’s 32nd annual conference and exhibition since its official incorporation in 1990, It was WTUI’s first in-person gathering since 2019.

Innovation that allows turbine systems to increase performance in various ambient conditions was a key topic of discussion in break-out sessions. Fogging, mechanical chilling, evaporative chilling, and inlet heat were among the subjects showcased at WTUI.

Industrom Power, a Houston-based startup founded by GE veterans, introduced its ready-to-launch, closed-loop CO

 system that, according to the company, can boost turbine plant power up to 20% and improve its heat rate by as much as 17%.



ProEnergy Services analyzed various turbine-cooling methods before determining its best investment would be an innovative fogging technology that can be combined with its wet-compression technology for superior outcomes, according to Constantin Dinu, a senior performance engineer at ProEnergy Services. The goal of the innovative system, still under development, is to improve a plant’s power output by 10% percent.

The quest for cleaner fuel production has driven innovation in selective catalytic reduction (SCR), a technology introduced in the 1950s to control nitrogen oxides (NOx).

When a power plant is designed and permitted, the needed SCR is determined by various factors. These include how many turbine starts are anticipated, how many hours a year it will run, and the expected load, Dan Johnson, P.E., Senior Director of Sales at CORMETECH.

The full show report will be available in Turbomachinery International's May/June print issue. 

Innovation that allows turbine systems to increase performance in various ambient conditions was a hot topic in break-out sessions at WTUI 2023.