Figure 1: Ideal field wiring (top) has no resistance, inductance, or capacitance, unlike real field wiring (bottom).

While it is tempting to think of wire as an ideal conductor that gets a signal from point A to point B without alteration, this is often not the case – particularly for long cable runs. In an ideal world, the cable connecting a sensor to its associated monitoring system would be a perfectly lossless conductor that would not alter the signal whatsoever.In the real world, however, the cable exhibits, resistance, inductance, and capacitance ((Figure 1). These values for R, L, and C are typically expressed on a per-meter or per-kilometer basis when SI units are used. These distributed parameters act to alter and distort the sensor signal in four undesirable ways (Figure2):

Figure 2: Filtering, slew rate, and resistance effects

Low-pass filtering effects: The distributed cable parameters form a low-pass filter that allows low frequencies to pass with little or no attenuation but effectively blocks high-frequency components of the signal from passing. This results in an altered waveform that may be unsuitable for conducting proper diagnostics. The signal may be so degraded that it is unsuitable not just for diagnostics, but protection as well.

Slew-rate effects: For speed measurements, the signal often originates as a rectangular pulse train but distorts due to the impact of wiring capacitance (known as slew-rate). The pulse train shape with abrupt vertical changes originates because the speed sensor is often observing a toothed surface, a key, a keyway, or some other physical discontinuity in the surface observed by the sensor. If there were no limitations on slew rate, such vertical discontinuities could be reproduced. But in real wiring, the capacitance limits the ability for instantaneous changes in signal voltage and the crisp, rectangular pulse train begins to resemble a series of smoothed pulses where the abrupt edges are rounded. While slew-rate rarely affects vibration and dynamic pressure signals, it can frequently affect speed signals.

Resistance effects: Cable resistance forms a voltage divider that drops some of the original signal voltage produced by the sensor across the wiring instead of entirely across the input impedance of the monitor. This has the undesirable effect of decreasing the signal-to-noise ratio. 




There are several other factors that can influence wiring. IEPE (integrated electronic piezo-electric) devices are vulnerable to an effect that creates asymmetry in the waveform when there is insufficient margin between the source of constant current (usually the monitoring system) and the minimum constant current required by the device (typically around 4mA). This asymmetry is essentially a slew-rate effect that affects only the positive portion of the signal.It arises due to cable capacitance and the phase difference it creates between current and voltage, allowing sufficient current during the negative part of the waveform but not the positive.

Voltage and current must also be considered. When the signal is transmitted as a varying voltage, it is referred to as voltage-mode signal transmission. Although voltage-mode is considered the conventional method for transmitting vibration signals, and is commonplace, it is the most vulnerable to the four effects discussed above. As such, voltage-mode transmission tends to constrain the length of field wiring more than alternative modes. Many manufacturers, however, do not support anything other than voltage-mode transmission with their sensors.

When the signal is instead transmitted as a varying current, known as current-mode signal transmission, it mitigates many of these effects and allows much longer field wiring lengths than with conventional voltage-mode transmission.

Note, though, that there are certain situations in which neither voltage-mode nor current-mode transmission are adequate over long distances. One example is in applications where the cable is underwater such as submerged vertical pumps. By using frequency modulation to transmit the signal and then demodulating at the monitor, longer field wiring distances can be supported than by other means. This can be useful for transmission of speed (tachometer) and phase signals, as well as quasi-static signals where a conventional 4-20mA scheme proves inadequate.


While signal degradation is always a constraint due to field wiring length, another constraint occurs when the installation is in a hazardous area and intrinsically safe (IS) methods must be used to achieve compliance: stored energy. Both cable inductance and cable capacitance have the effect of storing energy. When a fault in the wiring or device takes place, IS constrains a resulting spark from releasing sufficient energy to ignite the surrounding flammable atmosphere. It does not prevent a spark, but instead limits the energy in the spark. Consequently, approvals for IS provide strict limits on the total amount of inductance and capacitance that can exist in the hazardous area, and thus the amount of energy that can be stored and released as a spark.

Signal degradation is not the only constraint that exists on field wiring length when the installation involves a hazardous area and IS wiring. In such installations, the user must compute the wiring length constraint under both signal degradation and stored energy criteria and then use the more restrictive of the two separate constraints.

For more information, visit www.Meggit.com

Dr. Luc Fromaigeat, Technical Support Engineer Energy at Meggitt SA Switzerland. He has 35+ years of field experience in Vibration, acoustics analysis, and diagnostics. He teaches Vibrations for the Swiss “Brevet Federal de Maintenance” and for Meggitt worldwide. He authored an extensive application note with worked example calculations and a downloadable calculator for field wiring calculations https://meggittsensing.com/energy/app-note-cable-length/

AN INTRODUCTION TO CABLE LENGTH CONSIDERATIONS 

Field Wiring Effects

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Richard Saab of Siemens Energy discussed HRSGs and hydrogen.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

All hydrogen sessions at PowerGen were standing room only.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

HYDROGEN GENERATION, DECARBONIZATION, AND DIGITALIZATION DOMINATE

PowerGen 2022

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.

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 higher-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 re-balancing 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 measurement devices 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.

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

Turbo Tips: Large Fans

Epoxy grout placed (the dark grey material) for a large piece of equipment.

When 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.

Euclid Chemicals DL grout on the right, traditional grout on the left.

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, dustless grout is finding wider application within the turbomachinery industry.

Vance Pool is National Resource Manager at Euclid Chemical Company of Houston, TX. Euclid Chemical provides cementitious and epoxy grouts including DL products. For more information call (281)836-1276 or visit euclidchemical.com. You can also view a video on DL Technology at www.euclidchemical.com/help-support/video-library/

How to correctly apply grouting and enhance plant safety

Grouts for Turbomachinery

Natural gas prices are spiking. Recent reports indicate a dramatic 7% increase in pricing in the US, or $9.33 per million British thermal unit (BTU) of energy. Current demand is straining diminished stock levels. While America sits securely on its current reserves, Europeans don’t have that luxury. The main fuel arteries to the EU from Russia are actively disrupted, which means Europeans are forced into paying top dollar for gas from other sources. To cope, the global energy map is being redrawn, and alternatives are being explored.

Gas is seeing significant price hikes due to strained suppliers.

Energy companies need to find new suppliers on the global market to compensate for Russian absence. Incentives to be green are being cut back to make way for cheaper, more available fossil fuels. Germany is seeing a reversal in its tax policy, as it lowered the tax on gas from 19% to 7% until March 2024. The 12% decrease is expected to lessen the burden of growing inflation.

The United Kingdom (U.K.) is increasing its regulatory consumer energy bill limit. The country can’t afford to subsidize the cost for consumers at the current rate. Those on the Isles are going to see a dramatic increase. In October 2021, the average household paid £1,400 for its energy bill. With the new limits, the cap may be pushed as high as £5,456. This is roughly 1/5th of the median U.K. income. 31 British energy companies have been forced to close their doors since the start of 2021. With such a deficit in supply, those remaining have to take on the burden. Energy company profit margins are slim due to the price cap. This showcases the problem with intrusive regulatory standards. Even though there is unprecedented demand, the private sector in the U.K. is nearly powerless to meet it.

Shortfalls are being made up by countries like the US and Qatar. Competition for supplies is amplified by an unusually warm summer in Asia. South Korea and Japan are in a price war with Europeans. The result is an extremely advantageous position for the sellers and worry for buyers. This shows a major shift in the global energy map, with once-reliable sellers now out of the market. Moreover, securing ways to increase capacity on fewer routes brings further contention.

Supply lines are seeing a major shift. Liquified natural gas (LNG) tankers are in high demand. This is part of the reconsolidation of global supply routes. LNG tankers help secure trade between suppliers and buyers. There is nothing short of an absolute scramble for nations to obtain as many of these vessels as possible. European powers are facing the possibility of supply chain collapse pending the outcome of the Ukrainian conflict. Alternatives are being explored as an insurance policy for resource-strapped regions.

LNG carriers are being bought out to secure supply lines.

One choice is in hydrogen, but it’s costly and requires enormous backing to produce enough. Coal is the elephant in the room, but with the EU shying away from its use, it doesn’t seem like the savior. Until the energy map is reorganized, higher prices are unavoidable.

Supply issues see international scramble to secure resources

Worrying Gas Prices

New impeller front side cavity design having an enlarged cavity to accommodate an annular disc with de-swirl vanes affixed to the casing wall, resulting in three distinct adjoining annular cavities, in part to diffuse, de-swirl and shunt entering leakage to hub away from rotating shroud

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 (

) at the eye seal and along rotating shroud, and increasing 

 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 (Figure 1).

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.

Michael Kenworthy is President of Technology Commercialization Corp., a private venture capital firm located in Vermont specializing in early-stage technology. For more information, 

Impeller Design

Coal makes up the majority of the Indian energy mix.

India is celebrating its 75th anniversary. Development in the energy sector has skyrocketed, and so too has an awareness of a significant problem – dependence on coal. India and China lead the global supply chain for coal investment, topping the scales at over $80 billion combined. India stands as the world’s second-largest coal consumer and producer. Roughly half of its 403 GW installed capacity is coal. Let’s look at what is being done to diversify India’s energy mix.

One of India’s primary goals is becoming a $5 trillion economy. To achieve this, exploitation of its natural resources is a necessity. India holds the fourth largest coal reserves in the world at over 350 billion metric tons (MT). State-run companies are putting 2.5 trillion rupees, or $31 billion into that market. The country is massively reliant on coal, both from an economic and energy standpoint. Recent efforts have been made towards renewables, but many officials believe coal will dominate for several more decades. India predicts $54.5 billion in investments for clean coal projects through 2031. While the technology is proven for carbon emission reduction, it’s costly and requires vast investment to reach large-scale implementation.

The government made clear its commitment to economic growth on India’s 75th anniversary. Depicted: Rashtrapati Bhavan, India’s Presidential Palace.

Power plants met 201 GW of demand back in April. It reached 210 GW in June. Analysts expect over 220 GW before the end of summer. The minimum expected fulfillment by coal inventories is 160 GW during peak hours. The power ministry predicts an increase in power requirements for coal at 1375 billion units (BU) for 2021-22, and 1650 BU for 2022-2023. This is a great increase from 2020-21, where demand was just 1275 BU. Monsoons and extreme heat account for two prominent power grid disruptions the country regularly faces. With coal making up so much of the energy economy, there isn’t much to fall back on when production lines are held up. As a result, rolling blackouts occurred for a period of 2-8 hours daily during April. Reports indicate that power plants in the country have roughly nine days of coal in reserve, which is a third of the recommended level. Widespread outages and increasing demand for coal are major problems the government seeks to address.

One significant project the country has been working towards is the Kakrapar Nuclear Power Plant in Gujarat. The third unit is expected to enter operation in December. It’s the first Indian-designed 700 MWe pressurized heavy water reactor (PHWR). This is just one of 21 new nuclear power plants currently in the construction phase around India. By 2031, 15.7 GWe of nuclear generating capacity is expected. 15.7 GW out of 220 GW is progress, but it’s only the tip of the Indian coal problem.

Another project is being contracted out to Siemens Gamesa Renewable Power. It involves the European company supplying onshore wind turbines for Indian energy firm Azure Power Global. It is sending 96 SG 3.6-145 onshore wind turbines for the company’s first wind energy project. To date, Siemens Gamesa’s has given 1.4 GW of wind energy to India. This follows legislation recently passed in the lower house of parliament, which requires greater use of renewable energy targeting industrial polluters. These developments allude to a carbon market similar to the US.

India is seeking further development of renewables. Mountainside wind farm in the Chitradurga Hills of Karnataka, India.

According to the International Trade Administration (ITA), India has set a goal to have 15% of its energy come from natural gas by 2022. The International Energy Agency (IEA)’s report “Energy in India Today” indicates that for this to be realized, India will need to increase current levels by roughly 10%. While recent advances have seen an uptick in natural gas, biomass, oil, and renewables, coal still reigns supreme. Government initiatives and positive media coverage may help inspire action, but the reality is India is troubled by a coal reliance that will take decades and billions of dollars to solve.

How the 75-year-old republic is dealing with coal

India Power Growing Pains

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 operation 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).

Figure 1: Differential pressure spikes during mist and fog events without coalescers. Small moisture droplets present in mist and fog can restrict air flow through fine filtration media.

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.

Figure 2: Observed minor pressure increases during high winds at the coastal high dust installation

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.

Figure 3: Differential pressure measurement of two products in a high dust environment. For the first six months, performance was similar. After six months, the differential pressure across the industry standard filter rose more rapidly compared with Parker clearcurrent ASSURE filters.

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.

Figure 4: Differential pressure measurement of two products in a moisture-rich environment (MTR4).

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.

Parker clearcurrent ASSURE Filters protecting latest generation gas turbines.

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.

Tim Nicholas is PowerGen Market Manager, Gas Turbine Filtration Division, Parker Hannifin, whose clearcurrent ASSURE filters provide protection and performance for advanced gas turbines.

Jim Lenox is Senior Product Manager, Gas Turbine Filtration Division, Parker Hannifin. For more information visit parker.com

Gas Turbine Filtration

Kistler RCD system with piezoelectric sensor. Credit: Kistler.

Kistler is offering a wireless rotary cutting dynamometer (RCD) with a piezoelectric sensor. It allows for accurate measurements of cutting forces in machining applications. It’s all on a new platform which performs automated analyses, increasing the efficiency of working processes.

The wireless RCD from Kistler is equipped with a piezoelectric sensor and connected via wireless technology to the data acquisition device. It comes with four channel piezo crystals to measure torque as well as forces in all three directions (Fx, Fy, Fz). The wireless technology has a range up to five meters. It has a 10 kHz sampling rate which can capture footprints of the measurement in applications up to 16,000 RPM.

The new PTS (Piezo Tool System) software automatically acquires and analyzes machining data while the machine is running. Users gain insight into the condition of the cutting tool as the software provides automatic signal trend analysis. This will improve the efficiency of testing in laboratories and research centers.

Articles

First wireless rotary cutting dynamometer with a piezoelectric sensor

Kistler Wireless Piezoelectric RCD

Top: Eagle's Creek's High Rock hydro facility in North Carolina. Bottom: FirstLight's Stevenson Generating Station in Connecticut.

GE Research received a 30-month, $4.3 million project through the US Department of Energy’s Water Power Technologies Office to improve both the operating capacity and flexibility of hydropower assets.

A multi-disciplinary team of engineers from GE Research will work with GE Renewable Energy’s Hydro business and two major hydro plant operators, Eagle Creek Renewable Power, and FirstLight Power. The goal is to outfit three plants with minimal sensors and other tools to enhance the existing operational flexibility by more effectively ramping electricity generation up or down with their hydro assets.

Arvind Tiwari, Principal Investigator on the project explained that a key objective of the demonstration is to show the increased flexibility and operating capacity of hydro plants with existing components, without compromising the life of plant equipment. The GE Research team believes that with more data and great visibility of plant behavior, they can introduce more variability in operations such as fast ramp ups of hydro units without compromising component lifespans.

$4.3 million research project for flexible operation of hydro turbines

GE Instrumentation “Flexes” Hydropower

ENOGIA has a contract for the supply of ORC modules and associated services for €6.5 million. The buyer is a German biogas company. Prior to placing the order, the company was testing an ORC module coupled with a biogas engine for more than a year. The order is the biggest ever signed by ENOGIA.

ENOGIA’s ORC modules will be installed in the world's largest anaerobic digestion plant, which will be Europe’s largest ORC site and the second largest worldwide. The modules will be used to recover the heat from the cooling circuits of the biogas genset engines. Electricity produced will be recycled on site to reduce draw from the grid.

ORC Modules for German anaerobic digestion plant

ENOGIA Biogas Order

Baker Hughes is purchasing Quest Integrity. Quest deals with development and delivery of technology-enabled asset inspection and reliability management solutions across the pipeline, refining, petrochemical and power generation sectors. Quest also has experience conducting assessments in pipelines, pressure vessels, tanks, and turbine blades.

Baker Hughes’ asset integrity solutions include pipeline inspection services that detect, characterize, locate, and size anomalies in the wall of a pipeline. Quest’s technology supports pipelines that are difficult to inspect using conventional methods.

Quest Integrity’s Invista and Furnace Tube Inspection (FTIS) technology helps in inspections across pipelines, marine loading lines, petrochemical, chemical, refining, power, utility and more.

FTIS technology enables the inspection of heater coils, a critical component in furnaces, detecting issues with corrosion and deformation for customers in the petrochemical and refining industries.

The acquisition is expected to close in the fourth quarter of 2022 and will be integrated into the Process & Pipeline Services product line within Baker Hughes’ Digital Solutions segment.

Expansion extends Baker Hughes’ asset inspection solutions

Featured Content