February 2017

Combined cycle and co-generation 6 • Equipment reliability models 22 • Sequential tripping 27

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FEBRUARY 2017

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Transient torsional vibration problem due to electrical noise

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Basic thermodynamics: Why combined cycle and co-generation are much more efficient than conventional steam generated power production

By Brad Buecker, Kiewit Engineering Group, Inc.

COLUMNS

17

Machine Doctor

Transient torsional vibration problem due to electrical noise

By Patrick Smith

22

Maintenance Matters

A comparative assessment of asset management and equipment reliability models

By Rick Roberts, Electric Power Research Institute

27

Turbine Tech

An overview of steam turbine generator sequential tripping

By Bradford J. Snyder, Senior Consultant, TG Advisers, Inc.

ASME FEATURE

8

Generator collector brush holder testing and design improvements Albert E. Steinbach, Frank A. Scalzo, III and Matthew T. Preston, General Electric Co. GE Power

INDUSTRY NOTES

4 31

Editor’s Note and Calendar Advertiser’s Index

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February 2017 ENERGY-TECH.com

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EDITOR’S NOTE

What will 2017 bring?

Print issues in February, May, August and November. Weekly e-newsletters and new online training opportunities.

Welcome to Energy-Tech’s first quarterly issue of 2017. As you are reading this issue, I’m closing in on the end of my first year as editor for Energy-Tech. I have to say that I’ve finally starting to feel comfortable with the magazine and what I’m doing day–to-day. I’ve quickly gotten acquainted with turbines, emission controls, heat exchangers and other products vital to electrical power plants. I enjoy learning about the power generation industry and look forward to meeting the experts behind many of the articles that we present to you, our readers, throughout the year as I attend some of the industry conferences.

Whether you attend any of the many industry conferences or not, you always have the choice to continue your education through on-line training courses and webinars. These affordable courses, presented by key industry leaders, offer professional development from the convenience of your office.You have the option of attending a live training course as they happen, or downloading a past course that you can watch at a time convenient to you. Just look for the webinar and events tab on our website – www.energy-tech.com – to see what’s available.You’ll want to visit often as we keep adding to the list throughout the year. Don’t see what you need on the list or have an idea for a new online training course? Give me a call at 563-588-3857.

I’d love to hear your ideas.

CALENDAR April 5-7, 2017 Connected Security Expo @ISC West Sands Expo, Las Vegas, Nev. www.connectedsecurityexpo.com April 10-13, 2017 Electric Power Conference & Exhibition McCormick Place West, Hall F1 Chicago, IL www.electricpowerexpo.com June 26-30, 2017 ASME 2017 Power & Energy Conference & Exhibition Charlotte, NC www.asme.org/events/power-energy September 12-14, 2017 Turbomachinery & Pump Symposium George R. Brown Convention Center Houston, TX www.asme.org/events/power-energy Dec. 5-7, 2017 Power-Gen International Las Vegas Convention Center Las Vegas, Nev. www.power-gen.com Submit your events by emailing editorial@woodwardbizmedia.com

And finally, thank you to those that completed our assessment survey that was emailed in November.Your comments will be forwarded to our columnists so that we can keep up with your needs.

As we move through 2017 you can expect four printed issues of Energy-Tech magazine again – February, May, August and November – and a weekly e-newsletters every Tuesday in your inbox. Also watch your email for online training opportunities as we get them on the schedule.

Look for us in April at the Electric Power Conference and Exhibition in Chicago and the 2017 ASME Power & Energy Conference in Charlotte, N.C. Thanks for reading.

Kathy Regan

4 ENERGY-TECH.com

February 2017

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FEATURES

Basic thermodynamics: Why combined cycle and co-generation are much more efficient than conventional steam generated power production

By Brad Buecker, Kiewit Engineering Group, Inc.

Introduction When the author began his career in the power industry in 1981, and subsequently began assisting with plant heat rate testing, it became apparent that at typical coal-fired power plants only about a third of the energy in the coal was actually converted to electricity. Even though plant personnel worked diligently to maximize unit efficiency, the overall low energy conversion was rather naturally considered a fact of life. Coal was cheap and concerns about carbon dioxide emissions were just in their infancy. There was more focus on control of other air pollutants such as sulfur dioxide, nitrogen oxides (NOx), and particulates. Now, as most readers undoubtedly realize, energy efficiency and carbon emissions control are of immensely more concern than in the past. This article examines some modern ideas in this regard.

work. Some exhaust heat must be extracted. For a conventional power plant, this waste heat is significantly greater than the energy output from the turbine-generator, as we shall see.

Another aspect of Figure 1 that observant readers may have noted is that the steam emerging from such a basic boiler would be at the saturation point, and would immediately begin to condense in the turbine. Above about 10 percent moisture, serious turbine blade damage will occur. For this reason and a number of others, modern conventional steam power units evolved into the outline shown below. It is important to note that this is a schematic of a drum boiler.

Background information Conventional steam power plants operate on the Rankine cycle, whose fundamental process is shown in the figure below.

Figure 2. Schematic of a drum-type power unit.

Figure 1. A basic steam generation system, the Rankine cycle.

QB is heat input to the boiler, QC is heat extracted in the condenser, WT is work done by the turbine, and WP is work done by the feedwater pump to boost the condensate to boiler pressure. (WP, to boost the pressure of the basically incompressible fluid water is negligible compared to the other energy flows.)

This fundamental diagram illustrates a classic thermodynamic principle. For all processes in which heat is utilized to produce work, it is impossible to convert all of the heat into 6 ENERGY-TECH.com

Of the various enhancements to improve the Rankine process, and especially for power generation, the most important is superheating. For the time being, we will ignore the reheating process shown in this diagram and examine superheating only.

Many units of the type shown in Figure 2 were designed with a 2,400 psi drum pressure, so we will use that for the following example.

The steam tables indicate that the saturation temperature at 2,400 psia is 662o F. A once-common steam temperature was 1000o F, so for this example the superheat becomes 338o and the enthalpy is 1460.3 Btu/lbm. Now, let’s see how much of February 2017

FEATURES this superheat steam enthalpy is available to produce work in a turbine with the following process parameters: • Turbine is 90 percent efficient • The turbine exhaust steam enters an efficient condenser, where the absolute pressure is 1 psia.

Fundamental thermodynamic calculations show that the exhaust steam has an enthalpy of 856.7 Btu/lbm. The condensate produced from this process has an enthalpy of 69.7 Btu/ lbm, and from this data we can make the following calculations.

• Heat extracted in the turbine = 1460.3 – 856.7 = 603.6 Btu/lbm • Latent heat exhausted in the condenser = 856.7 – 69.7 = 787.0 Btu/lbm So, only 43 percent of the steam energy is recovered as work in the turbine, while the remaining energy, and this is key, is lost as latent heat transfer in the condenser. Combined with other losses in the steam generator, the overall net efficiency of such subcritical units might at best be around 35 percent.

Advanced supercritical and ultra-supercritical units may have net efficiencies approaching 45 percent, but it is still quite obvious that enormous amounts of energy are lost in the condenser.

Before proceeding, I wish to comment on one other issue from the example above. At the conditions chosen, the exhaust steam quality is only 76 percent, meaning that at the turbine outlet the steam contains 24 percent moisture. This can be very damaging to low-pressure turbine blades, and is a primary reason why virtually all high-pressure steam generators include steam reheating. Space does not permit a discussion of this process now, but reheating significantly improves steam quality at the turbine exhaust.

Improved efficiency: combined cycle power and cogeneration In the power industry, apart from the continued growth of renewable energy such as wind and solar, combined cycle power generation is the dominant replacement for coal.

A combined-cycle power plant utilizes both the Brayton cycle (the combustion turbine) and the Rankine cycle (heat recovery steam generator, HRSG) to obtain high efficiency.

On its own, the maximum efficiency from the combustion turbine might be in the low 30-percent range. But rather than waste the 900o F to 1,100o F exhaust gas of the turbine, it is used to generate steam for an accompanying steam turbine or turbines. Net efficiencies of modern combined cycle plants have crept beyond 60 percent, but even at this high efficiency for a power plant, much energy is still lost. A problematic aspect of combined cycle power plants is that they often cycle on and off very frequently, sometimes on a daily basis. Such cycling places the units under serious thermal and mechanical stress, and can play havoc with water/steam chemistry.

Co-generation is where efficiencies can truly be remarkable, and may approach 80 percent. In some of these applications, the steam from the boiler produces power in a non-condensing turbine and then is extracted to serve as the energy source for process functions. The latent heat of the steam is not wasted, but rather directly powers chemical reactions or other mechanisms. The author spent two years at a facility where steam directly heated, and also provided makeup, to a series of chemical baths that converted cellulose to cellophane. In other applications, the steam may condense directly on heat exchanger tubes to provide energy for chemical processes in which direct fluid-to-fluid contact is not permissible.

A variation of this concept is the increasingly popular technology known as combined heat and power (CHP). District heating with steam is well known technology (and the author remembers warm spring days at his alma mater, Iowa State University, when steam was still poring through the dorm heating system) but if it is combined with power generation can boost efficiency. ■ Brad Buecker is a Senior Process Specialist for Kiewit Engineering Group, Inc. of Lenexa, Kansas. He has over 35 years of experience in or affiliated with the power industry, much of it in chemistry, water treatment, air quality control, and results engineering positions with City Water, Light & Power (Springfield, Illinois) and Kansas City Power & Light Company’s La Cygne, Kansas station.

He has a B.S. in chemistry from Iowa State University, with additional studies in fluid mechanics, energy and material balances, and advanced inorganic chemistry. He has written many articles and three books for PennWell Publishing on steam generation topics. Buecker is a member of the ACS, AIChE, ASME, NACE, the EPRI-sponsored Research Committee on Power Plant & Environmental Chemistry and the Electric Utility Chemistry Workshop planning committee.

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February 2017 ENERGY-TECH.com

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ASME FEATURE

Generator collector brush holder testing and design improvements Albert E. Steinbach, Frank A. Scalzo, III and Matthew T. Preston, General Electric Co. GE Power.

Abstract Electric generators and synchronous motors with static excitation use rotating slip rings (also known as collector rings) and stationary carbon brushes to transfer the field current from the stationary exciter to the rotating generator field. The carbon brushes experience wear from both mechanical friction and electrical contact with the rings.

Therefore, the brushes need to be periodically inspected and replaced. This is often the most frequent maintenance activity for an electric generator. It is generally recognized that if brushes are not changed when worn down, this can result in a damaging condition called a flashover that will usually force the generator offline. Several collector flashovers were investigated to look for other common characteristics with the aim of reducing the risk of flashover occurrence and improving generator reliability. Some features of the generator collector brush holders were identified as significant contributors to collector flashovers and also to other, more common maintenance problems. Several brush holder designs were evaluated with regard to these features and also with regard to feedback received from operators. In addition, an in-house test rig was developed and used to compare multiple, existing brush holder designs and new prototype concepts for brush wear rate and current selectivity. This work led to a new brush holder design that addresses these concerns and has

Figure 1a

8 ENERGY-TECH.com

subsequently been successfully tested in a laboratory and at a customer site. That new brush holder design is being applied to both new units and as a retrofit to in-service aftermarket generators..

Introduction and background In 2011, the authors’ company conducted a review of forced-outages of company built generators occurring from 1993 to 2010. The review identified that problems with generator collector rings and brush rigging were among the leading causes of generator forced outages. This prompted a

series of projects to understand and reduce these problems.

One of the first projects was a survey of eighteen customers regarding their experience and preferences for generator collector systems. That survey confirmed that there was significant room for improvement in the design, installation, and operation of collector systems. In order to test and validate hypotheses for root causes and proposed improvements, the company rebuilt a dormant collector laboratory test rig and began extensive tests of existing company brush holders and those available from three suppliers. Each design had some beneficial features, but none contained all of the desired features. So the authors’ company developed a new brush holder that includes all of the beneficial features identified. The new design has been successfully tested on the laboratory test rig and at a customer site since March 2015.

ASME Power Division Special Section | February 2017

ASME FEATURE Nomenclature • COD = commercial operation date • AVR = automatic voltage regulator Forced-outage review The Forced-Outage Review found that most of the collector and brush rigging failures included some arcing and generally were categorized as “flashovers.” Therefore,

that general term will be used for this summary. Most of the failures included some arcing between one collector ring and the surrounding brush holders. The automatic voltage regulator (AVR) generally responds to this arcing as merely extra resistance and noise in the DC field circuit and therefore responds by raising the field voltage to maintain the field current and hence generator output. This destructive arcing can continue for many hours before the voltage exceeds the limits set in the AVR or an arc jumps to the collector ring of opposite polarity or an arc jumps to the adjacent, uninsulated shaft material. The AVR will trip the unit offline from either exceeding the voltage limit or a short circuit. These short circuits can also occur quickly without any voltage build-up if carbon dust from the brushes (which is conductive) is allowed to accumulate and bridge the creepage path between slip rings or bridge from a slip ring to the uninsulated shaft.

Flashovers can destroy much of the evidence by melting, vaporizing, or disfiguring it as shown in Figures 1a and 1b. So it is often difficult to determine the root cause. In addition, there are often multiple contributing factors. The following problems were the contributing factors that could be clearly identified in the cases reviewed.

Failure to replace worn brushes As a brush passes its wear-out indicator, the brush holder spring cannot reliably keep the brush in contact with the slip ring so brush bouncing increases. This generally causes intermittent sparking at this brush and shifts most current to 9 ENERGY-TECH.com

ASME Power Division: Fuels & Combustion Technology

A Message from the Chair Electric power has become a basic need for today’s society and directly affects the quality of our own life. The ASME Power Conference is focusing on every part in the generation, transmission, distribution and consumption of power. The convergence of experience, current issues, “hot topics” as well as latest R&D aspects results in an excellent platform for current and future needs.

The Steam Turbine-Generator and Auxiliaries track that I preside for 2017 focuses on the challenges that these systems currently face. Life-time extension, new regulations as well as changes in power production and power distribution (“smart grid”) directly affect today’s fleet. Improvement, modernization and implementation of new technologies is a must to have reliable and affordable power available.

Please join us at ASME Power, June 26-30, 2017, in Charlotte, N.C., and be part of a sustainable change in our industry.

Dr. Thomas Bauer, Chief Operating Officer SvoBaTech, Inc. thomas.bauer@svobatech.com Phone: +41 (77) 453-4004 other “healthy” brushes. The healthy brushes will eventually become electrically overloaded as more brushes wear out and shed current. Overloaded brushes generally first fail as their copper leads (“pigtails”) overheat and burn out. In an uninsulated metal holder, the current can bypass the pigtail and continue through the spring and/or holder body back to the energized stationary support.

Current flowing through the holder can result in the brush spring being damaged by arcing and overheating as shown in Figure 1b. Bouncing brushes can also progress from sparking at the brush-to-ring interface to arcing.

If the arc bridges the gap from the ring to the brush holder, a metal holder also can become the primary current path.

Figure 3 ASME Power Division Special Section | February 2017

ASME FEATURE pigtails, further overloading the remaining brushes and thus potentially causing a runaway of this condition. Aggravating circumstances such as high brush vibration, hung-up brushes, oil contamination, or mixing of brush grades on the same ring are usually present before extreme cases occur.

One source of selectivity is very counterintuitive.

Selectivity often increases when the average current density in the brushes is too low. It is recommended to keep the average current density above 40 Amps/in2 (6 A/cm2). Therefore, if the average current in the brushes will stay consistently low, it is recommended to remove some of the brushes to raise the average current density to at least 40 Amps/square inch (6 A/ cm2) [2].

High brush vibration Over time the collector ring can become rough due to corrosion or electrical pitting from brush sparking which leads to further brush bounce and sparking. Spring suppliers recommend that springs be replaced after approximately five years of operation. Of course, the springs can lose their effectiveness faster if they carry current. Another cause of brush vibration is intermittent brush hang-ups within the brush holder. This can occur when carbon deposits build up inside the holder, especially if current is passing from the holder directly to the brush. Another potential cause of brush hang-up occurs when the brush is much taller than the holder body, as shown in Figures 2 and 3. The top edge of the box can abrade the side of the soft brush material, especially when the brush is bouncing.

Brush vibration can also occur due to poor brush alignment to the slip ring. Brushes that are not normal or “radial” [1] to the slip ring surface should be in a trailing [1] orientation to minimize vibration. Figure 4 shows that with a “trailing” brush alignment, the amount of brush extending below the trailing edge of the brush holder is a little larger than the amount of brush extending below the leading edge of the brush holder.

Poor electrical contacts at brush holder Figure 2 shows the brush terminal being bolted to the brush holder. These connections must be tight and with the terminal correctly aligned to the assigned contact area.

Otherwise, it becomes Figure 5 an intermittent or high resistance connection.

Figure 5 shows multiple electrical contact clips between the stationary electrical source and the brush pigtail. These clips can be hard to maintain with equal contact pressure over time and can become a source of high selectivity.

Stubbing can cause a stick-slip action between the brush and the slip ring. Alignment tooling can be beneficial for correctly setting the brush holder alignment and spacing to the collector rings to avoid this problem..

High selectivity Selectivity, which in this context refers to the unwillingness of the parallel brushes to share current equally, is a natural phenomenon on slip rings. In mild forms selectivity leads to high brush wear on those brushes consistently carrying high current, but it has been found that most brushes go through cycles of high and low current conduction for an averaging effect. In extreme cases selectivity can render the overloaded brushes ineffective by burning off their copper 10 ENERGY-TECH.com

ASME Power Division Special Section | February 2017

ASME FEATURE experienced staff so that rate of failure for the 1970s and 1980s are the lowest found. The trend toward smaller staff, especially at gas-turbine plants, may explain why the rate of failure increased significantly for units built following the 1980s even though the hardware design did not change much since that time. This all accentuates the need for more robust designs for brush and holder assemblies that reduce the amount of inspection and maintenance time for operators and that reduce the risk of conditions leading to a flashover.

Incorrect brush holder installation Incorrect installation of a brush or brush holders can result in the brush not being free to slide within the brush holder and therefore not continuously pressed against the slip ring. Holders that provide clear visual indication of complete installation were less prone to experience this problem.

Customer survey The survey of operators from eighteen power plants revealed the following parameters of brush rigging performance were most important to them: • Brush temperature and selectivity: 31.5% • Brush vibration: 18.6% • Film contamination: 14.7% • Ring vibration: 12.6% • Ring temperature: 12.1% • Ring run out: 10.5%

The collector flashovers among the 1993-2010 forced outages are summarized in Figures 6 through 8. Figure 6 shows when the failures occurred relative to the generator commercial operation date (COD). The most striking thing about Figure 6 is the high flashover rate during the first five years of operation. In fact, eleven of these failures occurred within the first six months and twenty five were within the first eighteen months of operation. That highlights the importance of both correct plant installation and new operator training. In addition, it highlights the need for hardware that is more robust with regard to both installation and operational variability.

Figure 7 similarly shows the quantity of flashovers versus the decade of the generators’ COD. Since the building of power plants has not been uniform over time, the data from Figure 7 was divided by the quantity of company generators with static excitation installed during each of those decades and plotted as Figure 8. Together these figures indicate that collector flashovers are a significant cause of forced outages for new and old generators.

Many units from the 1940s through 1960s still have brush holders with adjustable springs that require frequent adjustment by skilled operators to maintain adequate pressure on the brushes. Increased problems with them are likely influenced by the trend toward smaller staff to operate and maintain collectors with less time to care for those finicky designs. New brush holder designs introduced by the 1970s with constant-pressure springs appear to work adequately for 11 ENERGY-TECH.com

In addition, the survey identified the following features were most desirable for a brush holder: • Safe on-line maintenance • Permanent handle for each individual brush-holder • Site replaceable brush spring, as required • Long service life between brush changes • Quick and fool-proof brush changing process • Brush holder weight low enough for one-hand

operation (for those needing to do on-line replacement) • Ideal brush holder features

ASME Power Division Special Section | February 2017

ASME FEATURE The list of ideal brush holder features in Table 1 was accumulated from the customer survey, the observed contributors to the flashovers, and other company experience.

Each feature is shown to relate to one or more key benefits.

The authors’ company compared Table 1 to three existing company brush holder designs and three currently available designs from other suppliers and found them each to be lacking at least four of these desired features.

Laboratory tests The authors’ company tested existing company-designed brush holders and three suppliers’ designs on the rotating test rig shown in Figures 9 and 10. All tests were run with the same brush material. The steel slip ring is helically grooved and was rotated with a surface speed of 212 feet per second (65 m/s). Each configuration was tested for 500 hours with continuous monitoring of the current in each brush. The brushes were periodically inspected for any sparking between the brush and the slip ring. The brush wear rate was determined by manually measuring the brush length before and after each test.

The testing showed that the Figure 9 following best practices worked together to generally reduce selectivity, increase brush life, and decrease sparking: a. The constant-pressure spring should be oriented with the axis of the coil parallel to the slip-ring axis (as shown in Figures 2 and 11) in order to achieve a stable placement of the brush within the box. The spring primarily pushes the top of the brush radially toward the slip ring, but it also pushes the brush away from where the spring is mounted.

12 ENERGY-TECH.com

The arrangement in Figure 3 is undesirable because the top and bottom of the brush are not being pushed in parallel directions. The top of the brush is being pushed by the spring axially along the shaft and the bottom of the brush is being dragged circumferentially by the ring rotation. This results in an unstable brush within the box that is more prone to vibration. If the spring and ring are both pushing the brush circumferentially relative to the ring, the brush is more stable within the box. Note that a brush is stable whether the spring is pushing in the same direction as shaft rotation or in the opposite direction.

These two stable orientations are called “Face location” and “Diagonal location”, respectively in [3]. b. Limit the length of the new brush extending above the top of the box. This reduces the chafing of the brush sides and brush hang-ups, as described earlier. c. Ensure smooth, hard sides within the box to avoid carbon build-up between the box and brush. When this is ASME Power Division Special Section | February 2017

ASME FEATURE Since the authors’ company could not find any available brush holder that contained all of the desired features from Table 1 and the lessons learned during testing, the company continued to develop a new brush holder that contains all of the desired features. The new design is shown in Figures 11, 12 and 13. This is a box-style holder that contains two brushes. The anodized aluminum components provide strong, durable surfaces yet result in a lightweight holder that can easily be inserted and removed with one hand. The insulated handle is permanently attached, keeps the operator’s hand well away from energized components and provides clear visual feedback of the complete installation (see Figures 11 and 12). The removable holder slides securely into grooves in the stationary support (see Figure 13) which also engages the electrical connection between the silver-plated copper knife and corresponding louvered fork.

Site validation tests

combined with “a” and “b”, the holder can be mounted with the shaft rotation in either direction. d. A smooth, flat pad on top of the brush is beneficial to allow the constant-pressure spring to freely coil up as the brush wears. In contrast, when the spring is in a groove in the top of the brush, there is frequently stick-slip action as the spring tries to coil resulting in non-constant pressure on the brush. A groove is also undesirable since variation in springs and groove dimensions cause variation in the spring to brush contact angle. e. It is essential to align the brush holder so the brush is radial or slightly trailing. An alignment tool is helpful for this process.

The cumulative benefit of these changes is demonstrated in the two graphs in Annex A. The first graph is for brush holders without these changes and the second graph is after making all of these changes. Both graphs show the current in each of six brushes (three positive and three negative) over a period of 500 hours. During the first test, the current averages and spreads varied dramatically whereas during final test the current values were very consistent with relatively little variation. Similarly, the amount of sparking decreased dramatically and the brush life was increased. This provided strong confirmation of the benefit of these changes.

New brush holder design

13 ENERGY-TECH.com

ASME Power Division Special Section | February 2017

ASME FEATURE Prototypes of the new brush holder were tested in the laborator test rig and then installed in a model 7FH2 generator at a customer plant in March 2015. They have been running successfully there since installation.

Annex B is a graph comparing the performance of brushes at the customer site in the new prototype brush holder to prior performance at the same site with the same type of brushes in the holders that the authors’ company originally supplied with this generator.

The generator was operated through a variety of load conditions with daily load fluctuation (dictated by utility demand). Each set of data covers four months of operation. The collector rings were refinished before the testing with the original holders. The new brush holders were installed after the completion of the tests with the original holders. The rings were not resurfaced before installing the new brush holders due to site constraints.

The current in each brush was measured once per second during test of new brush holders and every ten seconds during test of original holders.

The current measurements were made using individual, dedicated, Hall-Effect current transducers. As a measure of selectivity and current variation, each brush measurement was compared to a current threshold of 250 Amps.

Note that brief excursions to these levels should not cause brush or pigtail damage, but sustained operation at elevated currents will lead to problems.

The number of times the current was equal to or greater than 250 Amps was divided by the total measurements taken that day and then multiplied by 100 to yield a percent of occurrences for the day. The day over day results were then added together in a cumulative fashion to yield the Annex B plot.

In the Annex B plot it can be seen that the original holder accumulated a higher percentage of current values exceeding the 250 Amps threshold than did the new brush holder during the

14 ENERGY-TECH.com

ASME Power Division Special Section | February 2017

ASME FEATURE duration of the test. In addition to an overall lower percentage of occurrences, the new brush holder also shows a much more gradual rate of increase in the cumulative percentage of occurrences implying that the new brush holder performance is more stable through its operation than the original holder and hence has a lower risk of having overheated brush leads which could cause runaway selectivity.

Inspection of the brushes in the new brush holders has not shown any discoloration of pigtails nor sparking which are prime visual indicators of poor brush holder performance.

At submission of this paper the new brush holders have been running for more than eight months without issue. Lastly, at the time of the inspection brush wear measurements were also taken and used to project brush life as if the brushes were run for the entire wearable brush length. For this particular test the brushes were projected to have a life of between 18 and 24 months, however it is important to understand that brush life is highly dependent on site conditions and that this brush life may not be typical for all sites.

Conclusions Problems with collector brush holders have historically contributed to many generator forced outages. A new brush holder has been developed and tested that provides several benefits over other existing holders and minimizes the risk of flashovers and other identified problems. Key benefits of the new brush holder design include: a permanentlyattached handle that isolates the operator from the energized components, two brushes changed at a time to minimize the operator’s exposure to the rotating and energized components, no tools required for brush or spring replacement, low selectivity, long brush life, light-weight for easy one-hand operation, robust brush replacement and operation, and an installation tool provided for proper holder alignment. ■ Acknowledgments The authors acknowledge with appreciation the following companies for their support in this investigation and development: • Fulmer Company • Mersen Company • Morgan Advanced Materials • Orlando Utilities Commission, Stanton Energy Center

Unit B. References 1. “Definitions and nomenclature for carbon brushes, brushholders, commutators and slip-rings,” IEC 60276, International Electrotechnical Commission, page 10

2. “Brush Digest,” National Electrical Carbon Products, Inc. (now part of Morgan Advanced Materials), Chapter 11, page 51 3. Definitions and terminology of brush holders for electrical machines, IEC 60560, International Electrotechnical Commission, page 9 4. “Brushes for slip-rings,” Technical Note STA BE 16-42 GB, Carbone Lorraine (now part of Mersen Co.) 5. “Brushholders and the Performance of Carbon Brushes,” Technical Note 22, Helwig Co. 6. “Guidelines for Successful Commutator and Brush Operation”, NAT CP02 12/98 1K, National Electrical Carbon Products, Inc. (now part of Morgan Advanced Materials) 7. “How to Select Carbon Brushes for Motors and Generators One Horsepower and Above,” NAT CP01 5/02 1K, National Electrical Carbon Products, Inc. (now part of Morgan Advanced Materials) 8. Parslow, J. H., 2010, “Improved Safety of Carbon-brush Collector Maintenance on Turbine-generators Retrofitted with On-line, Removable Plug-in Brush Holders,” Energy-Tech Magazine, June 2010 9. Shobert, E. I., 1965, “Carbon Brushes - The Physics and Chemistry of Sliding Contacts,” Chemical Publishing Company, NY

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ASME Power Division Special Section | February 2017

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MACHINE DOCTOR

Transient torsional vibration problem due to electrical noise

By Patrick Smith

Torsional vibration problems in rotating machinery can be difficult to recognize. Unlike radial vibration which can be easily measured with readily available sensors, torsional vibration is more difficult to measure because it involves the twisting of shafts while the machine is rotating. It can typically only be measured with special devices such as strain gauges or torsional lasers.

If the torsional vibrations are high enough, high radial (lateral) shaft vibrations can result. The purpose of this article is to present a case study of a torsional problem in a motor driven compressor that resulted in high compressor shaft vibrations.

As described, these high vibration excursions occurred intermittently during periods when the power supply to the electrical motor was noisy.

Compressor design and configuration This case study pertains to a dual service, 5 stage, integrally geared centrifugal compressor driven by a 1,790 RPM, 6,500 HP induction motor. The motor is directly coupled to the compressor with a flexible disc type coupling. The compressor gearbox consists of a bullgear and three rotors. The low speed (LS) rotor operates 12,560 RPM and consists of a pinion with impellers mounted at each end. The high speed rotor (HS) operates at 14,776 RPM and consists of a pinion with an impeller mounted at one end. The LS and HS rotors comprise the MAC section of the compressor. The cover rotor operates at 35,885 RPM and consists of a pinion with impellers mounted at each end. The cover rotor comprises the booster air compressor (BAC) section. The LS and HS rotors are mounted on the gear case horizontal split line, while the cover rotor is installed in a split line in the upper gear case cover. The

compressor configuration is shown in Figure 1. Note the cover rotor is omitted for clarity.

The gearbox utilizes combination tilting pad journal bearings and tapered land thrust bearings for all three pinions.

There is a single non-contacting proximity type radial shaft vibration probe adjacent to each impeller side bearing. The bullgear journal bearings are a combination cylindrical sleeve type radial bearing and tapered land type thrust bearing. There is a single non-contacting proximity type radial shaft vibration probe on both the drive end (DE) and non-drive end (NDE) on the bullgear rotor. The compressor protection system includes the following: • High pinion vibration alarms, high high pinion vibration shutdowns • High axial position alarms, high high axial position shutdowns • High bullgear vibration alarms, high high bullgear vibration shutdowns As part of the compressor design, lateral and torsional rotordynamic analyses were performed. The lateral analysis included each rotor and the results showed that all separation margins and amplification factors met the requirements of API-617/API-672. For the torsional analyses, API-617 requires that the torsional natural frequencies of the complete train be at least 10% above or 10% below any possible excitation frequency within the specified operating speed range. The calculated lowest fundamental torsional natural frequency (TNF) of the system was determined to be 1278 cycles/min (cpm). This resulted in a separation margin of 28.7% from the motor speed.

February 2017 ENERGY-TECH.com

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MACHINE DOCTOR Vibration observations during commissioning The compressor underwent a mechanical shop test. After some initial HS rotor vibration and cover rotor thrust bearing issues were resolved, the compressor passed the shop test and all vibration levels were within API617 limits. When the compressor was commissioned, the vibration levels were initially low and stable. However, two days later, intermittent vibration spikes were observed on the bullgear NDE and both ends of the LS rotor. Some of the spikes were above the alarm limits. These vibration excursions occurred about five times a day and lasted for about 30 to 40 minutes. See Figure 2. Table 1 shows the vibration levels during periods of low vibration and typical peak values during the excursions.

A vibration analyzer was connected to some of the vibration transmitters.

During the vibration excursions the spectrum data showed a peak at about 1500 CPM. This was close to the calculated torsional natural frequency TNF of 1278 CPM. This compressor is part of an air separation plant that provides oxygen to a steel plant. The steel plant uses an electric arc furnace (EAF) and it was observed that the vibration excursions coincided with the steel plant heat cycles (firing of the furnace). The steel company provided power to the air separation plant and it used the same power lines as the EAF. An EAF creates an electrical arc to melt the raw materials in the furnace.

The arc is established between an electrode and the melting material. The random movement and composition of the melting material creates rapid changes in power supply which in turn can lead to large voltage and current oscillations in the electrical power system. It was suspected that these voltage and current oscillations caused torque oscillations in the compressor main drive motor which then excited the TNF. It was further suspected that the torque oscillations were severe enough to cause high radial vibrations in the compressor.

18 ENERGY-TECH.com

February 2017

MACHINE DOCTOR machine damage. Kelm Engineering was contracted to perform vibration and dynamic torque measurements to confirm the suspected source of subsynchronous vibration. Kelm Engineering is a consulting firm specializes in analytical and field testing of turbomachinery.

Kelm attached a pair of temporary strain gauges with wireless transmitters to the motor shaft end. See Figure 3. This would be used to measure dynamic torque during startup and steady state operation. In addition, Kelm connected a vibration analyzer to the each of the proximity probe vibration transmitters.

A similar problem is discussed in the paper entitled “Electric Power Supply Exciting Torsional and Lateral Vibrations of an Integrally Geared Turbocompressor” by Leonard, Kern and Reischl.

Discussion The concern was that these vibration excursions could cause high enough alternating loads to eventually lead to

Prior to starting the compressor, several impact tests done to determine if there were any structural natural frequencies that coincided with the frequency of high vibration. No interferences were found. When the compressor was started the vibration data was recorded as the machine accelerated to full speed. The spectrum of the dynamic torque measurements during startup showed excitation of the TNF at approximately

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MACHINE DOCTOR 1575 RPM. See Figure 4. In addition, vibration data from the proximity probes also showed a lateral response of the LS and HS pinions when the TNF was excited during the start-up.

See Figure 5. This coincided with the earlier observations of a vibration spike at a frequency about 1500 cpm vibration during the vibration excursions.

Based on a TNF of 1575 CPM, there was a 12% separation margin to the motor speed. After the compressor reached full speed, the vibration peak at 1500 to 1575 RPM was very small.

This confirmed that the12% margin was acceptable. However, during periods of EAF operation, both the dynamic torque measurements and the proximity probe data showed a very high response at 1575 CPM. In Figures 6 and 7, the proximity probe spectrum data is shown during periods when the EAF was operating and when it wasn’t.

The measured electrical data showed notable electrical noise during EAF operation. When the EAF was running, both the voltage supply and current oscillated. It is likely that this was caused by harmonic distortion of the power supply that was not present when the EAF wasn’t running. The oscillations were broadband and likely the cause of the excitation of the TNF. Analysis of the data showed dynamic oscillating torques up to about 70% of the nominal operating torque. It was concluded that this could eventually lead to a fatigue failure of something in the compressor/motor system. And so, it was determined that it was not acceptable to operate the compressor in this condition.

Corrective action Because the electrical noise was broadband, shifting the TNF by changing the coupling stiffness would not correct the problem. The TNF would still be excited. In general, the two solutions to correct this problem would be to either connect the motor to a power source separate from the EAF, or to install an electric filter to dampen the electrical noise. Both of these solutions would require a large capital investment and would take a long time to implement. And so, it was not practical to pursue these solutions. The compressor/motor system could have potentially been designed to handle the high dynamic torques, but it was also not practical to redesign an existing compressor/motor system for the same reasons.

An alternate solution of retrofitting an elastomeric coupling was pursued. This is the same solution that was done to the machine discussed in the article by Leonard, Kern and Reischl.

An elastomeric coupling could potentially dampen the high dynamic torque oscillations when the TNF would be excited by the EAF. This wouldn’t correct the problem. It would only mask the underlying issue. An elastomeric coupling is also relatively expensive and would require much more maintenance than a typical disc pack type coupling. And although this would address the symptoms of the problem, the high dynamic torque

20 ENERGY-TECH.com

oscillations would still exist. And this would mean a higher risk of a machine failure in the future.

An elastomeric coupling was identified. However, there was a change in business and the customer no longer needed the product from the new plant. And so, the change was never implemented.

Conclusions During periods of EAF operation, the power supply to the compressor motor was noisy and this resulted in high oscillating torques. This in turn caused high radial shaft vibrations in the compressor. The compressor/motor system was not designed for the high alternating forces that resulted from the torque oscillations. Because this wasn’t identified during the design stage, it was not practical to make electrical system changes to correct the electrical noise. It was also not practical to redesign the compressor/motor system. The solution to retrofit an elastomeric coupling addressed the symptoms of the problem, but it wouldn’t correct the problem. It would still result in a compromise which could still cause long term reliability issues.

It is important to recognize the potential for electrical noise when designing motor driven turbomachinery systems. As described in this article, certain processes, like EAF operations, can cause high electrical noise. It is critical to recognize this and address the potential for these types of problems in the design phase. Waiting until the equipment is designed and being commissioned can result in expensive, long lead time corrective action and/or changes that can impact the long term reliability of the equipment. ■

References 1. Smith, Patrick J., “Why Torsional Analyses Are Important When Making Motor Changes”, Energy- Tech Magazine, September 2013 2. API-617, “Axial and Centrifugal Compressors and Expander-compressors for Petroleum, Chemical and Gas Industry Services”, Seventh Edition, API, Washington, DC. 3. Leonard, Martin L. Kern, Ulrich and Reischl, Klaus, “Electric Power Supply Exciting Torsional and Lateral Vibrations of an Integrally Geared Turbocompressor”, Proceedings of the Thirtieth Turbomachinery Symposium, 2001 4. Pavelek, Dustin, PE, “MAC Vibration and Torque Testing”, Report Number: 11528-ReportRevA, Job Number: 11528, Kelm Engineering, LLC, May 6, 2015 Patrick J. Smith is lead machinery engineer at Air Products & Chemicals in Allentown, Pa., where he provides technical machinery support to the company’s operating air separation, hydrogen processing and cogeneration plants. Questions about this article may be sent to editorial@WoodwardBizMedia.com.

February 2017

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MAINTENANCE MATTER

A comparative assessment of asset management and equipment reliability models

By Rick Roberts, Electric Power Research Institute.

Over the past decade, economic and regulatory changes have significantly affected the operations and maintenance (O&M) of power plants. In response to these changes, power plant management faces pressure to implement processes to improve the performance of plants, even when confronted with more flexible operating regimes and reduced O&M budgets.

The key areas of improvement include cost, environmental compliance, safety, unit reliability, and prevention of major plant failures.

A critical part of these efforts to improve plant performance is “asset management,” which involves the operational, engineering, maintenance, and financial/administrative processes that an organization applies to maximize the value of its assets.

A highly effective asset management system is required to manage all of the market and regulatory changes, deal with the uncertainties of the external forces, and ensure that plans are in place to deal with risks and potential consequences. The asset management system should involve the entire life cycle of an asset—from the identification of the need of the asset through its acquisition or construction; its utilization; maintenance; and the retirement of the asset and any remaining liabilities after it is retired.

To help the power generation industry better understand asset management, the Electric Power Research Institute (EPRI) recently conducted studies of two relevant models: the Process Safety Model, and EPRI’s Equipment Reliability Model. The studies sought to clarify the similarities and differences of the models, along with their similarities and differences to key Asset Management Standards, the International Organization for Standardization (ISO) 55000 suite of standards. The studies also addressed how the models can be used as a part of a plant’s asset management strategy.

entity that has potential value to an organization. The value can be tangible, intangible, financial or non-financial.”

Asset management is defined by ISO 55000 as “the effective control and governance of assets by an organization to realize value through managing risk and opportunity, in order to achieve the balance of cost, risk and performance.”

In EPRI’s Equipment Reliability Model, asset management is defined as “a systematic process of making operational, resource allocation, and risk management decisions associated with physical plant equipment to maximize power plant value to stakeholders, while maintaining safety to the public and the plant staff.”

The elements that make up the effective management of assets include the following: • Equipment reliability processes • Work management processes • Engineering design processes • Operations procedure and practices The following business management elements are also part of asset management: • Strategic planning • Financial management (O&M and capital) (see Figure 1) • Risk management • Leadership and governance

Asset management Assets and asset management are defined in various ways within the power generation industry.

Assets are defined variously as financial resources (cash and investment), personnel, information technology, intellectual property, power plants, power generating units, plant equipment, and so on. ISO 55000 defines an asset as “an item, thing or 22 ENERGY-TECH.com

Figure 1. Asset management: industry perspective

February 2017

MAINTENANCE MATTER Process safety model The process safety model was developed by Lockheed Martin’s Information Systems and Global Solutions (IS&GS) and a United Kingdom utility. It has been used in several countries other than the United Kingdom, including Australia, Canada, and New Zealand.

Because utilities in the United States are familiar with Process Safety Management (PSM) when dealing with hazardous chemicals, this may cause some confusion about the process safety model. PSM and the process safety model are not the same process.

The process safety model focuses on the prevention of major accident hazards (MAHs) of any type, not only chemical—for example, turbine overspeed, generator hydrogen fires, pressure systems ruptures, or hazardous chemical releases.

This prevention is achieved by the application of a risk model that generates proactive risk indicators. These risk indicators are used to demonstrate to an organization the current effectiveness of the risk barriers in place to minimize the likelihood of an MAH, and if required, intervention can then take place if a control barrier loses effectiveness.

These risk indicators typically cover technical risk management, critical systems, alarm and instrumentation management, maintenance management, operations management, operations and compliance audit, staff competence, and emergency preparedness.

The driver for the development of the process safety model as a risk management tool came from the many major process industry disasters, including Flixborough (England), Bhopal (India), Piper Alpha (North Sea), and Texas City (Texas, United States), which indicated that the current risk management

processes were insufficient to efficiently manage the complex hazards involved. Around the world, regulators then initiated the production of guidance on the application of process safety.

The cornerstone of the model is a systematic 10-step process that is underpinned by the utilization of “bow-tie” risk assessments (see Figure 2) to quantify the effectiveness of control barriers in the prevention of an MAH. The bowtie model identifies the threats that could lead to a hazard being realized and identifies the barriers to control each threat. It also identifies the consequences of hazard realization and identifies the barriers to militate against the consequence.

The process safety model includes a generic table of the eight risk control areas in a typical power plant that are utilized to manage process safety.

The bow-tie model is applied to all MAH scenarios that a power generation plant identifies as being critical. The outputs from the bow-tie models are then integrated into the 10-step process.

The ten steps in the process safety model are: 1. Collect existing information.

2. Analyze hazard scenarios, control, and mitigation barriers.

3. Establish risk control framework.

4. Categorize control and mitigation measures.

5. Define key performance indicators (KPI).

6. Ranks risks and categorize KPIs. 7. Categorize KPIs. 8. Capture and measure KPI performance.

9. Automate KPIs, capture and measure.

10. Staff engagement and safety culture.

Figure 2. Bow-tie assessments February 2017 ENERGY-TECH.com

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MAINTENANCE MATTER The final part of the 10-step process is a process safety dashboard of KPIs that shows the effectiveness of the power plant risk mitigation barriers.

ISO 55000 ISO 55000 is an asset management suite of standards that describes a process to manage assets from concept to decommissioning. The standard encompasses common practices that are suitable for implementation by a broad range of industries, organizations and cultures.

ISO 55000 can be used for organizations to improve the value from their asset base, and can be used by those persons involved in all aspects of establishing or improving asset management systems. It can be used to both improve existing asset management systems and also to create new asset management systems.

ISO 55000 consists of three separate but interlinking documents: 1. ISO 55000 Asset Management—Overview, Principles, and Terminology Provides high-level overview of asset management. The ISO 55000 asset management standard does not define the detail of the process and procedures but states what they should achieve.

2. ISO 55001 Asset Management—Management Systems—Requirements Describes which management systems are required to be in place to effectively implement ISO 55000.

3. ISO 55002 Asset Management—Management Systems—Guidelines for Application of ISO 55001 Gives detailed guidelines on how management systems described in ISO 55001 should be structured and operated.

Guidelines include context of the organization, leadership, planning, support, operation, performance evaluation and improvement.

EPRI Equipment Reliability model The EPRI Equipment Reliability (ER) model is a clearly defined equipment condition assessment and maintenance strategy that focuses on a power plant’s ER. Its elements include scoping and identifying system/component criticality, establishing and improving ER maintenance bases, preventive maintenance (PM) implementation, system and component health and conditioning monitoring, corrective actions, longterm asset planning, and life cycle management.

The ER model provides the structure to integrate and uniformly assess equipment condition/ health data and information from a variety of sources. This integrated information can then be used for decision making to most

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February 2017

MAINTENANCE MATTER effectively apply resources for sustaining and improving plant reliability.

In power plants, a large amount of available data could be brought to bear on assessing the health of major/critical assets.

Implementation of the ER model enables an organization to more effectively integrate the data to optimize O&M and capital expenditures to support high levels of asset health.

The ER model focuses primarily on identifying the optimum short-term and long-term activities to ensure high levels of reliability at minimal cost. The key outputs of the ER process are work orders/work requests for execution by the maintenance, operations, and/or projects organizations.

Key findings: Similarities and differences of the models • Although similarities exist between the ISO 55000 Asset Management Standard and the process safety model in their implementation, ongoing monitoring, and reporting,

Deploying the ER model should be done to accomplish specific plant ER performance objectives, including: • Equipment performs reliably between major planned outages. ® • Component criticality is identified based on the importance to company values and objectives but usually addresses safety and environmental functions, along with power generation capability.

• Equipment and system performance criteria are established, performance is monitored, adverse trends are identified, and corrective actions are implemented and verified for 90° Prism & effectiveness.

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MAINTENANCE MATTER the systems fulfill differing organizational needs and require to be implemented as separate processes.

• The ISO 55000 Asset Management Standard focuses on the establishment of an asset management strategy that covers a wide area of operations, including value, alignment, leadership, and assurance.

• The process safety model focuses on proactively controlling MAHs and risks to improve safety, environmental, plant, and financial performance. The model is a separate, clearly defined process that fits within an existing asset management system. The process provides a system that measures the performance of the control barriers that stop major accidents occurring. The performance of these barriers is measured and displayed as KPIs in near-real-time to allow proactive intervention when required.

• ISO 55000 is a high-level asset management model; most of the process details are to be determined by the model’s implementer. The process safety model is at a level below ISO 55000 and a level above the EPRI ER model.

model begins with a focus on safety, but has a big impact on the reliability of the equipment.

• If ER and related processes are not in good control, the EPRI ER model is a good tool to implement first to improve ER. Rolling out the process safety model at a later point would be beneficial as an effective process implemented for ER. • When ER is not in control, in addition to the EPRI ER Model, implementing part of the Process Safety Model’s bow-tie process would be very useful if hazard mitigation plans are not in place. Identifying the consequences of potential hazard events and documenting the barriers to mitigate the consequences would be good steps in conjunction with the EPRI ER model. These steps would allow a plant manager to have a plan of action if an event actually occurred.

• If ER and related processes are in good control, the process safety model would be a good tool of choice to manage MAHs. This model would allow a focus on the MAHs and having controls and mitigation plans in place to manage a potential hazard incident.

• In general, the EPRI ER Model begins with a focus on ER, but has a big impact on safety. The process safety

GENERATORS EMERGENCY or PLANNED OUTAGE National Electric Coil’s Generator Services Group will be at your site day or night, helping you get your generator back online as quickly as possible.

EPRI’s comparative analysis and its findings are published in two reports: The EPRI Equipment Reliability Process and The Process Safety Model: A Comparative Analysis, June 30, 2016, 3002008579, and A Comparative Analysis of Equipment Reliability and Asset Management Models, December 2016, 3002008580. ■ Rick Roberts is Principal Program Manager of EPRI’s Maintenance Management and Technology Program. Questions about this article may be sent to editorial@WoodwardBizMedia. com.

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February 2017

TURBINE TECH

An overview of steam turbine generator sequential tripping Bradford J. Snyder Senior Consultant TG Advisers, Inc. Wilmington, Delaware

In my role as a turbine generator consultant and generator specialist, I am frequently asked to discuss the concept of Sequential Tripping. To set the stage, we need to look back to the middle of the last century, when power plant capacities and corresponding levels of complexity grew rapidly. With these increasing levels of high energy systems, standardization of an orderly shutdown process became an operating and engineering priority. Traditional “old-school” trip methods, wherein an operator would trip the boiler/turbine systems, and then trip the unit main breaker(s) shortly afterwards unfortunately exposed the turbine generator train to an unnecessary risk of catastrophic overspeed. Combine these older home-brew methods with the added complexity of thermal cycles with multiple steam admissions and extractions, and with modern turbine steam paths designed more closely to margin, and we have a recipe for disaster. In the typical shutdown scenario, it is absolutely critical that the motive energy to the prime mover be controlled prior to tripping the unit main breaker.

Why is this so? Recall that the typical grid connected AC generator is a synchronous machine. While this configuration has a number of electrical engineering ramifications, there is one salient mechanical feature of a synchronous generator which is pertinent to our current discussion. The generator’s rotational speed is “synchronized” to the grid. By adding or subtracting steam flow to the turbine, you can change the power output of the synchronous machine, but never its rotational velocity.

In fact, with no steam flow at all, the generator will become a synchronous motor consuming power from, rather than providing power to, the grid. Synchronous motoring is generally not harmful to the generator, but full-speed operation with no steam flow will likely lead to turbine damage. In the absence of grid synchronization, the unit is relying solely on the stop, governor and non-return valves to control steam flow and hence speed.

Should any of these fail to control or become “stuck open” an overspeed condition can result.

Around the 1970s, the dangers of uncoordinated planned shutdown and emergency trip practices had become well recognized. Many turbine generator OEMs began to issue technical advisories recommending or suggesting that owner/operators review their trip/shutdown practices with an eye to implement sequential tripping schemes. The intent was to provide a means of automatic, orderly shutdown and isolation when taking units off-line.

By implementing a sequential trip scheme, the potential for a damaging overspeed condition is minimized.

The objective is to verify that all motive power to the turbine has been removed as a permissive to allow the tripping of the generator breaker.

The “gold standard” for ascertaining that a turbine trip or orderly shutdown has successfully removed all motive power from the turbine generator train is activation of a reverse power or anti-motoring relay. The most effective sequential trip schemes use an “AND” logic combination of the turbine trip signal together with the generator reverse power detection relay as a trip signal to the generator breakers. Typically, a short (1-3 second) time delay is also interposed to ensure there is a genuine

Figure 1 Simplified Sequential Tripping Control Logic February 2017 ENERGY-TECH.com

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National Electric Coil’s Annual Seminar on Advanced Generator Reliability Improvements & Troubleshooting Each year National Electric Coil and HPC Technical Services join forces to put together a week-long, comprehensive advanced generator seminar. This year the course will be August 7-11, 2017 in Sarasota, Florida.

Doing more with less money and fewer personnel is the growing challenge for power plant management. So when performance and efficiency fall off or when an alarm or trip happens, knowledge is the key to minimizing machine damage, budget trauma and unscheduled down time.

The 4-½-day course is meant to bring plant managers, engineering managers, maintenance managers, operators and technical staff up to date on skills needed to improve generator reliability and troubleshoot generator problems, including those encountered during operation and those discovered during maintenance outages. A team of 16 recognized industry experts will bring their expertise to the following sessions and topics: Day 1 will focus on generator design and construction, as well as an explanation of generator machine characteristic curves, stator winding diagrams, and system protection. Case histories will be used illustrate generator troubleshooting and problem solving techniques.

Day 2 includes visual inspections and testing techniques, diagnosing stator winding partial discharge (PD), stator end winding vibration, bump testing and how to improve winding dynamics.

Day 3 focuses on emergency failures, vibration diagnostics, rotor thermal sensitivity, shorted turns, flux probes, rotor cycling and fatigue, generator bushings and stator core heating.

Day 4 covers a number of generator auxiliary system problems such as stator cooling water systems and chemistry and hydrogen gas dryer issues including new H2 fast purging methods.

Sessions on stator core failures and prevention and roundtable discussions complete this day.

Day 5 (half day) wraps up with sessions on documentation methods, reviews of the most common generator failures and prevention, and discussions of root cause analysis (RCA) methods and techniques.

For details on the course and session content, brief speaker biographies and registration information, please go to: www.National-Electric-Coil.com/generator-course.php.

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TURBINE TECH and persistent relay signal and to limit any full speed, no-load exposure of the turbine. In many systems there are duplicate reverse power implementations, one of which operates at short time delay for sequential trip, and a second with longer time delay for anti-motoring protection of the turbine.

There are different sequential trip designs which use variables other than reverse power as indicators of zero steam flow to the turbine. These other design choices typically employ a position limit switch on the Main Stop Valve(s) or a pressure switch on the Control Oil System to prove a valves closed/no flow condition. Other choices include measurement indication of actual steam flow, or monitoring of increased exhaust hood temperatures. I have seen failures of these alternate trip designs, particularly valve position switch indications, lead to catastrophic overspeed events, and in this author’s opinion, the reverse power implementation is the most robust and reliable.

As well, there are other trip and shutdown scenarios to consider: Simultaneous tripping: This method trips the steam turbine and the generator at the same time. It is intended primarily to protect the generator from electrical faults and abnormalities which are extremely fast acting.

Generator tripping: This method trips the generator main breaker and field breaker together while leaving the turbine in operation. This is a deliberate design choice typically in response to a power system or switchyard fault, where rapid correction may be possible, enabling quick generator resynchronization to the grid. In this instance one relies on the turbine governor system to hold the turbine at synchronous operating speed in order to expedite return to service. The turbine control must be capable of rapid response following such a load rejection.

Unit separation tripping: This is similar to generator tripping, but while the unit is tripped from the grid, connections to local house load or station service are maintained. The intent here is to maintain critical in-house systems power supply and enable quick grid reconnection.

Because the generator becomes “islanded” in this scheme there is no grid synchronism to constrain generator speed, and again one relies on correct operation of the turbine governor for speed control. The turbine control must be capable of rapid response following a load rejection.

These three trip schemes, along with sequential tripping are discussed in detail in the IEEE paper, Sequential Tripping of Steam Turbine Generators.

Three additional trip schemes, less commonly encountered, are described in General Electric Company’s GEK77512, Generator Protection.

Most turbine generator units that I have encountered employ a combination of simultaneous and sequential trips to address different operating scenarios and emergencies.

A very simple “black and white” classification of these two trips is as follows: 1) Turbine, boiler and balance of plant trips are usually implemented as “sequential trips” 2) Generator protection trips (e.g. relay operations) are usually implemented as “simultaneous trips.”

February 2017

TURBINE TECH The logic behind this division of trip schemes is: Generator electrical faults are extremely fast acting, i.e. millisecond durations, and the removal of damaging electrical energy via excitation and generator breaker trips, ASAP, is desired.

Simultaneous steam valve closure serves to reduce, but doesn’t eliminate, the risk of overspeed. In these cases, the risk of immediate severe electrical damage is deemed to outweigh the risk of a potential overspeed in the event of failure to isolate motive steam.

Turbine related issues (including boiler and BOP), while possibly urgent, tend to happen on the scale of seconds and minutes, as opposed to milliseconds. Regardless of how fast we trip the boiler or close the steam valves, the TG train inertially retains significant rotating momentum, so immediate shutdown to zero speed (zero mechanical energy) is impossible to achieve. The best we can do is take overspeed out of the picture, by keeping the generator grid-synchronized (restraining overspeed) until we have proof positive (reverse power or related turbine thermal/mechanical indications) that the motive steam is isolated.

In the sequential trip, the risk of overspeed is judged to outweigh the risk of other damage mechanisms.

In the simultaneous trip, the risk of immediate electrical damage to the generator is judged to outweigh the risk of overspeed.

As discussed above, there are some subtleties, and additional trip modes to address grid system related trips, and less-common prime mover or internal station service arrangements, but in general, the above description summarizes both the industry and OEM recommended standard approaches to trip schemes.

This has been a highly simplified overview of a complex subject, which is an independent engineering discipline in its own right. ■ For further information, I recommend starting with: • Guide for AC Generator Protection - ANSI/ IEEE C37.102 • Sequential Tripping of Steam Turbine Generators – IEEE Transactions on Power Delivery,Vol. 14, No.1, January 1999 • Generator Protection – GE Energy, GEK 75512 (General Electric Company)

• Property Loss Protection Data Sheets, Electric AC Generators 5-12, FM Global/Factory Mutual Insurance Company Brad Snyder joined TG Advisers in 2008 as a Senior Consultant. He has provided life assessment; shop and site surveillance; trial expert witness; development of commercial and technical maintenance, refurbishment and new procurement specifications; development of comprehensive test programs; new equipment startup; troubleshooting; and numerous other services for main steam and combustion turbine generators located throughout North America, and the Caribbean area. Snyder is an electrical engineering graduate of the University of Delaware, and is a member of IEEE and its Power and Energy Society, with over 40 years of experience in the power generation industry. Questions about this article may be sent to editorial@WoodwardBizMedia.com.

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