RM-3 Vibration Gener Maughan

© 2010 Doble Engineering Company -77th Annual International Doble Client Conference

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STATOR ENDWINDING VIBRATION DETECTION

Clyde V. Maughan P.E. Emeritus

Maughan Engineering Consultants

ABSTRACT

Stator endwinding vibration has been a major deterioration concern on large turbine-generator windings for almost

50 years. The capability of endwinding support systems has evolved upward during this period, but still there

remain periodic failures due to high general vibration and/or local resonant vibration conditions. The ongoing

endwinding problems relate in part to the lack of a safe, convenient and reliable method for measuring vibration in

the high voltages which exist in the endwindings.

An early primitive method of measuring this vibration involved using inertial vibration instruments reading on the

end of an insulating rod, but for obvious reasons, this was not a viable method of measurement. In more recent

years, resonant-reed vibration pickups were used on some suspect machines, but these pickups did not give

quantitative information. Fortunately, there are now devices available that can measure local vibration magnitudes

and safely transmit accurate quantitative signals via fiber optics to instrumentation outside the generator casing.

This paper will discuss industry experience relating to generator vibration problems on stator endwindings,

evolution of stator endwinding support systems, historic efforts for measurement of endwinding vibration, and

finally, experience with the modern fiber-optics vibration monitoring equipment.

INTRODUCTION

Vibration of components has been a problem on turbine-generators since the infancy of the power generation

industry. Throughout the first half-century of power generation, vibration related problems occurred essentially

from the rotating field and on the stator core. The vibration measurement devices were relatively uncomplicated

since readings were being taken on non-rotating, electrically grounded components, e.g., bearing pedestals, core

outside diameter. These vibration levels could be measured adequately with hand-held devices, (Figure 1) and

inertial pickups mounted directly on the bearing pedestal.

As generators gradually became larger and more complex, improved instrumentation evolved, particularly for

monitoring rotating field vibration. These devices included equipment that could directly measure shaft vibration

via shaft-riding pickups or optical sensors. The sophistication of these devices made it possible to accurately

measure both the magnitude and angle of the shaft vibration – information that is essential to expeditiously reaching

optimum mechanical balance of large rotating components.

Hand-held Inertial Vibration Measurement Device

Figure 1

Generators are not well monitored, with several of the more destructive deterioration mechanisms monitored poorly

or not at all. [1] Endwinding vibration has historically been in the category of “poorly monitored”. Until recently,


All Rights Reserved 2

little capability had evolved for measuring vibration in high voltage regions such as stator windings, and these

windings were becoming increasingly difficult to design for reliability.

This paper will discuss the evolution of generator design leading into high vibrational driving forces and the

evolution of monitoring capability to meet the needs of these evolving designs. Focus of the discussion will be

primarily on stator endwindings.

MONITORING OF GENERATOR COMPONENT VIBRATION

Rotating Fields & Stationary Electrically-Grounded Components

Instrumentation of the rotating and stationary electrically-grounded components is well understood and documented,

and will not be addressed in detail in this paper. However, this is not to suggest that vibration problems do not exist

on these components. Several examples:

Stator Core and Frame

High core vibration may result in numerous and sometime important issues, including:

Noise levels that preclude being in the vicinity of the generator without ear protection.

Core vibration driving stator endwinding vibration at unsatisfactory levels.

Cracking of frame components due to excessive core vibration and/or inadequate isolation of core vibration

from frame.

Cooler vibration resulting perhaps only in minor dust generation, but in more severe cases, fracture of

structural components or cooling tubes.

Rotating Fields

There are two basic vibration concerns on generator fields:

1. Normal vibration caused by the expected mechanical unbalances. Since the long fields of larger high-speed

generators operate above the first critical, satisfactory balance requires placing compensating weights along

the length of the field body, as well as at the ends of the body. This balancing cannot be done at low

rotational speed, and must be done at or near operating speed.

2. A special problem exists on these long fields, i.e., vibration magnitudes and angles may change as a function

of generator load (field current). The change may be small and un-noticeable, <25µm (1 mil), or it may be

rather large, ranging from 75 or 100µm (3 or 4 mils) up to magnitudes that will completely prevent operation

of the unit. The thermal-vector (unbalance) produced by changing field current can be easily measured and

defined by its magnitude and angle as a function of field current. With this magnitude and angle information,

careful selection of balance weights (to compensate for the thermal vector) may permit continued operation

with a stable thermal vector as high as 100 or 125µm (4 or 5 mils).

Stator Winding Vibration in the Slot

By the early 1960s, improved stator winding cooling methods permitted large increases in generator power output

capability. This improved cooling was accomplished by direct flow of the cooling media within the stator ground

wall, e.g., hydrogen gas flow through tubes within the stator ground insulation and liquid flow through the bars

(Figure 2).



Left to Right: Indirect, Direct Gas, and Direct Liquid

Cooled Stator Bars

Figure 2

The resulting much higher electromagnetic forces presented increasingly severe challenges for controlling stator

winding vibration magnitudes. At that point in time, stator winding vibration became a major design and service

issue, both vibration in the slots and in the endwindings.

Magnitude of slot electromagnetic forces until the late 1950s was typically no higher than about 1.2 Kg/cm (8

pounds/inch) of bar length. But with the direct-cooled designs, forces ranged up to about 22 Kg/cm (120

pounds/inch) of slot length – perhaps 40 Gs, making design of wedging systems a difficult challenge and a major

service problem. Over time, improved slot restraining systems were developed. These evolving designs

incorporated much better wedging systems and materials as well as use of side pressure springs and radial pressure

springs. These new designs, if properly assembled, largely control slot vibration.

But relative movement (vibration) between the bar and the core iron simply cannot be tolerated by the insulation

systems. Vibration greater than perhaps a fraction of a mil can rapidly deteriorate the stator bar ground wall

insulation system. Deterioration mechanisms included mechanical impact damage, mechanical abrasion and wear,

slot discharge and a phenomenon sometimes called “vibration sparking”. [2]

Severe slot bar vibration can be heard as an audible noise. The vibration sparking phenomenon may in some cases

be indirectly monitored by partial discharge equipment and by electromagnetic interference. But otherwise, stator

bar slot vibration remains largely unmonitored.

An instrumentation system that can directly monitor bar slot vibration has been developed. But at the present time,

limited application has been made. This lack of direct monitoring of bar slot vibration can be a significant issue,

since generator manufacturers have not always been successful in preventing relative movement between the stator

bar and the core.

Stator Endwinding Vibration

Endwinding forces, while lower, are still high – in the order of one-third to one-half the slot forces. Because

endwinding force restraint systems were inherently much weaker than the slot systems, endwinding vibration

became a major ongoing problem. Evolution of endwinding support systems is discussed in some detail below

under the heading: STATOR ENDWINDING VIBRATION.

Stator bar endwinding vibration has historically been poorly monitored. The requirements of monitoring

endwinding vibration and slot vibration are fundamentally different. Specifically,

In the endwinding, resonances are likely and can be either individual bars or general resonance. Resonance in

the slot is unlikely.

In the endwinding, high voltage must be assumed to exist everywhere on the outside surfaces of the bar. In

the slot, voltages are possible but unlikely to be high, and grounded instrumentation can safely be installed,

e.g., resistance temperature detectors.



In the endwinding, vibration of the bars is inevitable and acceptable if small and controlled, i.e., less than

perhaps 50 or 75µm (2 or 3 mils). In the slot, relative vibration between the bar and core iron simply cannot

be permitted.

With these factors in mind, it is perhaps reasonable to conclude that monitoring of the slot portion of the stator

winding is of lower priority from a design engineer viewpoint. Whereas, monitoring capability for the endwindings

would be of very high priority. Fortunately, instrumentation for safely and accurately monitoring endwinding

vibration has become available, and one such system will be discussed below under the heading: AVAILABLE

ENDWINDING VIBRATION MONITORING DEVICES

Endwinding vibration will be the focus of the remainder of this paper.

STATOR ENDWINDING VIBRATION

Early Endwinding Tie Systems

The endwinding support systems in use until the introduction of direct cooling in the 1950s were typically a “string-

tied” system, i.e., bars restrained only by individual blocks and string ties spaced along the length of the bar end-arm

(Figure 3).

Early Indirect-Cooled Winding of the 1950s

Figure 3

Early Direct-Cooled Winding of the 1960s

Figure 4

There was little difference between the tie systems of the early 1900s and the tie systems of the late 1950s. Minor

materials changes were made in the 1950s, e.g., glass cord replaced cotton cord, and composite blocks replaced

hardwood blocks. But the configurations remained basically unchanged. These tie systems were adequate for the

low forces of small, indirectly cooled windings, i.e., less than about 200 MW, but inadequate for the high forces

associated with direct cooling (Figure 4). With the introduction of direct cooling, problems immediately surfaced,

and these problems were serious. Blocks became loose, vibrated, and wore completely through the ground wall

insulation. The bars themselves vibrated and wore into the support structures. Electrical connections broke due to

high-cycle fatigue resulting from component vibration.

It immediately became apparent that much better endwinding support systems must be developed.



Endwinding Design Evolution

Immediately after the vibration problems on the new direct-cooled windings became apparent, manufacturers began

developing greatly improved endwinding support systems. This led to a difficult period of about 20 years in the

industry, starting in the early 1960s, as individual manufacturers evolved through several iterations of upgraded

design. Full scale models were built, as shown in (Figure 5), but these models focused primarily on the control of

the very high forces of the relatively rare sudden short circuits. Evaluation for reliability against long-term, normal-

operation endwinding vibration was much more difficult to accomplish. Calculations were attempted and small-

scale models were attempted with little success.

The 4th and Final Version of the GE Endwinding Support Development Model

Figure 5

Present GE Endwinding Support System

Figure 6

Mainly, these new systems were developed by slow and costly trial-and-error and by adaptation from successful

design features of other manufacturers. Confirmation of long-term, normal-operation reliability required observing

performance over many years. As a result, the evolution process extended over several design iterations and two

decades of time. By about 1980 all manufacturers of large generators had arrived at good, if not perfect, endwinding

support systems (Figure 6). But during this period of design evolution, vibration problems continued to be

experienced in endwindings, and problems continue into today. Thus, the importance of capability to safely and

accurately monitor endwinding performance in service.

Confirmation of New Winding Quality

On new, modern windings, the primary operational concern is that of resonances. In order to assure that there are no

resonance conditions within a new stator winding, “bump” tests are normally conducted on the newly assembled

windings. This relatively simple and well understood test is conducted by exciting individual locations with the

impact of a calibrated hammer, while reading and recording the resulting resonance frequencies (Figure 7and Figure

8).



Hammer for “Bumping” Test Piece

Figure 7

Pickup for Receiving Signal

Figure 8

In general, it is desirable and practical to bump test every individual series and phase connection on the winding, as

well as every connection ring. This test sequence will identify potentially dangerous local resonance locations, as

well as overall endwinding resonance.

There is not a consensus as to allowable vibration magnitude limits or resonant frequency margins. With no

accurate in-service way to measure endwinding vibration levels, it has not been possible to ascertain safe limits.

Vibration magnitudes of 50 or 75µm (2 or 3 mils) are generally considered safe. Different manufacturers accept (on

60 cycle units) resonance limits as low as 130 Hz and as high as 140+ Hz. Natural resonant frequencies will reduce

immediately when the component is heated, and become progressively lower over time due to wear associated with

operating duties. Thus it is probably advisable not to accept test resonance values with a margin lower than perhaps

20 Hz, i.e., 140 Hz (on 60 cycle units).

Operating Problems

Two general categories of vibration problems are being experienced on stator endwinding systems, general vibration

and local resonances. It has not been possible to distinguish with certainty between the two, since endwinding

monitoring systems have not been available. But based on the nature of the evidence associated with a specific

vibration problem, it is possible to distinguish with some confidence between resonance and general vibration. This

has been done in the observations which follow.

General vibration may be less common than local resonances, but has been encountered on some generators. It is

likely that general resonances are involved in the condition shown in (Figure 9).



General Vibration on Stator Endwinding

Figure 9

Local resonances appear to be more common and have caused numerous in-service winding failures. Local

resonances are suspected of contributing to the wide-ranging failures shown in (Figures 10-13).

Failed and Burned off Series Connection

Figure 10

Failing Bar/Phase Connection

Figure 11

Failed and Burned away Phase Ring

Figure 12



. Failed Half-bar at Top-to-Bottom Bar Connection

Figure 13

AVAILABLE ENDWINDING VIBRATION MONITORING DEVICES

Historic Monitoring Availability

Historically, it has not been possible to directly monitor stator winding vibration. But indirectly, evidence of

vibration can readily be found by visual inspection, e.g., dusts and “grease”, holes worn in the insulation, loose and

broken parts (Figure 9 to Figure 13).

In the very early days of hard (polyester and epoxy) windings, before slot wedging systems were greatly improved,

it was possible to actually hear the rather loud noise of bars vibrating in the slots. Of course, vibration of this

magnitude would fatally damage the stator bars in a matter of weeks.

In the early 1980s, one manufacturer who was experiencing in-service vibration issues developed a rather ingenious

single-frequency, fiber-optics monitor. The monitor was in effect a tuned reed selected to resonate at a few hertz

above driving frequency, i.e., above 100 or 120 Hz. Before operation, the winding resonances were controlled (by

the tie and block system) to be well above 120 Hz. These devices were installed at selected location where

resonance might be expected, and thereby effectively monitored the endwinding condition as the resonant values

drifted down toward driving frequency. A typical installation is shown in (Figure 14).

Tuned Reed Vibration Monitor

Figure 14

But, in general, direct monitoring of stator endwinding vibration remained unavailable until recently.

Presently Available Monitoring Systems

At present, there are limited options for monitoring endwinding vibration. The device shown in (Figure 14) has

been available for about 30 years, but is limited in capability as it detects only the natural frequency of the vibrating

reed in the pickup. Piezoelectric accelerometers have also been available for measuring the spectrum of frequencies,

but these systems rely on insulating materials to electrically isolate the conductive sensor and cable from the high

voltages in the endwinding. There are obvious limitations of reliability, safety and accuracy with such equipment,

and applications have been limited.



Only recently has there been instrumentation available to safely and accurately measure and transmit actual

vibration magnitudes throughout the range of frequencies that are of interest in endwindings. VibroSystM of

Canada has produced such a device (as well as instrumentation to monitor slot vibration), and during the last few

years there have been a significant number of applications of the endwinding monitoring device. This

instrumentation system will be the focus of the remainder of this paper.

EXPERIENCE WITH THE VIBROSYSTM ENDWINDING VIBRATION DETECTION

EQUIPMENT

Detector System Description

The fiber optics accelerometer (FOA) consists of an optical head and conditioning electronics connected by a fiber-

optic cable ranging in length from 6 to 16 meters. This cable provides immunity and safety from the high level of

voltages that exist in an endwinding, i.e., line-to-neutral stator winding voltage rating. Vibration measurement is

accomplished by sensing changes to specific wavelength properties as the optical head accelerates. The pickup can

function safely up to 40 Gs, roughly twice the maximum level of vibration that can be expected on an endwinding.

The FOA optical head can be mounted anywhere in an endwinding or on the connection rings. It is nonconductive

and immune to electro-magnetic interferences. The optical link is rated well above the highest voltages used on

generators that are in service today. The sensor body (pickup) has no metallic components (Figure 15).

Close-up of Single-Direction and Bi-Directional Optical Heads

Figure 15

The sealed feed-through houses both the optoelectronic and conditioning circuitry (Figure 16).

Feed-Through, Identified by Red Arrow

Figure 16

The raw acceleration output can be processed into peak-to-peak displacement. A typical installation is shown in

(Figure 17).



Mounted on a Stator Winding Connection

Figure 17

The pickup output can be fed directly into existing condition monitoring systems able to accept a 6 VDC signal. For

example, a PCU-5000 programmable analog-to-digital rack mounted signal processor can be set up to display

parameters including RMS, peak, AC/DC, average, maximum or raw data. (Note: that raw acceleration output can

be processed into RMS displacement including phase or peak-to-peak displacement.)

Experience with the VibroSystM Detectors

The first turbine-generator application of these detectors was made about 10 years ago. There are now over 100

installations. Vibration levels of from 50µm to 375µm (2 mils to 15 mils) have thus far been observed. (All values

cited here are peak-to-peak.) There has not yet been sufficient experience to allow providing valid rule-of-thumb

levels of normal and worrisome vibration. On a specific moderate-sized generator, one original equipment

manufacturer (OEM) has allowed 275µm (11 mils) as a maximum safe level for a limited time of operation.

The safe level of vibration can be expected to depend on several variables, e.g., whether the vibration is local or

general, resonant or driven, stable or accelerating, endwinding support design, rating of the generator, number of

poles, As more industry-wide information is gathered, better understanding of safe and worrisome vibration levels

will evolve, but it is probable that the safe level for larger generators will be below 125µm (5 mils).

It is interesting that both positive and negative correlation has been observed between vibration and temperature,

depending on whether resonance frequency lies above or below driving frequency – 120Hz (or 100Hz).

The detectors have thus far proven valuable over a wide range of situations:

simply confirming that the endwinding vibration levels are acceptably low

monitoring the increasing levels of vibration on a problem generator

permitting safe operation while developing a design and accumulating materials for correction to high and

increasing vibration

assisting in the resolution of warranty claim differences of opinion.

The value of endwinding vibration detectors will increase as a data base is accumulated. This data base will allow

defining safe levels of vibration based on solid engineering information rather than chiefly opinion and intuition.

Three anecdotal examples of VibroSystM detector application are summarized below.

Consumers Power

An early application of the VibroSystM sensors was made on two units by Consumers Power at their Campbell

plant. One unit was a relatively small generator installed in 1962 and rated 156 MVA; this unit has a direct

hydrogen-cooled stator winding. The second unit was a very large 1025 MVA generator installed in 1980; this

generator has a water-cooled stator winding. Two different manufacturers were involved. [3]



Oddly, while the VibroSystM detectors on the larger unit are recording very low endwinding vibration levels, the

smaller unit is experiencing significant vibration. This small generator will have low electromagnetic forces driving

endwinding vibration, and thus perhaps the endwinding vibration is driven at least partially by the stator core. The

minimum readings of the detectors are in the range of 125-150µm (5-6 mils), but trend upward with time. When

vibration levels have reached about 250µm (10 mils), the endwindings have been reworked. The repair attempts

thus far have not been completely successful in permanently containing the vibration. Thus, the detectors are

serving as a powerful tool to monitor vibration and identify when rework becomes necessary on the endwindings

The larger unit has very high electromagnetic forces driving vibration of the endwindings. However, the

endwinding support system is functioning well, and vibrations levels are low, near 50µm (2 mils). Again, the

detectors are performing the intended purpose, i.e., monitoring the condition of the endwindings on a very large

generator with very high forces driving vibration of the endwindings.

Arizona Public Service Company (APS)

In the spring of 2003, APS started up a large (1060 MW) combined-cycle power plant. In June 2003, APS was

notified by the OEM that a serious concern existed with high vibration of the endwindings and connection rings.

(This problem had resulted in a catastrophic failure of a duplicate generator.) APS was faced with the purchase of

400 MW of replacement generation during the summer peak load, or finding another option. APS proposed to the

OEM that a set of vibration detectors be installed and monitored on critical locations in the endwinding. The OEM

accepted this option, and provided APS with maximum safe vibration levels of about 275µm (11 mils). [4]

Six single-direction VibroSystM detectors were installed during a short weekend shutdown, and the machine

returned to service with satisfactory levels of vibration being recorded. But by October 2003, vibration levels had

climbed to the safe limit the OEM had provided, and the generator was shut down for endwinding support

modification. These modifications were only partially effective. Upon restart, vibration was under 100µm (4 mils),

but within about 2 months of operation, levels were again above 250µm (10 mils).

In 2005, a second modification to the endwindings was made, based partially on the information gathered by the

vibration detectors. This modification appears to have been successful.

This installation was the first APS application of the VibroSystM detectors in an endwinding. The work involved

considerable application engineering by APS personnel in order to accomplish the urgent detector installation and

provide for off-site monitoring of the vibration magnitude output.

Based on the success of this first application, APS applied the VibroSystM detectors on a second site. The detectors

were installed to confirm a new end-turn stabilization technique utilizing epoxy filled fiberglass rope which had

been applied. The detectors confirmed that the modified end-turn system was performing well.

The detectors have since been applied to a third APS generator. South Carolina Electric and Gas

Upon startup of a new 405 MW unit, the generator had very high vibration levels throughout the frame and stator

endwindings. Vibration levels were sufficiently high to within a short time break a foundation bolt, damage the

IP/LP turbine cross-over compensator (expansion joint), and fracture stator endwinding expansion spring plates.

Noise levels were sufficiently high to preclude standing any period of time under the generator frame even with ear

protection. After less than 3 years of service, a stator winding phase connection ring fractured. The resulting three

phase arc severely contaminated the generator. Repairs required three months to complete.

Attempts were made to reduce endwinding vibration levels by making minor connection ring support modifications,

with limited success. In order to quantify the levels of endwinding and connections vibration, VibroSystM detectors

were added to the endwindings: 6 on the drive end stator endwindings, 6 on the non-drive end stator endwindings,

and 6 on suspect connection ring elbows. These detectors recorded high levels of vibration, in excess of 250µm (10

mils), predominantly on the non-drive end windings.



Based on the data from the VibroSystM detectors and other data on the generator and turbine, it was concluded the

only permanent fix would be replacement of the stator. A major issue was resonance vibration of certain non-drive

end components at 2 times running frequency (120 Hz). This was confirmed by bump testing with the unit off-line.

A new stator designed specifically for 60 Hz operation has been ordered and will be installed on this generator in

2010.

CONCLUSION

Stator endwinding vibration has been a major deterioration concern on large turbine-generator windings for 50

years. Until recently there has not been a safe, convenient and reliable method for measuring vibration magnitudes

and frequencies in the high voltages which exist in the endwindings.

Fortunately, there is now available at least one device that can measure local vibration and safely transmit accurate

quantitative signals via fiber optics to instrumentation outside the generator casing.

Because of the high costs associated with ongoing problems being experienced with endwinding vibration, the

availability of these devices to the industry is extremely important. This equipment should be of great assistance to

generator designers but also to personnel responsible for operating and maintaining large turbine generators.

Because of the vital need for such capability, application of such devices should become wide-spread.

It is unlikely that application of endwinding vibration measuring equipment will become as universal as, for

example, resistance temperature detectors. However, it can be expected that these devices will eventually become

standard monitoring instrumentation on all large generators, as well as common on smaller generators.

REFERENCES

[1] Clyde V. Maughan, Maughan Engineering Consultants, Schenectady, NY, USA. “Monitoring of Generator

Condition – and some limitations thereof”. IEEE/EIC Conference, October 2005, Indianapolis, Indiana,

USA.

[2] G. C. Stone, Iris Power, et al, “Impact of Slot Discharges and Vibration Sparking on Stator Winding Life in

Large Generators”. IEEE Electrical Insulation Magazine, September/October 2008 – Vol. 24, No. 5.

[3] Mike Hoffer, Consumers Energy, Jackson, Michigan, USA. “Stator Bar Vibration sensors and Fibre-Optic

Accelerometers. New Tools Used to Measure Stator Winding Vibration in Large Turbine Generators”. EPRI

Winter Technical Workshop and TGUG Meeting, January 2003. Orlando, Florida, USA.

[4] John Demcko & John Velotta, Arizona Public Service Company, Phoenix, Arizona, USA. “Generator End

Turn Vibration Monitoring. A Case Study”. EPRI Winter Technical Workshop and TGUG Meeting,

January, 2005. St. Petersburg, Florida, USA.

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