Advantages of Continuous Monitoring of Partial Discharges in ...

Advantages of Continuous Monitoring of Partial Discharges in Rotating Equipment and Switchgear Claude Kane Cutler Hammer Predictive Diagnostics 5421 Feltl Road, Suite 190 Minnetonka, MN 55343 Phone: 952-912-1358 Fax: 952-912-1355 Email: [email protected]

Igor Blokhintsev Cutler Hammer Predictive Diagnostics 5421 Feltl Road, Suite 190 Minnetonka, MN 55343 Phone: 952-912-1334 Fax: 952-912-1355 Email: [email protected]

Abstract -- For over fifty years companies have been performing partial discharge measurements on electric equipment in order to obtain information as to the quality of insulation on operating equipment. Partial discharge activity is a well-accepted indicator of insulation deterioration. Consequently, trending of partial discharge activity provides equipment owners the opportunity to reduce forced outages and increase productivity of plant equipment. Traditionally, periodic testing is performed, but advances in technology allow the continuous monitoring of partial discharge activity. Index Terms -- Partial discharge, motors, generators, switchgear, continuous monitor

I. I NTRODUCTION Last year US industry spent over $600 billion on plant and equipment maintenance. According to industry experts, at least $200 billion was wasted. Other industry statistics suggest that 80% of all failures of plant and equipment occur on a random basis and only 20% of the failures are age related. This means that 80% of failures have not been predicted with current test and maintenance practices and therefore have not been prevented. Can the situation be improved? In today's competitive environment, increasing demands are being placed on the management of physical assets. Many things have been done to improve the efficiency of maintenance work through the use of computerized maintenance management systems (CMMS), but they are more focused on corrective and preventative (periodic) measures.

Stephen V. Carney Chemicals & Energy Division Manager Electrical Maintenance US Steel Group Clairton Works - MS #42 400 State Street Clairton, PA. 15025 Phone:[412]-233-1409 Fax: [412]-233-1356 [email protected]

John Pozonsky Cutler Hammer Engineering Service & Systems 130 Commonwealth Dr Warrendale, PA 15086 Phone: 724-779-5815 Fax: 724-779-5828 Email: [email protected] Advances in technology are allowing new approaches to maintenance. These include reliability-centered maintenance, predictive maintenance, condition monitoring and expert systems. Trend setting organizations are increasingly taking advantage of the convergence of these new technologies to implement proactive maintenance programs to improve their company's bottom line. One such condition based maintenance technology is the measurement, monitoring and analysis of an electrical phenomenon know as Partial Discharge (PD), a well-known and accepted precursor or indicator to the failure of insulation systems in higher voltage electrical equipment. Although it has been successfully applied to equipment rated as low as 2,300 volts, customer value is low. Value is created at voltage levels of 4,000 volts and above. II. TRADITIONAL APPROACH OF PD MEASUREMENTS Traditionally, PD measurements have been performed on equipment on a periodic basis, one to four times per year. The periodicity is based on the analysis of the most current reading, trend analysis, availability of resources, etc. Typical monitored equipment includes motors, generators, switchgear, cables, bus duct and transformers. Some of the deficiencies in performing periodic PD measurements as well as periodic off-line tests such as insulation resistance and over potential testing are: 1) Time duration between tests are typically six to twelve months (if on-line) and frequently much longer for off-line tests. Many problems will manifest themselves in a much shorter period of time.

2)

During the performance of a periodic test a problem is detected, one starts to ask the following questions: • When did the problem start? • How fast is it degrading? Not only the velocity of change, but also the acceleration of change. • How fast will it continue to degrade?

The true answer is - one does not really know! In a periodic mode one will need, at least, two consecutive tests to establish a rate of defect development which could mean another year of testing. Therefore, one does not have enough qualitative and quantitative data to make a proper judgment at the time of problem detection, so arbitrary decisions are made. 3) In many cases PD activity is unstable. It may not be active today, but active tomorrow. Wide variations of PD activity are frequently observed based on data from continuous monitoring. Many factors can affect PD activity. A few include: • Voltage • Load • Temperature • Humidity • Vibration • Pressure As more and more data is collected in conjunction with other dynamic factors, much is being learned. Correlation of the certain dynamics with PD activity provides additional insight and can improve diagnostics. Most accepted PD standards focus on off-line partial discharge tests. OEM’s test labs commonly have their own test specifications and acceptance levels vary from OEM to OEM and are specific for specific insulation and equipment. Most PD standards dealing with on-line PD measurements avoid the stating of specific levels or quantities to determine acceptability limits. Instead, trending is stressed. In order to perform proper trend analysis, one should make sure all dynamics are nearly identical at each testing interval. This is very difficult, and sometimes impossible, to accomplish and can be time consuming. At this time, knowledge on correction factors to account for the change in dynamics is more academic than practical. Another reason for the avoidance of establishing levels is that even a very low level of PD activity that is trending upward will be indicating the development of a defect. Conversely, a high level of PD activity that is stable should be of concern, but at least one knows that the problem or defect is not getting worse, which should provide some level of comfort. 4) Time consuming. Taking periodic readings is labor intensive and frequently requires an expert to take and analyze the data to extract valid information. Maintenance

organizations that are being driven to do more with less are looking for ways to increase reliability with fewer resources. The only true way to reduce maintenance costs is to take the "work" out of it, which is the essence of condition-based maintenance. III. CONTINUOUS MONITORING OF PD ACTIVITY A continuous monitoring system will overcome all of the deficiencies listed above and will be an effective condition based maintenance tool: Advantages include: 1.

Finding a problem quickly. The monitor will identify a problem in its earliest stages of defect development. This will provide one with sufficient information as to the growth rate and the severity of the defect.

2.

Providing information as to which phase the defect is in and generally what type of defect such as: • Corona • Surface Discharge • Void type of defect (Insulation Delamination) • Conductive tape deterioration (Slot Discharge) • Loose high voltage connection that is arcing It is even possible to localize even further the location of the defect. 3.

Since no labor is required to perform the tests, continuous monitoring allows the use of limited resources to finding solutions to problems instead of finding problems.

4.

Reducing unnecessary maintenance because the monitor will be constantly testing and will have accurate data on which to base decisions.

5.

Collecting more accurate data as tests are conducted under real operating condition

6.

Requiring no outage to perform the test, therefore there is no loss of asset productivity.

7.

No introduction of infant mortality failure patterns via more invasive testing procedures.

8.

Reduction of forced outages and increased safety of personnel. One will always be aware of conditions and/or problems.

9.

Correlation of other dynamics such as temperature, humidity and load current to PD activity, which provides additional insight for diagnostics. There will be no need to go to several sources and gather the information.

10. Provides the opportunity for remote diagnostics. The expert does not need to come out to the field for basic diagnostics. A site visit by an expert will be the exception and not the rule. This can be done my emailing data to an expert or perhaps have a modem connected to the monitor so the expert can dial-in and upload the information for analysis and even provide a special test if necessary. 11. Evaluation of a piece of equipment is based on its own history and not by comparison to other equipment. This will make the detection of subtle problems easier. 12. Easily monitor worsening conditions so one can defer repairs and allow time to plan an outage. IV. PD DYNAMIC EXAMPLES As it was stated above, dynamics will significantly affect partial discharge activity. This complicates establishing PD trend and some times makes trending based on periodical measurements (one – four times a year) almost impossible. The following examples show frequent PD behavior that one can find in the field. Data was collected utilizing a continuous partial discharge monitor developed for MV equipment. The monitor is an intelligent stand alone device and has the following features: • • • • • • •

15 PD signal and 1 noise channel 75 dB of signal dynamic range frequency band of 1 –20 MHz RS-485, 4-20mAmp interfaces and two alarm contacts up to two years of on board data storage measurement is triggered by event, schedule, time interval or operator request Recording of dynamics such as temperature, load current and humidity

Figure 1. 13.,8 kV switchgear, PD, different magnitude scales

Figure 2a shows partial discharge intensity (PDI) and temperature correlation for cubicle 2. One can observe there is a negative correlation between these two quantities. Figure 2b shows the correlation of PDI to humidity for cubicle 14. (Quantities are normalized to their own maximums.) Lack of information on dynamics in both cases would cause wrong conclusions to be made on PD trend. In the second case, trend is also complicated by the instability of PD.

Figure 2a. 13.8 kV switchgear, mainly negative temperature correlation

The monitor acquires PD data in the form of phase-resolved pulse height PD distribution (PRPHD). Case 1. Trend. 13.8 kV Switchgear Line-up. The line-up has 15 breakers equipped with Radio Frequency Voltage Sensors (RFVS) type sensors. Several cubicles are exhibiting partial discharges. Figure 1 illustrates a flat projection of PRPHD on the magnitude and phase plane for all breakers at a selected time. A pulse is represented on the plot by a dot. Pulse repetition rate is color-coded.

Figure 2b. 13.8 kV switchgear, mainly humidity correlation

Figure 2b shows significant unstable PD activity starting in May and the PD activity shows a correlation with humidity. If periodic PD tests were performed it would be a hit or miss proposition due to the wide fluctuations. Additional on-line field tests were performed and it was determined the cause of the PD activity was a voltage transformer (VT). In late August, the VT was replaced and as can be observed, the PD activity is no longer present.

V. N OTES ON MEASUREMENT OF PD IN ROTATING EQUIPMENT As stated earlier, in order to make a good decision as to the state of a piece of equipment, one needs as much valid data or information as possible. This means having multiple sensing points, which can easily be done in switchgear since sensors can be placed in every cubicle, if necessary. In the case of rotating equipment, sensors have traditionally been placed at the line terminal of the machine. Due to signal attenuation, all sensors have their own "zone of sensitivity". Some of the factors that affect this "zone of sensitivity" are the physical design of the machine, the type of sensor used and frequency band of the PD measuring device. The typical sensors used on the line terminals of a machine are 80 pF coupling capacitors or RFCT on surge capacitor ground. If these are the only sensors used, only a very small portion of the machine is being monitored. On a large turbine generator, it may be only the ring bus and the first bar and on a large hydro the ring bus and first two to three coils. As one can observe, only a very small percentage of the winding is truly being monitored. The sensors located at the line terminals will not detect any developing defects that are deeper in the winding. One could argue that the further away from the line terminals, the voltage is lower, and therefore PD is not prevalent. Another argument is that the condition of the winding found at the line terminals is indicative as to the overall condition of the winding, such as a slot discharge. Let's address these issues. One of the major factors that affect PD activity and the destructive capability of PD activity is the voltage. Assume the monitoring a 13.8 kV (~8 kV phase to ground) machine that has 75 coils / phase, therefore there is a 107-volt drop per coil. This means after three coils, the voltage is still at 7,679 volts to ground. PD will still exist.

transducer does not affect the measurement of the connected temperature monitoring equipment and only passes the high frequency PD signals to the PD instrument. Over 500 machines, primarily motors, have been tested over the past five years with impressive results. RTDs were used for both the initial survey/evaluation and for on-going periodic measurements and data trending. RTDs are currently very effective in trending of machine PD activity when used with an analyzer or continuous monitor that can effectively reject noise and process PD data. As an example: The effects of signal attenuation discussed above may cause errors in the evaluation of the stator winding insulation condition, if the sensors located at the machine line terminals were the only ones used for assessment. Figure 3 shows PD test results of three 13.8kV motors of a similar design at the same facility. All motors have permanent radio frequency current transformers (RFCT) sensors placed on the surge capacitor grounding conductors. Temporary PD sensors were also connected to the existing RTDs in each machine. Figure 3 (top) shows maximum PD magnitudes recorded from the line terminal sensors. Based on these results, one would conclude that Motor 1 is in a good state and the Motors 2 and 3 have moderate level of discharges. The data from three RTDs that showed the highest reading for each motor are shown on Figure 3 (bottom). Conclusions based on this data, are the same as above for the Motors 2 and 3. The conclusion is different for the Motor 1. It has a high level of PD at the zone of RTD01 and is the first candidate for additional testing and internal inspection. RFCT Sensors

Motor1

One can assume the overall condition of the machine can be determined from just a small sample of the overall machine. In some cases this is true, but there also are many localized defects that occur in the machine that will not be detected from the line terminals. What can be done? Simple. Use detectors that are embedded in the windings of the machine. This could become very expensive and would be difficult and expensive to add to existing machines. But not all is lost. Most machines already have RTD detectors embedded into the winding by the manufacturer and these temperature detectors can be used for partial discharge measurement [3]. Special PD transducers have been developed that connect to the existing RTD wires and is installed in series at the RTD terminal block located on the frame of the machine. The

Motor2

Motor3

RTD Sensors

Motor1

Motor2

Motor3

Comparison or PD Magnitudes from Line Terminal Sensors and RTD Sensors Figure 3

In most cases, the sensitivity of the RTDs is comparable to that of the line couplers. This is especially true in motors and small generators. However, in some cases (specifically older large turbine generators, 500 MW and greater)

sensitivity can be much lower. But, there is no question the RTDs do provide additional information so a more valid decision can be made as to the condition of the overall insulation integrity of the machine. Over 500 motors and generators have been successfully tested using RTDs. Use of the existing embedded RTDs as a PD detector is proven technology that will detect PD that is occurring deep in the winding that may not be seen from the line terminals. Another item that significantly affects signal attenuation is the frequency band of the analyzer. The higher the frequency detected, the quicker the signal attenuates. Since the signal attenuates faster, the "zone of sensitivity" of the sensor/analyzer combination is reduced. The reason for higher frequency measurement under field conditions is to reduce noise. Making measurements in the field can be difficult at times due to the many sources of noise. Sources of noise include, radio stations, control electronics, microprocessor based relaying and metering packages, etc. The higher the frequency measured, the less noise needs to be dealt with, but the sensor will have a much smaller "zone of sensitivity."

VI. PD DYNAMIC EXAMPLES (CONTINUATION)

Figure 4b. 13.8 kV, 8,000 HP Synch motor, PD variations are both temperature and humidity related

Case 3. Trend. Two 13.8 kV identical 36MVA generators. This example examines two identical turbine generators. The generator shown in Figure 5a operates as a peaking unit. As can be seen, there is positive correlation of PD activity with temperature and load. The generator shown in Figure 5b is base loaded and virtually no correlations are evident.

Figure 5a. PDI correlates to both temperature and load.

The above discussion was centered around PD measurements on rotating equipment and signal attenuation aspects. Now, let's look at the effects and correlation of PD activity and specific dynamic parameters. Case 2. Trend. Two 13.8 kV motors of the same manufacturer. This case examines two 13.8 kV synchronous motors. Both motors are outdoors and drive compressors. Figure 4a shows that this motor has a slight temperature correlation with PD activity. Most of the variations are load dependent. Figure 4b shows this motor has correlation of PD activity to both temperature and humidity.

Figure 4a. 13.8kV, 28,000 HP Synch. Motor. PD variations are slightly load and temperature related.

Figure 5b. PDI is stable. Correlation to both temperature and load is not evident.

VIII.

WHAT CAN BE DONE ON CABLES?

On-line monitoring or testing of cables is an unique application. The effectiveness of performing PD tests on in service cables presents unique situations. Two types of sensors are typically used. On solid extruded cables such as XLPE, HMWPE and EPR, typically the drain shield of the cables is placed though a Radio Frequency Current Transformer (RFCT). This is difficult to do on Paper Insulted Lead (PILC) since the terminations on in a pothead and there are no drain shields. For PILC cables, one can insulate the pothead from ground and then ground the pothead with and external ground cable and passing this ground cable through an RFCT. Anther option is to install 80 pF coupling capacitors, phase to ground (one per phase).

Experience has shown that in the solid dielectric cables, typically locations for PD is found in the terminations and splices. Unfortunately, experience has also taught us the water trees in these type of cables do not product PD until right before failure. Consequently, effectiveness of a system to detect water trees in the insulation of a cable system is minimal. Also, the length of cable that can be monitored is limited by the cable insulation and design. Typically, one can monitor 1,000 - 1,500 feet of XLPE and HMWPE cables and only about 300 feet of EPR type cable. EPR cable has shown to have high losses to the high frequency signals produced by a PD event.

where γ ?is the resultant – Gamma (commonly represented as a percent of initial current), I0 is an initial current, C0 is the initially measured value of the bushing insulation capacitance C1 , and ∆C and ∆tan δ are the changes in capacitance and dissipation factor, respectively, during monitoring. Fig. 6 illustrates a simple schematic of the measuring circuit. UA UB

In PILC cables, PD events can easily occur within the main part of the cable insulation structure. Typical effective distances approach those of XLPE cables.

UC C1A 1A

C1B 1B

C C1c

PD Sensors

IX.

IA

CONTINIOUS MONITORING ON LARGE POWER TRANSFORMERS

IBB

ICC

∆I Σ

K

The main difference between on-line and off-line measurements is the voltage source. In on-line test one has three separate voltage sources (three-phase system) that can behave somewhat different over a time. This has an effect on the measurement accuracy of a single measurement. An on-line test is continuous in nature and large amounts of data are available for statistical processing. In the author’s North American experience the accuracy of 0.1% is easy to achieve. This accuracy is sufficient for almost any practical application. The deterioration of bushing insulation is accompanied with an increase or decrease in its dissipation factor and/or an increase in its capacitive current under the operating voltage. Dissipation factor changes are usually more sensitive to initial defects, while capacitance changes tend to indicate a developed defect. The relative value of the current change can be expressed in the form:

γ =

∆I = (∆ tan δ ) 2 + (∆C Co ) 2 Io

K - Current Balancing Balancing Unit Unit Σ - Current Summer

Figure 6. Simple System Schematic Bushings dielectric properties can vary significantly with temperature, especially if defects exist. Some examples are shown in Figure 7.

Tan Delta v.s. Temperature 100 Tan Delta [%]

Depending on the data analyzed, bushing failures account from 10% to 35% of all power transformer failures. On-line monitoring of the bushing dielectric characteristics has been successfully utilized for several decades. The original concept is quite simple: The current that can be obtained from the test or potential tap of a bushing contains both reactive and active components representing respectively bushing capacitance and power loss. Three bushings are normally available on transformers or transformer group (including CTs and CCVTs). Assuming that at least one bushing is in a good condition, a comparison between the three currents can be made and diagnostic conclusion be derived on this comparison. It would be highly unusually that more than one bushing would deteriorate at the same rate at the same time. Normally, only one of the three bushings would be in poor condition at the same time.

10

1

0.1 0

20

40

60

80

100

Temperature [C] Good

Some contamination

Severe moisture contamination

Semi-conductive sediment

Figure 7 The tanδ of good and dry insulation normally has none or a very slight U-shaped temperature dependency. Severe moisture contamination causes almost an exponential rise of tanδ with temperature. If there is semi-conductive sediment settling in the bottom of the inner porcelain surface, tanδ may show a slight negative temperature effect even causing negative dissipation factor reading at elevated temperature.

Consequently temperature dependency is a very important diagnostic parameter of bushing insulation. On the other hand, temperature dependency some times can cause problems with interpretation of the data obtained at different temperatures in off-line tests. Doble provides a guideline for this situation. Temperature correction coefficients vary with bushing design, year of manufacturing and so determining the temperature correction factor is a “scientific” problem. When there is a change in γ, there is both a magnitude change and a vector change. Monitoring of the magnitude change provides information as to the rate of change and the critically of the unbalance. The vector change provides the user information as to which bushing is deteriorating and the cause. As shown in Figure 8, there is a step change in the slope of γ as well as a vector at 330o . The vector change

X.

This paper reviewed the features and advantages of a continuous monitoring system for partial discharge activity on a wide variety of equipment utilizing both traditional PD detectors and winding RTD’s. A continuous monitoring system can save the user a considerable amount of time and money and provides more accurate data allowing for more informed decision. Some of the advantages of a continuous monitoring system include: • • • •

•

indicates that the power factor of the "C" Phase bushing is changing. Figure 8

SUMMARY

•

No labor is required to conduct tests. More efficient deployment of personnel. Labor is freed up to fix problems and finding solutions instead of looking for them. More accurate data as tests are conducted under real operating conditions. Finding a problem is not left to chance (like interval testing). One will know when a problem started and how rapidly it is progressing, thereby allowing a better outage/service decision. Unnecessary maintenance is reduced because the monitor is constantly testing providing more accurate data on which to base decisions. In effect, achievement of a predictive-based maintenance is reached versus interval/chance maintenance. Prioritization of which equipment receives service first.

The main obstacle in practical on-line electrical measurement of PD on transformers is there is a high level of radio frequency noise in these high voltage/ extra high voltage substations. To date there is no know technology that is effective in the electrical measurement of PD at voltages of 69 kV and greater on a continuous basis. There does exist one method using a specialized analyzer that can be used on a periodic basis. Utilizing of this analyzer, the following defects have been uncovered.

The advantages of using the existing RTDs in rotating equipment as a PD sensor in conjunction with the more traditional sensors that are installed at the machine line terminals were also discussed. Use of the information obtained from both types of sensors provides a higher quality of information so better decisions can be made.

Particularly, the following problems have been identified in the transformers already tested: • The source of critical PD was detected in a 750 kV autotransformer of a nuclear power plant. These PD were caused by a progressing creeping discharge across the 750 kV bushing insulation that was confirmed by internal inspection. The problem was associated with water penetration through loosed top sealing of the 750 kV lead. Internal inspection has shown that a really catastrophic failure had been prevented. The sketch of defects found at inspection is presented in Fig. 2 and picture of a barrier in Fig 3. • A source of PD was located in a 500-kV bushing of a 300 MVA autotransformer; • Defective bus bar isolators were found on 13.8-kV side of a large GSU transformer. • Arcing contacts on No Load Tap Changers.

[1] ASTM, Standard D 1868-93 (Reapproved 1998),“Standard

REFERENCES Test Method for Detection and Measurement of Partial Discharge (Corona) Pulses in Evaluation of Insulation Systems.” –ASTM, 1998, West Conshohocken, PA.

[2] IEEE P1434 “Trial-Use Guide to the Measurement of Partial Discharges in Rotating Machinery, 1998. [3] Z. Berler, I. Blokhintsev, A. Golubev, G. Paoletti, A. Romashkov “RTD as a Valuable Tool in Partial Discharge Measurements on Rotating Machines”Proceedings of 67th Annual International Conference of Doble Clients, March 2731, 2000, Watertown, MA

[4] IEEE Guide for Partial Discharge Measurement in Power Switchgear—IEEE Std. 1291-1993

[5] IEEE Guide for Partial Discharge Measurements in Liquid Filled Transformers and Shunt Reactors—IEEE C57.113-1991 [6] IEEE Recommended Practice for the Detection of Partial Discharge and the Measurement of Apparent Charge in Dry-type transformers—IEEE Std. C57.124 (R2000)