Hot Springs VA Combined Test Report.pdf

Electrical Maintenance & Testing ProjectElectrical Maintenance & Testing Project

CoverCover

Submitted by

Veterans Affairs Medical Center

Hot Springs, South Dakota

Contract No. 36C26321Q0786

Project Report

October 28-30, 2021

845 Long Branch Circle

Sugar Hill, Georgia 30518

P - (678)546-9393, F – (678)828-5903

16901 Blakeway Place

Mosely, Virginia 23120

(512)484-5594 in cooperation with

Slocum & Associates

Signed by:_________________________________

Jerry M Parks Jr, Project Manager

Electrical Maintenance and Testing Project Contract No. 36C26321Q0786

Veterans Affairs Medical Center

Hot Springs, South Dakota October 28-30, 2021

Section 1 Electrical Testing and Maintenance Summary

Section 2 Publications/Exhibits

Section 3 Electrical Test Records

Section 4 Specialized Tools & Equipment

Table of Contents

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Electrical Testing & Maintenance Report Summary

General

SDV Services Inc. provided electrical testing and maintenance services at the Veteran Affairs Medical Center in Hot Springs, South Dakota October 28-30, 2021. All services were conducted in accordance with contract specifications, industry standards, NFPA 70B and manufacturer’s recommendations.

The traditional types of equipment tested during this testing session included:

Medium Voltage Oil-Type Transformers

Switchboards (medium and low voltage) with Enclosed Circuit Breakers/Relays

Automatic Transfer Switches

Test results were compared with manufacturer’s recommendations for each specific equipment item and type.

This report consists of the following:

Section 1 Electrical Testing and Maintenance Report Summary

Section 2 Publications/Exhibits

Section 3 Electrical Test Records

Section 4 Specialized Tools & Test Equipment

Findings & Recommendations

1. Equipment Age & Condition

Issue

With the exception of the recently-installed medium voltage transformers and new distribution panels in building 12, the majority of electrical equipment in this facility has exceeded its industry-standard useful service life of twenty-five (25) years and the fifteen

(15) year service life established by VA standards. Replacement parts are becoming increasingly more difficult to obtain due to age and technical obsolescence. Equipment of this age and condition raises the question of reliability in regards to the ability of the equipment to properly and safely protect the building. Careful consideration should be given to replacing the entire electrical system. It should be noted the main switchboards

Slocum & Associates in cooperation with

2 | P a g e for buildings 10 and 12 contain air circuit breakers that can be upgraded with the latest technology trip devices (Digitrip RMS-510) that can greatly extend their useful service life.

As electrical equipment ages, the associated risk of a failure increases significantly. Such failures usually occur without prior warning and can be potentially catastrophic. Repairing or replacing aged equipment is another issue due to obsolescence or non-availability of parts. In the event of a failure, there is a great possibility parts will not be available or will have significant lead times. As an example, Millennium found a defective main switch in a federal building that took 6 months to acquire a replacement part due to technical obsolescence. This can lead to very costly repairs and extended down time for equipment and related circuits.

Included in section 2 to this report is an article presented by three professional engineers (PEs) specializing in electrical distribution systems – “Renovating Electrical Distribution Systems” by Syed M. Peeran, PhD, PE; Mario Vecchiarello, PE; and Jeff Romeo, PE. The first page of this article references the hazards of aging electrical systems and the unpredictability of equipment exceeding its useful service life. Even the VA acknowledges a typical 15-year useful service life in section 1 of its VA Electrical Design Manual.

Equipment identified in this report has far exceeded this service life without upgrade and has this element of unpredictability regardless of past performance or testing.

Recommendation

Due to age, technical obsolescence and unpredictability of failure, the entire electrical system needs to be considered for replacement to ensure it properly and safely protect the electrical system and its occupants.

Initiate a project to upgrade the trip units on the circuit breakers in the main switchboards for buildings 10 and 12. This will serve to extend their useful service lives as well as ensuring the buildings are properly and safely protected.

2. Arc Flash Hazard Levels - Maintenance Setting Procedures

The main switchboards in this facility have been labeled as “dangerous” per the recently-performed arc flash study. There is no level of personal protective equipment (PPE) available to protect maintenance personnel in operations requiring work on energized circuits within these switchboards. Presently, the switchboards would have to be de-energized at the medium voltage transformer to perform such work. In an effort to minimize the impact on hospital operations in such cases, Slocum hereby proposes implementation of a “maintenance setting” program whereby the Main circuit breaker trip unit settings could be adjusted to enable “safe” energized work.

Such a program would focus on developing protective device settings for the Main circuit breaker trip units to reduce the arc flash incident energy levels below 40 cal/cm2 where safe PPE levels exist. This is best determined by the contractor performing the latest arc flash hazard analyses.

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Contact the contractor performing the latest arc flash hazard analyses to perform necessary calculations to develop protective devices settings for this “maintenance setting” effort to reduce arch flash incident energy levels at or below 40 cal/cm2.

Implement a “maintenance setting” program on the main switchboards based on the proposed “maintenance settings.” This would identify both “maintenance settings” and “normal operating settings.” Procedures would then outline how to adjust protective device settings using the maintenance settings to safely perform energized work followed by the procedures to restore protective devices to normal operating settings.

A placard or maintenance guideline incorporating these procedures should be affixed to the main switchboard as a ready reference. Attachment A to this summary provides a guideline for such a program. Of great importance, is the section detailing present breaker setting to ensure the breakers are returned to a setting established by the recently-performed selective coordination study.

3. Bldg. 12 Arc Flash Incident Energy Levels

The main switchboard for building 12 has arc flash incident energy level warning labels on the front of each cubicle of this switchboard. The incident energy levels range from 1.44 cal/cm2 to 39.2 cal/cm2. While not ideal, this is acceptable when simply racking the individual circuit breakers in and out of their respectable cubicles. However, this leads to a safety hazard should energized work be required in the rear of the switchboard. The rear of the switchboard is not compartmentalized, meaning the cubicles are not physically segregated from each other. A fault from one cubicle can cascade to another or even the entire switchboard. The individual working in one cubicle and following the PPE levels at

1.44 cal/cm2 could be subjected to incident energy levels up to 39.2 cal/cm2. This presents a significant safety hazard to maintenance personnel.

The highest arc flash incident energy level labels on all main switchboards should be maintained. All other warning labels should be removed. This will ensure personnel working within these switchboards are properly protected regardless of which cubicle they are working.

4. Transformer Oil Test Results

Test Results

Oil samples were taken of all medium-voltage oil-type transformers. Each sample was tested using dissolved gas analysis (DGA) and found to be normal with the exception of transformer 12B. Outlined below is an overview of the findings for this transformer:

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▪ Building 12, Transformer 12B – oil showed abnormal to high levels of thermal gases (methane, ethane and ethylene), abnormal acetylene levels and abnormal TDCG (Total Dissolved Combustible Gas) levels.

Abnormal voltage readings were noted following re-energization of the transformer as a part of the 4-hour ESS outage. The results for this transformer confirm that an internal fault had occurred in this transformer.

Laboratory test results have been incorporated into the test records for the medium-voltage transformers located in tab 3 to this report

The transformer was scheduled to be replaced. No further action required.

5. Transformer Negative Pressure

The oil-type transformers listed below were found to have negative or neutral pressure per the enclosed pressure gauge.

Building Transformer ID Pressure Level

10 TF-10A -1

10 TF-10B -1

12 TF-12B 0

12 TF-12XR -2

17 TF-17 0

18 TF-18 -1

43 TF-43 -2

53 TF-53 -1.5

65 TF-65 -1

Negative pressure creates the potential for moisture and air to be pulled into the oil compartment. This can lead to “bubbling” with the potential for a flashover and catastrophic failure. Transformer manufacturers recommend placing a positive pressure on the oil compartment by first pulling a vacuum and then placing a nitrogen blanket on top to prevent such an occurrence. Typical pressures range from +3 – +7.5 psi.

Enclosed is a publication by Transformer Testing and Repairs, Inc. discussing the importance of transformer gauges and reasons for maintaining a positive pressure in the oil tank. An excerpt from an ABB publication has also been included describing the process for establishing the vacuum and subsequent nitrogen blanket on the oil compartment.

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The oil tank for the above-referenced transformers need to have a positive pressure applied as outlined in manufacturer’s recommendations. This can be done by pulling a vacuum on the tank and filling the space between the oil and the top of the tank with a nitrogen blanket.

6. Defective Circuit Breakers

The circuit breakers below were found to be defective. Each is listed by location along with a description of the deficiency.

Building Swbd/Panel Circuit ID Issue

18 Main Panel DP-1 Breaker failed to trip during overcurrent testing.

18 Main Main Water Pump #2 Breaker failed to trip during overcurrent testing.

18 Main Spare Breaker failed to trip during overcurrent testing.

The following recommendations are made to correct noted breaker deficiencies:

Building Swbd/Panel Circuit ID Recommendation

18 Main Panel DP-1 Replace the breaker.

18 Main Main Water Pump #2 Replace the breaker.

18 Main Spare Replace the breaker.

7. Bldg. 12 Outside Bus Duct

Two sections of bus duct bring power into the main switchboard from the outdoor transformers for building 12. The outdoor segments of these bus ducts begin outside and are located directly below the roof edge leading water to fall directly onto the bus duct.

Additionally, these bus sections are exposed to abnormal weather conditions that can lead to deterioration of the seals around the bus duct. These conditions can lead to moisture penetration of the bus duct with the potential for a phase-to-phase or phase-to-ground leading to a catastrophic failure of the bus duct. This would create an extended normal power loss to the facility while a corrective solution is developed and installed.

The two outdoor sections of bus duct for building 12 need to have some form of physical protection provided to prevent water from falling directly onto the bus duct. Additionally, the weather seals around the joints of these bus sections should be inspected annually to ensure serviceability. These conditions can lead to moisture penetration of the bus duct with the potential for a phase-to-phase or phase-to-ground leading to a catastrophic

6 | P a g e failure of the bus duct. This would create an extended normal power loss to the facility while a corrective solution is developed and installed.

CD-ROM Version

Inside the front cover of each report copy is a CD-ROM containing an electronic copy of the Electrical Testing & Maintenance Report. These have been created using Adobe Acrobat and can be viewed by anyone with Adobe Acrobat Reader 7.0 or higher on their computer.

Additional report and work order copies can be printed using this CD-ROM.

In the event you do not have a compatible viewer, you can download a free version from the internet following the instructions at:

www.adobe.com/products/acrobat/index.html http://www.adobe.com/products/acrobat/index.html

Attachment A. Maintenance Setting Guidelines

Prior to starting work on MSB-A or MSB-B requiring a cubicle or cover to be opened, the following guidelines should be followed to minimize potential arc flash hazards:

WARNING!!!

Appropriate personal protective equipment (PPE) must be worn when performing the procedures outlined below.

1. Main Circuit Breaker (Main-A or Main-B) – short delay pickup and delay times should be set to minimum (red dot). Use a small screwdriver and rotate counterclockwise until red dot appears and is aligned with the white line above the setting indicator.

2. Open circuit breaker requiring maintenance by using the green “OPEN” switch above the cubicle. In the event maintenance is required on the main or tie breaker is to be closed, all breakers on the affected side should be opened.

3. Perform required maintenance procedures.

4. Close all circuit breakers (except Main-A or Main-B) opened to perform required procedures.

5. Close Main-A or Main-B using the red “CLOSE” switch above the cubicle, as applicable.

6. Restore Main-A or Main-B short delay pickup and delay times to original settings. The black dot above the applicable setting should be aligned with the white line above the setting indicator.

Those settings are presently:

Short Delay Pickup 4X Short Delay Time 0.33s

NOTE

If the Tie breaker is to be used, the applicable main circuit breaker (Main-A or Main-B) must first be opened and racked out. The A3 interlock key should then be rotated clockwise and removed.

The A3 key must be inserted into the key slot above the Tie cubicle and rotated counterclockwise. The Tie breaker can then be racked into the cubicle and closed. Reverse the process to re-energize the applicable main circuit breaker.

Electrical Testing and Maintenance Project, Contract No. 36C26321Q0786

Publication Section

Enclosed are publications or articles referenced in this report. Such publications are invaluable and designed to provide additional discussion, authoritative commentary and/or guidance on issues noted during this testing session. Publication/articles have been broken down into categories and separated by a red divider page as follows:

Equipment Installation Guidelines

▪ “Renovating Electrical Distribution Systems,” article by Syed M Peeran, May 2009 issue of Consulting-Specifying Engineer (re-print)

▪ “Inertaire® Oil Preservation Systems Installation, Operation, & Maintenance Guide RN_ _” by ABB, May 1996

Renovating electrical distribution systems

How to decide what to keep and what to discard in an electrical distribution system.

Syed M. Peeran, PhD, PE; Mario Vecchiarello, PE; and Jeff Romeo, PE

05/09/2011

Like death and taxes, failure of electrical distribution equipment is inevitable; it is only a matter of time before we need to deal with it. Upon installation, all electrical equipment begins to deteriorate due to absorption of moisture, daily temperature cycles, collection of dust, condensation, mechanical wear of circuit breaker contacts and contactors, weakening of operating springs, deterioration of insulating materials, rusting of switchgear enclosures, or drying out of capacitor dielectric.

Aging electrical components are potential hazards in any distribution system, particularly in modern automated and unattended systems. After the expected useful life, the failure of electrical equipment is unpredictable. Electrical equipment failures have been the most common cause of fires in buildings and facilities. Therefore, renovating electrical distribution systems is essential to deliver reliable power to the loads.

Aging of electrical equipment

Moisture and dust are sworn enemies of all electrical equipment. Many types of electrical equipment are installed outdoors or in unconditioned spaces where there is no control of temperature and humidity. Even in the case of equipment installed in weather-conditioned spaces, there is a gradual but definite deterioration. Eventually, the equipment will reach a condition in which its reliability becomes questionable.

All electrical equipment ages at different rates based upon the quality of equipment, maintenance, and its environment. This article will help the reader identify when the equipment has reached the end of its useful life. See Table 1 for some general life expectancies. While planning renovation of an electrical distribution system, a starting point would be to determine the ages of the various components of the system.

http://www.addthis.com/bookmark.php?v=250&pub=xa-4a8ac57416db70f7

Electrical insulation

The weakest and fastest degrading component of any electrical equipment is the insulation. In cables, transformers, reactors, trip coils of circuit breakers, operating coils of contactors, motors, and capacitors, solid synthetic and paper insulation is used. The degradation of this insulation depends greatly upon the maximum temperature to which it is subjected. Insulation is, therefore, classed according to the maximum temperature it can be exposed to. Table 2 shows the temperature rating of different classes of insulation used in electrical equipment.

A general rule of thumb is that the life of the insulation is halved for every 10 C rise in the operating temperature above the rated maximum temperature.

Capacitors

Several types of capacitors are in use in low-voltage (LV) and medium-voltage (MV) distribution systems, such as surge capacitors to protect motor windings, power factor correcting capacitors, commutating capacitors in variable frequency drives (VFDs), capacitors in active and passive filters, and pole-mounted capacitors in overhead distribution lines for voltage drop compensation. The most common application is for power factor correction in ratings up to several hundred kVAR. Three-phase and single-phase capacitors in hermetically sealed units are available in rectangular and cylindrical metal enclosures. The dielectric material used is metalized polypropylene film encapsulated in a thermal setting resin. Pressure-sensitive interrupters are provided to disconnect the capacitors in the event of an internal fault. Externally, the capacitors are invariably fused because the failure is generally due to short circuits.

There is a continuous power loss internally of approximately 0.5 W/kVAR due to dielectric hysteresis.

This loss causes internal heating and drying of the insulating resin resulting in a reduction of the kVAR compensation which goes undetected. Manufacturers state that the expected life is approximately

150,000 hours of continuous operation (approximately 17 years). Actually, the expected useful life at nameplate values is shorter than 17 years because capacitors are constantly exposed to system over-voltages and voltage transients. The operating environment is more severe than the shop testing environment.

Internal short-circuits in the polypropylene film can be detected by input current measurements.

Reduction in the kVAR compensation due to aging can also be detected by current measurement using a clamp-on ammeter.

Liquid filled transformers

Liquid filled transformers are typically installed outdoors in weatherproof enclosures on concrete pads

(pad-mounted transformers) or on poles. The liquid serves the dual purpose of cooling the transformer coils by convection and providing insulation between the coils and the grounded tank. Modern transformers use stable silicon-based or fluorinated hydrocarbons or combustion-resistant vegetable oil-based dielectric fluids or synthetic esters. Older transformers used insulating mineral oils.

In the transformer, the insulating fluid degrades first. The degradation is due to ingress of moisture, corona (minute arcing at the windings generating gases that get dissolved in the fluid), loss of dielectric strength due to moisture content, impurities, and periodic heating and cooling. With regular maintenance, testing, and replacement of the fluid when necessary, the liquid-filled transformer can provide reliable service for more than 30 years.

LV molded case circuit breakers

Molded case circuit breakers are used widely in LV distribution systems. There are two components that wear out with use: the copper contacts and the spring-loaded operating mechanism. The contacts wear out due to abrasion while closing and arcing while opening the breaker. In large breakers, the contacts are replaceable.

With use, the operating mechanism becomes sluggish, resulting in delayed clearing times beyond that given in the manufacturer’s published curves. The springs generally retain their strength for the life of the breaker and beyond. The lubrication, however, becomes the limiting factor. Grease and red oil used in the lubrication deteriorate, resulting in the slower clearing times. As shown in Figure 2, the manufacturer’s published tripping curves are actually bands within which a good breaker is expected to operate.

A possible shifting of this band is due to aging. If the tests reveal that the breaker operation is much above the original tripping band, then it is time to replace the breaker.

Most manufacturers state that the expected useful life is 20 years. Beyond 20 years it would be prudent to replace all molded case breakers of 100 A and lower rating. For larger breakers, it may be worthwhile to perform tests to determine satisfactory operation and develop a replacement program.

LV and MV power circuit breakers

LV power circuit breakers are available in continuous current ratings of up to 6000 A at 600 V. MV circuit breakers are available for up to 35 kV rating. These breakers are most commonly the draw-out type. The current-carrying contacts separate in air and the arc is quenched by the de-Ion grid extinguisher. The moving contacts are pivoted. Operation of the breaker is by a charged spring, which is released by the trip coil. The trip coil is controlled by an electronic trip unit, which can provide adjustable time overcurrent and instantaneous overcurrent protection.

The current-carrying contacts consist of the main and the arcing contacts, the latter opening last when the breaker trips. The arcing contacts are easily replaceable. As in the molded case breakers, contact wear results from abrasion while closing and from pitting due to the arc while opening. The condition of the contacts can be determined by measuring the contact resistance with a micro-ohmmeter, when the breaker is drawn out. A 4000 A, 480 V breaker in good condition should have a contact resistance of less than 30 micro-Ohms. The condition of the contacts can also be checked by infrared photography.

The operating mechanism requires greater attention, adjustments, and maintenance. Excessive pressure between the contacts would cause bending and misalignment. Inadequate pressure would lead to minute arcing and heating. Lubrication of the moving parts is the key to successful consistent operation of the breaker. Most manufacturers use red oil for both the current-carrying parts and the operating mechanism. As the breaker ages, the oil dries out and flakes off. There will then be metal-to-metal sliding, which wears out the surfaces and can cause misalignment. Eventually the breaker will “seize,” resulting in a failure to open or taking several seconds to open. This could be the beginning of a catastrophic failure unless there is an upstream backup breaker to clear the faulted condition. It is, therefore, essential to check out the mechanism, lubricate it, and exercise it on a regular basis. As with transformers, the useful life of power circuit breakers can be extended with preventive maintenance and testing. As a result, power circuit breakers are not normally included in the list of equipment to be replaced during renovation unless test results suggest otherwise or the breakers are antiquated and replacement parts become difficult to procure.

MV vacuum circuit breakers

In vacuum circuit breakers, the current-carrying contacts are encased in vacuum bottles.

Theoretically, current interruption should take place within one cycle. Practically, however, it takes two to three cycles to interrupt the current. Because of the reduced arcing due to the vacuum, the current-carrying contacts of the vacuum breaker should last longer than those in the air-break power circuit breaker. Because there are no arcing contacts, the entire vacuum bottle needs replacement when the contacts wear out.

The operating mechanism is similar to that of the air-break power circuit breaker. As in the case of the air-break circuit breaker, lubrication of the operating mechanism constitutes a limiting factor.

Therefore, the life of the vacuum circuit breaker is approximately the same as that of an equivalent air-break power circuit breaker.

Dry-type transformers and reactors

Dry-type transformers are used widely to supply lighting loads and other LV single- and three-phase loads. Reactors are used for short-circuit current limiting in situations where the potential short-circuit current exceeds the rating of the existing equipment. Reactors are also used as chokes in tuned harmonic filters and in the dc links of older variable frequency drives. Generally, they are dry-type using vacuum pressure impregnated insulation.

The first sign of degradation of insulation appears as discoloration of the bright yellow insulation due to the heat produced in the coils. The insulation becomes brittle and cracks, permitting ingress of moisture when it cools, which leads to further deterioration.

Eventually, failure occurs as short-circuits between the winding turns. The expected life of dry-type transformers and reactors is approximately 25 to 30 years. There are no known methods of determining the remaining life of an old transformer or a reactor. Therefore, the industry’s practice is to replace the equipment only after it equipment fails. While renovations are planned, these two types of equipment should not be included in the list of equipment to be replaced unless they are older than

30 years.

LV and MV cables

To a layman, what could be simpler than an electrical cable? It is a stranded aluminum or copper conductor wrapped with insulation and a weather-resistance jacket to give mechanical strength. Yet, manufacturing electrical power and control cables is a highly specialized industry. The assessment of a cable’s electrical integrity and the estimation of its remaining life are highly complex. A cable is a piece of equipment whose electrical integrity degrades rapidly and progressively while in service primarily due to the development of air and gas pockets or voids inside the insulation due to thermal expansion and contraction. The voids are the areas of high dielectric stress, which causes partial discharges

(minute arcing inside the void) that further degrade the insulation. Cable insulation degradation may be accelerated if the cables are immersed in water. Water submergence may produce water treeing within the cable’s insulation, which could result in insulation failure. It is a common occurrence for cables installed within underground duct banks to become submerged.

Measurements of the mechanical properties such as the jacket material hardness and loss of elongation retention do not indicate electrical insulation integrity. Electrical integrity of the cable is tested by Hipot tests and insulation resistance tests. Estimation of the remaining life of the cable based upon these measurements is questionable. The best conclusion that can be drawn is that, if the results are satisfactory, the cable is acceptable with no guarantee of future satisfactory performance.

Internal void formation is an indication of the degradation of the cable. The voids contain air or gases that are ionized. The void size increases due to the ionization. Therefore, the sizes of the voids indicate the age of the cable. One technique to determine the void size is acoustic spectroscopy. As the number and size of voids increase, the effective thickness of insulation to withstand the voltage decreases. The limit of equivalent thickness of insulation that is just enough to prevent failure is determined for each type of insulation by separate test. Using this information and the information about the number and size of the voids, the remaining life of the cable can be accurately predicted.

Electromagnetic protective relays

Older protective relays to provide overcurrent, overvoltage, reverse power, and other protective functions used the induction disk, induction cylinder, or beam-type construction. They depend upon a delicately balanced aluminum disk, aluminum cylinder, or a beam for their respective successful operation. (Because of this, they are generally unable to ride through seismic events.) Settings are adjustable by taps in the operating coil, the position of a braking magnet and length of travel of the moving contacts to meet the fixed contacts.

Most of the time, the relays are inactive. They are activated only when there is a fault. The useful life of the relay depends upon the number of times it is called upon to operate. The useful life of the electromagnetic relay is approximately 30 years. However, these relays are rapidly giving way to more versatile and infinitely adjustable microprocessor-based electronic relays. Electronic relays are more reliable than electromagnetic relays and can meet seismic withstand requirements. In addition, the need to be compatible with modern supervisory control and data acquisition systems at the facility has essentially made the electromagnetic relays obsolete. Therefore, when renovation is planned, the list of equipment to be replaced should include electromagnetic protective relays.

VFDs and UPSs

VFDs and uninterruptible power supplies (UPSs) are complex assemblies of several components such as power electronic devices, capacitors, inductors, integrated electronic circuits, and microprocessors, which have different aging characteristics. Theoretically, the useful life of the VFD is the least of the useful lives of the various components. Practically, however, the individual major components are modularized and can be replaced at fraction of the cost of a new VFD. Therefore, the useful life of the

VFD is determined by the useful life of the components that cannot be replaced.

In the past 40 years, VFD technology has advanced considerably. Older VFDs used silicon diodes, thyristors, and gate turn-off thyristors as the power devices and analog control circuits. Present-day

VFDs use insulated gate bipolar transistors and similar power devices that have low switching losses and can be switched faster. Control circuits are microprocessor based and energized by UPSs.

Instrumentation is by LED and LCD digital multifunction instruments. Most of the components are modular. Since VFD technology is evolving so rapidly, the unavailability of the replacement components determines whether the VFDs need to be replaced during system renovation.

Electric motors

Electric motors are generally considered to be robust pieces of equipment. However, because they are rotating, failures can be of electrical or mechanical origin. Electrical failures occur when the insulation fails to support the applied voltage and the expected voltage surges and spikes. Mechanical failures occur when the rotor becomes excessively eccentric due to uneven wear of the bearings.

Causes of the failure of electrical insulation are thermal aging, contamination, and vibrations that can cause cracks to develop in the insulation, abrasion of turn-to-turn (T-T) insulation due to electromagnetic forces between the turns, or overvoltages during operation and voltage spikes due to switching.

During the starting period, a cyclically varying squeezing action develops between the turns of each coil due to the electromagnetic force of attraction between parallel conductors carrying current in the same direction. This force causes abrasion of the enamel insulation between the turns in a random-wound machine and in the taped insulation between the turns in a form-wound machine. When the machine is new, the dielectric strength of the insulation between turns is 34 kV for a 4160 V machine.

Over time this strength reduces due to abrasion and contamination to a level that can cause a turn-to-turn failure. In approximately 20 years of operation, the chance of a turn-to-turn failure becomes very high. Switching of motors, capacitors, and other loads generates voltage spikes. When the motor receives a voltage spike with a high rate of rise, the line-end turns of the windings are electrically stressed more than the inner turns. Therefore, when the turn insulation has degraded, the spike is likely to cause a turn-to-turn failure in the end turns.

The question is: How do we assess the condition of the insulation? IEEE Standard 43, Recommended

Practice for Testing Insulation Resistance of Rotating Machinery, is a useful guideline. Three types of tests are performed to determine the condition of the motor insulation: the insulation resistance (IR) test, the polarization index (PI) test, and the surge test.

The IR test indicates the condition of the overall insulation to ground and does not indicate the condition of the insulation between turns or between phases.

The polarization index test is a high-voltage dc test for a period of over 10 minutes. A PI of 2.0 or more indicates healthy insulation. The plot of the current against the applied voltage should be a straight line. Any abrupt increase in the slope of the curve (an upward swing) indicates defective insulation.

The surge test is the only test that indicates the condition of the turn-to-turn insulation as well as the phase-to-phase insulation.

Mechanical damage is mostly due to bearing damage by a process called “fluting.” Fluting takes place due to the flow of currents in the shaft across the bearing. Slight magnetic dissymmetry at the two ends of the shaft causes a voltage to be induced electromagnetically in the shaft that tends to create current in the axial direction. The induced voltage in the shaft tends to pass current in the loop formed by the shaft, the two bearings and the motor frame. Insulating one of the bearings electrically would block the flow of the circulating current.

Voltage is also induced in the shaft electrostatically due to capacitance, albeit small, between the stator coil overhangs and the shaft. The electrostatically induced voltage becomes significant in case of motors driven by variable frequency drives due to the high frequency components of the motor voltage produced by pulse width modulation inverters. The thin film of lubricating oil or grease between the bearing rollers (or the balls) and the bearing race forms an insulation to block the flow of high-frequency circulating currents through the bearings.

The electrostatically induced voltage is generally higher than the electromagnetically induced voltage, and is adequate to cause dielectric breakdown of the film of the lubricating oil. A small arc is established between the rollers and the bearing race. This arc erodes the bearing race and causes a premature failure of the bearing. A shaft grounding brush can discharge the electrostatically induced voltage to ground and can prevent the arcing between the rollers and the race. Recently, a shaft grounding ring that has metallic microfibers has become available. Such a ring will last much longer and is a better method of grounding the shaft than the grounding brush.

- Peeran is senior technical specialist, and his experience includes LV and MV distribution systems, system analysis, harmonic analysis, large motors, and VFDs. He is a member of the Consulting-

Specifying Engineer editorial advisory board. Vecchiarello is senior VP and practice leader, and his experience includes design and construction services for water and wastewater treatment plants, airports, food processing industry, biotechnical and pharmaceutical industry, and military installations.

Romeo is principal and electrical group leader, and his experience includes design and construction services for water and wastewater treatment plants, renewable energy systems hazardous area classification, life safety systems, fire alarms, and security systems. All three are with Camp, Dresser

& McKee, and are members of IEEE.

What to add during renovation

While renovating an existing system, there is always some room for improvement. The following items are worth investigating.

Power monitoring systems (PMS): The cost of energy is a major item in the bottom line in most industrial facilities. The PMS, being always ON, provides valuable information 24/7 on the energy usage in the various areas of the facility as well as inadvertent outages, equipment shut down, and alarms. PMS also supplies information remotely from locations that are either not accessible or unsafe for personnel to visit.

Electronic multifunction relays: Even though the existing electromechanical relays are working satisfactorily, it is worthwhile to investigate the feasibility of replacing them with electronic relays for greater reliability, flexibility of adjustment, communications, and monitoring, as well as customized protection for motors. Some of the problems posed by the electromagnetic relays disappear with the electronic relays. The electronic relays have negligible burden on the current transformers (CT). High impedance relays are available to minimize the effects of CT inaccuracy and saturation in differential protection.

Zone selective protection: In a well-coordinated power system, the protective devices are set to trip after increasing time delays to allow the downstream devices to trip first. In a zone selective protection system, all devices are set to operate with the minimum time delay. The relay that detects the fault sends a restraining signal to the next upstream device. In the absence of the restraining signal, each device would trip at the end of the minimum time delay. This system is particularly applicable for sensitive ground fault protection.

Arc flash hazard labels: OSHA and NFPA 70E require arc flash labels. An arc flash study of the electrical system is required to create the appropriate labels to be affixed on the switchgear, switchboards, motor control centers, and panel boards. OSHA also requires that the arc flash study should be updated at regular intervals to account for changes and system modifications. The labels should be properly color-coded for easy identification of the required personal protective equipment category.

Arc detecting relays and arc-resistant switchgear: Arcing faults are difficult to detect and clear because of the lower current magnitude than in the case of “bolted” faults, resulting in delayed tripping. Some electronic relays are now available that can detect arcing faults optically and open the breaker immediately. Optical detection is done by an optical diffuser appropriately placed inside the switchgear or by a bare plastic fiber-optic cable laid in the switchgear. The detecting system is continually monitored by injecting light pulses created by a LED transmitter internal to the relay.

Many companies now offer arc-resistant LV and MV metal-clad switchgear. In this type of switchgear the expanding hot gases created by an arcing fault inside the switchgear are routed through vents and flaps to the top of the switchgear, away from the front doors, the sides, and rear of the switchgear.

The internal pressure is released by the vents and the flaps, and the likelihood of the doors blowing open is reduced.

Mimic panels for remote operation of switchgear: In many MV switchgear installations, the arc flash hazard cannot be reduced to safe levels. In such cases, remote operations are made possible by mimic panels. Remote racking in and out of breakers is possible by the motorized racking mechanism.

Remote opening and closing of the breaker is possible by locating the breaker control switch in the mimic panel. Panel meters, power monitoring equipment, ON/OFF indicating lamps, and lock-out relays can be located in the mimic panel. The mimic panel can be located remotely either in the switchgear room or in the control room.

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Inertaire® Oil Preservation Systems Installation, Operation, & Maintenance Guide Types RN_ _ IZUA 7633-210en

ABB 15

Figure 10: Typical nitrogen cylinder dimensions for which RNC and RND enclosures are designed to accept. The cylinder is not included with the standard system but may be purchased separately.

Using a similar process, attach the other two elbows to the transformer gas space couplings. The tubing ends should point downward.

The tube fittings come preassembled finger-tight. Insert the tube into the fitting. Make sure that the tubing rests firmly on the shoulder of the fitting and that the nut is finger tight. Scribe the nut at the 6 o-clock position. While supporting the body of the fitting with a back-up wrench, tighten the nut 1.25 turns, watching the scribe mark make one complete revolution and continue to the 9 o-clock position. Repeat this process for each of the four tube connections.

Secure the tubing along its path with supports and hardware as shown in Figure 8.

2.3.C. Connect electrical leads and run wiring.

Consult transformer controls wiring diagram for specific con-nections in the transformer’s control scheme. A schematic diagram of the standard Inertaire® system alarms and other electrical equipment is shown in Figure 9.

1. Cut one or more holes in the enclosure to accommo-date the cable or conduit fitting(s) required. Refer to Figures 6 & 7 for suggested location.

2. Install fitting(s) (not included) into the hole(s) and install the wiring.

3. Connect leads to the appropriate terminals on the 12-point terminal block.

4. For RN_2 units:

a. Connect the 120 V Line, Neutral, and Ground leads to the appropriate points on the 6 point terminal block.

b. The utility switch is wired to terminal block points 10, 11, and 12, and may be connected to suit.

Two 0.25 inch (6.4 mm) diameter holes along the lower edge of the "Active Part" can be used to secure wiring with wire ties.

CAUTION

Do not use a low voltage bell ringer when checking the alarm circuits; this could exceed the interrupting ratings of the contacts and may damage the contacts. An indicating light device is best for checking the circuits. Figure 9 lists the interrupting ratings of the alarm contacts.

3. Operation (all units)

3.1 Replacing/connecting a nitrogen cylinder

When the pressure in the cylinder is below 100 psi (689 kPa) it should be replaced with a full cylinder of nitrogen. The nitrogen used should comply with the requirements of the transformer manufacturer, however the following guidelines are provided for reference:

Cylinder Dimensions:

Capacity 200 ft3 [5.66 m3]

(2200 psi @ 70° F) [15,168 kPa @ 21° C] Height: 55 in [1397 mm] Diameter: 9 in [229 mm] Weight: approx. 140 lbs [63 kg]

16 ABB

Valve Connection: CGA 580 Female Purity: max impurities 0.20% by volume Moisture: Dew Point of -55° C [-67° F] or lower Oxygen Content: Maximum 0.20% (2000 ppm) by volume

WARNING

Always follow this sequence of steps when replac-ing a nitrogen cylinder. Failure to do so may cause equipment damage or severe personal injury.

This procedure covers the complete process of replacing a nitrogen cylinder; for installation of the initial cylinder begin on step 5.

1. Close the valve on top of the installed nitrogen cylinder by turning clockwise (CW).

2. Close the Inertaire® system’s Outlet Valve (CW) to the limit to isolate the transformer gas space from the regu-lator system.

3. Slowly loosen the connection between the nitrogen cyl-inder and the Inertaire® system’s High Pressure Hose by turning the union nut counter-clockwise (CCW). A small amount of gas should escape from the fitting. Pro-ceed to detach the hose fitting from the cylinder and secure the hose out of the way. If the hose will be left disconnected for more than a few minutes, install a dust cap to prevent entry of dirt or moisture into the system until the new cylinder is ready to install.

4. Release the cylinder strap, swing it out of the way, and remove the cylinder. Install the cylinder valve’s protec-tive cap.

5. Verify that the Bypass Valve is closed (CW), so that gas will be directed through the Low Pressure Regulator.

6. Remove the protective cap from the full nitrogen cylin-der, and position the cylinder in place. Secure the cyl-inder with the strap and store the cylinder’s protective cap in a safe, convenient location.

7. Be sure the cylinder valve is free of dirt. A good proce-dure is to briefly open the cylinder valve slightly (CCW) to allow any contamination lodged in the valve to be blown out.

CAUTION

Point the opening of the valve away from personnel in the area to avoid injury from a high pressure gas stream or from blowing particles.

8. Connect the high pressure hose to the cylinder tightening the union nut only hand tight. Slowly open the cylinder valve slightly and allow the gas leaking out of the connec-tion to blow off any fine dirt. Tighten the union nut with a 1-1/8 inch wrench until the gas leak stops; then open the cylinder valve (CCW) to the fully open position.

9. Briefly open the drain cock on the bottom of the Inertaire® system’s sump by turning the wings counter-clockwise (CCW). When only dry gas exits the sump, close the drain cock (CW).

10. Open the Outlet Valve (CCW) to its limit. The system may operate to stabilize the gas space pressure within its range.

Monitor the pressure/vacuum gauge to see that an ac-ceptable level is reached.

The unit is now in “Operating Configuration”.

3.2 Adjusting the 2nd Stage Output Pressure and Testing

the Pressure Relief Unit.

This procedure may be performed as part of routine mainte-nance to verify proper operation of the equipment. The in-structions assume that the system is set in the “Operating Con-figuration” as defined in section 3.1.

1. Read the nameplate inside the Inertaire® system to deter-mine the preset value for the Pressure Relief Unit (stan-dard setting is +6.5 psi (44.8 kPa)).

2. Close the Outlet Valve (CW to limit).

3. Open the Bypass Valve (CCW to limit).

4. Release the 1/2 inch jam nut on the high pressure regulator’s T-handle. While watching the pressure/vacuum gauge, turn the T-handle clockwise slowly to increase the pressure. Gas should begin escaping from the Pressure Relief Unit within +/- 0.5 psi (+/- 3.4 kPa) of the setpoint value.

CAUTION

Opening the cylinder valve should be done very slowly to avoid damage to the valve seat. Always backseat the open valve with the same force that would be used to close the valve. Failure to ob-serve these precautions may cause equipment damage or personal injury.

ABB 17

If the Pressure Relief Unit does not operate at the correct value, adjust it with a 5/64 inch (0.078 inch) Allen wrench through the hole in the center of the unit’s face. Labeling and arrows on the unit show proper direction.

5. Turn the regulator T-handle counter-clockwise (CCW) to reduce the pressure to its setpoint (+5.0 psi [+34.5 kPa], standard). Excess pressure may be bled by briefly opening the sump’s drain cock and watching the pressure/vacuum gauge stabilize.

6. Close the Bypass Valve (CW).

7. Open the Outlet Valve (CCW).

The unit is now back in “Operating Configuration”.

3.3 Purging the Gas Space

Some transformers are shipped with dry air in the gas space rather than nitrogen to allow breathable gas be present for a technician to attach internal leads and perform other commis-sioning activities. When the transformer has been prepared for operation, the Inertaire® system may be used to purge the gas space with nitrogen. Follow the instructions provided by the transformer manufacturer for filling the transformer with oil and gas.

The following procedure may be used generally to purge the gas space. The instructions assume that the system is set in the “Operating Configuration” as defined in section 3.1. Also verify there is adequate nitrogen pressure in the cylinder be-fore beginning the procedure.

1. Close the Outlet Valve (CW).

2. Open the Bypass Valve (CCW).

3. Verify the pressure within the sump is +5.0 psi [+ 34.5 kPa].