2022 GJ VA Combined Triennial Electrical Report.pdf

Project Report

January – May 2022

Electrical Testing & Maintenance ProjectElectrical Testing & Maintenance Project

CoverCover

Veterans Affairs Medical Center Grand Junction, Colorado

CoverCover in cooperation with

Slocum & Associates

337 Sundance Trail

Liberty Hill, Texas 78642

P - (512)484-5594

845 Long Branch Circle

Sugar Hill, Georgia 30518

P - (678)546-9393, F – (678)828-5903

Contract No. 36C25922P006

Electrical Testing & Maintenance Project Contract No. 36C25922P006

Veterans Affairs Medical Center

Grand Junction, Colorado January – May 2022

Section 1 Executive Summary

Section 2 Publications/Exhibits

Section 3 Electrical Test Records

Section 4 Grounding System Evaluation

Section 5 Thermographic Report Section

Section 6 System Voltage Evaluation

Section 7 Phase Rotation Evaluation

Section 8 Generator Load/Capacity Evaluation

Table of Contents

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Electrical Maintenance & Testing Report Summary

General

SDV Services Inc. provided electrical testing and maintenance services at the Veterans Affairs Medical Center in Grand Junction, Colorado on January 4-7, 2022 and May 12-15, 2022 under contract no. 36C25922P006. All services were conducted in accordance with contract specifications, industry standards, NETA/ANSI MTS 2015 guidelines and manufacturer’s recommendations.

The types of equipment tested during this testing session included:

Medium Voltage Substation

Medium Voltage Sectionalizing Switches & Termination Compartments

Medium Voltage Oil-Type Transformers

Low Voltage Switchboards with Enclosed Circuit Breakers

Automatic Transfer Switches

Disconnect Switches

Motor Control Centers

Low Voltage Dry-Type Transformers

Panelboards

Solar Inverters, Power Factor Correction Capacitors

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 Grounding System Evaluation

Section 5 Thermographic Report Section

Section 6 System Voltage Evaluation

Section 7 Phase Rotation Evaluation

Section 8 Generator Load/Capacity Evaluation

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Previous Testing Project – Action Steps

The 2017 testing project report identified several areas of concern for which positive action steps or corrective action have been taken by the VA staff. Those steps are briefly described below:

1. Switchboard or Distribution Panel Replacement – due to age and condition the following switchboards or distribution panels were replaced:

a. Building 1 North – switchboard MSA and distribution panels DPQ, DPC and DPLS.

b. Building 9 – switchboard 9-ECP

c. Building 20 – main switchboard

The previously noted issued raised significant question as to the ability of these systems to provide safe and proper protection of the electrical system.

2. Protective Device Selective Coordination – providing a selectively coordinated electrical system was incorporated into the arc flash hazard analyses outlined in the scope of work for the current testing project. Previously, the overwhelming majority of protective devices were set at factory minimum default settings with the potential for nuisance trips or a fault not clearing at the lowest possible level within the electrical system.

The selective coordination study was an integral part of the existing arc flash hazard analyses. Protective devices were selectively coordinated wherever possible to create a balance between clearing faults at the lowest possible level within the electrical system as well as providing for manageable arc flash incident energy levels and related personal protective equipment (PPE).

3. Transient Voltage Surge Suppression (TVSS) – there was a tremendous improvement in the installation of TVSS systems designed to protect sensitive electronic equipment from surges related to power shifts and lightning strikes.

4. Transformer T-6 (NRAD) - aged transformer with an oil leak as well. Transformer was replaced.

5. Emergency Equipment Markings – a considerable effort was noted to incorporate white lettering on red identification tags making the emergency equipment components readily identifiable as being a part of the emergency system.

6. Low Voltage Dry-Type Transformer Disconnects – disconnect switches were added to comply with National Electric Code (NEC) requirements to have a means of disconnect within sight of the transformer.

7. Lack of Updated Electrical Drawings – drawings have not been updated for many years in spite of significant system changes. The current project incorporates an update of the electrical drawings. The updated drawings can be used to update lockout/tagout procedures providing a safer operating environment for maintenance personnel.

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Overall, the result of these efforts is a greatly improved overall system reliability and significantly less issues noted during the current testing session.

Findings & Recommendations

Outlined below are issues or observations with related recommendations noted during this testing session.

1. Electrical System Age & Condition

Issues

As noted above, there are or have been recent electrical system upgrades in this facility designed to provide a safer and more reliable environment for the buildings and their occupants. However, there are a couple of areas containing equipment in fair to poor overall condition and exceeded their useful industry service life 25 years of age and the 15-year service life outlined in the VA Electrical Design Manual reference below.

VA Electrical Design Manual Reference

1.15.4 AGE AND PHYSICAL CONDITION

(b) The equipment should be capable of remaining in use for a minimum of 15 years of additional life or having 60 percent of remaining life, if not the equipment shall be replaced.

Primary Condition Issues

Those areas and equipment considered to be the primary target areas for replacement or upgrade are as follows:

Building 13 Basement Equipment – switchboard 13-MDP and related capacitor bank, located in the basement of this building, are located in less than ideal conditions. This area is heavily dependent on steam that bleeds out into the room and penetrates the equipment. The related moisture penetration into the equipment impacts system reliability leading to a reduced service life.

Additional issues were noted with specific components of the electrical system and are documented further down in the summary.

Supplemental Notes on Equipment Aging

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, SDV 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

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

Additionally, the Publications section of this report contains a Square D publication concerning placing electrical equipment in adverse environments with guidelines for properly protecting such equipment.

Recommendation

Due to the condition, age and obsolescence of the above-referenced systems, the following corrective action should be taken:

Building 13 Basement Equipment – the condition of the 13-MDP panel and the capacitor bank should be monitored for worsening conditions related to the effects of steam and moisture penetration. Corrosion of the internal components of 13-MDP is the key area to monitor. A Facilities Condition Assessment (FCA) code of “C” should be applied to this equipment.

2. Adverse Conditions – Outdoor Conditions

Issue

The MDP panels and automatic transfer switches (ATS) for buildings 8, 33, 35 and 36 are located on the exterior of these buildings protected only by their basic enclosures reflected in the picture to the right. Even though the MDP panels are NEMA 3R enclosures rated for outdoor usage, the enclosed circuit breakers in these MDPs are exposed to abnormal ambient operating temperatures that can lead to internal grease hardening. This can cause the circuit breaker to either fail to open or be delayed in opening in response to a fault with the potential for a catastrophic failure. A delayed response in opening (seconds versus cycles) can lead to a sustained arc while failing to open can lead to a fire. Both have the potential for a catastrophic failure if left uncorrected.

The same grease hardening conditions can cause the transfer switch motors to burn out while attempting transfer operations. This can directly impact the ability of the transfer switches to properly and safely transfer to and from emergency power with the potential for a total power loss to downstream circuits.

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Additionally, the recently-installed ATS for building 45 as well as the main circuit breaker for 2MDP for building 1 South have been placed outside without any additional protection from the elements. Pictured to the right is the 2MDP Main Breaker already showing abnormal dirt/debris accumulations. This dirt/debris is beginning to penetrate the circuit breaker that can directly impact its ability to respond in the event of a fault. The same concerns outlined above with grease hardening come into play for this circuit breaker. There are no heater strips, etc. to offset abnormal temperatures as well as moisture.

Finally, room 1215 of building 1 South containing switchboard EDP-1 and the ATS’ has open louvres to the outside creating the same conditions noted above in relation to dirt/debris.

The room has a thermostatically-controlled heater but was not operating leading to abnormal temperatures.

Recommendation

Ideally, the outdoor equipment should be relocated indoors. In the event this is not feasible, an exterior protective shell should be placed around the above-referenced buildings MDPs and ATS’. This shell should contain a conditioned air system to ensure the enclosed equipment operates in a stable temperature range to ensure a proper response in the event of a fault.

Room 1215 in building 1 South needs to have the open louvres sealed off from the outside air.

The installed heater needs to be checked to determine why it is not functioning and either repaired or replaced.

Until this action is taken, above-referenced outdoor enclosures as well as room 1215 of building 1 South should be cleaned and enclosed circuit breakers exercised every 6 months.

This should help to reduce or minimize the effects of dirt/debris accumulations and ensure the internal grease does not harden preventing proper operation of the circuit breakers.

Additionally, the publication section contains a Square D publication called “Electrical Equipment and Components in Adverse/Corrosive Environments” outlining provisions for protecting electrical equipment from such conditions.

3. 8-MDP Enclosure Voids

Switchboard 8-MDP (outside, building 8) was found with a gap around the base of the enclosure as pictured to the right. This gap can enable rodents, etc. to penetrate the enclosure with the potential to initiate a fault within the switchboard leading to a total power loss to downstream circuit.

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Recommendation

A seal needs to be placed over the 8-MDP opening to prevent rodent penetration.

4. Transformer Pressure Gauges/Negative Pressure

Transformer T2 does not have oil-tank pressure gauges installed and the pressure status of the tank could not be determined.

Pressure gauges are designed to indicate whether the transformer has negative, neutral or positive pressure in the oil tank. Of great importance is where a transformer has negative pressure as obtaining oil samples on these transformers 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 to +7.5 psi.

Recommendation

A pressure gauge valve assembly needs to be installed in transformer T2. A nitrogen blanket needs to be installed over the oil in the tank to a manufacturer-recommended positive pressure.

It should be noted the Grounding Transformer could not be shut down and serviced/adjusted due to the way it is tied into the utility grid and relaying system.

5. Transformer Enclosure Condition

The enclosures for transformers T-4, T-6 and T-8 have mild to moderate levels of corrosion with deteriorating paint. T- 4 is in the worst condition as pictured to the right.

Additionally, transformers T-6, T-7 and T-10 have concrete pads placed at grade level and do not have their enclosure bases sealed as represented by the picture to the right.

These conditions enable water and debris to freely flow into their enclosures that will lead to corrosion and premature failure of the enclosures.

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Transformers T-4, T-6 and T-8 need to treated with a rust-inhibiting paint such as Rustoleum that chemically bonds the existing corrosion with the newly applied paint. T-4 should first be scoured with a wire brush to remove any large corrosion deposit for the best possible results.

Transformers T-6, T-7 and T-10 need to have trough dug around the base and filled with crushed gravel to minimize the ability of water to penetrate these enclosures. The work done around the pad for T8 (buildings 35/36) is an example of how these concrete pads should be re-worked. Future installations need to specify a concrete base at a minimum of a 6” above grade level. The base of these transformers and all other outdoor enclosures need to be sealed with a silicone caulk or equivalent to prevent water/debris from penetrating the enclosure.

6. Transformer Oil Test Results

Oil samples were obtained from the medium voltage oil transformers in the facility and sent to a test laboratory for dissolved gas analysis (DGA) among other tests reported in tab 3 to this report. All test results were found to be normal with the exception of transformers T6 (NRAD), T8, T10 and T12 showing high levels of ethane gas (C2H6). These transformers use FR3 insulating oil where elevated levels of ethane gas are present and considered normal provided other hydrocarbon gas levels are low. In this case, those other gas levels were normal and ethane gas levels are not an issue.

Recommendation

No further action is required beyond continuing to trend current oil test results against future testing sessions looking for an early warning sign of potential transformer issues.

7. Transformer Oil Leak

The oil level for transformer T8 (buildings 35 & 36) was found to be slightly low. A small leak was discovered around the bushings.

Recommendation

The oil leak was corrected by SDV personnel during the scheduled power outage. The remaining oil level was found to be adequate. No further action is required.

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8. Transformer High Temperature Indicators

During the data gathering phase for the arc flash study, the new NRAD transformer (T6) for building 1 North was found with the high temp indicator off scale on the high temp side. It is unclear if this was related to a true overtemperature condition or of the indicator was inadvertently shifted into that position.

Additionally, during the testing phase, transformer T-9 (Boiler Plant) was found with a high temperature reading of 130C or roughly 45 over the manufacturer’s temperature rise limit.

Again, it was unclear if this was a true reading or had been inadvertently shifted into that position.

Finally, transformer T7 (building 1 North) has a defective high temperature indicator.

When the oil sample for T6 was obtained during the scheduled testing session, the high temperature indicator was found in the normal operating range. This leads us to believe the indicator had simply been inadvertently shifted off scale.

However, the same could not be determined for transformer T-9 as the high temperature reading was not noted until the testing session. This transformer should be monitored on a weekly basis for several weeks to determine if there is an internal issue resulting in a true overtemperature condition. If at any time an overtemperature reading is noted, a company regularly involved in transformer evaluations and repairs should be contacted as soon as possible to perform an evaluation to determine the cause and provide corrective action. Lack of corrective action could lead to a catastrophic failure of the transformer.

A positive sign is that both transformers produced normal oil test results that typically will provide some indication of an abnormality or issue with the transformer.

Replace the transformer T-7 temperature gauge.

9. Improper Working Clearance

Switchboard 1MDP (building 1 South) and 45MDP (building 45) have been placed directly against the wall represented by the picture to the right.

National Electric Code section 110.26(A)(1) requires a minimum 30” working clearance outlined below.

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NEC Reference 110.26(A)(1)(a) Dead-Front Assemblies

(a) Dead-Front Assemblies. Working space shall not be required in the back or sides of assemblies, such as dead-front switchboards or motor control centers, where all connections and all renewable or adjustable parts, such as fuses or switches, are accessible from locations other than the back or sides. Where rear access is required to work on nonelectrical parts on the back of enclosed equipment, a minimum horizontal working space of 762 mm (30 in.) shall be provided.

NEC Reference Exhibit 110.9

Distances measured from the live parts if the live parts are exposed or from the enclosure front if the live parts are enclosed. If any assemblies, such as switchboards or motor-control centers, are accessible from the back and expose live parts, the working clearance dimensions would be required at the rear of the equipment, as illustrated. Note that for Condition 3, where there is an enclosure on opposite sides of the working space, the clearance for only one working space is required.

There are bus connections located in the rear of the enclosure that cannot be serviced from the front as they are blocked by other installed equipment (circuit breakers, support structures, secondary conductors, etc.). Any attempts to service these connections as well as clean the rear portion of the enclosure from the front would require extensive disassembly of circuit breakers and secondary conductors that clearly is not the intent of the manufacturer or the NEC.

There appears to be confusion and misapplication related to installation guidelines of similar “dead-front switchboards” throughout the country based on our findings. The National Electric Code (NEC) defines “dead front” as “without live parts exposed to a person on the operating side of the equipment.” The recently-installed main low voltage switchboard located in the basement of the building is a “dead-front switchboard” based on this NEC definition. Operating personnel are protected from the energized components when covers are in place. However, this definition makes no reference to working space requirements.

NEC section 110.26(A)(1)(a), Dead-Front Assemblies (outlined below) uses this definition and applies other qualifying factors or elements in determining working spaces around such assemblies. Those factors or elements are:

1) Connections,

2) Renewable or adjustable parts, such as fuses or switches, and

3) Accessibility from locations other than the back or sides.

Additional clarification regarding work space requirements is provided in Exhibit 110.9 further down in NEC Section 110.26(A)(1)(a). It states, “If any assemblies, such as switchboards or motor-control centers, are accessible from the back and expose live parts, the working clearance dimensions would be required at the rear of the equipment.” The switchboard in question does have covers providing rear access that expose the switchboard bus components. This installation clearly meets these conditions requiring a minimum 30” horizontal working space.

Switchboard 1MDP needs to be relocated to provide the minimum 30” horizontal working distance as required by NEC Section 110.26(A)(1)(a). This is necessary to facilitate proper maintenance and servicing of the bus and other components of the switchboard to include

10 | P a g e cleaning. Until this is accomplished, consideration should be given to performing annual infrared inspections of this switchboard.

Ensuring proper working clearances are maintained needs to be a point of emphasis for future switchboard installations.

10. Combustible Material

Panels EMEQ and EMCR (rm. 1215, building 1 South) were found with particle board barriers (combustible material) as pictured to the right. These were apparently installed in an effort to shield the enclosed conductors from accidental contact by personnel. Such combustible materials are specifically prohibited by National Electric Code sections 110.27 and 408.50 outlined below.

NEC Reference.

110.18 Arcing Parts.

Parts of electrical equipment that in ordinary operation produce arcs, sparks, flames, or molten metal shall be enclosed or separated and isolated from all combustible material.

NEC Reference.

408.50 Panels.

The panels of switchboards shall be made of moisture-resistant, noncombustible material.

The particle board barriers need to be replaced by a manufacturer-approved barrier to properly and safely guard the enclosed conductors.

11. Thermographic (Infrared) Scan Issues

Seven (7) thermal issues were noted during the infrared scan of the electrical systems for this facility. Issues were primarily due to either high internal resistance or loose connections.

Each issue and related recommendation are summarized by location in Attachment A following this summary and is fully reported on in section 5 to this report.

High internal resistance is common in electrical panels where breakers don’t get exercised.

The breaker contacts begin to weld shut increasing resistance while drawing more current that can lead to overheating with the potential for nuisance trips.

Of special note were the noted issues related panel PVEL1.1 in the outside solar array for building 1 North. This panel was found with several loose line side connections leading to overheating of the breaker and bus connections. The extent of the overheating and resultant damage is unknown requiring additional inspection.

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With the exception of panel PVEL1.1, all loose connections were corrected on the spot by Slocum/SDV personnel.

Each breaker identified with high internal resistance was exercised at least six (6) times to wipe the contacts during the scheduled power outages. These breakers should be monitored and replaced if nuisance trips develop.

Panel PVEL1.1 needs to be de-energized. Remove breakers that have been overheated and inspect for damage requiring the breakers and/or bus segments to be replaced. All connections need to be tightened per manufacturer’s recommendations.

12. 4-Hour ESS

The 4-hour ESS Test was performed on May 14, 2022 in accordance with guidelines established by NFPA 110 and VHA Directive 1028. Below is the timeline for completion of this phase of the project:

a) Outage was initiated at 8:00 Am by Excel Energy turning power off to the facility.

b) All generators were reported as starting properly and all transfer switches transferred to the emergency position.

c) No reports of equipment problems were reported by VAMC personnel.

d) Slocum/SDV had technicians standing by to help with any equipment problems. No problems were reported by VA personnel.

e) After one hour of the facility being on emergency power only, VA personnel had not requested assistance nor were any equipment problems reported by VA personnel.

f) After two hours of the facility being on emergency power only, VA personnel had not requested assistance nor were any equipment problems reported by VA personnel.

g) After three hours of the facility being on emergency power only, VA personnel had not requested assistance nor were any equipment problems reported by VA personnel.

h) After four hours of the facility being on emergency power only, VA personnel had not requested assistance nor were any equipment problems reported by VA personnel.

i) At this time, 12 Noon, the 4-hour requirement had been met and all power was restored to the facility.

j) All transfer switches transferred back to normal power and all generators went through normal cool down and shutdown.

k) During the entire utility outage, no problems were reported by VA personnel and no requests for assistance were made of Slocum personnel.

Supplemental Evaluations

In addition to normal testing procedures, supplemental evaluations were outlined in the scope of work. These were designed to provide further insight into the overall health and condition of the facility’s electrical system. Each evaluation has been fully documented, with findings and recommendations (where applicable), in the following sections to this report:

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1. Section 4 - Grounding System Evaluation

2. Section 5 – Thermographic Report

3. Section 6 - System Voltage Evaluation

4. Section 7 - Phase Rotation Evaluation

5. Section 8 - Generator Load/Capacity Evaluation

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

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Attachment A. Thermographic Report Summary

▪ Bldg. 1 South, Rm. 1222, Panel 1N1D3 - Circuits 24 & 26 have high internal resistance based on Voltage Drop Test results.

▪ Bldg. 1 South, Rm. 1222, Panel 1EQ1D - Circuit 32 was found to have a loose secondary connection.

▪ Bldg. 1 North, Solar Array, Panel PVEL1.1 - This panel had numerous issues related to defective connections and high internal resistance.

▪ Bldg. 1 North, Rm. 1690, Panel ANL1 Section 2 - Circuits 56 & 58 have high internal resistance based on Voltage Drop Test results.

23.3

36.4 °C

23.2

34.7 °C

6.5

20.4 °C

23.5

30.4 °C

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▪ Bldg. 1 North, Rm. 2638, Panel LP3 - Circuit 4 was found with a loose secondary connection.

▪ Bldg. 6, Main Electrical Closet, Panel 6L2-1 - Circuits 40 & 42 were found with a loose secondary connection.

▪ Bldg. 1 South, Rm. 1222, Panel 1N1D3 - Circuits 24 & 26 were exercised during the scheduled power outage. No furher action required.

▪ Bldg. 1 South, Rm. 1222, Panel 1EQ1D - Circuit 32 connection was inspected and corrected on the spot by Slocum personnel. No further action required.

▪ Bldg. 1 North, Solar Array, Panel PVEL1.1 - Panel needs to be de-energized. Bus side connections need to be inspected for serviceability. Repair or replace defective connections.

Exercise all breakers at least six (6) times to ”wipe” the contacts. Replace breakers if nuisance trips develop.

▪ Bldg. 1 North, Rm. 1690, Panel ANL1 Section 2 - Circuit 56 & 58 were exercised during the scheduled power outage. No furher action required.

▪ Bldg. 1 North, Rm. 2638, Panel LP3 - Circuit 4 secondary connection was inspected and corrected on the spot by Slocum personnel. No further action required.

▪ Bldg. 6, Main Electrical Closet, Panel 6L2-1 - Circuits 40 & 42 secondary connections were inspected and corrected on the spot by Slocum personnel. No further action required.

23.7

29.9 °C

20.5

35.8 °C

Electrical Maintenance & Testing Project, Contract No. 36C25922P006 Veterans Affairs Medical Center – Grand Junction, Colorado

Publications Cover

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)

▪ “Electrical Equipment and Components in Adverse/Corrosive Environments” by

Square D, September 2004

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.