Arc-Flash Study 2016.pdf

6324 N. Chatham Ave, Suite 155 Kansas City, MO 64151 Office: 816-550-4557 / Fax: 888-824-6640

PROJECT SUBMITTAL

PROJECT NAME:

PROJECT NUMBER:

SUBMITTAL NUMBER:

SUBMITTED TO:

Correct Deficiencies Bldg. 40

589-10-204

12/8/2016

Larry Stoss

H. W. Lochner, Inc.

2335 East Crawford Strett

Salina, KS 67401

260573 Resubmittal of Resubmittal of Coordination Study - Submitted by Schneider

For Approval

Lauren Bellm

NOTES:

SUBMITTAL DATE:

SUBMITTED TO:

ITEM ACTIONDESCRIPTION

By:__________________________________ L & J Building Company, LLC

SPEC SECTION

PROJECT NO.

DATE NO EXCEPTIONS TAKEN

BY MAKE CORRECTIONS NOTED

FOR Lochner AMEND AND RESUBMIT

REJECTED-SEE REMARKS

NOTE:

REVIEW DOES NOT RELIEVE THE CONTRACTOR FROM ANY

RESPONSIBILITY FOR ERRORS OR DEVIATIONS FROM THE

CONTRACT REQUIREMENT OR FOR ANY DEFICIENCIES OF

EQUIPMENT, WORK OR MATERIALS.

10632 12/19/2016

LWS

Printed copies uncontrolled Corey Jasper

2016.12.07 11:04:45 -06'00'

Power System Engineering

December 2016

DISCLAIMER

The following report was prepared by the Power System Engineering group of Schneider Electric Engineering Services, LLC (SEES) utilizing industry-accepted standards and practices along with the proprietary methodologies and analysis tools of SEES. Data used in this analysis was acquired by Power System Engineering and provided by others, through onsite discovery, published information, equipment nameplates, manufacturer ratings, testing, analysis, or other means. SEES assumes no responsibility for inaccuracies in data provided by others. The study is intended for use by qualified individuals to facilitate the installation, operation, maintenance, and safety of the electrical power system depicted. Modification of equipment, changes to system configuration, adjustment of protective device settings, or failure to properly maintain equipment may invalidate these results.

The stylized trademarks “Square D” and “Schneider Electric” and any other trademarks and trade names that are the property of Schneider Electric USA, Inc are used by permission.

TABLE OF CONTENTS

1 EXECUTIVE SUMMARY

1.1 Overview

1.2 Revision History

1.3 Study Highlights & Important Findings

1.3.1 Short-Circuit Results

1.3.2 Coordination Results

1.3.3 Arc Flash Results

2 INTRODUCTION

3 STUDY DATA

3.1 Power Company Data

3.2 Generator Data

3.3 Estimates & Assumptions

4 SHORT-CIRCUIT ANALYSIS

4.1 General Procedure

4.2 Data Used in the Calculations

4.2.1 Power Company Data

4.2.2 Generator Data

4.2.3 Cable Data

4.2.4 Transformer Data

4.2.5 Motor Contribution to Short-Circuit Current

4.3 Short-Circuit Analysis Results and Recommendations

4.4 Short-Circuit Evaluation Table

5 OVERCURRENT DEVICE COORDINATION ANALYSIS

5.1 General Procedure

5.2 Specific Procedure

5.2.1 Short-Circuit Current Considerations

5.2.2 Molded Case Breaker Coordination

5.2.3 Time-Overcurrent Relay Coordination

5.2.4 Low-Voltage Ground-Fault Relay Settings

5.2.5 Transformer Protective Devices

5.2.6 Selective Coordination and the National Electric Code

5.3 Analysis of Results and Recommendations

5.3.1 TCC Plot Remarks

5.4 Overcurrent Device Setting Table

5.5 Time-Current Coordination Graphs - Recommended Settings

6 ARC FLASH HAZARD ANALYSIS

6.1 General Procedure

6.2 Specific Procedure

6.3 AF Hazard Analysis Results and Recommendations

6.3.1 Common Arc Flash Hazard Table Terms

6.3.2 Protective Arc Rated (AR) Clothing Characteristics

6.3.3 Arc Flash Hazard Analysis Table – Recommended Settings

APPENDIX A: ABBREVIATIONS AND TRADEMARKS

APPENDIX B: SHORT CIRCUIT INPUT/OUTPUT DATA

APPENDIX C: REFERENCES

APPENDIX D: SYSTEM STUDY ONE-LINE DIAGRAM

1 EXECUTIVE SUMMARY

1.1 Overview

This report documents the results of a Power System Engineering analysis for the VA Medical Center in Kansas City, MO. The objective of this section is to briefly summarize the results of the analysis and highlight key issues and findings in the electrical distribution equipment. For items addressed by equipment, conductor, or device settings changes, the power system study results may need to be re-evaluated in a revision to this study. The full analysis can be found in the main body of the report.

The scope of the short circuit and coordination studies are limited to the new equipment as marked on Page 1 of the one-line diagrams in Appendix D.

The scope of the arc flash evaluation is limited to all equipment represented in the one-line diagrams in Appendix D.

1.2 Revision History

This section will document revision history after the initial study has been submitted. Subsequent revision numbers are each listed on the front cover of the report and are explained below by indicating the following details: date of issue, reason for revision, and who initiated the revision.

When necessary, engineer’s comments and/or pertinent emails will be referred to in the references section of the report.

Revision 2 (December 6, 2016) This revision includes short-circuit values on the one-line in Appendix D.

Revision 1 (November 4, 2016) This revision reflects changes to the arc flash evaluation section and the system one-line as shown in Appendix D with the addition of equipment from existing power system studies on connected electrical systems. In addition, changes to the cable lengths are made according to updated cable data as shown in Appendix C. Changes are listed below:

1. Equipment downstream of transformers T-B1W-T8, T-10, T7 (T-B6), TBIO SC (T-12), T11, T-B1E-T9, T-B15-T15, and T-B26A and downstream of GEN-19 are represented if included in past studies performed by Schneider Electric Engineering Services. Data from past studies were used for all equipment represented in the one-line diagrams in Appendix D.

2. Cable type and sizes were changed according to the cable lengths presented in Appendix C, from 100A MSS or 100B MSS to downstream transformers.

1.3 Study Highlights & Important Findings

1.3.1 Short-Circuit Results

Of the 4 device locations evaluated for adequacy to interrupt or withstand the maximum three-phase short-circuit current to which they could be subjected, none were identified to be

INADEQUATE.

1.3.2 Coordination Results

Setting recommendations have been made for adjustable devices to ensure optimum selectivity, reduce arc flash, or protect equipment. Time-current coordination (TCC) graphs were used to perform the evaluation for the overcurrent devices. The results showed that acceptable levels of selectivity were achieved among devices in the system.

The breakers and relays in the system should be set to the recommended levels found in the Overcurrent Device Setting Tables section.

1.3.3 Arc Flash Results

Equipment was analyzed to determine the level of arc flash incident energy to which a worker might be exposed during an arc flash event. The majority of locations were determined to be 8 cal/cm2, or less. It is not recommended to perform work on energized equipment with the “Over 40 cal/cm2” designation (13 locations). Note that upstream emergency source information for three ATSs was not available, so the emergency case arc flash energy was not able to be calculated on equipment downstream of these ATSs. These are marked in the one-line diagram in Appendix D with the note ‘Upstream Information Unavailable’ or ‘To portable generator’.

It is recognized that recommendations in this report may not be implemented simultaneously. It is the customer’s responsibility to apply and update labels as recommendations are implemented or as conditions change.

2 INTRODUCTION

This report has the following components:

Studies were performed using nationally recognized electrical engineering analysis software.

The system short-circuit analysis evaluates the adequacy of the distribution equipment shown on the enclosed one-line diagrams to withstand or to interrupt the calculated maximum available short-circuit current at its location.

The overcurrent device time-current coordination analysis determines the suggested settings and, where appropriate, the ampere ratings and types for the electrical power system protective devices to achieve the desired system protection and electrical service continuity goals.

The arc flash analysis establishes the arc flash boundary around electrical equipment within which a worker exposed to an arcing fault would expect to receive 2nd degree burns if not adequately protected. The analysis also determines the incident energy levels at specific working distances from equipment, which can be used to select appropriate personal protective equipment (PPE) to be worn when working within the arc flash boundary.

This report supersedes and invalidates results from any prior study for the scope of equipment being reviewed.

Electrical system changes within the facility or in the utility system can have a significant impact on the results of this power system analysis, which is a “snapshot” of as-found system conditions. As such, it is recommended that this analysis be re-evaluated on a regular basis, not to exceed 5 years, to account for electrical system changes. NFPA 70B and 70E address the issue of equipment maintenance and failure to properly maintain equipment may invalidate these results

A “REFERENCES” section near the end of the report cites who supplied information or how the data was obtained. The majority of this data is filed with the project and has not been reproduced in this report. Abbreviations and trademarks referenced throughout this report are also listed in an appendix.

3 STUDY DATA

3.1 Power Company Data

Kansas City Power and Light has advised that their system is capable of delivering a maximum available three-phase short-circuit current of 4,293 A at 13.2 kV with an X/R ratio of 3.852 on the East feeder (#6112) and 2,799 A at 13.2 kV with an X/R ratio of 1.631 on the West feeder (#7402). These values determined the starting point for the analysis.

3.2 Generator Data

Generator data was obtained from an earlier study performed by Schneider Electric (Q2C# 24071382). The calculated maximum available bolted three-phase RMS symmetrical short-circuit current at the point of common coupling to the system (i.e. ATS) is considerably higher from the normal source compared to the generator source. The "Short Circuit Evaluation Table" is based on the higher source calculations. Therefore, all equipment determined to be adequate under normal utility supply conditions will also be adequate when the generator is in operation.

3.3 Estimates & Assumptions

Some assumptions, or estimates, were required and may affect the results of this study. In general, assumptions, or estimates, are needed because of limited access, safety concerns in obtaining equipment nameplate data, or lack of documentation. Significant differences between the assumptions, or estimates, listed here and actual values will require that this power system analysis be revised.

The following assumptions, or estimates, were made for the reasons given above:

1. The circuit breaker in emergency switchgear ‘BE’ feeding the primary disconnect for transformer ‘T-GRP’ was not known. The breaker was modeled as a switch for conservative arc flash results.

2. Equipment data retrieved from prior studies is assumed to be unchanged from when the data was initially provided to Schneider Electric. Assumptions from prior reports apply.

4 SHORT-CIRCUIT ANALYSIS

4.1 General Procedure

An electrical system short-circuit analysis is used for the following:

1) To compare the calculated maximum fault current with the interrupting ratings of overcurrent protective devices such as fuses and circuit breakers.

2) To investigate applicable short-circuit series ratings and the protection of electrical equipment by current-limiting devices.

3) To verify the adequacy of other equipment, such as switches and equipment bussing, to withstand the effects of the calculated maximum fault current levels.

4) To assist in the selection and/or determination of settings for relays, fuses and circuit breakers.

5) To provide input (along with device trip characteristics) to an arc flash hazard analysis.

This analysis calculates maximum available three-phase, RMS symmetrical, short-circuit amperes at each piece of equipment in the system. The calculation procedures are based on recommendations included in ANSI/IEEE standards C37.13, C37.010, and C37.5.

The modeling software simulates a bolted three-phase fault at each point of consideration in the system and calculates the maximum available short-circuit current at that point without any reduction due to current-limiting overcurrent devices which may be present. (However, the effects of current-limiting devices are considered when determining the adequacy of the equipment.) The calculated short-circuit values are RMS symmetrical amperes and are comparable with the RMS symmetrical short-circuit ratings of electrical equipment.

Electrical distribution equipment must be able to withstand and/or interrupt the most severe fault duty that it may be subjected to at its location in the system. In particular, NEC Section 110.9 requires circuit breakers to have a rating sufficient for interrupting the maximum available fault current present at their line side terminals. For locations where calculated fault currents exceed the ratings of the equipment, recommendations for corrective actions are provided.

Equipment short-circuit withstand and interrupting ratings are expressed in symmetrical RMS current. However, fault currents are not purely symmetrical in practice, as system inductance introduces a degree of asymmetry for at least the first few cycles of a fault. The magnitude and duration of this asymmetrical component depends on several factors, including characteristics of system components (conductors, transformers, and loads) and the exact point on the current waveform that the fault begins—the level of asymmetry even differs from phase to phase in a three-phase system. Because of the uncertainty in asymmetry for a given fault event, the capability of devices to interrupt asymmetrical fault current is based on the maximum possible asymmetrical fault current level at the point of application. The more inductive the circuit, as measured by the calculated system X/R ratio, the more asymmetrical the fault current can be. If the calculated X/R level exceeds a certain level, then the increased asymmetrical duty must be taken into account when breaker ratings are assessed.

Low-voltage circuit breakers and fuses are tested to establish their interrupting ratings based on a circuit with a fixed X/R ratio, as defined in the various product standards (UL and ANSI). For example, an ANSI low-voltage power circuit breaker is tested in a circuit with an X/R ratio of

6.591. If such a breaker is applied at a system bus with a calculated X/R ratio of 6.591 or less and the calculated RMS symmetrical fault current is within the symmetrical interrupting rating of the breaker, then it is assumed that the breaker is also able to interrupt and withstand the asymmetrical current resulting from a fault at that location. If a low voltage breaker is applied at a location with an X/R ratio greater than that of the design test circuit, the calculated fault current must be multiplied by an adjustment factor that accounts for this. This resultant “fault duty,” which is greater than the calculated fault current, is then compared to the breaker’s interrupting rating in order to determine if the breaker is adequately rated. Different classes of low-voltage breakers have different test X/R values, and each type has its own set of multiplication factors. Design test circuit power factors and associated X/R ratios are as shown in Table 1. The low-voltage short-circuit output report shows the calculated fault duty levels calculated at each bus, and when these values differ from the calculated short-circuit current levels, they are used in the device evaluation tables. See IEEE 1015-1997, IEEE Recommended Practice for Applying Low-Voltage Circuit Breakers Used in Industrial and Commercial Power Systems, for additional details.

Table 1: Summary of Test Power Factor and X/R Values for LV Devices.

Device pf X/R Ratio Power circuit breaker, unfused 0.15 6.591 Power circuit breaker, fused 0.20 4.899

Molded case breaker, interrupting rating greater than 20000 A 0.15-0.20 6.591-4.899

Molded case breaker, interrupting rating 10001 to 20000 A 0.25-0.30 3.9-3.18

Molded case breaker, interrupting rating 10000 A and less 0.45-0.50 2.0-1.732

For power circuit breakers, the power factors are taken from ANSI/IEEE C37.13. For molded case breakers, the power factors are taken from NEMA standard AB1. Since the NEMA standard specifies a range of test circuit power factors, the highest value (lowest X/R ratio) is used to determine the multiplying factor. This produces the most conservative (largest) factor.

The included one-line diagram is a simplified version of the system drawings, showing only those parts of the electrical system under consideration. The various circuit locations on the diagram have been labeled with bus identification numbers so input data could be supplied to the computer and the computer output could be readily interpreted.

4.2 Data Used in the Calculations

4.2.1 Power Company Data

Kansas City Power and Light has advised that their system is capable of delivering a maximum available three-phase short-circuit current of 4,293 A at 13.2 kV with an X/R ratio of 3.852 on the East feeder (#6112) and 2,799 A at 13.2 kV with an X/R ratio of 1.631 on the West feeder (#7402). These values determined the starting point for the analysis.

4.2.2 Generator Data

Generator data was obtained from an earlier study performed by Schneider Electric (Q2C# 24071382). The calculated maximum available bolted three-phase RMS symmetrical short-circuit current at the point of common coupling to the system (i.e. ATS) is considerably higher from the normal source compared to the generator source. The "Short Circuit Evaluation Table" is based on the higher source calculations. Therefore, all equipment determined to be adequate under normal utility supply conditions will also be adequate when the generator is in operation.

4.2.3 Cable Data

The conductor (cable and/or busway) data used for each circuit segment are shown in the SHORT CIRCUIT INPUT/OUTPUT DATA appendix. Included are lengths, number per phase, size, conductor material, cable insulation type, conduit material and resistance and reactance values.

Also, conductor lengths, number per phase, and size and conductor material are recorded on the one-line diagram.

Resistance values are based on 25 degrees Celsius (room temperature) rather than the full load temperature usually shown in descriptive literature because short-circuits can occur when the circuit is initially energized or lightly loaded as well as when fully loaded.

4.2.4 Transformer Data

Schneider Electric nameplate transformer percent impedance and typical X/R ratio values were used for all transformers. The exact R and X component values used are shown in the SHORT CIRCUIT INPUT/OUTPUT DATA appendix.

4.2.5 Motor Contribution to Short-Circuit Current

Motor contribution to the short-circuit current is taken into account in this short-circuit analysis.

During the first few cycles of a fault, running motors act as generators and produce a current which will combine with the source short-circuit current flowing to the fault as illustrated in Figure 1. Sources may be, but are not limited to, the Power Company, local generators, or both.

Figure 1: Example motor contribution.

Connected motors shown on the study one-line were assumed to be running at the time of the fault. Motors fed by adjustable speed drives equipped with bypass contactors were considered to contribute to system fault currents as well. However, motors fed by drives without bypass contactors were not considered since they do not contribute to fault current. Redundant motors shown on the study one-line were also assumed to be running at the time of the fault unless operating controls prohibit these conditions.

A motor’s contribution to a fault at its terminals is equal to the full-load ampere (FLA) rating of the motor divided by its per-unit subtransient reactance, similar to the contribution from a generator. However, at the upstream switchboard, panelboard, or motor-control center, the fault contribution from the individual motors is reduced by the impedance of the motor branch circuit conductors. Since data on motor subtransient reactances and branch-circuit conductor lengths is often difficult to obtain, assumptions regarding the motors’ subtransient reactances are typically made when the system model is built.

For calculation of low-voltage fault duty, the contribution from induction motors and synchronous motors in the system are considered. For small induction motors (less than 50 hp) where the impedance of the installation (i.e., motor and conductor) is not known, an equivalent subtransient reactance of 0.25 pu, resulting in a fault contribution of 4 times rated current, is assumed. Larger motors (50 hp and above) have an assumed subtransient reactance of 0.2 pu, resulting in a fault contribution of 5 times rated current. This is consistent with recommendations in IEEE Std. 141, IEEE Recommended Practice for Electric Power Distribution for Industrial Plants (the IEEE Red Book).

If applicable, multiplying factors are adjusted per Table 7 of ANSI/IEEE C37.010, IEEE Application Guide for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis for medium/high voltage fault duty. The table also shows contributions from induction motors less than 50 hp to be neglected.

The motor short-circuit contribution is determined and included in the computer short-circuit analysis so that the results should represent the highest short-circuit current to which the equipment might be subjected.

Unless otherwise indicated in the SC Computer Input Tabulations appendix, some motor loads are modeled as lumped induction motors connected directly to the low voltage buses using the recommended subtransient reactance values from C37.010, C37.13, and IEEE Std. 141. These modeled values appear in the appendices.

4.3 Short-Circuit Analysis Results and Recommendations

After making the calculations, the distribution equipment was checked to determine its adequacy to interrupt or withstand the effects of the calculated maximum short-circuit current at its location.

For some solidly-grounded systems, like close-coupled unit substations and generator gear, it is possible the bolted three-phase fault current is not the maximum fault current. When applicable, the bolted line-to-ground fault current was considered instead. The results are listed in the

"SHORT-CIRCUIT EVALUATION TABLE".

Short-circuit case description(s): The given utility data was used as the starting point for the short circuit analysis. For the short circuit analysis, the tie breaker for Switchgear MSS was open.

Listed in the tables are the calculated short-circuit currents at each piece of equipment and the ratings of the lowest rated device in the equipment enclosure. Comparing the two sets of values shows that all of the equipment examined is either adequate by itself or when used in series with another circuit breaker or protected by a line side current-limiting fuse or circuit breaker.

If applicable, equipment using series ratings that are shown in the short-circuit evaluation table must meet field labeling requirements per NEC Sections 110.22 and 240.86(B). There are two types of markings which must be present; the first requires series combination ratings to be marked on equipment by the manufacturer. The second equipment marking must be readily visible and state the following:

CAUTION – SERIES COMBINATION SYSTEM RATED _____ AMPERES.

IDENTIFIED REPLACEMENT COMPONENTS REQUIRED.

This labeling serves as a warning to those who may install new breakers or replace existing breakers at the given location in the future, alerting them to the fact that a specific device type must be used in order to ensure that the series rating is maintained.

Though not shown in the table, the momentary short-circuit duty for medium-voltage equipment was also evaluated vs. the corresponding equipment ratings. For equipment shown as “adequate”, both the momentary and interrupting ratings were found to be adequate.

Input data and short-circuit output data are included in the appendices.

4.4 Short-Circuit Evaluation Table

VA Hospital Kansas City, MO

POWER SYSTEM ENGINEERING

SHORT-CIRCUIT

EVALUATION TABLE

EQUIP. DESCRIPTION LOWEST RATED DEVICE MAXIMUM LINE SIDE LINE SIDE

BUS PER SYSTEM ONE NOMINAL IN EQUIPMENT ENCLOSURE AVAILABLE X/R MAXIMUM SERIES NOTES NO. LINE DIAGRAM(S) L-L VOLTS TYPE AIC OR WCR SCA OR DUTY RATIO DEVICE RATING EVALUATION # 100A MSS 13200 VR-15075-12 40,000 5,174 4.15 Adequate 100B MSS 13200 VR-15075-12 40,000 3,001 2.11 Adequate 101 PNL GRP 208 QO 10,000 4,222 1.70 AdequateQ , 102 T-GRP DISC 480 HEV DUTY SS-R 200,000 4,160 0.49 Adequate

#N/A = Number not available.

SCET Page 1 of 1

[Form Ver. 3.6]

5 OVERCURRENT DEVICE COORDINATION ANALYSIS

5.1 General Procedure

An overcurrent device time-current coordination analysis is an organized effort to determine the settings and, where appropriate, the ampere ratings and types for the over-current protective devices in an electrical system. The objective of the coordination analysis is to effect a time-current coordination among the devices, thereby achieving the desired system protection and electrical service continuity goals.

Maximum protection requires that the overcurrent protective devices be rated, selected, and adjusted to allow the normal load currents to flow while instantaneously opening the circuit when abnormal currents flow.

However, maximum service continuity requires that the overcurrent protective devices be rated, selected, and adjusted so that only the overcurrent protective device nearest the fault opens and isolates the faulted circuit from the system, permitting the rest of the system to remain in operation. Protective devices farther from the fault location should therefore essentially act as backup protection for the devices nearer to the fault, allowing the fault to be cleared with a minimum of disruption to the system. This is referred to as “coordination” between the protective devices. This may allow longer duration faults when the fault point is nearer the service entrance;

however, such faults are not as common, and setting the protective devices to operate in this manner is generally more desirable than deenergizing most or all of the system for a fault near one of the loads.

Selecting and setting the overcurrent devices is a procedure where the time-current characteristic curves of the various devices in series are compared with one another on a log-log graph. This procedure should take into account boundaries defined by load currents, short-circuit currents, and ANSI and NEC requirements.

Coordination usually will be obtained when the log-log plots of time-current characteristics show sufficient clear space or no overlap between the curves for the protective devices operating in series. Coordination will often stop short of complete selectivity when an acceptable compromise is reached between the various boundaries imposed on the selecting and setting procedure.

As shown on the one-line diagram, each overcurrent protective device or motor under consideration by the program has been assigned an identification number so that the computer output could be readily interpreted.

5.2 Specific Procedure

5.2.1 Short-Circuit Current Considerations

All protective device characteristic curves shown on the time-current graphs end at the calculated maximum short-circuit current at that device.

5.2.2 Molded Case Breaker Coordination

A molded case circuit breaker will trip with no intentional time delay for short-circuit currents above its instantaneous trip setting. Because of this, molded case breakers in series can only be selectively coordinated with each other if there is sufficient impedance between them so that the maximum available short-circuit current at the downstream breaker is less than the instantaneous trip setting of the upstream breaker. In Figure 2, breaker “C” illustrates this principle.

Figure 2: Example molded case breaker coordination.

There is enough cable impedance to limit the maximum available short-circuit current at “C” to less than the instantaneous trip setting of either “A” or “B”. When molded case breakers are in series without sufficient impedance between them to permit complete coordination, e.g., a panel main breaker and one of the branch devices in the panel, the time-current curves will overlap in the high-current instantaneous trip region. This is illustrated by the overlap between the curves for devices “A” and “B” in Figure 2. Most molded case breakers exhibit some degree of current limitation that will often result in selective operation in the overlap region. Time-current coordination curves included in this report do not match the results from the latest edition of the Schneider Electric data bulletin 0100DB0501. The software used to generate the curves is incapable of accounting for the dynamic impedance the system has when two or more devices in series “see” a fault. The data bulletin takes the dynamic impedance introduced by the downstream device into account. Greater separation between the instantaneous settings may increase the likelihood that the two devices will operate selectively. The potential lack of coordination is generally not considered critical and can be avoided only by adopting a different and, in general, less economically practical design especially when the following are considered:

Most faults occur in equipment such as motors, lighting panels, and process control panels which typically are located at the end of branch circuits, significantly reducing fault level and thereby reducing or eliminating the possibility of non-selective operation.

Lower magnitude arcing faults in rotating machinery and lighting panels are statistically more common than bolted three-phase faults.

Ground faults are more common than three-phase faults.

Maximum fault current is a random event depending on point-on-wave of the fault occurrence and other factors.

The device cutoff points on time-current coordination graphs are based on bolted fault current levels which correspond to zero impedance. Typical fault current impedance is usually greater than zero so the actual fault current seen by overcurrent devices can be less than what is shown on the time-current coordination graphs.

Recommended breaker trip settings are given in the "OVERCURRENT DEVICE SETTING TABLE – LV CIRCUIT BREAKERS". In addition, an illustration of the actual magnetic trip adjustment dials for Schneider Electric circuit breakers is included in the REFERENCES section to aid the setting process.

5.2.3 Time-Overcurrent Relay Coordination

The overcurrent relays were examined and settings selected to provide the best possible coordination with the appropriate line and load side protective devices.

These relay time-current curves are plotted as single lines as opposed to the manufacturing tolerance band plotted for fuse and low-voltage circuit breakers. However, certain time margins have been considered when coordinating these relays. These time margins account for manufacturing tolerances, induction disk over-travel, circuit breaker opening time and a safety margin. The coordinating time margins consist of the downstream breaker clearing time plus the upstream relay disk overtravel time, plus a safety margin to account for relay and CT inaccuracies.

For electromechanical relays, time margins of 0.3-0.4 seconds are desirable. For digital relays upstream, there is no significant allowance necessary for overtravel and a smaller interval such as 0.25-0.3 seconds can be used. For fuses upstream, a 10% margin in current for any time or a 25% margin in time for any current may be used to account for ambient temperature and preloading effects.

Note that the main 13.2 kV switchgear main and tie digital relays provide other protective functions which have recommended settings shown in the “Device Setting Table”.

5.2.4 Low-Voltage Ground-Fault Relay Settings

The feeder ground fault time settings were chosen to coordinate with the appropriate load side devices. Where possible, the ground fault current pickup settings on these feeders were chosen to coordinate with small load side branch breakers rated 20A and smaller with the consideration that most of the exposure to ground faults would likely occur in the electrical system downstream of these numerous small breakers.

Coordination with larger downstream breakers does not exist for any ground fault current exceeding the pickup setting but less than the magnetic setting of the load side breaker. This is unavoidable because the larger load side protective devices are not equipped with ground fault protection. Figure 3 illustrates this.

Figure 3: Example ground fault coordination (current scale X 10).

As shown in Figure 3, the feeder ground fault device B does not coordinate with branch breaker C for ground fault currents in the range of 320A-790A as indicated. Main breaker A and feeder breaker B phase device time-current curves are omitted for clarity.

The main and tie ground fault time and pickup settings have been set just high enough to coordinate with the settings chosen for the feeder ground fault relays.

All ground fault settings are tabulated in the appropriate overcurrent device setting tables.

For healthcare facilities, per NEC Section 517.17, wherever ground-fault protection of equipment is provided on the service disconnecting means, an additional level of ground-fault protection must be provided on the next downstream feeder disconnecting means. This requirement is intended to reduce the risk of a ground fault in the system causing nuisance tripping of the main service disconnect, which is more likely if only one level of ground fault protection is required.

This section does not require ground-fault protection in locations where it would otherwise not be required, e.g., on 208V systems. Where multiple levels of ground-fault protection are required, full selectivity is to be provided between the service and feeder ground-fault protective devices to achieve coordination.

5.2.5 Transformer Protective Devices

If in the project scope, medium- and/or low-voltage transformer primary overcurrent protective devices were checked for compliance with NEC Article 450. Also, medium voltage protective devices, primary, secondary and secondary feeder, were evaluated with respect to the applicable ANSI/IEEE Through Fault Guides (C57.12.59 for dry and cast resin type and C57.109 for liquid immersed type) and the Appendix for ANSI/IEEE C37.91. Transformer standards define low-voltage transformers as having a primary voltage less than or equal to 600V. Transformer full load currents and magnetizing inrush currents were also considered.

To evaluate through fault protection according to the ANSI Guides, the applicable curve was plotted representing a transformer's projected damage threshold for the cumulative effects of through faults. However, this ANSI through fault curve must be reduced for certain unbalanced secondary faults, because even though full short-circuit current is flowing in one or more secondary windings, the primary overcurrent device experiences less current.

Secondary line-to-neutral faults on delta-wye connected transformers produce only 0.577 of the maximum 3-phase fault current in the primary overcurrent device while one secondary winding experiences the full short-circuit current as illustrated in Figure 4 below. Therefore, to account for this fault condition, the ANSI through fault curve has been adjusted by a factor of 0.577. Both curves (three phase line-to-line and single phase line-to-neutral) are plotted on the time-current graphs.

Figure 4: Delta–Wye 3-PH and L-N fault current per unit values.

Since the through fault curves represent a transformer's projected damage threshold for the cumulative mechanical and thermal effects of through faults, all applicable primary and secondary overcurrent devices were checked to ensure interruption before these through fault curves were reached.

Further, to avoid nuisance interruptions, the primary overcurrent devices were also checked to ensure they will carry the transformers rated full load and equivalent magnetic inrush currents which are plotted on the time-current graphs.

Because of the restrictions mentioned above, coordination between the transformer primary and secondary main devices may not exist for any transformers examined as shown by the overlapping of their characteristics on the time-current graphs. However, this is judged acceptable, because the opening of either device results in the same extent of service interruption.

5.2.6 Selective Coordination and the National Electric Code

Selective coordination, while always desirable, is not required by the NEC except in certain situations:

In health-care facilities, per NEC 517.17(C): “Ground-fault protection for operation of the service and feeder disconnecting means shall be fully selective such that the feeder device, but not the service device, shall open on ground faults on the load side of the feeder device.”

In elevator circuits when more than one elevator motor is fed by a single feeder. See

NEC 620.62.

In emergency and legally-required standby power systems (including those in hospitals and other health-care facilities where so required), per NEC 700.28 and NEC 701.27.

In critical operations power systems (COPS) such as, but not limited to, power systems, HVAC, fire alarm, security, communications, and signaling; refer NEC 708.54.

Generally, these are facilities or parts of facilities that require continuous operation for reasons of public safety, emergency management, national security, or business continuity.

The requirements for selective coordination in emergency and legally-required standby systems, call for each overcurrent device to be “selectively coordinated with all supply side overcurrent protective devices.” This requirement can be problematic for system designers because it recognizes only device coordination and not system coordination. Special consideration of selective coordination (beyond the traditional coordination study) must be given when the system is initially designed, since for both fusible and circuit-breaker based systems, designs that are otherwise NEC compliant may not meet the selective coordination requirements of the NEC.

The system zones of protection may still be coordinated even though individual devices may overlap. For example, where two devices are in series with no loads connected between them, operation of either device interrupts power to the same portion of the system.

5.3 Analysis of Results and Recommendations

The basic results of an overcurrent device coordination analysis are the time-current coordination graphs which are plotted to illustrate the degree of coordination achieved in the system. Settings for devices which have adjustable characteristics are summarized in the appropriate overcurrent device setting tables.

To generate the time-current graphs, a computer program was used which allows the power system engineer to determine optimum coordination, after first insuring that loading and protection requirements are satisfied. The engineer’s objective is to determine the best coordination for the entire system. This approach necessitates tradeoffs in selectivity for some parts of the system to achieve maximum coordination in more critical areas. Regions in which coordination has been sacrificed are as previously discussed involving transformer primary and secondary main devices, high current regions of molded case breakers, etc.

5.3.1 TCC Plot Remarks

The following comments refer to the graphs shown in the Time Current Coordination Graphs section of this report. Adjustable breakers have been set to obtain the highest level of selectivity possible for the equipment provided and system design.

Time-current coordination graph MSS-T10(TB4) shows overlap between devices 100-F6 and MB SWGR A. Because of the restrictions mentioned in Section 5.2.5, coordination between the transformer primary and secondary main devices may not exist for the transformers as shown by the overlapping of their characteristics on the time-current graph. However, this is judged acceptable, because the opening of either device results in the same extent of service interruption.

Similar issues occur in the following:

MSS-T12.tcc, Devices: 100-F11 and SS1-B1O-MAIN MSS-T15.tcc, Devices: 100-F18 and B15-MAIN MSS-T17.tcc, Devices: 100-F3 and 101-00 MB GRP MSS-T26.tcc, Devices: 100-F8 and SWBD26-MSB-1 MSS-T7.tcc, Devices: 100-F7 and SS1-B6-MAIN MSS-T8.tcc, Devices: 100-F4 and F-B1W-MAIN MSS-T9.tcc, Devices: 100-F16 and F-B1E-MAIN

5.4 Overcurrent Device Setting Table

DEVICE SETTING TABLE Kansas City, MO

POWER SYSTEM ENGINEERING RELAYS

DEVICE NUMBER & NAME MANUFACTURER BUS VOLTS

BUS NUMBER & NAME DEVICE TYPE DESCRIPTION DEV. VOLTS CT RATIO SETTINGS

100A MSS 100-F11 MSS-T12 RLY 50/51, 5A CT 13200.0V 200 / 5 Phase Electronic 230000V Is IDMT 0.3 (60A)

IEEE Ext Inv, Sec. 0.2

INST 1.3 (260A)

Ground Is0 (Sum of CT's) 0.1 (10A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.3 (30A)

100B MSS 100-F12 MSS-T11 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 1.5 (450A)

IEEE Ext Inv, Sec. 0.6

INST 3.9 (1170A)

INST Delay 1

INST 5 (1500A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 1.5 (450A)

100B MSS 100-F14 MSS-PV RLY 50/51, 5A CT 13200.0V 200 / 5 Phase Electronic 230000V Is IDMT 0.6 (120A)

IEEE Ext Inv, Sec. 0.4

INST 15 (3000A)

Ground Is0 (Sum of CT's) 0.1 (20A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.5 (100A)

100B MSS 100-F16 MSS-T9 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 0.5 (150A)

IEEE Ext Inv, Sec. 0.7

INST 3 (900A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.9 (270A)

100B MSS 100-F18 MSS-T15 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 0.5 (150A)

IEEE Ext Inv, Sec. 0.2

INST 5.3 (1590A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 REL - Page 1 of 3 [Form Ver. 2.11]

POWER SYSTEM ENGINEERING RELAYS

DEVICE NUMBER & NAME MANUFACTURER BUS VOLTS

BUS NUMBER & NAME DEVICE TYPE DESCRIPTION DEV. VOLTS CT RATIO SETTINGS

INST (Sum of CT's) 1.2 (360A)

100B MSS 100-F19 MSS-T26A RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 0.3 (90A)

IEEE Ext Inv, Sec. 0.1

INST 2 (600A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.6 (180A)

100A MSS 100-F3 MSS-T17 RLY 50/51, 5A CT 13200.0V 100 / 5 Phase Electronic 230000V Is IDMT 0.1 (10A)

IEEE Ext Inv, Sec. 0.1

INST 0.8 (80A)

Ground Is0 (Sum of CT's) 0.1 (10A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.15 (15A)

100A MSS 100-F4 MSS-T8 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 0.3 (90A)

IEEE Ext Inv, Sec. 0.1

INST 3 (900A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 1 (300A)

100A MSS 100-F6 MSS-T10 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 1 (300A)

IEEE Ext Inv, Sec. 0.1

INST 8 (2400A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 2.5 (750A)

100A MSS 100-F7 MSS-T7 RLY 50/51, 5A CT 13200.0V 200 / 5 Phase Electronic 230000V Is IDMT 0.1 (20A)

IEEE Very Inv, Sec. 1.5

INST 1.4 (280A)

Ground Is0 (Sum of CT's) 0.1 (20A)

REL - Page 2 of 3

POWER SYSTEM ENGINEERING RELAYS

DEVICE NUMBER & NAME MANUFACTURER BUS VOLTS

BUS NUMBER & NAME DEVICE TYPE DESCRIPTION DEV. VOLTS CT RATIO SETTINGS

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.3 (60A)

100A MSS 100-F8 MSS-T26 RLY 50/51, 5A CT 13200.0V 300 / 5 Phase Electronic 230000V Is IDMT 0.7 (210A)

IEEE Ext Inv, Sec. 0.4

INST 6.9 (2070A)

Ground Is0 (Sum of CT's) 0.1 (30A)

IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 1.8 (540A)

100A MSS 100-M1 MSS RLY 50/51, 5A CT 13200.0V 1200 / 5 Phase Electronic 230000V Is IDMT 1 (1200A)

IEEE Ext Inv, Sec. 0.1 Ground

Is0 (Sum of CT's) 0.2 (240A) IEEE Mod Inv, Sec. 0.4

INST (Sum of CT's) 2 (2400A)

100B MSS 100-M2 MSS RLY 50/51, 5A CT 13200.0V 1200 / 5 Phase Electronic 230000V Is IDMT 1 (1200A)

IEEE Ext Inv, Sec. 0.1 Is, Def Time 4 (4800A)

Ground Is0 (Sum of CT's) 0.2 (240A)

IEEE Mod Inv, Sec. 0.4 INST (Sum of CT's) 2 (2400A)

100A MSS 100-T1 MSS RLY 50/51, 5A CT 13200.0V 1200 / 5 Phase Electronic 230000V Is IDMT 0.9 (1080A)

IEEE Very Inv, Sec. 0.1 Ground

Is0 (Sum of CT's) 0.1 (120A) IEEE Mod Inv, Sec. 0.25

INST (Sum of CT's) 1.5 (1800A)

REL - Page 3 of 3

5.5 Time-Current Coordination Graphs - Recommended Settings

100-M1 MSS RLY - Phase 100-T1 MSS RLY - Phase

100-F8 MSS-T26 RLY - Phase

0.

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0.400.40

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0.800.80

100100

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400400

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Name: 100-M1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 80 Frame/Model: Sepam Series 80 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 1 (1200A) IEEE Ext Inv, Sec. 0.1

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.9 (1080A) IEEE Very Inv, Sec. 0.1

Name: 100-F8 MSS-T26 RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 300 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.7 (210A) IEEE Ext Inv, Sec. 0.4

INST 6.9 (2070A)

Name: 100-M1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 80 Frame/Model: Sepam Series 80 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 1 (1200A) IEEE Ext Inv, Sec. 0.1

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.9 (1080A) IEEE Very Inv, Sec. 0.1

Name: 100-F8 MSS-T26 RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 300 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.7 (210A) IEEE Ext Inv, Sec. 0.4

INST 6.9 (2070A)

0.

s

0.

s

Name: *MSS-M1.tcc Current Scale x 10 Reference Voltage: 13200

May 3, 2016 VA Hospital, Kansas City, MO Power System Engineering

100-F14 MSS-PV RLY - Ground 100-T1 MSS RLY - Ground

100-M2 MSS RLY - Ground 0.

0.

0.

0.

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1K 1K

2K 2K

4K 4K

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0.020.02

0.040.04

0.060.06

0.080.08

0.100.10

0.200.20

0.400.40

0.600.60

0.800.80

100100

200200

400400

600600

800800

10001000

CURRENT IN AMPERES

CURRENT IN AMPERES

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Name: 100-F14 MSS-PV RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.1 (20A) IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.5 (100A)

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.1 (120A) IEEE Mod Inv, Sec. 0.25 INST (Sum of CT's) 1.5 (1800A)

Name: 100-M2 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 80 Frame/Model: Sepam Series 80 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.2 (240A) IEEE Mod Inv, Sec. 0.4 INST (Sum of CT's) 2 (2400A)

Name: 100-F14 MSS-PV RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.1 (20A) IEEE Mod Inv, Sec. 0.1 INST (Sum of CT's) 0.5 (100A)

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.1 (120A) IEEE Mod Inv, Sec. 0.25 INST (Sum of CT's) 1.5 (1800A)

Name: 100-M2 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 80 Frame/Model: Sepam Series 80 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Ground Is0 (Sum of CT's) 0.2 (240A) IEEE Mod Inv, Sec. 0.4 INST (Sum of CT's) 2 (2400A)

Name: *MSS-PV(G).tcc Current Scale x 1 Reference Voltage: 13200

100-F14 MSS-PV RLY - Phase

TX Inrush

T-PV SYSTEM 01

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1K 1K

2K 2K

4K 4K

6K 6K

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0.020.02

0.040.04

0.060.06

0.080.08

0.100.10

0.200.20

0.400.40

0.600.60

0.800.80

100100

200200

400400

600600

800800

10001000

CURRENT IN AMPERES

CURRENT IN AMPERES

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Name: T-PV SYSTEM 01 PRI FUSE Manufacturer: S&C Type: SM-5, 14.4kV E-Rated Frame/Model: SM-5, 50E Trip: 50.0 A Voltage: 13200.0 V Settings: Phase 50 Amps

Name: 100-F14 MSS-PV RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.6 (120A) IEEE Ext Inv, Sec. 0.4

INST 15 (3000A)

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.9 (1080A) IEEE Very Inv, Sec. 0.1

Name: T-PV SYSTEM 01 Nominal kVA: 1000.0 kVA Pri Voltage: 13200 V Sec Voltage: 480 V Z = 5.7500 % InrushFactor 12.0

Name: T-PV SYSTEM 01 PRI FUSE Manufacturer: S&C Type: SM-5, 14.4kV E-Rated Frame/Model: SM-5, 50E Trip: 50.0 A Voltage: 13200.0 V Settings: Phase 50 Amps

Name: 100-F14 MSS-PV RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.6 (120A) IEEE Ext Inv, Sec. 0.4

INST 15 (3000A)

Name: 100-T1 MSS RLY Manufacturer: SQUARE D Type: Sepam Series 20 & 40 Frame/Model: Sepam 20/40 CT Ratio: 1200 / 5 A Voltage: 13200.0 V Settings: Phase Is IDMT 0.9 (1080A) IEEE Very Inv, Sec. 0.1

Name: T-PV SYSTEM 01 Nominal kVA: 1000.0 kVA Pri Voltage: 13200 V Sec Voltage: 480 V Z = 5.7500 % InrushFactor 12.0

0.

s

0.

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Name: *MSS-PV.tcc Current Scale x 10 Reference Voltage: 13200

100-M1 MSS RLY - Ground

100-F6 MSS-T10 RLY - Ground 100-T1 MSS RLY - Ground

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2K 2K

4K 4K

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0.020.02

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0.080.08

0.100.10

0.200.20

0.400.40

0.600.60

0.800.80

100100

200200

400400

600600

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10001000

CURRENT IN AMPERES

CURRENT IN AMPERES

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Name: 100-M1 MSS RLY Manufacturer:…