Attachment 5 - Power System Analysis.pdf

Power System Engineering 11416 Coachmans Way

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COVER LETTER

COVER PAGE

POWER SYSTEM ANALYSIS

Troy USACE Facility Troy, NY

Prepared by Brandon McNeil under the supervision and direct control of

Kristen Goldman, P.E.

SE Engineering, P.C.

New York Firm No. 16 082309

Job Numbers Rev. Date Description Prepared By Q2C: 45161994 - January 23, 2024 Final Report BLM

1 - - - 2 - - -

This document has been authorized for release by the engineer whose seal and signature are hereto affixed. Altering this document is unlawful unless performed by or under the direction of a licensed professional engineer. Any changes shall be described and the engineer authorizing such alterations shall seal, sign, and date the revised document.

FILE: 45161994 - Troy USACE Facility Report

WARNING: IT IS A VIOLATION OF THE NYS EDUCATION LAW ARTICLE 145 FOR ANY PERSON, UNLESS HE IS ACTING UNDER THE

DIRECTION OF A LICENSED PROFESSIONAL ENGINEER, TO ALTER THIS ITEM IN ANY WAY.

DISCLAIMER

The following report was prepared by the Power System Engineering group of SE Engineering, PC utilizing industry-accepted standards and practices along with the proprietary methodologies and analysis tools provided to SE Engineering by Schneider Electric USA, Inc. Data used in this analysis was acquired by SE Engineering and provided by others, through onsite discovery, published information, equipment nameplates, manufacturer ratings, testing, analysis, or other means. SE Engineering 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.

TABLE OF CONTENTS

1 EXECUTIVE SUMMARY

1.1 Overview

1.2 Revision History

1.3 Study Recommendations

1.4 Study Highlights

1.4.1 Short-Circuit

1.4.2 Coordination

1.4.3 Arc Flash

1.4.4 Other Findings

2 INTRODUCTION

3 STUDY DATA

3.1 Importance

3.2 Missing 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

4.4 Short-Circuit Evaluation Tables

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 Transformer Protective Devices

5.2.4 Cable Protection

5.3 Overcurrent Device Coordination Analysis Results

5.4 Coordination Discussion Table

5.5 Overcurrent Device Setting Tables

5.6 Time-Current Coordination Graphs

6 ARC FLASH HAZARD ANALYSIS

6.1 General Procedure

6.2 Specific Procedure

6.3 AF Hazard Analysis Results

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

6.4 Power System Engineering Arc Flash Labeling Practice

6.4.1 Arc Flash Information Labels

6.4.2 General Safety Labels

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 Troy USACE Facility in Troy, NY. 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 this study is limited to that equipment shown on the study one-line diagram located in the back of the report. Unless specifically required by job specifications, branch circuit utilization equipment, as defined per NEC Article 100, was not included in this study (this may consist of small equipment, 100A and less, such as:

safety switches, industrial control panels, and enclosed starters/drives).

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.

1.3 Study Recommendations

TROY USACE FACILITY

TROY, NY

REFER TO ONELINE

Item # Priority Description Reference

BOM

Change Recommendation

1 Required NEC 240 ‐ Cables not protected

CBL‐2010

CBL‐2015‐1

CBL‐2015‐2

N

Change the cables from 4/0 AWG to 350kcmil to ensure they are adequately sized and protected for their relevant protective devices.

2 Required

NEC 240 ‐ Cable tap rule. Overcurrent protection on secondary side of transformer is not present or is greater than 25 feet.

CBL‐2015‐2 Maybe Install overcurrent protection rated 300A maximum within

25 feet of the transformer secondary.

RECOMMENDATIONS TABLE

1.4 Study Highlights

1.4.1 Short-Circuit

Of the 23 device locations evaluated for adequacy to interrupt or withstand the maximum three-phase short-circuit current to which they could be subjected, all were identified to be adequate. The Short-Circuit Evaluation Table lists equipment that was not evaluated because the equipment’s rating could not be determined.

1.4.2 Coordination

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.

No circuits were identified as requiring coordination. Therefore, the electrical system for this facility meets the specified coordination requirements.

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

1.4.3 Arc Flash

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 graph below shows the number of pieces of equipment for each IE level denoted in the key. It is not recommended to perform work on energized equipment.

Graph of arc flash hazard incident energy occurrence

Regardless of which IE calorie breakpoint levels are favored, or which NFPA 70E PPE selection table is used in this facility, a common approach is to use a clothing system with protection at 8 cal/cm2 and 40 cal/cm2. This method simplifies what workers must select/wear as well as what companies must issue to their employees and most importantly, will comply with NFPA 70E.

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.

1.4.4 Other Findings

Other issues, which are not formally in the scope of work, were observed in the course of data collection and analysis. These could be NEC compliance issues, equipment having poor condition of maintenance, grounding, or some other critical factor.

Three cables were found to be inadequately sized for their respective overcurrent protective devices. Therefore, the following cable changes are recommended:

CBL-2010 -> Increase to 500kcmil CBL-2015-1 -> Increase to 350kcmil CBL-2015-2 -> Increase to 350kcmil

The cable (CBL-2015-2) on the secondary side of transformer TX is longer than 25ft without overcurrent protection, which is a violation of NEC 240.21. Therefore, it is recommended to add a 300A fused disconnect within 25ft of the transformer secondary to ensure adequate protection of the cables. Alternatively, moving the transformer and downstream panel closer to each other is an option if viable.

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 Importance

The results of the study analyses are highly dependent on the accuracy of study data.

Modifications or clarifications of study data will likely alter study results.

3.2 Missing Data

The following information was not available:

The main and branch breakers in MDP were not provided and have been excluded from the arc-flash analysis.

The system one-line diagram identifies equipment with missing data.

Typical One-line color codes Black = Verified/Complete Orange = Assumed/Estimated Blue = Incomplete/Missing Red = NEC Compliance Issues

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 utility source was assumed to contribute a maximum fault current of 50kA at 4.16kV with an X/R ratio of 12.

2. The utility transformer was assumed to have an impedance of 3.75% with a 60% impedance tolerance and an X/R ratio of 3.5.

3. Transformer TX was assumed to have an impedance of 4.88% with an X/R ratio of 1.86.

4. The fused disconnects for LP-2, LP-3 and POWER PANEL were assumed to have Bussmann FRN-R fuses.

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/IEC standards: 399 (Brown Book), 551 (Violet Book), 62271-37-013 (supersedes C37.013), C37.04, C37.13, & C37.010.

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.

For equipment supplied from more than one source, there is no industry standard that defines hard requirements for whether the equipment must be rated for the short-circuit contribution from all sources. The National Electrical Code requires that “consideration shall be given to the contribution of fault currents from all interconnected power sources for the interrupting and short-circuit current ratings of equipment on interactive systems”. This does not require full rating to the sum of source short-circuit contributions, but rather consideration of the specific application. It is common industry practice to allow equipment which parallels sources for only very short windows of time – typically during closed-transition load transfers between sources – to have short-circuit/interrupting ratings suitable for the short-circuit contribution from the single source with the highest available fault current. The paralleling time may be limited to a specific value, such as 100ms, by the serving utility, or may otherwise be undefined but presumed to have no intentional paralleling delay and thus be approximately 100ms, or less. The value of 100ms is also mentioned in IEEE 1547-2018 as a paralleling time below which that standard does not apply to other than application with utility network systems.

In this analysis, equipment supplied by multiple sources where there is a reasonable expectation of “no intentional paralleling delay”, the highest single-source fault duty is given as the basis of adequacy of short-circuit withstand/interrupting ratings. This is not intended to construe that all risks due to faults in different locations relative to the equipment during a paralleled condition have been evaluated, but rather as a tool to allow the system designer to perform such evaluation. It is advised that a means of limiting the paralleling time to approximately 100ms, outside of an automation controller, PLC, or similar device, be considered in the over-all mitigation of risk.

Further, this is not intended to construe that all utility restrictions on paralleling time have been met; such considerations are within the purview of the system designer and beyond the scope of this study.

For equipment supplied by multiple sources where there is not a reasonable expectation of “no intentional paralleling delay”, such as sources that are intentionally paralleled continuously or for a finite period of time for soft load transfers, the full short-circuit contribution from all sources of supply is used as the basis for adequacy of short-circuit withstand/interrupting ratings.

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

National Grid has advised that the maximum available three-phase short-circuit current is 3,528A at 4.16kV with an X/R ratio of 1.78. This has been deemed “too low” and therefore has been used as the minimum available fault current. These values determined the starting point for the analysis. No minimum or alternate switching levels were given.

4.2.2 Generator Data

It has been determined that the 150kW generator has a subtransient reactance of 7.8% with an 80% PF and a calculated X/R ratio of 5.65 at 208V. 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, a fault contribution of 4 times rated current, is estimated. Larger motors (50 hp and above) have an estimated 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

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): 3,528A at 4.16kV is provided from the utility source to the equipment in this study. Motors were assumed to be connected and running and the ATS was assumed to be in its normal configuration.

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.

The short-circuit evaluation table shows buses with #N/A in the “NOTES” column. This is defined at the bottom of the table as #N/A = Number not available. Some of these buses do not require evaluation and may correspond to equipment such as transformer windings or motor terminals.

The table also lists some equipment that was not evaluated because the equipment’s rating could not be determined at the time of study preparation. These are identified by #N/A in the far right hand column of the table. The study recommends a field evaluation of this equipment by the customer to verify the equipment’s short-circuit current rating is greater than the calculated fault duty which can be evaluated by referring to the short-circuit output report. For each bus modeled, that report contains evaluations for UL and ANSI equipment and if necessary, Power System Engineering can assist in this evaluation.

For equipment evaluation, 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 found in industry standards.

Refer to the Summary of Test Power Factor and X/R Values for LV Devices table in the General Procedure section for more information.

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

4.4 Short-Circuit Evaluation Tables

REFER TO ONELINE

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 #

1000 MAIN DSC 208 SCCR200 200,000 10,252 2.20 Adequate 1

1005 MDP 208 #N/A 9,547 2.17 #N/A

1010 SUB PNL 208 SCCR10 10,000 8,411 1.51 Adequate 5

1020 LP‐2 DSC 208 HEV DUTY SS‐R 200,000 4,642 2.03 Adequate 2

1025 LP‐2 208 SCCR10 10,000 3,988 1.73 Adequate 5

1030 LP‐3 DSC 208 HEV DUTY SS‐R 200,000 4,598 1.94 Adequate 2

1035 LP‐3 208 SCCR10 10,000 2,945 1.01 Adequate 5

1040 POWER PNL DSC 208 HEV DUTY SS‐R 200,000 4,626 2.00 Adequate 2

1045 POWER PNL 208 SCCR10 10,000 3,337 1.32 Adequate 5

1050 LP‐1 208 SCCR10 10,000 9,369 2.01 Adequate 5

1100 MB PNL 208 SCCR10 10,000 9,828 1.14 Adequate 4

1105 SHACK PNL 208 QOB‐VH 22,000 6,401 0.78 Adequate

2000 ATS‐1 208 SCCR35 35,000 12,127 2.29 Adequate 3

2003 MDP‐1 208 FD6 65,000 5,188 1.94 Adequate

2010 TX DISC 208 SCCR200 200,000 4,691 1.84 Adequate 1

2020 MDP‐2 208 ED2 10,000 2,529 2.12 Adequate

2035 NW STAND 208 ED2 10,000 584 0.55 Adequate

2045 LOCK SYS 208 SCCR10 10,000 2,229 1.75 Adequate 5

2056 HEATER‐2 208 SCCR10 10,000 1,601 0.98 Adequate 5

2065 EMER SH‐2 208 SCCR10 10,000 525 0.41 Adequate 5

2080 LH HOUSE PNL 208 SCCR10 10,000 4,902 1.76 Adequate 5

2090 EMER SH‐1 208 BA 10,000 1,797 1.59 Adequate

2095 SAND HOUSE 208 SCCR10 10,000 509 0.40 Adequate 5

3000 GEN‐1 208 LH 65,000 7,088 5.56 Adequate

Notes

1. The Westinghouse DSL‐206 has an interupting rating of 200kA

2. Rating based on the disconnect rating when protected by the assumed class R fuses

3. Rating based on the time based rating of the 400A ASCO 300 series ATS at 208V.

4. Rating based on the interupting rating of the Cutler Hammer type BW breaker.

5. Rating based on industry minimum rating of 10kA.

SHORT‐CIRCUIT

EVALUATION TABLE

#N/A = Number not available.

ETAP SCET Page 1 of 1

[Template Ver. 14.8]

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 establish 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 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.

If a transformer is subject to a through fault, thermal damage occurs to conductors and insulation due to resistive heating. Mechanical damage occurs to windings and structural components due to large magnetic forces associated with the fault current. In general, smaller transformers are assigned a single damage characteristic that accounts for both thermal and mechanical damage. Larger transformers are assigned a two-part characteristic with a thermal characteristic and a more restrictive mechanical characteristic. For the most conservative protection, the thermal-mechanical limits should be used. In many cases, it may be acceptable to use only the thermal characteristic, especially if the transformer is not subject to frequent through faults.

Transformers connected to overhead secondary feeders should be considered to be subject to frequent through faults.

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 3 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 3: 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.

5.2.4 Cable Protection

Feeder overcurrent protective devices were reviewed to verify the protection of their load side cables as shown on the one-line diagram in accordance with NEC Article 240.

When applicable, a cable short-circuit withstand line is drawn on some time-current graphs for medium-voltage cables. The line is drawn from ICEA Publication P-32-382.

Medium-voltage overcurrent devices were set to interrupt before this cable withstand is reached.

However, the above analysis does not include any aspects of cable ampacity adjustment factors such as derating for conduit fill, elevated ambient temperature, and so on allowed by the NEC.

It is not possible to damage the phase conductor during short-circuits below the AIC rating of the breaker protecting the phase conductor when a low-voltage phase conductor is properly sized per NEC 240. UL tests to verify the short-circuit rating of a circuit breaker are performed considering 75C cable. The corresponding phase conductor is sized per the NEC and must pass the fault tests without compromising its integrity. Therefore, the ICEA cable withstand curves have not been included on the time-current coordination graphs.

5.3 Overcurrent Device Coordination Analysis Results

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. Smaller devices with fixed time-current characteristics are not shown on the graphs unless they directly affect the setting of an adjustable upstream device or are protective devices for transformers rated 15 kVA and larger.

It is assumed the impedance ground return path for the equipment grounding conductors (EGCs) and conduit for equipment rated 600V and less exhibit very low impedance levels—generally much less than 0.25 ohms for circuits 50A and larger; and can be in that range when larger sized EGCs are used. Although design and installation standards are intended to provide a ground return path with suitably low impedance, failure to maintain the ground return path with suitably low impedance will affect the ability for ground fault relays to operate as designed and intended. This impedance is not to be confused with the resistance to remote earth of a grounding electrode system, which is often specified in the 3-5 ohm range and does not impact whether ground fault devices operate properly. IEEE Std 1100 (Emerald Book) provides recommended maximum impedance values for EGCs and IEEE 81 provides test methods for measuring resistance to remote earth of a grounding electrode system. Field measurements may result in additional engineering and field work to correct the grounding system. Field testing and analysis are outside of the scope of work for this project.

To generate the time-current graphs, a computer program was used which allows the power system engineer to determine optimum coordination, after first ensuring 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. System protective zones involving transformer primary and secondary main devices, series devices in the same zone, or high current regions of molded case breakers may not show full device coordination.

5.4 Coordination Discussion Table

REFER TO ONELINE

Item # Priority Description Reference

BOM

Change Recommendation

1 Noted Coordination ‐ General

TCC 1025

TCC 1105

ETCC 2025

TCC 2025

ETCC 2035

TCC 2035

N None ‐ Informative only. Not required to coordinate.

COORDINATION DISCUSSION TABLE

5.5 Overcurrent Device Setting Tables

DEVICE SETTING TABLE TROY USACE FACILITY

LV CIRCUIT BREAKERS TROY, NY

REFER TO ONELINE

Frame (A) Instantaneous

Sensor (A) Pickup

Setting

Pickup

Setting Pickup Setting

Pickup

Setting

Model Rating Plug (A) Trip (A) Trip (A) Trip (A) Trip (A)

1100‐01 MB PNL MB 1100 MB PNL 0.24

Eaton

CSR

Fixed

1100‐02 SHACK PNL FDR 1100 MB PNL 0.24

Square‐D

QOM1‐VH

Fixed

1105‐01 SHACK PNL MB 1105 SHACK PNL 0.24

Square‐D

QO‐VH

Fixed

2000‐01 ATS‐1 MB ATS‐1(N) 0.24

Square‐D

LH

HI

2003‐01 MDP‐1 MB 2003 MDP‐1 0.24

Siemens

JXD2‐A

HI

2003‐02 LH HOUSE PNL

FDR

2003 MDP‐1 0.24

Siemens

FD6‐A

HI

2003‐03 EMER SH‐1 FDR 2003 MDP‐1 0.24

Cutler‐Hammer

KD

2020‐01 MDP‐2 MAIN 2020 MDP‐2 0.24

Cutler‐Hammer

KD

6.875

2059.98

2020‐02 SUMP PUMP

FDR

2020 MDP‐2 0.24

Siemens

FXD6‐A

1370.075

2020‐03 NW XFMR FDR 2020 MDP‐2 0.24

Siemens

ED2

Fixed

2020‐04 LOCK SYS FDR 2020 MDP‐2 0.24

Siemens

ED2

Fixed

2020‐05 HEATER‐2 FDR 2020 MDP‐2 0.24

Siemens

ED2

Fixed

2020‐06 EMER SH‐2 FDR 2020 MDP‐2 0.24

Siemens

ED2

Fixed

2035‐00 NW STAND

MAIN

2035 NW STAND 0.24

Siemens

ED2

Fixed

2090‐00 EMER SH‐1

MAIN

2090 EMER SH‐1 0.24

Cutler‐Hammer

HKD

2090‐01 SAND HOUSE

FDR

2090 EMER SH‐1 0.24

Cutler‐Hammer

BA

Fixed

3000‐02 ATS‐1 EFDR 3000 GEN‐1 0.24

Square‐D

LHL

10X

Short‐Time Ground

Delay

Curve

Device ID Equipment Designation

ManufacturerMax

Voltage

(kV)

Long‐Time

Delay

Curve Band Band I2T

Delay

Curve Band I2T

Frame, Sensor and Plug types must be verified to agree with this list prior to installing settings. I2t dial settings follow In = On and Out = Off.

LVCB ‐ Page 1 of 1

[Form Ver. 1.7]

5.6 Time-Current Coordination Graphs

3000-02 ATS-1 EFDR

Square-D LHL 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = 10X

GEN-1

Stator Damage Curve

GEN-1

FLA = 520.4

SUMP PUMP-100%

40 HP

TX

75 kVA (Secondary) 4.88 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2003-01 MDP-1 MB

Siemens JXD2-A 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2010-02 TX DISC

Cutler-Hammer DSL-206 0.208 kV Other 0.6 kV 300A

2020-02 SUMP PUMP FDR

Siemens FXD6-A 0.208 kV Size = 175 Amps Thermal Trip = Fixed Magnetic Trip = 4

2020-01 MDP-2 MAIN

Cutler-Hammer KD 0.208 kV Size = 300 Amps Thermal Trip = Fixed Magnetic Trip = 6.875

TX

Inrush

Multiplier = 11.7 xFLA

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 3000 GEN-1 (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 3000 GEN-1 (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

ETCC 2025

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY Contract: 45161994

V20.5PSE_20220104.lib

2035-00 NW STAND MAIN

Siemens ED2 0.18kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed 0.575kA @ 0.18kV

GEN-1

No Load Compound Excitation = 300% Total Fault Current

GEN-1

FLA = 520.4

NW XFMR

30 kVA (Secondary) 2.7 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2020-03 NW XFMR FDR

Siemens ED2 0.208 kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed

3000-02 ATS-1 EFDR

Square-D LHL 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = 10X

TX

75 kVA (Secondary) 4.88 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2003-01 MDP-1 MB

Siemens JXD2-A 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2010-02 TX DISC

Cutler-Hammer DSL-206 0.208 kV Other 0.6 kV 300A

2020-01 MDP-2 MAIN

Cutler-Hammer KD 0.208 kV Size = 300 Amps Thermal Trip = Fixed Magnetic Trip = 6.875

TX

Inrush

Multiplier = 11.7 xFLA

NW XFMR

Inrush

Multiplier = 12 xFLA

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 3000 GEN-1 (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 3000 GEN-1 (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

ETCC 2035

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY Contract: 45161994

1000-02 MAIN FUSE

Westinghouse DSL-206 0.208 kV Other 0.6 kV 250A

1020-01 LP-2 FUSE

Bussmann FRN-R (10/08) 0.208 kV Time Delay 0.25 kV 150A

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 1000 MAIN DSC (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 1000 MAIN DSC (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

TCC 1025

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY

1030-01 LP-3 FUSE

Bussmann FRN-R (10/08) 0.208 kV Time Delay 0.25 kV 100A

1000-02 MAIN FUSE

Westinghouse DSL-206 0.208 kV Other 0.6 kV 250A

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 1030 LP-3 DSC (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 1030 LP-3 DSC (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

TCC 1035

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY

1100-02 SHACK PNL FDR

Square-D QOM1-VH 0.208kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed 11.445kA @ 0.208kV

1100-01 MB PNL MB

Cutler-Hammer CSR 0.208kV Size = 200 Amps Thermal Trip = Fixed Magnetic Trip = Fixed 11.445kA @ 0.208kV

1105-01 SHACK PNL MB

Square-D QO-VH 0.208kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed 7.009kA @ 0.208kV

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 1100 MB PNL (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 1100 MB PNL (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

TCC 1105

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY

SUMP PUMP-100%

40 HP

TX

75 kVA (Secondary) 4.88 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2000-01 ATS-1 MB

Square-D LH (Discrete Mag) 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2003-01 MDP-1 MB

Siemens JXD2-A 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2010-02 TX DISC

Cutler-Hammer DSL-206 0.208 kV Other 0.6 kV 300A

2020-02 SUMP PUMP FDR

Siemens FXD6-A 0.208 kV Size = 175 Amps Thermal Trip = Fixed Magnetic Trip = 4

2020-01 MDP-2 MAIN

Cutler-Hammer KD 0.208 kV Size = 300 Amps Thermal Trip = Fixed Magnetic Trip = 6.875

TX

Inrush

Multiplier = 11.7 xFLA

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 TX(P) (Nom. kV=0.208, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 TX(P) (Nom. kV=0.208, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S econds

ETAP Star 20.5.0C

TCC 2025

Rev: Base Fault: Phase

Project: Troy USACE Facility Location: Troy, NY

NW XFMR

30 kVA (Secondary) 2.7 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2020-03 NW XFMR FDR

Siemens ED2 0.208 kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed

2035-00 NW STAND MAIN

Siemens ED2 0.18 kV Size = 100 Amps Thermal Trip = Fixed Magnetic Trip = Fixed

TX

75 kVA (Secondary) 4.88 %Z Delta-Wye Solid Grd Curve Shift = 0.58

2000-01 ATS-1 MB

Square-D LH (Discrete Mag) 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2003-01 MDP-1 MB

Siemens JXD2-A 0.208 kV Size = 400 Amps Thermal Trip = Fixed Magnetic Trip = HI

2010-02 TX DISC

Cutler-Hammer DSL-206 0.208 kV Other 0.6 kV 300A

2020-01 MDP-2 MAIN

Cutler-Hammer KD 0.208 kV Size = 300 Amps Thermal Trip = Fixed Magnetic Trip = 6.875

TX

Inrush

Multiplier = 11.7 xFLA

NW XFMR

Inrush Multiplier = 12 xFLA

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K Amps X 10 NW XFMR(P) (Nom. kV=0.24, Plot Ref. kV=0.208)

10K.5 1 10 100 1K3 5 30 50 300 500 3K 5K

Amps X 10 NW XFMR(P) (Nom. kV=0.24, Plot Ref. kV=0.208)

1K

.01

.1

.03

.05

.3

.5

S ec on ds

1K

.01

.1

.03

.05

.3

.5

S…