Joint Base Charleston
Charleston AFB
Electrical Distribution System Engineering Evaluation
Contract FA4418-06-D-0003
Volume 1 – Power System Evaluation
Report No. EE-12-265
Final Report – August 2012
Prepared for:
Department of the Air Force
628 CES/CEPMD
Joint Base Charleston
2482 Redbank Road, Bldg 5
Goose Creek, SC 29445
Department of the Air Force
HQ AMC/A7OI
507 Symington Dr.
Scott AFB, IL 62225-5022
Prepared by:
Edan Engineering Corporation
900 Washington St., Suite 830
Vancouver, WA 98660
(360) 750-4842
Glick/Boehm & Associates, Inc.
439 King St., Suite 100
Charleston, SC 29403
(843) 577-6377
Department of the Air Force
HQ AFCESA/CEOA
139 Barnes Dr., Suite 1
Tyndall AFB, FL 32403-5319
EXECUTIVE SUMMARY
Purpose
The purpose of this project is to perform an electrical analysis of the Charleston AFB electrical
distribution system. The project scope is specified in Performance Work Statement to Perform
Electrical Distribution System Engineering Study and Energy Security Assessment, dated August
11, 2011.
The project activities consist of three distinct phases:
1. Phase 1: Conduct field surveys and testing to support a detailed “as-building” of the existing
primary electrical distribution system.
2. Phase 2: Perform an electrical power system analysis of the existing primary distribution
system, including power flow, short circuit, and electrical protection/coordination. The
electrical analyses are performed using EasyPower® electrical analysis software. The study
serves to baseline performance of the existing system in support of a detailed engineering
evaluation of the primary distribution system.
3. Phase 3: Conduct a detailed engineering evaluation of the primary electrical system to
establish future modifications, expansions, and upgrades to support future electrical
requirements and improve system efficiency, reliability, and maintainability.
Project Deliverables
The following deliverables are provided in support of this power system study:

Analysis report summarizing project findings and results.

Field walkdown data files – on DVD.

EasyPower electrical model for the primary distribution system.

Electronic copies of photographs taken of electrical equipment during field walkdowns – on
DVDs.

EasyPower software and associated training.

New electrical distribution system single-line drawings.
ii

New electrical distribution system layout drawings.

Geobase documentation for the primary distribution system and airfield – on DVD.
Power Flow Study
The following summarizes the power flow results:
General Comments Regarding Primary Distribution System Capability
Feeders use 500 kcmil copper conductors for the main run for each feeder originating at the Main
Switching Station. With the completion of the recent underground construction, Feeder A and B
use 500 kcmil copper conductors for the main run. Feeder C is limiting with 1/0 awg copper
conductors for the underground distribution. Smaller conductors, #2 to 1/0 awg, are typically
used on lateral circuits.
The overhead distribution uses 1/0 copper or 3/0 ACSR for the main runs on each circuit. These
conductors in air are not limiting with respect to feeder capability.
Charleston AFB Power Consumption
The following summarizes the Charleston AFB total base power demand:

The base experienced a reduction in load for several years, followed by relatively consistent
peak demand in recent years. The peak demand for each year has been:
2004: 17,733 kVA
2005: 16,779 kVA
2006: 16,519 kVA
2007: 15,208 kVA
2008: 14,292 kVA
2009: 14,118 kVA
2010: 14,152 kVA
2011: 14,152 kVA
2012: 13,852 kVA

The year-by-year reduction in total power usage up to 2008 can likely be attributed to
a) removal of housing and b) base-wide energy conservation efforts.

For the Charleston area, the difference between peak demand and non-peak demand is mostly
air conditioning loads.

Given the above considerations, a reasonable upper bound for the total base peak demand is
about 15,000 kVA, or 700 amperes at 12.47 kV. This provides some margin to allow for
housing loads that are expected to increase in the near future.

The daily variation in power demand is about 25 percent.
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
Power factor varies from 0.90 to 0.96.
20,000
Total Power (kVA)
16,000
12,000
8,000
4,000
0
Jan‐04
Jan‐06
Jan‐08
Jan‐10
Jan‐12
Date
Figure 1
Charleston AFB Power Demand – kVA
Individual Feeders
Table 1 summarizes the load on each feeder that has been used in the EasyPower power flow
analysis. Table 2 provides additional information regarding the Flagpole Feeders sub-feeders (A,
B, and C). This forms the basis for the system analysis.
Table 1
Individual Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
Comments
FP
8,132
369
Flagpole Feeder splits into Feeders A, B, and
C. Refer to Table 15-2 for these feeders.
D
5196
236
E
633
29
F
713
32
HP
1,089
49
Totals:
15,763
715
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Table 2
Flagpole Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
A
900
41
B
3,448
158
C
3,732
171
Totals:
8,077
370
Comments
This is the total Flagpole Feeder load as
predicted at the Flagpole Feeder Switching
Station.
Table 1 provides the overall power flow results for normal operation during peak load
conditions. The term normal operation means that all feeders are in service.
The following summarizes the normal operation power flow results:

All lines are operating within their rated limits.

Voltage drop is acceptable throughout the primary distribution system; the voltage drop is
less than 2% for all feeders.

The Charleston AFB peak power demand is within the capability of the Main Substation.
Distribution Transformer Loading
Distribution transformers are generally lightly loaded. Most transformers are loaded to less than
20 percent of their rated kVA, even during periods of peak demand. Figure 2 provides a
histogram of the distribution transformers with respect to their typical peak loading; during offpeak times, the loading will be somewhat less. Almost 85 percent of these transformers are
loaded to less than 30 percent of their rated kVA. Over 95 percent of these transformers are
loaded to less than 50 percent of their rated kVA during periods of peak demand
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175
Number of Transformers n
150
125
100
75
50
25
0
0 - 10%
10 - 20%
20 - 30%
30 - 40%
40 - 50%
50 - 60%
60 - 70%
70 - 80%
80 - 90%
90 - 100%
Loading (Percent of Rated Value)
Figure 2
Distribution Transformers – Average Loading Histogram
Cross-Connect Capability
Cross-connect capability is evaluated in Section 7 for each point of potential cross-connect
between feeders. Cross-connection might be necessary under any of the following conditions:

Upon failure of a switching station feeder breaker or associated equipment.

Upon loss of a single feeder by feeder conductor damage.

To take equipment out of service for maintenance or repair.

While upgrading a feeder or replacing an underground distribution cable.
The term cross-connect is used here to mean that one feeder picks up all or part of another feeder
in addition to carrying its own load.
The cross-connect analysis results provided in this section are based on peak or near-peak
loading. During periods of less power demand, the cross-tie capability will be better than
discussed here.
This evaluation is based on the ability of a single feeder to supply power to one additional feeder.
The ability of one feeder to supply even more feeders simultaneously was not evaluated. This
type of evaluation would need to be completed using the EasyPower model for a specific
configuration.
It is assumed that phasing is identical between feeders at all potential points of cross-connection.
The exterior electrical shop should always confirm phasing at normally open points in the system
before closing a cross-tie. Whenever a new cross-tie is installed as part of a future construction
vi
project, exterior electrical shop personnel should visually observe the construction contractor
verify that phase rotation is identical on each side of the switch, including closing of the switch.
Whenever a system cross-connect is considered, the EasyPower model should be reviewed.
Loads in the model can be adjusted for seasonal variations to reflect currently measured feeder
loading and entire buildings can be removed from the model by allowing these buildings to be
carried by their emergency generators. By this approach, the EasyPower model can provide a
cross-connect prediction capability for the specific distribution system configuration.
Regardless of model predictions, affected feeders should be monitored closely whenever a crossconnect is performed.
The availability of emergency generators for individual facilities is not considered as part of this
cross-connect capability evaluation. This evaluation only applies to the capabilities of the
primary distribution system, with all normal loads connected. For each feeder, the evaluation is
based on the capability of a different feeder to provide power to that feeder.
The switch lineups in the following sections are readily evaluated by EasyPower. The evaluated
normally open switch is shut and other related breakers or switches are opened to determine the
cross-tie effect. The following sections summarize the EasyPower analyses.
Table 3 provides a summary of the cross-connects available for each feeder.
Table 3
Feeder Cross-Connect Summary
Feeder
Flagpole
Can Supply Feeders
None – it is the source for Feeders A, B, and C
A
B
C
D
B
A
C
C
A
B
C
D
A
C
HP
E
F
F
A
HP
D
E
Although the system has improved in recent years, some installed cross-tie points are not capable
of carrying an entire feeder; many cross-tie points are only suitable for carrying a portion of
another feeder. As more underground distribution projects are completed, the cross-tie capability
should improve. Refer to Section 7 for a discussion of the limitations for each cross-connect
location.
vii
Short Circuit Study
An evaluation of the system’s short circuit capability was conducted. The purpose of the short
circuit study was to confirm that critical system components (e.g., circuit breakers, fuses,
switchgear, transfer switches, and distribution panels) are operating within their nameplate short
circuit rating. The fundamental concern here is that a short circuit somewhere in the system
might produce high levels of fault current that exceed a component’s rating. The underrated
component might fail under this condition, potentially causing a fire, explosion, or unnecessary
outage. This aspect of system performance can only be determined through design analysis since
day-to-day operation offers no clues about the system’s ability to handle short circuits. Faults
are an infrequent event; thus, an underrated system can operate for years or even decades without
any apparent problems. The shortcoming only becomes evident when the system is subjected to
a fault. Electrical equipment used in applications that exceed the equipment’s nameplate short
circuit rating is a violation of the National Electrical Code (NEC), as well as other governing
ANSI, IEEE, and NFPA codes and standards. Circuit breakers are the focus of attention from a
code compliance point of view because they are the system’s primary line of defense against
hazardous and damaging electrical faults.
Table 5 provides a summary of the expected short circuit current ranges .
Table 5
Charleston AFB Short Circuit Currents On Feeders – Normal Operation
3-Phase Fault Current
(Momentary Symmetrical
RMS kA)
Line-to-Ground Fault Current
(Momentary Symmetrical
RMS kA)
Main Switching Station
7.57 kA
8.36 kA
Flagpole Feeder Switching Station
6.27 kA
6.52 kA
Typical range for feeders – 12.47 kV
3 – 7 kA
2 – 8 kA
Location
The following observations are provided regarding the available short circuit currents:

The fault current available on the primary distribution system is well within the interrupting
rating of typical distribution system equipment and protective devices during normal
operation.

As a general rule, ground fault current decreases rapidly as the distance from the source
increases. Ground fault currents near the substation are larger than the three phase fault
currents. However, three phase fault currents are larger than ground fault currents further
from the substation.

A fault impedance will cause a further decrease in the available short circuit current. The
largest fault impedance typically considered is 40 ohms, which would result in a ground-fault
current of about 180 amperes. IEEE C37-230, IEEE Guide for Protective Relay Applications
to Distribution Lines, states that fault impedances will usually be well below this amount.
viii

The fault current range on the secondary side of distribution transformers varies widely,
depending mainly on the transformer size and impedance in each case. Service entrance
conductor size and length causes an additional reduction of the fault current available at the
service entrance panel.
The fault current levels for the primary system are relatively low. All components in the primary
system are operating well within their short circuit ratings, as shown below.
Table 6
Primary System Fault Current Duties and Equipment Ratings
Location
Primary system switches (switchgear)
Equipment Rating
Fault Duty
12.5 – 22.0 kA
<8.0
Primary system fuses (switchgear) – SMU-20
14.0 kA
Load junctions and elbows
10.0 kA
7.1 kA sym
10.0 kA assym
Overhead distribution fused cutouts
Arc Flash Results
An arc flash summary is provided in Volume 2 Appendix F for the primary distribution system.
The recommended method for evaluating arc flash requirements for a specific work location and
setup is by the EasyPower model. Refer to UFC 3-560-01 for arc flash criteria and personal
protective equipment (PPE) requirements for energized line work. Refer also to Engineering
Technical Letter (ETL) 06-1, Arc Flash Personal Protective Equipment (PPE) Requirements for
High-Voltage Overhead Line Work at 69 kV (Nominal) or Less, which emphasizes that “Working
on energized electrical equipment is prohibited except in rare circumstances, and then only when
justified and approved by the BCE or equivalent in accordance with AFI 32-1064.”
The arc flash protective clothing requirements for energized work is mostly Category #0 and
Category #1 throughout the primary distribution system . Along the main portion of each feeder,
the substation relays, fuses, or VFIs are credited in the arc flash analysis as the protective devices
that clear the arcing fault. Fuses and VFIs are usually the recognized arc-fault clearing device
along downstream laterals.
The PPE requirements are specified for an unrealistically low working distance of 18 inches on
the primary distribution system. Lower arc flash values would apply to a reasonable hot-stick
working distance of 60 inches, or greater. The Charleston AFB EasyPower model should be
used to evaluate a specific work location and working distance.
Although this power system study extends to the service entrance of each facility, the study is
mainly an evaluation of the primary distribution system. Arc flash results for the service
entrance panel of any facility should be applied with care. The model was prepared in a manner
that allows the service entrance protective device (fuses or breaker) to be used in the arc flash
ix
calculations. These results only apply if the connections and buswork electrically upstream of
the service entrance disconnect are not accessible while performing energized line work.
An arc flash PPE level depends in part on the expected clearing time of an upstream protective
device. Maintenance and testing are both necessary to ensure a device is functional and can be
credited by an arc flash study. With respect to circuit breakers, maintenance confirms that the
circuit breaker is capable of operating as designed and testing confirms that a trip signal will be
initiated as designed. NFPA 70E-2012 addresses this by requiring:
“The arc flash hazard analysis shall take into consideration the design of the overcurrent
protective device and its opening time, including its condition of maintenance.”
The term “condition of maintenance” refers to maintenance and testing of sufficient quality that
the upstream protective device can be expected to operate as intended and within the analyzed
operating time.
For this primary distribution study, periodic maintenance and testing of the switching station
circuit breakers and protective relays is necessary to use the arc flash results. Refer to Section
14.8 for recommendations regarding periodic maintenance and testing.
Coordination Study
Proper electrical protection and coordination are essential for electrical distribution system
reliability. The fundamental objectives of system protection are to:

Isolate permanent faults with minimum disruption of power to unaffected portions of the
system.

Limit damage to faulted equipment and minimize hazards to personnel.

Minimize the possibility of fire or catastrophic damage to adjacent equipment.
Ideally, the protection scheme design is fully coordinated. A fully coordinated system
accomplishes the above objectives over the entire range of possible fault current. A partially
coordinated system has gaps in coverage, i.e., coordination is achieved only for a portion of the
fault current range. Lack of coordination generally results in an undesired protective action and
the unnecessary removal from service of portions of the distribution system.
Electrical coordination was evaluated using standard industry methods and criteria. Timecurrent coordination plots were developed for the system. The time-current curves for related
devices are graphically depicted on a common plot. The curves are then compared using the
specified criteria to confirm that the nearest protective device upstream from the fault will open
before other upstream devices. This comparison is made over the entire possible fault current
range. The postulated fault current ranges from a very light overload at the low end up to the
maximum predicted fault current for the fault location (based on short circuit study values). The
maximum predicted fault current represents the worst-case 3-phase momentary asymmetrical
fault current (line faults) or worst-case line-to-ground momentary asymmetrical fault current
(ground faults).
x
This study represents a review of the primary distribution system, which starts at the local utility
supply to each substation. The scope of the coordination review extends to the service entrance
disconnect of each evaluated facility. The following summarizes the analysis scope:

Protection and coordination along the primary distribution system, including the substations,
was evaluated fully.

The secondary side of distribution system transformers was evaluated up to and including the
main service disconnect.

The coordination criteria applied to low voltage equipment consisted of a confirmation that it
will not cause the complete loss of a substation feeder for the defined settings or size.

Branch breakers downstream of the service entrance disconnect are not included in the scope
of this analysis.
Section 10 provides the criteria applied to the coordination analyses. Section 11 provides the
coordination analysis for the switching stations. Relay setting changes are recommended in
Section 11.3. And, Section 12 addresses distribution system pad-mounted switchgear and
facility transformers. The following summarizes the issues addressed in these sections:
Main Substation

The original design documents on which the relay settings are based indicated identical 250
kVA voltage regulators on all feeders. Instead, Feeders E, F, and HP have 167 kVA voltage
regulators installed, with only 2/3 the capacity originally expected. The specified relay
settings should not allow overloading these voltage regulators. The recommended relay
settings will be based on Feeders E, F, or HP supplying a cross-tie to another feeder with the
voltage adjustment range reduced to ±5%. The maximum allowed current through the
voltage regulator for this configuration is 371 amperes. Note: the pickups can be left at 5
rather than reset to 4 if the voltage regulators are upgraded.

The instantaneous trip settings for the Flagpole Feeder were based on an overhead
distribution between the Main Substation and the Flagpole Feeder Switching Station, which
has changed. The available short circuit current at the Flagpole Feeder Switching Station is
now higher than it previously was for an overhead distribution supply. For this reason, the
Flagpole Feeder relay instantaneous trips now reach well into Feeder A, B, and C. A
complete loss of the Flagpole Feeder is not desired for a fault on Feeder A.

The instantaneous trip settings for Feeder HP were based on an overhead distribution
between the Main Substation and the Hunley Park area, which has changed. Feeder HP is
entirely underground now and this feeder should be set up similar to Feeders E and F.
Pad-Mounted Switchgear

Fused switchgear often uses fuses oversized for the application.
The above items are addressed in the body of the report.
xi
Recommended Design Criteria
Section 14.2 provides recommended design criteria to apply to future projects.
Recommended Projects
Projects have been recommended in Section 14. The projects include the following:

Recommended actions arising from the power system study of the existing system.

Replace live-front transformers.

Replace or repair SF6 switchgear with low gas pressure.

Continue infrastructure improvements.
xii
CONTENTS
1
Introduction ...................................................................................................................... 1-1
1.1
Purpose of Study ........................................................................................... 1-1
1.2
Power System Study ...................................................................................... 1-2
1.3
Deliverables ................................................................................................... 1-4
1.4
Description of Analyses ................................................................................. 1-4
1.4.1
Power Flow ............................................................................................. 1-4
1.4.2
Short Circuit ............................................................................................ 1-5
1.4.3
Arc Flash................................................................................................. 1-6
1.4.4
Electrical Protection and Coordination .................................................... 1-7
1.4.5
System Cross-Connect Capability .......................................................... 1-7
1.4.6
Motor Starting ......................................................................................... 1-7
1.4.7
Harmonics............................................................................................... 1-8
1.5
Electrical System Modeling and Analysis Software........................................ 1-8
1.6
Analysis Process.......................................................................................... 1-11
2
Data Acquisition and Model Development .................................................................... 2-1
2.1
Field Walkdowns ............................................................................................ 2-1
2.2
Inaccessible Equipment and Missing Data .................................................... 2-4
2.3
Equipment Naming Conventions.................................................................... 2-5
2.4
Electrical Model Overview .............................................................................. 2-6
2.4.1
Base Parameters .................................................................................... 2-7
2.4.2
Analysis Areas and Zones ...................................................................... 2-8
2.4.3
EasyPower Device Library ...................................................................... 2-8
2.5
Modeling of Individual Components ............................................................... 2-8
2.5.1
Utility Connection .................................................................................... 2-8
2.5.2
Buses ...................................................................................................... 2-8
2.5.3
Feeders................................................................................................. 2-10
2.5.4
Transformers ........................................................................................ 2-11
2.5.5
Distribution System Switches, Knife Blades, and Cutouts .................... 2-13
2.5.6
Medium Voltage Breakers and Protective Relays ................................. 2-14
2.5.7
Manholes .............................................................................................. 2-14
2.5.8
Service Entrance .................................................................................. 2-14
2.5.9
Motors ................................................................................................... 2-15
2.6
Model Database Summary........................................................................... 2-15
xiii
2.7
2.8
3
GeoBase Deliverable Overview ...................................................................................... 3-1
3.1
3.2
4
GeoBase Electrical Equipment Data Files ..................................................... 3-1
GeoBase Airfield Data Files ......................................................................... 3-10
Utility Supply to Charleston AFB .................................................................................... 4-1
4.1
4.2
4.3
4.4
4.5
4.6
5
Electrical Drawings ...................................................................................... 2-16
Equipment Photographs .............................................................................. 2-16
Utility Supply .................................................................................................. 4-1
Substation Transformers ................................................................................ 4-5
Short Circuit Current ...................................................................................... 4-8
Santee Cooper Relay Settings ....................................................................... 4-8
Charleston AFB Switching Station Supply ................................................... 4-10
Voltage Variation.......................................................................................... 4-11
Charleston AFB Electrical Distribution System Description ....................................... 5-1
5.1
Charleston AFB Overview .............................................................................. 5-1
5.2
Charleston AFB Main Switching Station ........................................................ 5-3
5.2.1
Circuit Breakers ...................................................................................... 5-5
5.2.2
Overcurrent Protection ............................................................................ 5-7
5.2.3
Circuit Breaker Reclosing ....................................................................... 5-8
5.2.4
Voltage Regulation ................................................................................. 5-9
5.2.5
Feeder Transfer Capability ................................................................... 5-11
5.3
Primary Distribution Feeders........................................................................ 5-11
5.3.1
Overview ............................................................................................... 5-11
5.3.2
Initial Feeder Conductor Size................................................................ 5-12
5.4
Flagpole Feeder Switching Station .............................................................. 5-13
5.5
Distribution System Switchgear ................................................................... 5-15
5.6
Underground Conductor Ampacity ............................................................... 5-19
5.6.1
Reference Information .......................................................................... 5-19
5.6.2
Feeder Ampacity ................................................................................... 5-22
6
Power Flow Analysis ....................................................................................................... 6-1
6.1
Purpose of Power Flow Analysis.................................................................... 6-1
6.2
Viewing the Power Flow Analysis Results in EasyPower ............................... 6-1
6.3
Electrical Power Consumption and Demand .................................................. 6-3
6.3.1
Power Demand Data – Total Base ......................................................... 6-3
6.4
Summary of Power Flow Analysis Results ..................................................... 6-6
6.4.1
General Comments Regarding Primary System Capability .................... 6-6
6.4.2
EasyPower Feeder Loading.................................................................... 6-6
6.4.3
Normal Operation Results....................................................................... 6-7
xiv
6.4.4
Distribution Transformer Loading ............................................................ 6-8
6.4.5
Conductor Loading ................................................................................. 6-8
6.4.6
System Voltage Variation........................................................................ 6-9
6.5
Motor Starting Analysis .................................................................................. 6-9
6.6
Bldg 516 Fire Pump Evaluation...................................................................... 6-9
7
System Cross-Connect Capability ................................................................................. 7-1
7.1
7.2
7.3
7.4
7.5
7.6
8
Purpose of Analysis ....................................................................................... 7-1
Analysis Limitations and Cross-Tie Considerations ....................................... 7-1
Primary System Ampacity .............................................................................. 7-2
Main Switching Station Transfer Bus ............................................................. 7-3
Main Switching Station Voltage Regulators ................................................... 7-3
Feeder Cross-Connect Locations and Capability ........................................... 7-3
Short Circuit Analysis ...................................................................................................... 8-1
8.1
Purpose of Short Circuit Analysis................................................................... 8-1
8.2
Interpreting Short Circuit Analysis Results ..................................................... 8-2
8.3
Modeling Considerations ............................................................................... 8-4
8.3.1
Utility Fault Contribution .......................................................................... 8-4
8.3.2
Pre-Fault Voltage .................................................................................... 8-4
8.3.3
Transformers .......................................................................................... 8-4
8.3.4
Motors ..................................................................................................... 8-4
8.4
Short Circuit Analysis Results ........................................................................ 8-5
8.5
Equipment Fault Current Duty........................................................................ 8-6
8.5.1
Analysis Terms ....................................................................................... 8-6
8.5.2
Analysis Requirements ........................................................................... 8-6
8.5.3
Equipment Duty Evaluation Criteria ........................................................ 8-7
8.5.4
Equipment Fault Duty Analysis Results .................................................. 8-7
8.6
Transformer Effects on Short Circuit Current Magnitude ............................... 8-8
9
Arc Flash Analysis ........................................................................................................... 9-1
9.1
Purpose of Arc Flash Analysis ....................................................................... 9-1
9.2
Arc Flash Analysis Basics .............................................................................. 9-2
9.3
Interpreting Arc Flash Analysis Results ......................................................... 9-3
9.4
Arc Flash Analysis Parameters ...................................................................... 9-4
9.5
Modifying EasyPower Arc Flash to Work on a Distribution System ............... 9-6
9.5.1
Changing Traverse Number.................................................................... 9-6
9.5.2
Changing the Short Circuit Analysis Options .......................................... 9-7
9.6
Practical Considerations ................................................................................ 9-8
9.7
Arc Flash Analysis Results........................................................................... 9-11
9.7.1
Results .................................................................................................. 9-11
9.7.2
Periodic Maintenance and Testing ........................................................ 9-12
xv
10
Electrical Protection and Coordination Criteria .......................................................... 10-1
10.1 Scope of Electrical Coordination Review ..................................................... 10-1
10.2 Electrical Protection and Coordination Criteria............................................. 10-2
10.3 Selection Considerations for Cutout Fuse Links .......................................... 10-3
10.4 Substation Feeder Relay Instantaneous Trips ............................................. 10-6
10.5 Substation Circuit Breaker Automatic Reclosing .......................................... 10-7
10.6 Cold Load Inrush.......................................................................................... 10-8
10.6.1 Transformer Magnetizing Inrush ........................................................... 10-8
10.6.2 Load Inrush ........................................................................................... 10-9
10.7 Conductor Protection ................................................................................... 10-9
11
Electrical Protection and Coordination – Main Substation and Switching Station . 11-1
11.1
11.2
11.3
12
Santee Cooper Substation ........................................................................... 11-1
Main Switching Station – Existing Settings .................................................. 11-2
Main Switching Station – Recommended Settings..................................... 11-12
Electrical Protection and Coordination – Primary Distribution ................................. 12-1
12.1 G&W VFI Pad-Mounted Switchgear ............................................................. 12-1
12.1.1 G&W VFI Trip Setting Recommendations............................................. 12-1
12.1.2 G&W Flagpole Feeder Switching Station .............................................. 12-3
12.2 S&C VFI Pad-Mounted Switchgear .............................................................. 12-5
12.3 Comparison of S&C Vista and G&W Switchgear ......................................... 12-8
12.4 Fused Pad-Mounted Switchgear .................................................................. 12-9
12.5 Overhead Distribution Fusing..................................................................... 12-14
13
Additional Evaluations .................................................................................................. 13-1
13.1 Energy Security Assessment ....................................................................... 13-1
13.2 Aurora Vulnerability Assessment ................................................................. 13-1
13.2.1 Overview ............................................................................................... 13-1
13.2.2 Evaluation ............................................................................................. 13-3
13.2.3 Analysis ................................................................................................ 13-3
13.3 Power Factor................................................................................................ 13-5
13.4 Harmonic Distortion ..................................................................................... 13-6
13.4.1 Purpose of Harmonic Distortion Evaluation .......................................... 13-6
13.4.2 Harmonic Measurements ...................................................................... 13-8
13.4.3 Evaluation Criteria ................................................................................ 13-8
13.4.4 Results .................................................................................................. 13-9
14
Master Planning and System Recommendations ....................................................... 14-1
14.1
Planned Infrastructure Changes .................................................................. 14-1
xvi
14.2 Recommended Primary Distribution Design Criteria .................................... 14-2
14.2.1 Tri-Service Design Criteria and Industry Standards .............................. 14-3
14.2.2 Distribution Transformers...................................................................... 14-4
14.2.3 Pad-Mounted Switchgear...................................................................... 14-6
14.2.4 Primary Distribution System Conductor Sizes ...................................... 14-8
14.2.5 Design Review Checklist ...................................................................... 14-8
14.3 Main Switching Station Voltage Regulators ............................................... 14-10
14.3.1 Installed Configuration ........................................................................ 14-11
14.3.2 Voltage Regulator Sizing .................................................................... 14-12
14.3.3 Increasing the Load Capability............................................................ 14-13
14.3.4 Cross-Tie Limitations Associated With Voltage Regulators ................ 14-15
14.3.5 Long-Term Voltage Regulator Recommendations .............................. 14-15
14.4 Live-Front Transformers ............................................................................ 14-15
14.5 Unfused Transformers ............................................................................... 14-17
14.6 SF6 Switches With Low Gas Pressure ...................................................... 14-18
14.7 Main Switching Station Relay Settings ....................................................... 14-19
14.8 Switching Station Equipment Periodic Maintenance .................................. 14-19
15
Conclusions and Observations .................................................................................... 15-1
15.1 Deliverables ................................................................................................. 15-1
15.2 Conclusions and Observations for the Power System Study ....................... 15-1
15.2.1 Power Flow Study ................................................................................. 15-1
15.2.2 Cross-Connect Capability ..................................................................... 15-5
15.2.3 Short Circuit Study ................................................................................ 15-7
15.2.4 Arc Flash Results .................................................................................. 15-8
15.2.5 Coordination Study ............................................................................... 15-9
15.2.6 Motor Starting ..................................................................................... 15-11
15.3 Recommended Design Criteria .................................................................. 15-11
15.4 Recommended Projects ............................................................................. 15-11
15.5 References................................................................................................. 15-11
15.5.1 Military Criteria .................................................................................... 15-11
15.5.2 Industry Standards .............................................................................. 15-12
15.5.3 Other Documents ................................................................................ 15-12
xvii
LIST OF FIGURES
Figure 1-1 Flowchart of Project Activities .................................................................................. 1-2
Figure 1-2 Typical EasyPower User Interface ............................................................................. 1-9
Figure 1-3 Typical EasyPower Data Entry Window ................................................................. 1-10
Figure 2-1 Example Walkdown Data Sheet – Transformers ....................................................... 2-2
Figure 2-2 Example Walkdown Data Sheet – Pad-Mounted Switchgear .................................... 2-3
Figure 2-3 EasyPower Model Elements ...................................................................................... 2-7
Figure 2-4 Example of EasyPower Analysis Node...................................................................... 2-9
Figure 2-5 Equipment Photograph Directory Structure ............................................................. 2-17
Figure 4-1 Santee Cooper Substation at Charleston AFB ........................................................... 4-1
Figure 4-2 Santee Cooper Overall Distribution to Charleston AFB ............................................ 4-2
Figure 4-3 Santee Cooper One-Line Drawing – Substation Side ................................................ 4-3
Figure 4-4 Santee Cooper One-Line Drawing – Switching Station Side .................................... 4-4
Figure 4-5 Nearby Substation Isolation Switches ........................................................................ 4-5
Figure 4-6 Substation Transformers ............................................................................................ 4-6
Figure 4-7 Santee Cooper Substation Transformer #1 Nameplate (Wagner) .............................. 4-7
Figure 4-8 Santee Cooper Substation Transformer #2 Nameplate (Ohio) .................................. 4-7
Figure 4-9 Santee Cooper Substation Circuit Interrupter ............................................................ 4-9
Figure 4-10 Santee Cooper Substation Circuit Interrupter Nameplate ...................................... 4-10
Figure 4-11 Santee Cooper Supply Line to Charleston AFB .................................................... 4-10
Figure 5-1 Charleston AFB Location .......................................................................................... 5-1
Figure 5-2 Charleston AFB – Aerial View .................................................................................. 5-2
Figure 5-3 Charleston AFB Main Switching Station ................................................................... 5-3
Figure 5-4 Electrical Distribution System Simplified One-Line ................................................. 5-4
Figure 5-5 Main Circuit Breaker Nameplate ............................................................................... 5-6
xviii
Figure 5-6 Feeder Circuit Breaker Nameplate ............................................................................. 5-6
Figure 5-7 Overcurrent Relays..................................................................................................... 5-7
Figure 5-8 Bus Differential Protection Relays............................................................................. 5-8
Figure 5-9 Basler Reclosing Relay .............................................................................................. 5-9
Figure 5-10 Voltage Regulators ................................................................................................... 5-9
Figure 5-11 Voltage Regulator Nameplate ................................................................................ 5-10
Figure 5-12 Flagpole Feeder Switching Station – Placed in Service Summer 2012 ................. 5-14
Figure 5-13 Flagpole Feeder Switching Station Configuration ................................................. 5-14
Figure 5-14 S&C Fused Switchgear .......................................................................................... 5-15
Figure 5-15 S&C SMU-20 Fuse Characteristics ....................................................................... 5-16
Figure 5-16 G&W VFI Switchgear............................................................................................ 5-17
Figure 5-17 G&W VFI Switchgear – Low Gas Level ............................................................... 5-17
Figure 5-18 NEC Figure 310.60 – Cable Installation Configurations ....................................... 5-19
Figure 5-19 Okonite Data – One Circuit.................................................................................... 5-20
Figure 5-20 Okonite Data – Multiple Circuits ........................................................................... 5-21
Figure 6-1 Typical EasyPower Power Flow Result ..................................................................... 6-2
Figure 6-2 Main Substation Power Demand – kVA .................................................................... 6-3
Figure 6-3 Main Substation Power Demand – Amperes ............................................................. 6-4
Figure 6-4 Monthly Peak Demand ............................................................................................... 6-4
Figure 6-5 Typical Daily Variation in Power Demand ................................................................ 6-5
Figure 6-6 Power Factor Variation .............................................................................................. 6-5
Figure 6-7 Distribution Transformers – Peak Demand Histogram .............................................. 6-8
Figure 6-8 Conductors – Peak Demand Histogram ..................................................................... 6-9
Figure 8-1 Typical EasyPower Short Circuit Result.................................................................... 8-2
Figure 8-2 Symmetrical Current Waveform ................................................................................ 8-3
Figure 8-3 Asymmetrical Current Waveform .............................................................................. 8-3
Figure 8-4 Short Circuit Current as a Function of Transformer Impedance –
208 Volt Secondary.............................................................................................................. 8-8
Figure 8-5 Short Circuit Current as a Function of Transformer Impedance –
480 Volt Secondary.............................................................................................................. 8-9
Figure 8-6 Substation Voltage as a Function of Short Circuit Magnitude ................................ 8-10
xix
Figure 9-1 Typical EasyPower Arc Flash Result ......................................................................... 9-3
Figure 9-2 Typical EasyPower Arc Flash Spreadsheet................................................................ 9-4
Figure 9-3 Arc Flash Analysis User Settings Dialog Box ........................................................... 9-5
Figure 9-4 Arc Flash Analysis Traverse Number ........................................................................ 9-7
Figure 9-5 Arc Flash Analysis User Settings Dialog Box – Integrated Analysis ........................ 9-8
Figure 9-6 Recommended Arc Flash Warning Label ................................................................ 9-11
Figure 10-1 Various Fuse Link Type Time-Current Response ................................................. 10-5
Figure 10-2 Various Fuse Time-Current Characteristics – Type QA Fuse Links ..................... 10-6
Figure 10-3 Maximum Short-Circuit Current for Insulated Copper Conductors .................... 10-10
Figure 11-1 Santee Cooper Overcurrent Relay Time-Current Curves ...................................... 11-2
Figure 11-2 Electrical Distribution System Simplified One-Line ............................................. 11-3
Figure 11-3 Bus Differential Protection Relays......................................................................... 11-4
Figure 11-4 Overcurrent Relays................................................................................................. 11-5
Figure 11-5 Main Breaker Coordination With Santee Cooper Relays ...................................... 11-7
Figure 11-6 Flagpole Feeder Coordination With Main Breaker ................................................ 11-8
Figure 11-7 HP Feeder Coordination With Main Breaker......................................................... 11-9
Figure 11-8 Feeder E/F Coordination With Main Breaker ...................................................... 11-10
Figure 11-9 Feeder D Coordination With Main Breaker ......................................................... 11-11
Figure 12-1 Recommended Flagpole Feeder Relay and G&W Switchgear VFI
Coordination ...................................................................................................................... 12-4
Figure 12-2 G&W Switchgear VFI Coordination With Downstream Switchgear Fusing ........ 12-5
Figure 12-3 Comparison of S&C Vista and G&W Switchgear VFI Settings ........................... 12-9
Figure 12-4 Various Fuse Time-Current Characteristics – Type SMU-20.............................. 12-10
Figure 12-5 Feeder E, F, and HP Coordination With Downstream Fused Switchgear ........... 12-14
Figure 12-6 Feeder C Relay Coordination With Overhead Fusing ......................................... 12-17
Figure 12-7 Feeder D Relay Coordination With Overhead Fusing ......................................... 12-18
Figure 13-1 Aurora Vulnerability Assessment Flowchart ......................................................... 13-2
Figure 13-2 Aurora Analysis for Building 204 Motor – Voltage Decay ................................... 13-4
Figure 13-3 Aurora Analysis for Building 204 Motor – Transient Torque Upon
Reenergization ................................................................................................................... 13-4
Figure 13-4 Aurora Analysis for Building 204 Motor – Motor Current Upon
Reenergization ................................................................................................................... 13-5
xx
Figure 13-5 Power Factor Variation – Total Base Demand ...................................................... 13-5
Figure 13-6 Harmonics of the Fundamental Frequency ............................................................ 13-6
Figure 13-7 Distorted 60 Hz Waveform (1st and 3rd Harmonics) .............................................. 13-7
Figure 13-8 Effect of Harmonics on the Sinusoidal Waveform ................................................ 13-7
Figure 13-9 Voltage Distortion Limits Specified in IEEE 519.................................................. 13-8
Figure 13-10 Current Distortion Limits Specified in IEEE 519 ................................................ 13-9
Figure 14-1 New Flagpole Feeder Switching Station ................................................................ 14-2
Figure 14-2 Preferred Transformer Configuration .................................................................... 14-4
Figure 14-3 Recommended Equipment Pad Ground Loop – Plan View ................................... 14-6
Figure 14-4 Recommended Equipment Pad Ground Loop – Elevation View........................... 14-6
Figure 14-5 Pad-Mounted Switch Design Without Spare Compartments ................................. 14-7
Figure 14-6 Voltage Regulators ............................................................................................... 14-12
Figure 14-7 Voltage Regulator Nameplate .............................................................................. 14-12
Figure 14-8 Voltage Regulator Load Adjustment ................................................................... 14-14
Figure 14-9 Voltage Regulator Load Adjustment – Close-Up ................................................ 14-14
Figure 14-10 Live-Front Transformers .................................................................................... 14-16
Figure 14-11 Live-Front Transformers .................................................................................... 14-17
Figure 14-12 Example of Low SF6 Gas .................................................................................. 14-19
Figure 15-1 Charleston AFB Power Demand – kVA ................................................................ 15-3
Figure 15-2 Distribution Transformers – Average Loading Histogram .................................... 15-5
xxi
LIST OF TABLES
Table 2-1 Charleston AFB Zone and Area Classification ........................................................... 2-8
Table 3-1 Transformer Data Mapping (uteletbk)......................................................................... 3-2
Table 3-2 Transformer Data Mapping (utelitfr)........................................................................... 3-4
Table 3-3 Transformer Attributes Table ...................................................................................... 3-5
Table 3-4 Power Poles Geobase Documentation ......................................................................... 3-6
Table 3-5 Pad-Mounted Switchgear Geobase Documentation .................................................... 3-7
Table 3-6 Sectionalizing Cubicle Geobase Documentation ........................................................ 3-8
Table 3-7 Electric Manhole Geobase Documentation ................................................................. 3-9
Table 3-8 Airfield Lighting Geobase Documentation ............................................................... 3-11
Table 3-9 Utility Undefined Feature Geobase Documentation ................................................. 3-12
Table 3-10 Storm Sewer Culvert Geobase Documentation ....................................................... 3-13
Table 3-11 Storm Sewer Headwall Geobase Documentation.................................................... 3-14
Table 3-12 Storm Sewer Manhole Geobase Documentation ..................................................... 3-15
Table 4-1 Short Circuit Current Available at Substation Input ................................................... 4-8
Table 4-2 Main Substation Overcurrent Relay Settings .............................................................. 4-8
Table 4-3 Differential Relay Settings .......................................................................................... 4-9
Table 5-1 Main Switching Station Circuit Breakers .................................................................... 5-5
Table 5-2 Overcurrent Relay Settings.......................................................................................... 5-7
Table 5-3 Voltage Regulators .................................................................................................... 5-10
Table 5-4 Feeder Descriptions ................................................................................................... 5-12
Table 5-5 Feeder Conductor Sizes ............................................................................................. 5-13
Table 5-6 G&W Switchgear Ratings ......................................................................................... 5-18
Table 5-7 Medium Voltage Conductor Sizes and Ampacity ..................................................... 5-22
Table 6-1 Individual Feeder Load Data for EasyPower Model – Peak Demand......................... 6-7
Table 6-2 Flagpole Feeder Load Data for EasyPower Model – Peak Demand ........................... 6-7
xxii
Table 7-1 Individual Feeder Load Data for EasyPower Model – Peak Demand......................... 7-3
Table 7-2 Substation Feeder Cross-Connect Summary ............................................................... 7-4
Table 7-3 Primary Distribution System Cross-Connect Capability ............................................. 7-4
Table 8-1 Short Circuit Current Available at Substation Input ................................................... 8-4
Table 8-2 Charleston AFB Short Circuit Currents On Feeders – Normal Operation .................. 8-5
Table 8-3 Primary System Fault Current Duties and Equipment Ratings ................................... 8-7
Table 9-1 Arc Flash PPE Categories ........................................................................................... 9-2
Table 10-1 Desired Electrical Protection and Coordination Criteria ......................................... 10-2
Table 10-2 Fuse Link Sizing Chart for Individual Transformers .............................................. 10-4
Table 11-1 Existing Santee Cooper Substation Overcurrent Relay Settings ............................. 11-1
Table 11-2 Overcurrent Relay Settings – Existing .................................................................... 11-5
Table 11-3 Overcurrent Relay Settings – Recommended........................................................ 11-12
Table 12-1 G&W Trip Setting Selection Chart to Provide Primary Protection for
Individual Transformers..................................................................................................... 12-2
Table 12-2 G&W Trip Setting Selection Chart to Provide Backup Protection for
Individual Transformers..................................................................................................... 12-3
Table 12-3 S&C Vista Trip Setting Selection Chart to Provide Primary Protection
for Individual Transformers ............................................................................................... 12-7
Table 12-4 S&C Vista Trip Setting Selection Chart to Provide Backup Protection
for Individual Transformers ............................................................................................... 12-8
Table 12-5 Fuse Sizing Chart to Provide Primary Protection for Individual Transformers .... 12-12
Table 12-6 Fuse Sizing Chart to Provide Backup Protection for Individual Transformers..... 12-12
Table 12-7 Fuse Link Sizing Chart for Individual Transformers ............................................ 12-16
Table 14-1 Planned Infrastructure Changes ............................................................................... 14-1
Table 14-2 Design Review Checklist ........................................................................................ 14-8
Table 14-3 Voltage Regulators ................................................................................................ 14-11
Table 14-4 Voltage Regulator Current Capability Versus Adjustment Range ........................ 14-15
Table 14-5 Live Front Transformers Recommended for Eventual Replacement .................... 14-16
Table 14-6 Unfused Pad-Mounted Distribution Transformers ................................................ 14-18
Table 15-1 Individual Feeder Load Data for EasyPower Model – Peak Demand..................... 15-3
Table 15-2 Flagpole Feeder Load Data for EasyPower Model – Peak Demand ....................... 15-4
Table 15-3 Feeder Cross-Connect Summary ............................................................................. 15-6
xxiii
Table 15-4 Charleston AFB Short Circuit Currents On Feeders – Normal Operation .............. 15-7
Table 15-5 Primary System Fault Current Duties and Equipment Ratings ............................... 15-8
xxiv
1
INTRODUCTION
1.1
Purpose of Study
The purpose of this project is to perform an electrical analysis of the Charleston AFB electrical
distribution system. The project scope is specified in Performance Work Statement to Perform
Electrical Distribution System Engineering Study and Energy Security Assessment, dated August
11, 2011.
The project activities consist of three distinct phases:
1. Phase 1: Conduct field surveys and testing to support a detailed “as-building” of the existing
primary electrical distribution system.
2. Phase 2: Perform an electrical power system analysis of the existing primary distribution
system, including power flow, short circuit, and electrical protection/coordination. The
electrical analyses are performed using EasyPower® electrical analysis software. The study
serves to baseline performance of the existing system in support of a detailed engineering
evaluation of the primary distribution system.
3. Phase 3: Conduct a detailed engineering evaluation of the primary electrical system to
establish future modifications, expansions, and upgrades to support future electrical
requirements and improve system efficiency, reliability, and maintainability.
A flowchart of project activities is shown in Figure 1-1.
1-1
Charleston AFB
Introduction
Phase 1
Conduct
Walkdowns
& Data Collection
Field Surveys
Equipment Photographs
Electrical As-Built Drawings
Load Data
Licensed Copy of EasyPower
Phase 2
Perform Electrical
Analysis of Existing
System
EasyPower Training
EasyPower Electrical Model
Perform Analysis of Existing
System
Issue Detailed Engineering Study:
Evaluate Load
Growth & Future
Requirements
Consolidate and
Evaluate
Information
Phase 3
Power System Study
Power Flow
Short Circuit
Coordination
Arc Flash
Detailed Evaluations
Electrical Drawings
Equipment Labeling
System Recommendations
Produce Detailed
Engineering Study
Figure 1-1
Flowchart of Project Activities
1.2
Power System Study
This report documents the results and findings of an engineering analysis of the existing
Charleston AFB electrical power distribution system. The analyses conducted include:

Power flow

Short circuit

Arc flash

Electrical protection and coordination

Motor starting
1-2
Charleston AFB
Introduction
The various analyses, as a group, provide design confirmation of the inherent ability of the
electrical power distribution system to perform reliably under normal and abnormal conditions.
The analyses are conducted using a specialized electrical analysis software program –
EasyPower®, a Microsoft Windows® graphical-based electrical power systems analysis program.
To conduct an engineering study of this type, an electrical model of the power system is first
developed. Once the model has been created and input into the software, the desired analyses
can be performed.
The following activities are completed as part of conducting the analyses:
following activities are completed as part of conducting the analyses:

Gather necessary site data, including a walkdown of the system configuration and collection
of service entrance loading data.

Obtain system data for the local utility power supply interface.

Using the walkdown data and utility interface data, develop an EasyPower model for the
electrical distribution system.

Perform a power flow analysis.

Perform short circuit calculations and evaluate the suitability of system equipment for the
available fault current, including normal and abnormal configurations.

Evaluate electrical overcurrent protective device protection and coordination.

Perform an arc flash analysis for the primary distribution system.

Assess harmonic distortion for the electrical distribution system.

Evaluate power factor for the electrical distribution system.

Provide new single line diagrams and electrical layout drawings of the primary electrical
distribution system, to include component sizes and nameplate information as appropriate.
Components include, but are not limited to, transformers, conductors, switchgear, reclosers,
large motors, circuit breakers, switches, sectionalizing cubicles, and fuses.

Provide a copy of equipment photographs obtained during the field walkdowns on a series of
DVDs.

Provide EasyPower software to the base and provide introductory training on the use of the
EasyPower software.

Provide the EasyPower model for the electrical model.
1-3
Charleston AFB
Introduction
1.3
Deliverables
The following deliverables are provided in support of this power system study:

Analysis report summarizing project findings and results.

Field walkdown data files – on DVD.

EasyPower electrical model for the primary distribution system.

Electronic copies of photographs taken of electrical equipment during field walkdowns – on
DVDs.

EasyPower software and associated training.

New electrical distribution system single-line drawings.

New electrical distribution system layout drawings.

Geobase documentation for the primary distribution system and airfield – on DVD.
1.4
Description of Analyses
Brief descriptions of the individual analyses conducted as part of this engineering study are
provided below.
1.4.1 Power Flow
A power flow study is commonly called a load flow study; the terms are used synonymously. A
power flow study determines voltages and power flow throughout the electrical distribution
system. The study provides insight into many aspects of system performance, including:

Adequacy of voltage levels throughout the system.

Current flow through all branches of the system.

The ability of generators to supply required load without exceeding their rating.

The ability of system equipment (such as switchgear, panels, transformers, or cables) to carry
the required load without exceeding any ratings.

Inappropriate or low reliability system lineups, including an evaluation of cross-connect and
alternate feed capability.

System expandability and choke points for load addition.

Equipment sizing and rating specifications for new/replacement equipment.
1-4
Charleston AFB
Introduction
Usually, a power flow study includes an analysis of system performance under various
conditions and operating modes. Different conditions of interest for Charleston AFB might
include:

Cross connect capability between the feeders (partial or full).

Proposed load additions.

System changes involving re-powering loads from a different feeder (load re-balancing).

Variations in transformer tap settings.
1.4.2 Short Circuit
Even the most carefully designed electrical power system can from time-to-time be subjected to
short circuits that produce potentially damaging levels of fault current. High levels of currents
that flow during an electrical fault can produce severe arc-blasts, overheating, and magnetic
forces that result in personnel injury, catastrophic equipment failure, fire, and/or prolonged down
time if the fault current exceeds equipment ratings. A short circuit study determines the
available fault current throughout the system. These fault currents are compared to the short
circuit rating of the equipment to confirm that the ratings are not exceeded.
A short circuit study provides a means to evaluate the following aspects of a power system:

The ability of system distribution equipment (such as switchgear, cables, disconnect
switches, panels, motor control centers, or bus ducts) to withstand the available fault current
without damage.

The ability of system protective devices (e.g., circuit breakers, fuses) to successfully interrupt
a fault without failing.

The adequacy of electrical protective device settings and sizes.

System lineups that result in unacceptable levels of fault current.

Baseline fault current levels for calculating arc flash energy levels.
Short circuit current levels for several types of faults are generally evaluated during a short
circuit study, including:

Three phase bolted fault – all three phases of a three-phase system short together with no
appreciable fault impedance (generally produces the highest available fault currents and
always produces the most fault energy).

Phase-to-ground fault – one phase of a three-phase system shorts to ground (also called a
line-to-ground fault or ground fault).
1-5
Charleston AFB
Introduction

Phase-to-phase fault – two phases of a three-phase system short together (also called a lineto-line fault).

Phase-to-phase-to-ground fault – two phases of a three-phase system short together and to
ground simultaneously (also called a double line-to-ground fault).
An evaluation of a system’s short circuit capability is critical to ensuring personnel and property
protection. This aspect of system performance can only be determined through design analysis
since day-to-day operation offers no information regarding the system’s ability to handle a
severe short circuit. Faults are an infrequent event; thus, an underrated system can operate for
years or even decades without any apparent problems. The shortcoming only becomes evident
when the system is subjected to a fault. Decades of industry experience confirm the risk to life
and property posed by underrated equipment. For this reason, all governing codes, standards,
and regulations clearly state the importance of not exceeding equipment short circuit ratings.
1.4.3 Arc Flash
The nature of equipment arcing failures and the rate of serious burn injuries in the electrical
industry have been studied for many years. Detailed investigation into the arc flash phenomena
by many researchers has led the NFPA to adopt arc flash guidelines in NFPA 70E, Electrical
Safety in the Workplace, for work on or near energized electrical equipment. IEEE-1584, IEEE
Guide for Performing Arc Flash Hazard Calculations, was issued to provide a calculation
methodology and equations for determining arc flash energies. Together, these guidance
documents add a new dimension to traditional electrical power analysis.
Arc flash hazard studies require knowledge of both the electrical power system and the system’s
electrical protection. Arc flash studies can be considered a continuation of the short circuit and
electrical coordination characteristics of a power system, since the results of each are required to
assess the incident energy associated with an arc flash event at any specific location in the power
system. Numerous design and configuration factors can affect the calculated arc flash energy
levels. Thus, development of an electrical analysis model for the purpose of arc flash
calculations requires a level of detail not generally included in past electrical modeling efforts.
An arc flash study accomplishes the following:

Calculates arc flash incident energy levels at key locations throughout the system.

Determines protective personal equipment (PPE) requirements based on arc flash analysis
results for specific work locations.

Evaluates potential equipment line-up or protective device setting changes that can reduce
the arc flash hazard at specific locations.

Identifies locations in which energized work cannot be conducted safely regardless of
available PPE.
UFC 3-560-01, Electrical Safety, O&M, states in Section 8-1, “Do not work on energized
electrical circuits operating at 50 V or more except when required to support a critical mission,
1-6
Charleston AFB
Introduction
prevent human injury, or protect property.” UFC 3-560-01 also explains the requirements
associated with working on energized circuits. An arc flash analysis is an integral part of this
process and will help establish the PPE requirements for the work location.
1.4.4 Electrical Protection and Coordination
A coordination study is a graphical analysis of a system’s electrical protective devices
(overcurrent relays, circuit breakers, and fuses). The term coordination comes from the basic
intent of the study, which is to evaluate how well a system’s overcurrent protective devices
coordinate with each other during an overcurrent condition (short circuit or overload) to isolate a
faulted circuit and protect other equipment from damage. The objective is for the protective
device closest to the fault to actuate before any other upstream protective devices actuate,
thereby limiting the portion of the system affected by the fault.
A properly protected and coordinated system will:

Rapidly isolate a faulted circuit at the closest possible point upstream of the fault, while
minimizing disruptions to unaffected portions of the system.

Minimize damage to the faulted circuit or equipment by rapidly removing it from service.

Minimize the possibility of damage to equipment upstream of the fault that “sees” the fault
current, but is otherwise unaffected.

Minimize the possibility of catastrophic equipment failure, fire, and personnel hazards.
Ensuring proper electrical protective device settings is important to maintaining a reliable and
safe electrical power distribution system. In many instances, the root cause of major power
outages, fires, and equipment failures can be traced back to an improperly coordinated system.
A review of electrical protection and coordination is considered a key element of this project.
1.4.5 System Cross-Connect Capability
The evaluation of system cross-connect capability is part of the power flow analysis, but it is
listed separately here because of its importance to system reliability. The system is evaluated
with respect to its ability to provide power through its various points of cross-connect. This type
of evaluation is important for the following applications:

Determine the impact of removing a single feeder supply from service.

Determine means of supplying power to individual loads when the normal source has been
lost.
1.4.6 Motor Starting
A motor starting study is also a specific type of power flow study. The objective of a motor
starting study is to confirm that the inrush current associated with starting a large motor does not
cause voltage at the motor’s terminals to drop below a level that prevents proper motor start.
1-7
Charleston AFB
Introduction
The study also checks whether the predicted voltage drop due to starting a motor is significant
enough to affect other loads.
A motor starting study is performed by conducting a power flow analysis with the motor of
interest modeled in a start condition. The power flow analysis results then provide predicted
voltages under the postulated motor start conditions. The voltages are compared to limits
established by the motor manufacturer to confirm acceptability. As a rule of thumb, terminal
voltages above 80 percent at the instant of motor start are generally acceptable.
1.4.7 Harmonics
Voltage and current harmonic data are obtained by field measurements as part of the walkdown
process. A harmonics analysis is conducted to evaluate the magnitude of distortion in the
electrical voltage and current waveforms that results from electronic loads either radiating and/or
conducting harmonics onto the power system. Distorted waveforms, if severe enough, can cause
problems to certain types of equipment. Detrimental effects associated with harmonics include:

Overheating of transformers.

Overheating of neutral conductors due to excessive current.

Inaccurate performance of protective relays.

Equipment malfunction.
In conducting a harmonics study, distortion of both the voltage and current waveform is
reviewed, with emphasis placed on voltage waveform distortion. Analytical harmonic studies
can be performed; however, they are quite sensitive to system parameters that are not always
easy to determine accurately. For an existing system, the best method of analyzing harmonics is
by recording measurements at the various points of concern.
System harmonics are specified as a percent of the total harmonic distortion (THD). For
example, a voltage THD of 2.1 percent means that 2.1 percent of the voltage waveform is
composed of frequencies other than the fundamental frequency (60 Hz).
1.5
Electrical System Modeling and Analysis Software
The electrical distribution system engineering study was conducted using EasyPower, a
Microsoft Windows graphical-based electrical power analysis program. With EasyPower, all
system modeling is performed in a graphical environment in which a one-line representation of
the electrical system is built. Behind the graphical one-line, the software establishes the “true”
electrical model of the system. The electrical model consists of an impedance (admittance)
network tied together through a matrix of analysis nodes. Figure 1-2 shows a typical EasyPower
user interface.
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Charleston AFB
Introduction
Figure 1-2
Typical EasyPower User Interface
An electrical model of the power distribution system is developed in the software and the
completed model serves as the basis for all analyses. In addition to the graphical one-line, the
software requires design and operating information about the various components in the system.
This data is entered by the user and is stored in a project database that is maintained by the
EasyPower software. A typical data entry screen is shown in Figure 1-3. The data entry window
shown is for a typical distribution transformer.
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Charleston AFB
Introduction
Figure 1-3
Typical EasyPower Data Entry Window
Creating an EasyPower electrical model is relatively straightforward once all the system data is
known. By far, the largest challenge and most time consuming effort in creating the system
model is obtaining the system configuration and component data. In many cases, it is only
necessary to know the make and model of a component because EasyPower has a built-in Device
Library for many common components. In this case, the user selects the make and model of the
component in the data entry screen and EasyPower fills in the required data parameters.
Once the electrical model is developed, EasyPower is a convenient and time effective tool for
conducting studies because the software allows virtually all key system parameters to be quickly
adjusted, including:

Opening and closing circuit breakers and switches.

Turning equipment on and off.

Varying load levels.

Adjusting pre-analysis voltage levels.

Changing transformer tap settings.

Changing circuit breaker trip settings.
The contingency analysis capability of the software is one of its most powerful features.
Proposed system changes can be quickly evaluated for suitability. In addition, different design
options can be compared with minimal effort. Contingency studies can also be conducted to
evaluate changes in operating modes. For example, it might be useful to evaluate temporary
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Charleston AFB
Introduction
power options for supplying a facility’s loads if the normal service transformer must be removed
from service for repair or replacement.
EasyPower analysis calculations are performed in accordance with current IEEE, NFPA, and
ANSI standards. NEMA, IEEE, and UL circuit breaker rating standards are incorporated into the
analysis algorithms, including adjustments to short circuit ratings based on system X/R ratios.
1.6
Analysis Process
The general activities associated with performing this type of engineering study are summarized
below:
Step 1: Collect Design Information

Electrical system drawings.

Electrical equipment information (technical manuals, specification sheets, test data, etc.).

System operating procedures and guidelines.

Utility interface parameters.

Past analyses and studies.

Historic load profiles.
Step 2: Conduct Field Surveys and Walkdowns

Confirm the as-built configuration of the system.

Verify to the extent possible electrical design information.

Collect data for equipment parameters not available from design documents.

Determine protective device settings and sizes.

Measure voltage, current, and power factor at strategic locations throughout the system to
establish baseline operating values.

Measure voltage and current harmonics at various locations throughout the system.

Visually assess the material condition of electrical distribution system equipment.
Step 3: Develop the EasyPower Electrical Model

Using design information and walkdown data, create the EasyPower one-line diagram.

Using design information and walkdown data, populate the electrical model database.
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Introduction
Step 4: Perform System Analyses

Determine operating modes and configurations of interest.

Perform and document power flow, motor starting, cross-connect, and load shed analyses.

Perform and document the short circuit analysis.

Perform and document the electrical protection and coordination evaluation.

Perform and document an arc flash analysis.

Review harmonic data collected during field surveys.
Step 5: Evaluate Analyses Results

Review analysis results.

Recommend design and/or operating changes (conceptual) to correct identified problems
and/or optimize system performance and reliability.

Summarize analysis results and recommendations in a final report.

Provide a copy of the EasyPower model for ongoing use in evaluating future modifications
and monitoring system performance.
1-12
2
DATA ACQUISITION AND MODEL DEVELOPMENT
Section 2 provides information regarding the field walkdown data acquisition and EasyPower
modeling process for Charleston AFB. The Database Report feature in EasyPower can be used
to review the modeling data for each component in the model.
2.1
Field Walkdowns
Field surveys and walkdowns were performed to (1) confirm the as-built configuration of the
electrical power system and (2) ensure accurate data for modeling. Electrical information was
acquired for the following electrical system equipment during the field walkdowns:

Utility substation equipment, including protective device settings.

Power poles, including electrical equipment associated with each pole. This includes
switches, transformers, risers to pad-mounted transformers, and associated equipment.

Distribution system conductors – overhead and underground.

Pad mounted switchgear, including protective device settings.

Distribution system transformers.

Accessible service entrance equipment, including protective device settings.
The goal was to determine the as-built design of the primary distribution system. The bulk of the
walkdown effort tended to focus on the distribution transformer for each facility, in which the
following information was acquired:

Source of electrical feed to the facility, including electrical protection, if applicable.

Transformer nameplate data.

Transformer configuration, including connection type and tap setting.

Conductor size and length on primary and secondary sides of the transformer.

Service entrance disconnect and protective device settings for larger distribution
transformers.
Figure 2-1 and Figure 2-2 show examples of the walkdown data sheets.
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Charleston AFB
Data Acquisition and Model Development
Figure 2-1
Example Walkdown Data Sheet – Transformers
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Charleston AFB
Data Acquisition and Model Development
Figure 2-2
Example Walkdown Data Sheet – Pad-Mounted Switchgear
In addition to collecting equipment data (make, model, size, settings, etc.) and confirming
connection relationships, electrical measurements were taken at strategic low-voltage locations
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Data Acquisition and Model Development
throughout the system. The measurements recorded include voltage, current, power factor, and
total harmonic distortion (THD). These measurements were typically taken on the secondary
side of accessible distribution transformers. The voltage, current, and power factor
measurements were used during development of the electrical model of the Charleston AFB
primary electrical distribution system. A Fluke 43B power quality analyzer was used for these
measurements.
The walkdown information was also used to develop the Charleston AFB primary electrical
distribution system one-line and layout drawings; these drawings have been provided as part of
the project deliverables. Refer to Section 2.7.
Photographs were taken of equipment during the walkdown process. These photographs have
been provided as part of the project deliverables. Refer to Section 2.8.
2.2
Inaccessible Equipment and Missing Data
During the initial project coordination meeting, inaccessible equipment was discussed in detail.
Most of the information necessary to create a complete and accurate electrical model for is
available from electrical drawings or was determined by field surveys/walkdowns. Examples of
component and configuration data not capable of being readily validated by walkdown include:

Distribution system transformers with missing nameplates or nameplates with missing data.

Pole-mounted transformers – inaccessible without the use of lift equipment. Also,
nameplates on older pole-mounted transformers are often illegible.

Distribution system fuse or cutout sizes – typically difficult to confirm without requiring a
partial (or complete) system outage, which was not planned for this project.

Fuse size for internal fuses in distribution system transformers or some pad-mounted
switchgear – cannot be confirmed without requiring extensive system outages, which was not
planned for this project.

Size and type of aerial lines – usually depends on available drawings and knowledge of
exterior shop personnel.

Size and type of some underground lines – might depend on available drawings and
knowledge of exterior shop personnel. In most cases, the conductor jacket labeling can be
read at installed switches or on the primary side of distribution transformers.
There is a point of diminishing returns in field verification beyond which data is acquired at great
expense without any real benefit to the electrical analysis. The selected scope of field
verification balances the need for accurate data with the real world difficulty of verifying
normally inaccessible equipment. No missing or estimated data was of a critical nature to the
project.
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Data Acquisition and Model Development
2.3
Equipment Naming Conventions
Equipment naming conventions matter. The following primary distribution system equipment
should have unique names that make sense to all users of the associated information:

Transformers – pole mount and pad mount.

Pad-mounted switchgear.

Sectionalizing cubicles.

Power poles.

Manholes and handholes.
Equipment names are used in the following documents or databases:

Geobase data – the primary database key should be the equipment name.

AutoCAD one-line drawings.

AutoCAD layout drawings.

EasyPower model.

Reports that rely on the above documents.
Equipment naming is considered an important part of the base-wide electrical safety program.
Civilian personnel, military personnel and contractors should have no doubt regarding their work
location and the equipment that is to be worked on.
This project developed a naming convention that is used across all documents provided as part of
this electrical distribution system engineering evaluation. This naming convention is similar to
the approach taken at over 40 other AFB power system studies. The primary distribution system
equipment has been named as follows:
Main Base Transformers

Transformers used for the main base are generally named to match the associated facility
number. For example, Transformer T78 supplies Building 78.

If a facility is supplied by more than one transformer, then a suffix is added to the name. For
example, Building 59 is supplied by Transformers T59A and T59B.

Pad-mounted transformers are identified by the prefix “T”.
identified by the prefix “TP”
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Pole-mounted transformers are
Charleston AFB
Data Acquisition and Model Development

Transformers not associated with a facility are provided a unique name. For example, a
street lighting transformer might be named T-LT1. A ramp lighting transformer might be
named T-Ramp1.
Pad-Mounted Switchgear

Pad-mounted switchgear were not renamed as part of this project for the main base. The
switchgear have existing names that have been maintained by this project. Note: The existing
names often imply the associated primary distribution feeder. Open points between feeders
can be moved, resulting in switchgear named for one feeder being energized by a different
feeder.

Sectionalizing cubicles followed a similar numbering method, such as J-C11. Sectionalizing
cubicles in housing are numerically numbered.
Power Poles

Power poles have an existing naming convention and are often already labeled with the
name. This naming convention was retained.
Electrical Manholes

Electrical manholes are named sequentially without any feeder reference. The manhole
names start at EM1, EM2, EM3, and continue to the last documented manhole. The ‘EM”
designation refers to electrical manhole and is intended to allow geobase personnel to
distinguish electrical manholes from other manhole types.
Overhead and Underground Lines

Electrical lines are not given a unique name for each line segment.

Overhead lines are shown on the electrical drawings as solid lines.

Underground lines are shown on the electrical drawings as dashed lines.
2.4
Electrical Model Overview
Within EasyPower, a model is made up of three basic elements, as shown in Figure 2-3 and
described below:
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Charleston AFB
Data Acquisition and Model Development
One-Line
Diagram
Database
Device
Library
Figure 2-3
EasyPower Model Elements

One-line diagram. The one-line diagram serves as the primary user interface. It is intended
to have the “look and feel” of a typical electrical one-line diagram. From a computational
perspective, the one-line diagram serves the important function of establishing analysis nodes
that represent all the branches of the electrical network. Each bus in the model is treated as
an analysis node.

Database. Each component in the one-line diagram has various attributes that quantify and
characterize the component. This information is needed by the software to perform the
various analyses. Component data is input by the user and is stored by EasyPower in a
database. The database is integral to the project file and cannot be accessed separately.

Device library. Each project file is linked to an EasyPower device library. The library is a
Microsoft Access database that contains data for commonly used power system equipment
and components. The library allows users to quickly populate equipment data fields since
only the equipment make and model need be entered. The device library can be modified by
the user to add components not included in the standard library.
The EasyPower project file for Charleston AFB is named Charleston AFB [Rev 0].dez. The
library file is named stdlib.mdb, and this file is accessible from the EasyPower main menu.
2.4.1 Base Parameters
Base system parameters must be established for each EasyPower Project. The base parameters
for the Charleston AFB study are listed below.
Base MVA:
10
Units:
US
Frequency:
60 Hz
Symbols:
ANSI
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Charleston AFB
Data Acquisition and Model Development
2.4.2 Analysis Areas and Zones
EasyPower allows the user to define Areas and Zones for the system buses so that filters can be
employed to run selective analyses. For example, in evaluating a proposed design change to a
specific feeder, it might be desirable to run a short circuit study for a portion of the system, and
not the entire system. By this approach, only the data applicable to that feeder would be
displayed or stored in text files. Table 2-1 shows the Charleston AFB model numbering scheme
for Areas and Zones.
Table 2-1
Charleston AFB Zone and Area Classification
Area
Zone
Description
1
1
Main Substation
2
1
Flagpole Feeder
3
1
Feeder A
4
1
Feeder B
5
1
Feeder C
6
1
Feeder D
7
1
Feeder E (Officer)
8
1
Feeder F (NCO)
9
1
Hunley Park Feeder
2.4.3 EasyPower Device Library
The equipment used is contained in the EasyPower default library (stdlib.mdb). For this reason,
a customized library was not created for the Charleston AFB model.
2.5
Modeling of Individual Components
2.5.1 Utility Connection
The local utility, Santee Cooper, provided technical information regarding the commercial
transmission and distribution system, including how it supplies Charleston AFB and the
available short circuit current at the point of supply. This information is provided in Section 4.
2.5.2 Buses
In the terminology of modeling, a bus is any point to which equipment is attached. All
equipment must be associated with a bus and conductor connection points must be to a bus.
Buses are designated by voltage class and are categorized based on equipment type. EasyPower
treats each system bus as a modeling connection point for analytical computations. Thus,
analysis results are provided for each bus. Not all buses are of interest; some only serve to
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Charleston AFB
Data Acquisition and Model Development
provide the connection point between cables and other equipment. For these situations, buses are
inserted in the model as analysis nodes. These nodes appear as “dots” in the model, as shown in
Figure 2-4. The identification (name) of each node can be displayed or suppressed depending on
the user’s preferences.
Analysis
Nodes
Figure 2-4
Example of EasyPower Analysis Node
Analysis results (per unit voltage and fault current) are suppressed on the one-line for these
analysis nodes, thereby allowing a less cluttered user interface. Although results are not
displayed for analysis nodes that have been reduced to “dots”, the results are readily available for
these locations by expanding the dot to a typical bus representation. Text reports provide results
for all buses. Analysis nodes are most often used for cases in which a component is connected to
a conductor. Cables (conductors) have a measurable impact on the calculated voltage drop and
short circuit current, and are therefore included in the model to obtain accurate results.
The designations used in the model for system buses are generally based on the distribution
transformers associated with the buses. For example, the service entrance bus for Transformer
T74 is named “B74.”
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Charleston AFB
Data Acquisition and Model Development
2.5.3 Feeders
The Base primary electrical distribution system consists of a combination of underground and
overhead distribution. Underground distribution conductor sizes were typically confirmed at
pad-mounted switchgear, sectionalizing cubicles, the primary side of distribution transformers,
or system design drawings. Overhead distribution conductor sizes were field confirmed with the
assistance of electrical shop personnel and historical documents.
Power pole data were recorded as part of the field verification effort, with the focus being the
information considered important for an electrical distribution system engineering evaluation.
The field walkdown results are tabulated in Volume 2 Appendix C. The following information is
provided in Volume 2 Appendix C:

Pole number – the unique number assigned to the pole.

Conductor size – the overhead conductor size on each side of the pole.

The presence of pole-mounted equipment.
 Fuse cutouts.
 Pole-mounted transformers.
 Riser to pad-mount transformer or underground distribution.
 Other equipment – identifies other equipment mounted on the pole such as switches or
capacitors.

Comments.
For the overhead system, a power pole is included as a bus in the model only if it is important to
the overall model. For example, a pole might be specified as a bus in the model for any of the
following reasons:

A tap on the pole feeds a single transformer or multiple transformers.

A lateral circuit from the pole supplies a feeder branch circuit.

The pole has equipment important to a power system study, such as switches or in-line fuses.

The conductor size changes at the pole.

An underground distribution starts or ends at the pole.

The pole is geographically significant.
Not all power poles are included in the electrical model. Indiscriminately including all poles in
the model would clutter the model with no additional benefit.
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Charleston AFB
Data Acquisition and Model Development
Poles are identified in the EasyPower model by the pole number. For example, pole D9 is
named P-D9 in the model. Pole identification numbers are also shown on the AutoCAD
drawings developed for the project.
Similar to the EasyPower model, the electrical one-line drawings only show poles that are
significant to the overall connection of the system. The electrical layout drawings show all
power distribution poles.
2.5.4 Transformers
2.5.4.1 Field Walkdown Data
Nameplate data were recorded for all accessible transformers, which generally applies to padmounted transformers. The field walkdown results are tabulated in Volume 2 Appendix B. The
following information is provided in Volume 2 Appendix B:

Identification number – a unique number assigned to each transformer.

Feeder – the primary distribution feeder that normally supplies power to the transformer.

Source – the closest source in the primary distribution system that provides power to the
transformer. For a predominantly overhead distribution system, this will often be the power
pole that has the riser feed to the transformer. For an underground system, this might be the
pad-mounted gear, sectionalizing cubicle, or other equipment used to provide primary power
to the transformer.

Manufacturer.

Primary and secondary voltage.

Primary and secondary connection – delta-wye, wye-wye, etc. (typically delta-wye for most
distribution transformers).

Rating – kVA rating.

Impedance.

Transformer class – typically OA (ONAN) for most distribution transformers.

Mounting – either pad-mount or pole mount.

Comments.
Not all of the above data could be obtained for inaccessible transformers. These data fields are
left blank in Volume 2 Appendix B.
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Charleston AFB
Data Acquisition and Model Development
Additional transformer data was acquired during the field walkdowns that is not included in
Volume 2 Appendix B. This additional information is provided in the Excel file provided in the
enclosed DVD.
Load measurements were also obtained at the secondary side of accessible transformers. Load
measurements were taken by a Fluke 43B power quality analyzer.
Transformer basic impulse level was typically 95 kV primary and 30 kV secondary for the
accessible transformers.
Photographs were taken of all transformers and of the nameplates of all accessible transformers.
These files are provided with the equipment photograph DVDs.
2.5.4.2 Transformer Modeling
Transformer characteristics (kVA rating, impedance, connection type, primary conductor size,
secondary conductor size, loading, and manufacturer’s data) were obtained by walkdown. The
following describes the data acquisition process:

Pad-mounted transformers were opened to obtain modeling data. Photographs were taken for
future reference.

Pole-mounted transformers could not be inspected. In these cases, the kVA rating was
obtained by visual inspection. The impedance is assumed for the EasyPower model based on
typical characteristics.

Whenever the transformer impedance is an assumed value, it is entered in the EasyPower
database as 2.999, 3.999, or 4.999, where the three-decimal 999 digits indicate that the
impedance is an assumed value.
Pad-mounted transformers usually contain internal fuses on the primary side. The principal
purpose of these fuses is to protect the transformer from a low-impedance internal fault. Fuse
sizes usually cannot be determined without taking the transformer out of service. If the fuse size
could be verified by labeling inside the transformer or other means, these fuses were included in
the model. The inclusion of transformer fuses in the model mainly applies to 1) transformers
using McGraw-Edison NX fuses in a live-front arrangement; or 2) Cooper and RTE transformers
where the fuse size is indicated on the nameplate or inside the door; or 3) transformers that
contained spare fuses inside the enclosure.
Transformer X/R ratios are the EasyPower calculated values, which are based on ANSI C37 and
C57 criteria, as appropriate. The X/R ratio is calculated based on the kVA rating and impedance
value obtained during the field walkdown.
Distribution transformers are operated in a delta–wye grounded configuration or a wye
grounded–wye grounded configuration, and have been modeled accordingly. Single-phase
transformers are typically connected in a grounded wye configuration. The ground connection is
a solid ground. The transformer grounding configuration is important for correct calculation of
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Charleston AFB
Data Acquisition and Model Development
zero-sequence current (ground current). The transformers are assumed to be of “core”
construction, which results in a slightly lower zero-sequence impedance.
2.5.4.3 Modeling Single Phase Transformers
Charleston AFB has over two hundred pad-mounted and pole-mounted single phase transformer
installations. The secondary side voltage is usually 240/120 volts.
An EasyPower power flow model is a single phase equivalent of a three phase system, with the
model expressed as a positive sequence network based on an underlying assumption of threephase characteristics. The entire model is treated as a balanced three phase system by
EasyPower, and EasyPower has no method by which it distinguishes between single phase and
three phase loads. This is why single phase loads are often modeled as simple lumped loads. It
helps that individual single phase loads are typically negligible in the overall power flow
analysis.
Because of the large number of installed single phase transformers, the electrical model was
developed with each single phase transformer specifically modeled. Although EasyPower treats
these transformers as if they are three-phase, this modeling limitation is considered minor,
mainly because each transformer has a minor effect on the system.
Pad-mounted single phase transformers are modeled based on nameplate data and field
verification. The primary side conductors are included. On the secondary side, one set of
conductors are used to establish the model. Pole-mounted transformers are modeled based on
their kVA rating and an assumed impedance. The secondary side conductor size for polemounted transformers is only estimated based on the transformer size.
2.5.5 Distribution System Switches, Knife Blades, and Cutouts
Primary distribution systems typically contain various types of equipment intended to allow
equipment isolation, feeder isolation, or cross-ties between feeders. The Charleston AFB
primary distribution system contains all of the following types of isolation devices.

Gang-operated air break (GOAB) switches.

Solid blade knife switches.

Fused cutouts.

Pad-mounted junction boxes, often referred to as sectionalizing cubicles.

Pad-mounted switchgear, typically containing a combination of fuses, switches, or vacuum
fault interrupters (VFIs).

Manhole equipment – load junctions or switches installed inside manholes.
All of the above equipment is included in the EasyPower model, including the fuse types and
sizes, if validated.
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Data Acquisition and Model Development
2.5.6 Medium Voltage Breakers and Protective Relays
Medium voltage circuit breakers are installed in the substation switchgear and in some facilities.
All breakers were field verified with respect to make, model, and ratings. The breaker
specifications are included in the EasyPower model so that their suitability with respect to short
circuit and continuous current capability can be evaluated. EasyPower automatically adjusts the
breaker interrupting rating based on nominal system voltage, as specified by ANSI C37 criteria.
EasyPower includes overcurrent relays in its modeling library and the protective relays have
been modeled using their existing settings.
2.5.7 Manholes
Manholes were included in the scope of the walkdown effort. Each accessible manhole had its
location recorded by GPS.
2.5.8 Service Entrance
2.5.8.1 Scope of Service Entrance Review
There is a point of diminishing returns in terms of field data acquisition of low voltage
equipment for a primary distribution system study. The service entrance was not field verified
for distribution transformers smaller than 300 kVA unless it was readily accessible.
The secondary side of small pole-mounted transformers is only estimated. The secondary side of
these small transformers has no practical effect on the primary distribution system.
2.5.8.2 Low-Voltage Breakers
Low-voltage breakers at each facility service entrance are included in the model if the facility
electrical room could be accessed. The facility service entrance panel was inspected to obtain
breaker interrupting and continuous current ratings. Make, model, size, and settings were
determined for a majority of the breakers during field walkdowns. In some cases, the exact
breaker model type could not be determined, usually because of the age of the breaker or because
of the panel configuration.
In several cases, the interrupting ratings could not be determined by visual examination of the
exposed breaker housing; however, it was not considered prudent to deenergize the facility solely
to determine the breaker rating, as the focus of the study is the primary distribution system.
Similarly, if the instantaneous setting of an adjustable breaker could not be determined, it was
assumed to be set to HIGH.
The conductors between the transformer secondary and the service entrance panel were also
included in the model because the 1) conductor resistance reduces the fault current magnitude
available at the breaker line terminals and 2) the conductor size and number of conductors
defines the available ampacity.
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Data Acquisition and Model Development
2.5.8.3 Fused Disconnects
Fused disconnect switches (safety switches) are also used for the service entrance disconnect
point. Nameplate ratings for the switches are included in the model, with fuse type and size
included for the time-current characteristic curves used in the coordination study. Some
disconnect switches could not be opened to verify fuse size. In these cases, representative fuse
types were specified based on the switch vintage, model, and rating.
2.5.8.4 Solid-State Trip Units
Some service entrance breakers use solid-state trip units. In some cases, the panel could not be
opened while energized to verify trip unit settings. In these instances, typical settings were used
with the instantaneous trip set to its maximum value. If there is ever a problem with
coordination at these locations, the EasyPower model provides a reasonable basis for adjusting
the as-found settings.
2.5.8.5 Loads
Loading at each facility was measured by a clamp-on ammeter when each pad-mounted
transformer was inspected. This loading is treated as a lumped load in the EasyPower model on
the transformer secondary at the service entrance bus.
In some cases, clamp-on measurements could not be taken, such as with pole-mounted
transformers. In these cases, the facility load was estimated based on typical building load and
average transformer percent loading across the Base.
The EasyPower total Base load was validated by reviewing local utility metering demand data.
The total Base loading included in the EasyPower model was deliberately specified on the high
end of historical Base peak demand to ensure an adequate evaluation of voltage drop and circuit
ampacity limitations. Section 6.3 describes this process.
2.5.9 Motors
The Charleston AFB electrical distribution system is more like a traditional commercial system
than an industrial system. There are no motors in the Base that can significantly influence the
primary distribution system. Consequently, motor loads do not have a significant effect on the
primary distribution system.
Larger low-voltage motors have been modeled to benchmark the maximum expected voltage
drop during motor starting. Air conditioning chillers have been modeled also to help distinguish
between times of peak demand and non-peak demand.
2.6
Model Database Summary
The Database Report feature in EasyPower can be used to review the modeling data for each
component in the model. The following summarizes the number of key components included in
the model:

Buses – 1,528
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Charleston AFB
Data Acquisition and Model Development

Transformers – 439

High voltage breakers – 13

Low voltage breakers – 162

Fuses (high and low voltage) – 401

Switches – 329

Relays – 23

Motors – 128

Overhead lines – 151

Cables – 969
2.7
Electrical Drawings
Electrical one-line and layout drawings have been provided as part of this project as follows:

Tabloid size versions of the one-line drawings and letter size versions of the layout drawings
have been included in Volume 2 so that they are readily available for review with this report.

D-size drawings have been provided separately in accordance with the SOW.

An oversized version of the layout drawing has been provided for use by the Exterior
Electrical Shop.

The electronic AutoCAD files are included in the enclosed DVD.
Feeder colors were selected for these drawings so that each feeder can be readily identified on
the drawings. The feeder colors are identified on the electrical drawings.
2.8
Equipment Photographs
Over 15,000 photographs were taken of system electrical equipment during the walkdown
process. These photographs have been provided with the report in a set of DVDs. The
photographs are stored in a series of file directories, sorted by equipment identification number.
Figure 2-5 shows an example of the directory structure.
2-16
Charleston AFB
Data Acquisition and Model Development
Figure 2-5
Equipment Photograph Directory Structure
2-17
3
GEOBASE DELIVERABLE OVERVIEW
Section 3 discusses the geobase deliverable, which is provided separately on a DVD.
3.1
GeoBase Electrical Equipment Data Files
Equipment data tables were developed for the following types of primary distribution system
equipment:

Transformers – pole-mounted and pad-mounted.

Pad-mounted switchgear.

Sectionalizing cubicles.

Power poles.

Manholes.
Primary distribution equipment positions were determined by resource grade GPS (Trimble
GeoXH). GIS GeoBase data was initially entered in a series of Excel files, which are contained
in the enclosed DVD. The conversion to a GeoBase-compliant GIS database was accomplished
using ESRI ArcGIS and the data is stored in the GeoBase directory in the enclosed DVD.
Common Installation Picture (CIP) data for structures and roadways were obtained from Base
personnel. The final product is delivered in ESRI personal geodatabase format and is intended
for viewing in ArcMap; the database is named Charleston.mdb and the ArcMap document file is
Charleston.mxd.
The SDSFIE specifications provide two transformer data tables, one of which (uteletbk –Table
3-1) is expected to be part and parcel of a geospatial layer, the other (utelitfr –Table 3-2) is a
‘supporting infrastructure’ table that is intended to be standalone yet have the capability to relate
back to the geospatial layer through an ID field. Neither of these table constructs sufficiently
reflect the data captured by a electrical distribution system engineering evaluation. The approach
taken here is use the geospatial layer (uteletbk) to hold the equipment locations and ID and then
to place the balance of collected data in its own table (transformer_attributes – Table 3-3). The
transformer_attribute table uses SDSFIE defined fields from both uteletbk and utelitfr in addition
to custom fields (allowed by SDSFIE) denoted by ‘EE_’. A relationship is created between the
two data tables based on the transformer ID which allows all of the data to be viewed together
seamlessly in ArcMap.
3-1
Charleston AFB
GeoBase Deliverable Overview
Notes:
1. Custom fields have been appended to the SDSFIE table structure for many feature types in
order to better describe these features. All custom fields are denoted with an ‘EE_’ prefix
and are detailed above.
2. All SDSFIE defined data elements in the transformer_attributes GeoBase deliverable retain
SDSFIE naming conventions and field definitions.
Table 3-1
Transformer Data Mapping (uteletbk)
elect_transformer_bank_point
(uteletbk)
OBJECTID
SHAPE
SUBTYPEID
tranbnk_id
map_id
meta_id
media_id
coord_id
date_instl
date_last
cond_d
dispostn_d
mount_d
pri_volt_d
sec_volt_d
no_trans
total_kva
phase_1_d
kva_1_d
no_tfrs_1
phase_2_d
no_tfrs_2
kva_2_d
circuit_id
substa_id
project_id
Mapping to GeoBase
Deliverable
system generated
system generated
populated in
elect_transformer_bank_point
(uteletbk)
populated in
elect_transformer_bank_point
(uteletbk)
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
3-2
Populated in Deliverable?
yes
yes
yes
yes
no
no
no (see transformer_attributes table)
no
no
no
no
no
no (see transformer_attributes table)
no (see transformer_attributes table)
no (see transformer_attributes table)
no
no (see transformer_attributes table)
no
no
no
no
no
no
no
no
no
Charleston AFB
GeoBase Deliverable Overview
elect_transformer_bank_point
(uteletbk)
Mapping to GeoBase
Deliverable
event_id
narrative
user_flag
instln_id
facil_id
grid_value
coord_x
coord_y
coord_z
tran_cap1
tran_cap2
tran_cap3
feeder_no
e_util_id
pcb_d
Populated in Deliverable?
no
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
populated in
transformer_attributes
3-3
no (see transformer_attributes table)
no
yes
no (see transformer_attributes table)
no
no (see transformer_attributes table)
no (see transformer_attributes table)
no
no
no
no
no (see transformer_attributes table)
no
no
Charleston AFB
GeoBase Deliverable Overview
Table 3-2
Transformer Data Mapping (utelitfr)
Transformer Table for utelitfr
OBJECTID
trans_id
media_id
date_manuf
dispostn_d
trf_type_d
tran_use_d
pri_volt_d
sec_volt_d
phas_ltr_d
no_phases
kva_rate
load_prcnt
cool_ty_d
instl_ty_d
fuse_ty_d
fuse_rate
tran_wt
weight_u_d
oil_cpcty
cpcty_u_d
manuf_id
model_no
serial_no
tranvlt_id
substa_id
tranbnk_id
instln_id
project_id
event_id
narrative
user_flag
owner_id
meta_id
facil_id
Mapping to GeoBase Deliverable
system generated
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in transformer_attributes
populated in elect_transformer_bank_point (uteletbk)
populated in transformer_attributes
populated in transformer_attributes
3-4
Charleston AFB
GeoBase Deliverable Overview
Table 3-3
Transformer Attributes Table
Transformer Attributes
OBJECTID
TRANS_ID
PRI_VOLT_D
SEC_VOLT_D
TRAN_WT
WEIGHT_U_D
OIL_CPCTY
CPCTY_U_D
MANUF_ID
SERIAL_NO
NARRATIVE
FACIL_ID
EE_source
EE_pri_con
EE_sec_con
EE_impedance
EE_class
EE_fuse_d
EE_date_manuf
EE_pri_cond
EE_live_fr_d
EE_feed_th_d
EE_tap_volts_d
mount_d
coord_y
coord_x
EE_tap_set
feeder_no
EE_sec_cond
EE_sec_cond_no
no_phases
total_kva
media_id
Populated in Deliverable?
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
yes
3-5
Charleston AFB
GeoBase Deliverable Overview
Table 3-4
Power Poles Geobase Documentation
electrical_pole_tower_point
OBJECTID
SUBTYPEID
pole_id
map_id
meta_id
media_id
coord_id
date_acqrd
cond_d
design_d
type_d
mat_d
pole_lgth
poleheight
dim_u_d
grounded_d
capped_d
manuf_id
instln_id
project_id
narrative
user_flag
facil_id
grid_value
treattyp_d
date_treat
coord_x
coord_y
coord_z
owner_id
p_class_d
antenna_id
area_size
area_u_d
perim
perim_u_d
EE_fco_d
EE_circuit_id
EE_equip_d
EE_polemount_d
EE_conductor
EE_arrestor_d
Populated in Deliverable?
system generated
yes
yes
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
yes
no
yes
no
no
no
no
no
yes
yes
no
no
no
no
no
no
no
no
yes
yes
yes
yes
yes
yes
3-6
Charleston AFB
GeoBase Deliverable Overview
Table 3-5
Pad-Mounted Switchgear Geobase Documentation
electrical_switch_point
OBJECTID
SUBTYPEID
switch_id
map_id
meta_id
media_id
coord_id
dispostn_d
instl_ty_d
swt_ty_d
swt_sta_d
switch_rat
voltage_d
switch_dim
dim_u_d
swt_weight
weight_u_d
no_phases
phas_ltr_d
no_switch
manuf_id
model_no
serial_no
sw_cub_no
circuit_id
substa_id
instln_id
project_id
event_id
narrative
facil_id
grid_value
coord_x
coord_y
coord_z
owner_id
e_util_id
fuse_size
EE_max_volt_d
EE_nominal_volt_d
EE_short_circuit_ka
EE_date_manuf
EE_oil_cpcty
EE_cpcty_u_d
Populated in Deliverable?
system generated
yes
yes
no
no
yes
no
no
no
no
no
yes
no
no
no
no
no
no
no
no
yes
yes
yes
no
yes
no
yes
no
no
yes
no
no
yes
yes
no
no
no
no
yes
yes
yes
Yes
yes
yes
3-7
Charleston AFB
GeoBase Deliverable Overview
Table 3-6
Sectionalizing Cubicle Geobase Documentation
electrical_pedestal_point
OBJECTID
ped_id
map_id
meta_id
media_id
coord_id
dispostn_d
manuf_id
model_no
serial_no
circuit_id
instln_id
project_id
event_id
narrative
user_flag
facil_id
grid_value
coord_x
coord_y
coord_z
e_util_id
EE_max_volt_d
EE_short_circuit_ka
EE_current
EE_date_manuf
EE_oil_cpcty
EE_cpcty_u_d
Populated in Deliverable?
system generated
yes
no
no
yes
no
no
yes
yes
yes
yes
yes
no
no
yes
no
no
no
yes
yes
no
no
yes
yes
yes
yes
yes
yes
3-8
Charleston AFB
GeoBase Deliverable Overview
Table 3-7
Electric Manhole Geobase Documentation
electrical_junction_point
OBJECTID
SUBTYPEID
elemnhl_id
map_id
meta_id
media_id
coord_id
dispostn_d
use_d
type_d
mat_d
no_cables
rim_elv
floor_elv
elv_u_d
mh_dia
dia_u_d
drain_ty_d
substa_id
instln_id
project_id
event_id
narrative
user_flag
facil_id
grid_value
manuf_id
coord_x
coord_y
coord_z
e_util_id
area_size
area_u_d
perim
perim_u_d
Populated in Deliverable?
system generated
yes
yes
no
no
no
no
no
yes
no
no
no
no
no
no
no
no
no
no
yes
no
no
yes
no
no
no
no
yes
yes
no
no
no
no
no
no
The electrical_cable_line feature class contains generalized locations of electrical cable group
lines and associated tabular data. Cable line locations were digitized based on pole, manhole,
switch and transformer locations as well as AutoCAD electrical layout drawings for general
reference. Tabular attribution was accomplished through the reference of AutoCAD one-line
electrical drawings.
3-9
Charleston AFB
GeoBase Deliverable Overview
Conductor size information is included for overhead and underground lines, wherever conductor
size could be determined. The electrical one-line drawings described in Section 2.7 also show
conductor sizes throughout the primary distribution system.
3.2
GeoBase Airfield Data Files
Data tables were developed for the following types of features found on the airfield:

Airfield lighting fixtures.

Electric manholes.

Stormwater culverts.

Stormwater headwalls.

Stormwater manholes.

Stormwater discharge points.

Undetermined manholes.
Airfield feature positions were determined by survey-grade RTK GPS (Trimble R6). The
GeoBase-compliant GIS database was produced using ESRI ArcGIS and the data is stored in the
GeoBase directory in the enclosed DVD. Common Installation Picture (CIP) data for airfield
surfaces were obtained from Base personnel. The final product is delivered in ESRI personal
geodatabase format and is intended for viewing in ArcMap; the database is named
Charleston.mdb and the ArcMap document file is Charleston.mxd.
Manholes found on the airfield were not opened. Where possible, the manhole system
association was determined by examining the manhole lid for indication of such, consultation
with Base personnel, and/or review of, and comparison to, existing maps of utility systems and
manhole locations. In situations where the manhole system association was unable to be
determined the positional and descriptive data has been stored as an ‘utility undefined feature’.
Additional information regarding data collection and processing methodology for each feature
type may be found in the FGDC compliant metadata supplied within the personal geodatabase.
Subsequent tables detail the SDSFIE attributes used for each feature type:
3-10
Charleston AFB
GeoBase Deliverable Overview
Table 3-8
Airfield Lighting Geobase Documentation
airfield_light_point
OBJECTID
SUBTYPEID
light_id
map_id
meta_id
media_id
coord_id
Last_repl
Light_use_d
luminesc
Color_d
user_flag
Instln_id
facil_id
grid_value
coord_x
coord_y
coord_z
Airfld_id
EE_bulb_watts
EE_mount_d
EE_manuf_id
EE_bulb_type_d
EE_direction_d
EE_narrative
Populated in Deliverable?
system generated
yes
yes
no
no
yes
no
no
yes
no
yes
no
yes
no
no
yes
yes
yes
no
yes
yes
yes
yes
yes
no
3-11
Charleston AFB
GeoBase Deliverable Overview
Table 3-9
Utility Undefined Feature Geobase Documentation
ut_undefined_feature_point
OBJECTID
SUBTYPEID
utfeat_id
map_id
meta_id
media_id
coord_id
coord_x
coord_y
coord_z
project_id
narrative
owner_id
poc_id
ground_elv
elev_u_d
mat_d
feat_typ_d
grid_value
instln_id
facil_id
user_flag
Populated in Deliverable?
system generated
yes
yes
no
no
no
no
yes
yes
yes
no
yes
no
no
no
no
no
no
no
yes
no
no
3-12
Charleston AFB
GeoBase Deliverable Overview
Table 3-10
Storm Sewer Culvert Geobase Documentation
storm_culvert_point
OBJECTID
culvert_id
map_id
meta_id
media_id
coord_id
coord_x
coord_y
coord_z
frcoord_x
frcoord_y
frcoord_z
tocoord_x
tocoord_y
tocoord_z
basin_id
area_size
area_u_d
perim
perim_u_d
grid_value
instln_id
facil_id
user_flag
owner_id
gat_type_d
drng_pat_d
slope_u_d
drng_zone
feat_name
mat_tex_d
slope_bot
inv_elv_2
inv_el_1
culv_lgth
lined_d
length_u_d
angle
canal_name
estuary
purpose
source
narrative
mat_d
Populated in Deliverable?
system generated
yes
no
no
no
no
yes
yes
yes
no
no
no
no
no
no
no
no
no
no
no
no
yes
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
yes
no
3-13
Charleston AFB
GeoBase Deliverable Overview
storm_culvert_point
critical_d
size_d
flow_type
verified_d
peak_flow
control
volt_req_d
Populated in Deliverable?
no
no
no
no
no
no
no
Table 3-11
Storm Sewer Headwall Geobase Documentation
storm_sewer_headwall_point
OBJECTID
sewrwal_id
map_id
meta_id
media_id
coord_id
instln_id
manuf_id
facil_id
feat_desc
user_flag
coord_x
coord_y
coord_z
sur_crs_id
feat_name
grid_value
frcoord_x
frcoord_y
frcoord_z
tocoord_x
tocoord_y
tocoord_z
owner_id
river_mile
poll_typ_d
top_elv
elv_u_d
project_id
feat_len
length_u_d
Populated in Deliverable?
system generated
yes
no
no
no
no
yes
no
no
no
yes
yes
yes
yes
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
3-14
Charleston AFB
GeoBase Deliverable Overview
Table 3-12
Storm Sewer Manhole Geobase Documentation
storm_sewer_junction_point
OBJECTID
SUBTYPEID
manhole_id
map_id
meta_id
media_id
coord_id
dispostn_d
use_d
type_d
mat_d
no_pipes
mh_width
mh_len
mh_dia
dim_u_d
rim_elv
invert_elv
elv_u_d
drain_ty_d
manuf_id
model_no
basin_id
stodcrg_id
instln_id
building_id
project_id
narrative
user_flag
facil_id
grid_value
coord_x
coord_y
Coord_z
owner_id
Populated in Deliverable?
system generated
yes
yes
no
no
no
no
no
yes
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
no
yes
yes
yes
no
3-15
4
UTILITY SUPPLY TO CHARLESTON AFB
Section 4 provides an overview of the utility supply to the Charleston AFB primary electrical
distribution system. The Charleston AFB primary distribution system is described in Section 5.
4.1
Utility Supply
Santee Cooper provides commercial power to Charleston AFB. The incoming transmission
system is designed for 115 kV operation and serves a substation located at Charleston AFB.
Figure 4-1 shows the substation. This substation is owned by Santee Cooper.
Transformer
#2
Transformer
#1
Circuit
Interrupter
Figure 4-1
Santee Cooper Substation at Charleston AFB
Figure 4-2 provides a one-line diagram of the Santee Cooper transmission and distribution
system for the supply to Charleston AFB.
4-1
Charleston AFB
Utility Supply to Charleston AFB
Carnes Crossroads
230 - 115 kV Sub
6837
6838 52
Mt. Holly
6839
0.684 Miles
5327
6879
10.96 Miles
5329
6878 52
6877
5317
5318
Circuit
Interrupter
5319
5311
GOAB
1200A
115 kV Bus
5301
CI
115 kV
Bus No. 1
52
262
Substation
Transformer T1
5331
GOAB
1200A
7.42 Miles
261
Figure 4-2
Santee Cooper Overall Distribution to Charleston AFB
4-2
5310
1200A
5333
1200A
5320
1200A
Station
Service
Substation
Transformer T2
North Charleston
115-12 kV Sub
263
5313
1200A
12 kV Bus
115 kV
South Bus
Charleston AFB
Switching
Station
Charleston AFB
Utility Supply to Charleston AFB
Figure 4-3
Santee Cooper One-Line Drawing – Substation Side
4-3
Charleston AFB
Utility Supply to Charleston AFB
Figure 4-4
Santee Cooper One-Line Drawing – Switching Station Side
4-4
Charleston AFB
Utility Supply to Charleston AFB
Figure 4-2 shows that two switches, 5317 and 5319, can be used to isolate a particular
transmission-side supply. These switches are located in the transmission line right-of-way area
on either side of Hill Blvd just outside of the substation. Figure 4-5 shows one of the switches.
Figure 4-5
Nearby Substation Isolation Switches
4.2
Substation Transformers
The substation contains two transformers. Transformer #2 is in service. Transformer #1 is out
of service and is an installed spare transformer.
The following provides the transformer data. Figure 4-6 shows the transformers.
Transformer #1
Manufacturer: Wagner Electric Corporation
Voltage:
110 – 12.47 kV
Rating:
12,000/16,000/20,000 kVA at 55ºC
13,500/17,900/22,400 kVA at 65ºC
OA/FA/FA
Impedance:
7.8%
Connection:
Δ – Y grounded
Tap setting:
B (112.75 kV – 12.47 kV)
4-5
Charleston AFB
Utility Supply to Charleston AFB
Tap range:
A (115.5 kV), B (112.75 kV), C (110.0 kV), D (107.25 kV), E (104.5 kV)
Transformer #2
Manufacturer: Ohio Transformer
Voltage:
110 – 13.09 kV (dual voltage capable at 4.36 kV)
Rating:
12,000/16,000/20,000 kVA at 55ºC
13,500/17,900/22,400 kVA at 65ºC
OA/FA/FA
Impedance:
7.31%
Connection:
Δ – Y grounded
Tap setting:
B (112.75 kV – 13.09 kV)
Tap range:
A (115.5 kV), B (112.75 kV), C (110.0 kV), D (107.25 kV), E (104.5 kV)
Notes:
1. Transformer #2 is a repaired RTE-ASEA transformer. The repair was completed in July
2001.
2. Although Transformer #2 has an OA/FA/FA rating of 13,500/17,900/22,400 kVA at 65ºC,
only one set of fans appear to be installed (refer to Figure 4-6).
Transformer
#1
Transformer
#2
Figure 4-6
Substation Transformers
4-6
Charleston AFB
Utility Supply to Charleston AFB
Figure 4-7
Santee Cooper Substation Transformer #1 Nameplate (Wagner)
Figure 4-8
Santee Cooper Substation Transformer #2 Nameplate (Ohio)
4-7
Charleston AFB
Utility Supply to Charleston AFB
4.3
Short Circuit Current
Santee Cooper provided the short circuit currents available at the substation input at 115 kV.
Table 4-1 provides a summary of the available short circuit currents. The available short circuit
current has increased by 1.6% from the 2003 level, which is a minor change. The substation
transformer secondary side short circuit current is almost identical to the 2003 calculated levels.
Table 4-1
Short Circuit Current Available at Substation Input
Voltage
Short Circuit Current
(amperes)
X/R Ratio
Three phase
115
11,632
5.7310
Single phase to ground
115
7,824
4.0357
Fault Type
4.4
Santee Cooper Relay Settings
Table 4-2 provides the relay settings for the transformers’ overcurrent protection. Phase
overcurrent protection is provided on the primary side of each transformer and neutral
overcurrent protection is provided on the secondary side of each transformer.
Table 4-2
Main Substation Overcurrent Relay Settings
Relay Settings
Transformer #1
Transformer #2
IAC53
IAC53
Tap
4
4
Time dial
6
6
Instantaneous pickup
None
None
CT ratio
200:5
200:5
IAC53
IAC53
Tap
5
5
Time dial
7
7
Instantaneous pickup
None
None
CT ratio
1000:5
1000:5
Phase Settings
Relay type
Neutral Settings
Relay type
Transformer protection is provided by GE 12BDD15B16A differential relays. The settings are a
little different for the two transformers as shown in Table 4-3 because of the different secondary
side CT ratio.
4-8
Charleston AFB
Utility Supply to Charleston AFB
Table 4-3
Differential Relay Settings
Relay Settings
Transformer #1
Transformer #2
12BDD15B16A
12BDD15B16A
CT ratio – high side
200:5
200:5
CT ratio – low side
1200:5
1500:5
Service tap – winding 1
3.2
4.2
Service tap – winding 2
8.7
8.7
Slope
25%
25%
Relay type
A bus differential relay has also been installed as part of the new switching station work in 2008.
According to Santee-Cooper documents, the relay is a SEL-587. Setting information was not
provided for this relay.
All Santee Cooper protective relays trip the primary-side circuit interrupter – an S&C Model
2040 circuit switcher rated for 1,200 amperes, short-time momentary current of 64,000 amperes,
and a one second current of 40,000 amperes. Figure 4-9 shows the circuit interrupter and Figure
4-10 shows the nameplate.
Circuit
Switcher
Transformer
#1
Circuit
Switcher
Controller
Figure 4-9
Santee Cooper Substation Circuit Interrupter
4-9
Charleston AFB
Utility Supply to Charleston AFB
Figure 4-10
Santee Cooper Substation Circuit Interrupter Nameplate
4.5
Charleston AFB Switching Station Supply
The Santee Cooper substation provides a single short overhead line to the Charleston AFB Main
Switching Station. The substation output passes through loadbreak Switch 5320 (shown on
Figure 4-11), which is the electrical boundary between the substation and the switching station.
Switch
5320
Figure 4-11
Santee Cooper Supply Line to Charleston AFB
4-10
Charleston AFB
Utility Supply to Charleston AFB
The Main Switching Station is owned by Charleston AFB. Refer to Section 5.2 for information
regarding the switching station.
4.6
Voltage Variation
The substation voltage is monitored on the secondary side of the transformers. During 2011, the
substation transformer secondary line-to-neutral normal operating voltage varied between 7,438
to 7,906 kV, with an average value of 7,691 kV. The line-to-line voltage variation was 12,882 to
13,693 kV, with an average value of 13,320 kV.
The Charleston AFB primary distribution system operates at 12.47 kV. Voltage regulators are
installed on each feeder to maintain voltage near this level. Refer to Section 5.2.4 for
information regarding this voltage regulation.
4-11
5
CHARLESTON AFB ELECTRICAL DISTRIBUTION
SYSTEM DESCRIPTION
Section 5 provides an overview of the Charleston AFB primary electrical distribution system.
5.1
Charleston AFB Overview
Charleston AFB is located north of Charleston, South Carolina (refer to Figure 5-1).
Charleston
AFB
Figure 5-1
Charleston AFB Location
Figure 5-2 shows an aerial view of the base. Charleston AFB is somewhat unusual in that it
shares its runway with the commercial Charleston airport. Airfield lighting is operated and
maintained by Charleston AFB personnel.
5-1
Charleston AFB
Charleston AFB Electrical Distribution System Description
Main Base
Area
Hunley
Park
Main Gate
Figure 5-2
Charleston AFB – Aerial View
Main
Substation
5-2
Charleston
Airport
Charleston AFB
Charleston AFB Electrical Distribution System Description
5.2
Charleston AFB Main Switching Station
One switching station supplies all primary distribution for Charleston AFB. The switching is
located adjacent to the Santee Cooper substation and is supplied by one short overhead line on
bus structure from the substation. Figure 5-3 shows the switching station. Charleston AFB owns
this switching station and Santee Cooper owns the associated substation.
Figure 5-3
Charleston AFB Main Switching Station
The Main Switching Station contains the following equipment:

One main circuit breaker with bypass switch.

Five feeder circuit breakers.

Voltage regulators on the output of each feeder.

Isolation knife blades on the input of each feeder circuit breaker and on the output of each
voltage regulator.

Bypass switch on each feeder that allows each feeder to be supplied by a different feeder via
a transfer bus located on the overhead bus structure.

Sectionalizing cubicles inside the Main Switching Station area for each feeder. This is the
first disconnect point for each feeder downstream of the voltage regulator.
Figure 5-4 provides a simplified one-line drawing of the Main Switching Station.
5-3
Charleston AFB
Charleston AFB Electrical Distribution System Description
Santee Cooper
Substation
5319
200/5
CI
5318
Circuit
Interrupter
1200/5
1000/5
5311
5313
51
51N
Substation
Transformer T2
200/5
M3
Blades
51
52
Main
5333
51N
12.47 kV Main Bus
M1
Blades
Transfer Bus
51N
Station
Service
F1 - Blades
1000/5
5331
51
5320
12.47 kV Bus
5301
115 kV Bus
5317
M5
Bypass
Switch
Substation
Transformer T1
50/
51
500/5
F7
Switch
Charleston AFB
Switching Station
52
F
D1 - Blades
E1 - Blades
50/
51N
50/
51
500/5
E7
Switch
52
50/
51N
E
500/5
D7
Switch
50/
51
C1 - Blades
50/
51N
52 D
50/
51
500/5
C7
Switch
52
A1 - Blades
50/
51N
Flagpole
50/
51
500/5
A7
Switch
52
50/
51N
Hunley Park
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
F3 - Blades
E3 - Blades
D3 - Blades
C3 - Blades
A3 - Blades
F Feeder
E Feeder
D Feeder
Flagpole
Feeder
To Flagpole Feeder
Switching Station
Figure 5-4
Electrical Distribution System Simplified One-Line
5-4
Hunley
Park
Feeder
Charleston AFB
Charleston AFB Electrical Distribution System Description
5.2.1 Circuit Breakers
One main circuit breaker and five feeder circuit breakers are installed. Table 5-1 provides the
breaker nameplate data for these circuit breakers.
Table 5-1
Main Switching Station Circuit Breakers
Breaker Data
Main Breaker
Feeder Breakers
Square D
Square D
Type
FVR1201120A
FVR1201120A
Voltage
15.5
15.5
Continuous current
2,000
2,000
Interrupting current
20,000
20,000
Interrupt time
3 cycles
3 cycles
January 2005
May 2007
Charging motor voltage
240 VAC
240 VAC
Trip coil voltage
250 VDC
250 VDC
Bushing CT – high side
1,200:5 MR
1,200:5 Tap
N/A
Bushing CT – high side
2,000:5 MR
1,200:5 Tap
2,000:5 MR
500:5 Tap
Bushing CT – low side
2,000:5 MR
2,000:5 Tap
1,200:5 MR
1,200:5 Tap
Manufacturer
Manufacturing date
The main breaker high side CTs are used for overcurrent protection and for bus differential
protection. The main breaker low side CTs are used for bus differential protection.
The feeder breaker high side CTs are used for overcurrent protection. The feeder breaker low
side CTs are used for bus differential protection.
Figure 5-5 shows the main circuit breaker nameplate and Figure 5-6 shows a feeder circuit
breaker nameplate.
5-5
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-5
Main Circuit Breaker Nameplate
Figure 5-6
Feeder Circuit Breaker Nameplate
5-6
Charleston AFB
Charleston AFB Electrical Distribution System Description
5.2.2 Overcurrent Protection
Overcurrent protective relays provide phase and ground fault protection for the main and feeder
breakers. The relays are GE IFC53 relays for the main breaker and GE IFC77 relays for the
feeder breakers. Figure 5-7 shows the relays and Table 5-2 provides the relay settings.
Figure 5-7
Overcurrent Relays
Table 5-2
Overcurrent Relay Settings
Relay Setting
Main
Feeder F
(NCO)
Feeder E
(Officers)
Feeder D
Flagpole
Feeder
Hunley
Park
Feeder
IFC53A1A
1 – 12
5
5
IFC77B1A
1 – 12
5
3
IFC77B1A
1 – 12
5
3
IFC77B1A
1 – 12
6
5
IFC77B1A
1 – 12
7
5
IFC77B1A
1 – 12
5
3
None
Disabled
Disabled
63
56
35
IFC53A1A
1 – 12
1.5
4
None
1200:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
38
500:5
IFC77B2A
0.5 – 4
2.0
8
35
500:5
IFC77B2A
0.5 – 4
1.2
4
28
500:5
Phase Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
Ground Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
CT ratio
5-7
Charleston AFB
Charleston AFB Electrical Distribution System Description
Notes:
1. Relay settings were obtained from the CEMIRT 2011 calibration report, which is available in
the enclosed DVD.
2. The IFC53 relay has very inverse characteristics. The A1A version used for phase and
ground protection has a tap range of 1 to 12, with no instantaneous trip unit.
3. The IFC77 relay has extremely inverse characteristics. The B1A version used for phase
protection has a tap range of 1 to 12, with an instantaneous trip range of 6 to 150. The B2A
version used for ground protection has a tap range of 0.5 to 4, with an instantaneous trip
range of 2 to 50.
Bus differential protection is provided by GE PVD21B1A relays. The PVD21 relay is a single
phase, high-speed, high-impedance, voltage-operated relay designed to provide protection in bus
differential schemes. The PVD21 utilizes the same operating principle (high impedance voltage)
as the earlier PVD models, but provides faster operating speeds and higher seismic capabilities.
The CT inputs to the relays are all 1,200:5 ratio and the relays are set on low.
Figure 5-8
Bus Differential Protection Relays
5.2.3 Circuit Breaker Reclosing
A Basler BE1-79M reclosing relay is installed on each feeder circuit breaker. Reclosing is
turned off and is danger-tagged off for Feeders E, F, HP, and Flagpole because these feeders are
predominantly underground. Reclosing is allowed for Feeder D because it is predominantly
overhead. Figure 5-9 shows the Feeder D reclosing relay.
5-8
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-9
Basler Reclosing Relay
5.2.4 Voltage Regulation
Single phase voltage regulators are installed on the output of each feeder breaker. Figure 5-10
shows the voltage regulators and Figure 5-11 shows a typical nameplate. Table 5-3 provides the
nameplate information and the voltage regulation settings.
Figure 5-10
Voltage Regulators
5-9
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-11
Voltage Regulator Nameplate
Table 5-3
Voltage Regulators
Item
Feeder F
(NCO)
Feeder E
(Officers)
Feeder
D
Flagpole
Feeder
Hunley Park
Feeder
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
Siemens
JFR
3-1 phase
250
7620 ± 10%
7200
Siemens
JFR
3-1 phase
333
7620 ± 10%
7200
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
219
219
328
437
219
OA, 55°C
OA, 55°C
OA, 55°C
OA, 55°C
OA, 55°C
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Voltage Regulator
Manufacturer
Model
Type
Rating (kVA)
Voltage
Voltage setting (nominal)
Maximum rated current
(amperes)
Class
Voltage Control Unit
Manufacturer
Model
Voltage setting
Bandwidth setting
Time delay (seconds)
5-10
Charleston AFB
Charleston AFB Electrical Distribution System Description
Section 14.3 discusses limitations of these voltage regulators; this discussion has been retained
from the 2009 power system study. However, base personnel have acquired replacement voltage
regulators and they are awaiting installation.
5.2.5 Feeder Transfer Capability
As shown on Figure 5-5, a transfer bus is included in the switching station design. During
normal operation, the main bus supplies the input to each feeder circuit breaker, which then
supplies each feeder through dedicated voltage regulators. The output of each set of voltage
regulators includes a normally open switch that can be closed to energize the transfer bus.
5.3
Primary Distribution Feeders
5.3.1 Overview
The Charleston AFB primary distribution system consists of overhead and underground
distribution. The following summarizes general characteristics of the primary distribution
system configuration:

The main part of the base is a mixture of overhead and underground distribution. The main
portion of the main base distribution often uses only 1/0 awg copper conductors.

The overhead distribution represents a substantial portion of the base electrical distribution –
there are 264 power poles after completion of the most recent (in progress) underground
distribution projects. All poles are wood construction.

The underground distribution has been built with a combination of pad-mounted switchgear,
sectionalizing cubicles, and manholes.

There are 123 pad-mounted switchgear, 177 sectionalizing cubicles, and only a few power
manholes.
Charleston AFB has five primary distribution feeders and one feeder (Flagpole Feeder) is treated
as three feeders at a second downstream switching station. Table 5-4 provides a brief summary
of each feeder.
5-11
Charleston AFB
Charleston AFB Electrical Distribution System Description
Table 5-4
Feeder Descriptions
Feeder
Number
Description
Flagpole
The Flagpole Feeder supplies the Flagpole Feeder Switching Station. At this
location, the Flagpole Feeder splits into three feeders, referred to as A, B, and
C Feeders.
D
Feeder D is the largest feeder geographically and supplies most of the main
base away from the flightline area. Serves facilities along Davis Drive
and Arthur Drive. Also, supplies the Base Exchange and Commissary
area.
E
Feeder E was originally referred to as the “Officers Feeder”. This feeder
supplies housing to the north of Hill Blvd.
F
Feeder F was originally referred to as the “NCO Feeder”. This feeder
supplies housing to the south of Hill Blvd.
HP
The Hunley Park Feeder was originally referred to as the “Navy Feeder”
because the Navy owned this area. This feeder supplies housing in Hunley
Park, which is located outside of the main base across Dorchester Road.
5.3.2 Initial Feeder Conductor Size
The following summarizes the conductor sizes used on each feeder.
Note: The information provided below includes the in-progress construction in which Feeder A
is entirely converted to underground distribution and the first portion of Feeder B is converted to
underground distribution.
5-12
Charleston AFB
Charleston AFB Electrical Distribution System Description
Table 5-5
Feeder Conductor Sizes
Feeder
Number
Flagpole
Description
Flagpole Feeder is entirely underground until it reaches the Flagpole Feeder
Switching Station. It starts with 500 kcmil copper conductors until the first
pad-mounted switch, SW-FP-1. From there, two parallel runs of 500 kcmil
conductors are routed to the Flagpole Feeder Switching Station.
Feeder A – entirely underground with 500 kcmil copper conductors for the
main distribution.
Feeder B – entirely underground with 500 kcmil copper conductors for the
main distribution.
Feeder C – 4/0 awg copper conductors initially for underground distribution
with 1/0 awg thereafter; 1/0 awg copper conductors for overhead distribution.
D
Feeder D starts with an underground distribution of a single set of 500 kcmil
copper conductors. Two parallel runs of 500 kcmil conductors are routed
from SW-D7-1 to SW-D6, where it returns to a single set of 500 kcmil
conductors. The downstream overhead along the main routes use 1/0 awg
copper and 3/0 awg ACSR conductors.
E
500 kcmil copper conductors are used along the main route.
F
500 kcmil copper conductors are used along the main route.
500 kcmil copper conductors are used along the main route until reaching the
switchgear in Hunley Park. Two parallel runs of 500 kcmil conductors are
routed from S-1H to the Hunley Park area.
HP
For the underground distribution, laterals along the main runs typically use either #2 or 1/0 awg
copper conductors.
5.4
Flagpole Feeder Switching Station
The Flagpole Feeder Switching Station was replaced in the summer 2012 with a new switching
station. The new switching station uses pad-mounted switchgear to split the Flagpole Feeder
into three sub-feeders – A, B, and C. Figure 5-12 shows the switchgear and Figure 5-13 provides
a one-line of the new arrangement. The Flagpole Feeder starts with a single set of 500 kcmil
conductors, which terminates at the first pad-mounted switchgear SW-FP-1. The Flagpole
Feeder leaves SW-FP-1 as two parallel 500 kcmil circuits until reaching the Flagpole Feeder
Switching Station.
5-13
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-12
Flagpole Feeder Switching Station – Placed in Service Summer 2012
Figure 5-13
Flagpole Feeder Switching Station Configuration
5-14
Charleston AFB
Charleston AFB Electrical Distribution System Description
5.5
Distribution System Switchgear
Various pad-mounted switchgear have been installed as part of the underground distribution
design. The following switchgear types are used:

S&C fused switchgear – PME style

ABB fused switchgear

S&C Vista VFI switchgear

G&W VFI switchgear

Shallbetter switchgear
The fused switchgear all use S&C SMU-20 standard speed fuses or equivalent. Figure 5-14
shows a typical switchgear and Figure 5-15 shows the fuse characteristics.
Figure 5-14
S&C Fused Switchgear
5-15
Charleston AFB
Charleston AFB Electrical Distribution System Description
3 4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000
2
3 4 5 6 7 8 9 10000 2
700
700
500
400
300
500
400
300
SM U-20
15E
200
200
SM U-20
40E
100
100
SM U-20
65E
70
50
40
30
70
50
40
30
SM U-20
100E
20
10
TIM E IN SECONDS
1000
20
10
SM U-20
125E
7
5
4
3
7
5
4
3
SM U-20
150E
2
2
1
1
SM U-20
175E
.7
.5
.4
.3
.7
.5
.4
.3
SM U-20
200E
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
.01
2
3 4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000
CURRENT IN AMPERES AT 12470 VOLTS
Figure 5-15
S&C SMU-20 Fuse Characteristics
5-16
2
3 4 5 6 7 8 9 10000 2
.01
TIM E IN SECONDS
1000
2
Charleston AFB
Charleston AFB Electrical Distribution System Description
Some switchgear contains SF6 vacuum fault interrupters (VFIs), provided by S&C or G&W.
Figure 5-16 shows an example. Some switches have low SF6 gas level; refer to Section 14.6 for
recommendations.
Figure 5-16
G&W VFI Switchgear
Figure 5-17
G&W VFI Switchgear – Low Gas Level
The G&W switchgear is used for cross-ties between several primary distribution feeders. Table
5-6 lists the ampacity ratings of this switchgear, which is an important consideration as feeders
are upgraded.
5-17
Charleston AFB
Charleston AFB Electrical Distribution System Description
Table 5-6
G&W Switchgear Ratings
Feeder
Model
Main Switch
Rating
(amperes)
SW-A0
A
PVI52-376
630
630
SW-B0
B
PVI41-376
630
630
SW-B2
B
PVI62-376-12-SP
600
200
SW-B3
B
PVI63-376-12-SP
600
200
SW-B6
B
SPRAM44-376-40PI
600
600
SW-C0
C
PVI41-376
630
630
SW-C1
C
PVI42-376-12-9
600
200
Cross-tie to Feeder A at J-A1.
Conductor size is 1/0 awg.
SW-C2
C
PVI51-376-12-SP
600
200
Cross-tie to Feeder D at Pole D90.
Conductor size is 1/0 awg.
SW-C3
C
PG6-44-15
600
600
Cross-tie to Feeder B at SW-B6.
Conductor size is 4/0 awg.
SW-C4
C
SPRAM44-376-40PI
600
600
Cross-tie to Feeder B at SW-B5A.
Conductor size is 500 kcmil.
SW-D1
D
PDS42-376-12-9
600
200
SW-D2
D
PVI42-376-12-9
600
200
SW-D3
D
222222/702
600
600
SW-D4
D
SPRAM44-376-40PI
600
600
SW-D5
D
SPRAM44-376-40PI
600
600
Switch ID
5-18
Tap Rating
(amperes)
Comments
Cross-tie to Feeder C at SW-C3.
Conductor size is 4/0 awg.
Cross-tie to Feeder A at SW-A1.
Conductor size is 500 kcmil.
Charleston AFB
Charleston AFB Electrical Distribution System Description
5.6
Underground Conductor Ampacity
5.6.1 Reference Information
NFPA 70, National Electrical Code (NEC), provides the basis for conductor ampacity. NEC
Figure 310.60 provides basic underground duct configurations to consider (see Figure 5-18). As
more sets of conductors are installed in a common duct bank, the ampacity of each set of
conductors has to be derated for the additional heat loading of multiple conductors.
Figure 5-18
NEC Figure 310.60 – Cable Installation Configurations
Figure 5-19 and Figure 5-20 provide Okonite data regarding conductor capability as a function of
number of circuits. This information matches NEC Table 310.77.
5-19
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-19
Okonite Data – One Circuit
5-20
Charleston AFB
Charleston AFB Electrical Distribution System Description
Figure 5-20
Okonite Data – Multiple Circuits
Using the above information, Table 5-7 provides the ampacity values used for this electrical
distribution system engineering evaluation.
5-21
Charleston AFB
Charleston AFB Electrical Distribution System Description
Table 5-7
Medium Voltage Conductor Sizes and Ampacity
Conductor Size
Underground
Duct
Ampacity –
One Circuit
(amperes)
Approximate
Derated
Ampacity –
Two Circuits
(amperes)
Approximate
Derated
Ampacity –
Three Circuits
(amperes)
#2 CU
155
140
130
1/0 CU
200
185
165
2/0 CU
230
210
185
4/0 CU
295
265
240
500 MCM CU
465
415
370
Notes:
1. Underground conductor ampacity is based on NEC and Okonite data at 90°C, which is the
typical temperature limit of the duct materials. The values used are also consistent with the
more detailed tables provided in IEEE 835, IEEE Standard Power Cable Ampacity Tables.
2. The above values assume that all circuits are fully loaded to the designated values. The
limits vary with the number of feeders in a common duct bank in service.
3. Derated ampacity for two circuits in a common duct bank is estimated as the linear average
of the one and three circuit values.
4. This table does not apply to direct buried conductors.
5.6.2 Feeder Ampacity
Feeders use 500 kcmil copper conductors for the main run for each feeder originating at the Main
Switching Station. With the completion of the recent underground construction, Feeder A and B
use 500 kcmil copper conductors for the main run. Feeder C is limiting with 1/0 awg copper
conductors for the underground distribution. Smaller conductors, #2 to 1/0 awg, are typically
used on lateral circuits.
The overhead distribution uses 1/0 copper or 3/0 ACSR for the main runs on each circuit. These
conductors in air are not limiting with respect to feeder capability.
5-22
6
POWER FLOW ANALYSIS
Section 6 provides the power flow analysis. The ability to cross-connect feeders without
exceeding feeder ampacity limits is addressed in Section 7.
6.1
Purpose of Power Flow Analysis
A power flow study ensures that an electrical power system is fundamentally sound and capable
of performing its design function. The principal objectives of the power flow analysis are:

Determine system voltages under normal and abnormal operating modes. Confirm voltage
drops throughout the system are within acceptable limits.

Determine real and reactive power flow (current flow) throughout the system. Confirm that
overload conditions do not exist.

Evaluate system growth potential with respect to distribution capacity.
Section 1 provides additional background information about power flow studies. This section
provides a summary of the EasyPower power flow analysis. Volume 2 Appendix E contains a
complete report of the base case power flow analysis, including:

Transformer overload summary.

Line overload summary – overhead lines and underground cables.

Power flow calculation output.
The Charleston AFB electrical model is a complete model of the primary distribution system.
With this model, the Base has the ability to generate future graphical and text outputs covering
all locations in the system. The model can be used to assess the viability of future load additions
or contingency line-ups. Text reports and on-screen presentation of power flow results can be
customized to accommodate individual user preferences.
6.2
Viewing the Power Flow Analysis Results in EasyPower
The EasyPower model is provided in the enclosed DVD, with the name Charleston AFB
[Rev 0].dez. A typical EasyPower power flow display is shown on Figure 6-1.
6-1
Charleston AFB
Power Flow Analysis
Figure 6-1
Typical EasyPower Power Flow Result
Referring to Figure 6-1, the interpretation of a typical EasyPower power flow display is as
follows:

Transformer T515 is designed for 12.47 kV on the primary and 480 volts on the secondary.

The primary current flow into Transformer T515 is 53.54 amperes.

The secondary current flow out of Transformer T515 is 1390.85 amperes.

The voltage magnitude on the secondary of Transformer T515 is 0.97 per unit, corresponding
to 467 volts (0.97 × 480 = 467).

The total load on Transformer T515 is 1051.17 kVA at a 0.95 power factor plus one chiller
operating at 76.49 kVA at a 0.82 power factor.
The power flow results are best viewed within EasyPower. As part of this project, EasyPower
training has been provided to Charleston AFB personnel to facilitate this preferred method of
viewing analysis results. A tabular printout of the base case is provided in Volume 2
Appendix E.
6-2
Charleston AFB
Power Flow Analysis
6.3
Electrical Power Consumption and Demand
As part of the model development for the power flow analysis, load estimates are required
throughout the power system. This was accomplished primarily by 1) acquiring service entrance
load measurements throughout the power system, 2) obtaining feeder load measurements during
periods of peak demand, and 3) obtaining utility revenue metering data. The goal of the power
flow analysis load estimates was to establish a total system loading near the high end of the peak
demand. And, it is important that the load be properly distributed along substation feeders so
that the power flow analysis results are meaningful. For this model, the metering data was used
as the guide for total system load, with the individual field measurements used to distribute load.
6.3.1 Power Demand Data – Total Base
Santee Cooper provided the base power demand metering data for the period from 2004 to early
2012. The following summarizes the information provided in the following figures.

Figure 6-2 shows the total power demand for the Main Substation and Figure 6-3 shows the
equivalent current.

Figure 6-5 shows the daily variation in power demand during a period of peak demand.

Figure 6-6 shows the power factor variation for the total base power demand.

Figure 6-4 shows the monthly peak demand.
20,000
Total Power (kVA)
16,000
12,000
8,000
4,000
0
Jan‐04
Jan‐06
Jan‐08
Date
.
Figure 6-2
Main Substation Power Demand – kVA
6-3
Jan‐10
Jan‐12
Charleston AFB
Power Flow Analysis
1,000
Current (amperes)
800
600
400
200
0
Jan‐04
Jan‐06
Jan‐08
Jan‐10
Jan‐12
Date
Figure 6-3
Main Substation Power Demand – Amperes
20,000
Monthly Peak Power Demand (kVA)
16,000
12,000
8,000
4,000
0
Jan-04
Jan-05
Jan-06
Jan-07
Jan-08
Jan-09
Month-Year
Figure 6-4
Monthly Peak Demand
6-4
Jan-10
Jan-11
Jan-12
Charleston AFB
Power Flow Analysis
16,000
Total Power (kVA)
14,000
12,000
10,000
8,000
6,000
2‐Jul
12‐Jul
22‐Jul
1‐Aug
Date
Figure 6-5
Typical Daily Variation in Power Demand
1.00
Power Factor
0.98
0.96
0.94
0.92
0.90
0.88
0.86
Jan‐04
Jan‐06
Jan‐08
Jan‐10
Jan‐12
Date
Figure 6-6
Power Factor Variation
Referring to the above figures, the following summarizes the Charleston AFB total base power
demand:

The base experienced a reduction in load for several years, followed by relatively consistent
peak demand in recent years. The peak demand for each year has been:
6-5
Charleston AFB
Power Flow Analysis
2004: 17,733 kVA
2005: 16,779 kVA
2006: 16,519 kVA
2007: 15,208 kVA
2008: 14,292 kVA
2009: 14,118 kVA
2010: 14,152 kVA
2011: 14,152 kVA
2012: 13,852 kVA

The year-by-year reduction in total power usage up to 2008 can likely be attributed to
a) removal of housing and b) base-wide energy conservation efforts.

For the Charleston area, the difference between peak demand and non-peak demand is mostly
summer air conditioning loads.

Given the above considerations, a reasonable upper bound for the total base peak demand is
about 15,000 kVA, or 700 amperes at 12.47 kV. This provides some margin to allow for
housing loads that are expected to increase in the near future.

The daily variation in power demand is about 25 percent.

Power factor varies from 0.90 to 0.96.
6.4
Summary of Power Flow Analysis Results
6.4.1 General Comments Regarding Primary System Capability
Feeders use 500 kcmil copper conductors for the main run for each feeder originating at the Main
Switching Station. With the completion of the recent underground construction, Feeder A and B
use 500 kcmil copper conductors for the main run. Feeder C is limiting with 1/0 awg copper
conductors for the underground distribution. Smaller conductors, #2 to 1/0 awg, are typically
used on lateral circuits.
The overhead distribution uses 1/0 copper or 3/0 ACSR for the main runs on each circuit. These
conductors in air are not limiting with respect to feeder capability.
6.4.2 EasyPower Feeder Loading
The power flow analysis needs reasonable peak load estimates before system performance
predictions can be made. The data provided in the previous sections were used to establish peak
loading for each feeder as well as peak loading for the entire base. Table 6-1 summarizes the
load on each feeder that has been used in the EasyPower power flow analysis. The loading is
slightly higher than the current peak demand to ensure conservative results. This forms the basis
for the analysis of the existing system.
6-6
Charleston AFB
Power Flow Analysis
Table 6-1
Individual Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
Comments
FP
8,132
369
Flagpole Feeder splits into Feeders A, B, and
C. Refer to Table 6-2 for these feeders.
D
5196
236
E
633
29
F
713
32
HP
1,089
49
Totals:
15,763
715
Table 6-2
Flagpole Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
A
900
41
B
3,448
158
C
3,732
171
Totals:
8,077
370
Comments
This is the total Flagpole Feeder load as
predicted at the Flagpole Feeder Switching
Station.
6.4.3 Normal Operation Results
The term normal operation means that all feeders are in service and operating in the normal
lineup shown on the system one-line drawings. Table 6-1 provides the overall power flow
results for normal operation during peak load conditions. Volume 2 Appendix E provides the
detailed power flow results for this configuration.
The following summarizes the normal operation power flow results:

All lines are operating within their rated limits.

Voltage drop is acceptable throughout the primary distribution system; the voltage drop is
less than 2% for all feeders.

The Charleston AFB peak power demand is within the capability of the Main Substation.
6-7
Charleston AFB
Power Flow Analysis
6.4.4 Distribution Transformer Loading
Distribution transformers are generally lightly loaded. Most transformers are loaded to less than
20 percent of their rated kVA, even during periods of peak demand. Figure 6-7 provides a
histogram of the distribution transformers with respect to their typical peak loading; during offpeak times, the loading will be less. Almost 85 percent of these transformers are loaded to less
than 30 percent of their rated kVA. Over 95 percent of these transformers are loaded to less than
50 percent of their rated kVA during periods of peak demand.
175
Number of Transformers n
150
125
100
75
50
25
0
0 - 10%
10 - 20%
20 - 30%
30 - 40%
40 - 50%
50 - 60%
60 - 70%
70 - 80%
80 - 90%
90 - 100%
Loading (Percent of Rated Value)
Figure 6-7
Distribution Transformers – Peak Demand Histogram
The combined rating of all distribution transformers, including housing, is about 75,000 kVA.
The historical Charleston AFB peak demand is about 15,000 kVA, or about 20 percent of the
combined kVA rating.
6.4.5 Conductor Loading
Primary distribution system conductors (overhead and underground) are generally lightly loaded,
even during periods of peak demand. Figure 6-8 provides a histogram of the conductors with
respect to their typical peak loading; during off-peak times, the loading will be substantially less.
6-8
Charleston AFB
Power Flow Analysis
800
600
n
rs
o
t
c
u
d
n 400
o
C
f
o
r
e
b
m
u 200
N
0
0 - 10%
10 - 20%
20 - 30%
30 - 40%
40 - 50%
50 - 60%
60 - 70%
70 - 80%
80 - 90%
90 - 100%
Loading (Percent of Rated Value)
Figure 6-8
Conductors – Peak Demand Histogram
6.4.6 System Voltage Variation
EasyPower calculated system voltage drops of less than 2 percent, and usually less than 1
percent. The switching station circuit breakers have voltage regulators on the output that provide
a nominal secondary-side voltage even with primary-side voltage variations.
6.5
Motor Starting Analysis
When a motor starts, it draws a higher than normal current as it accelerates to rated speed. This
temporary high current is termed motor inrush, which can be many times the normal running
current. The high inrush current results in additional voltage drop to the motor. A motor starting
analysis ensures that large motors can be started without motor terminal voltage falling below
acceptable values. Excessive voltage drop can cause a motor to stall during startup.
The Charleston AFB electrical distribution system is more of a commercial type system rather
than an industrial type system. Accordingly, there are not any large motors that have the ability
to affect the primary distribution system. For example, starting a 125 Hp motor at Building 680
will cause secondary side voltage to dip by about 2 percent and primary side voltage will dip by
less than 1 percent during the motor starting transient.
6.6
Bldg 516 Fire Pump Evaluation
New motor-driven fire pumps are planned for installation in Bldg 516. The supply transformer
will be 1,500 kVA and the fire pump motors will be rated for 400 Hp. Four motors will be
installed, but all four motors are not expected to run simultaneously.
The Feeder C peak demand is estimated at 171 amperes. The limiting portion of the circuit is the
1/0 awg conductor size (rated for 195 amperes) between pad-mounted switchgear SW-C1 and
6-9
Charleston AFB
Power Flow Analysis
SW-C2, which is estimated to carry 158 amperes during peak-load conditions. The following
summarizes the potential impact of these fire pump motors on Feeder C:

If one fire pump operates, the Feeder C peak demand increases to 188 amperes with the
supply to SW-C2 increased to 175 amperes.

If two fire pumps operate, the Feeder C peak demand increases to 206 amperes with the
supply to SW-C2 increased to 193 amperes. The 1/0 awg conductors are fully loaded to their
rated ampacity.

If three fire pumps operate, the Feeder C peak demand increases to 225 amperes with the
supply to SW-C2 increased to 212 amperes. The 1/0 awg conductors are overloaded by 9
percent.

If four fire pumps operate, the Feeder C peak demand increases to 244 amperes with the
supply to SW-C2 increased to 231 amperes. The 1/0 awg conductors are overloaded by 18
percent. Operating four fire pumps simultaneously must not be an expected configuration
because this would overload its distribution transformer by almost 7 percent.

The Feeder C conductors between pad-mounted switchgear SW-C1 and SW-C2 should be
upgraded from 1/0 awg to 4/0 awg to ensure that the feeder is not overloaded during monthly
fire pump testing and to ensure spare ampacity for other load additions to the circuit.
6-10
7
SYSTEM CROSS-CONNECT CAPABILITY
Section 7 addresses the cross-connect capability of the primary distribution system. Substation
cross-ties are also discussed.
7.1
Purpose of Analysis
Charleston AFB has several points of cross-connection between feeders. An evaluation of crossconnect capability is primarily part of a power flow analysis, in which the ability of each feeder
to carry additional load through a cross-connect point is verified.
Cross-connection might be necessary under any of the following conditions:

Upon failure of a switching station feeder breaker or associated equipment.

Upon loss of a single feeder by feeder conductor damage.

To take equipment out of service for maintenance or repair.

While upgrading a feeder or replacing an underground distribution cable.
The term cross-connect is used here to mean that one feeder picks up all or part of another feeder
in addition to carrying its own load.
The cross-connect points identified in the following sections are included in the system one-line
and layout drawings. Review these drawings for additional information. A switch summary is
provided in Volume 2 Appendix D and switch locations are shown on the electrical layout
drawings provided as part of this project.
7.2
Analysis Limitations and Cross-Tie Considerations
The cross-connect analysis results provided in this section are based on peak or near-peak
loading. During periods of less power demand, the cross-tie capability will be better than
discussed here.
This evaluation is based on the ability of a single feeder to supply power to one additional feeder.
The ability of one feeder to supply even more feeders simultaneously was not evaluated. This
type of evaluation would need to be completed using the EasyPower model for a specific
configuration.
It is assumed that phasing is identical between feeders at all potential points of cross-connection.
The exterior electrical shop should always confirm phasing at normally open points in the system
7-1
Charleston AFB
System Cross-Connect Capability
before closing a cross-tie. Whenever a new cross-tie is installed as part of a future construction
project, exterior electrical shop personnel should visually observe the construction contractor
verify that phase rotation is identical on each side of the switch, including closing of the switch.
Whenever a system cross-connect is considered, the EasyPower model should be reviewed.
Loads in the model can be adjusted for seasonal variations to reflect currently measured feeder
loading and entire buildings can be removed from the model by allowing these buildings to be
carried by their emergency generators. By this approach, the EasyPower model can provide a
cross-connect prediction capability for the specific distribution system configuration.
Regardless of model predictions, affected feeders should be monitored closely whenever a crossconnect is performed.
The availability of emergency generators for individual facilities is not considered as part of this
cross-connect capability evaluation. This evaluation only applies to the capabilities of the
primary distribution system, with all normal loads connected. For each feeder, the evaluation is
based on the capability of a different feeder to provide power to that feeder.
The switch lineups in the following sections are readily evaluated by EasyPower. The evaluated
normally open switch is shut and other related breakers or switches are opened to determine the
cross-tie effect. The following sections summarize the EasyPower analyses.
7.3
Primary System Ampacity
Feeders use 500 kcmil copper conductors for the main run for each feeder originating at the Main
Switching Station. With the completion of the recent underground construction, Feeder A and B
use 500 kcmil copper conductors for the main run. Feeder C is limiting with 1/0 awg copper
conductors for the underground distribution. Smaller conductors, #2 to 1/0 awg, are typically
used on lateral circuits.
The overhead distribution uses 1/0 copper or 3/0 ACSR for the main runs on each circuit. These
conductors in air are not limiting with respect to feeder capability.
Table 7-1 provides the feeder peak demand estimates developed by the power flow analysis; this
load does not include planned facilities. Referring to Table 7-1, feeders can be categorized as
follows:

Very little load – Feeders A, E, F, and HP.

Moderate load – Feeders B, C, and D.

Large load – Flagpole Feeder.
The Flagpole Feeder splits into Feeders A, B, and C.
7-2
Charleston AFB
System Cross-Connect Capability
Table 7-1
Individual Feeder Load Data for EasyPower Model – Peak Demand
7.4
Feeder
Estimated Peak
Load (amperes)
Feeder
Estimated Peak
Load (amperes)
FP
369
A
41
D
236
B
158
E
29
C
171
F
32
HP
49
Main Switching Station Transfer Bus
Figure 5-4 shows a simplified one-line drawing of the Main Switching Station, located next to
the Santee Cooper Substation. Each feeder breaker has the capability of supplying one or more
other feeders via the transfer bus installed in the bus structure above the circuit breakers. This
configuration enables any circuit breaker to be removed from service. The transfer bus can be
used to have one feeder supply another feeder by the following steps:

Remove the desired circuit breaker from service and isolate it. Open the circuit breaker and
open the manual knife blades installed before and after the circuit breaker.

Close the associated normally open manual transfer switch for the circuit breaker that has
been isolated. The deenergized feeder is now connected to the transfer bus.

Select which feeder circuit breaker will be used to supply the deenergized feeder and close its
associated normally open manual transfer switch. The transfer bus is now energized.
There are limitations with using the transfer bus because of the voltage regulator ratings. Refer
to Section 14.3 for more information.
7.5
Main Switching Station Voltage Regulators
The voltage regulators installed at the Main Switching Station do affect the available ampacity of
each feeder. Review Section 14.3 as part of any cross-connect evaluation.
7.6
Feeder Cross-Connect Locations and Capability
Table 7-2 provides a summary of the cross-connects available for each feeder downstream of the
Main Switching Station.
7-3
Charleston AFB
System Cross-Connect Capability
Table 7-2
Substation Feeder Cross-Connect Summary
Feeder
Flagpole
Can Supply Feeders
None – it is the source for Feeders A, B, and C
A
B
C
D
B
A
C
C
A
B
C
D
A
C
HP
E
F
F
A
HP
D
E
The following clarifications are provided regarding Table 7-2:

The Flagpole Feeder is routed as two separate circuits from the Main Substation to the
Flagpole Feeder Switching Station without any cross-ties to other feeders. It supplies
Feeders A, B, and C; and these feeders have cross-tie capability to other feeders.

Housing Feeders E and F were originally only designed to supply each other. A cross-tie
was recently installed between Feeder A and F, which helped facilitate construction during
the recent Flagpole Feeder Switching Station upgrade.
Table 7-3 provides the cross-connect locations for each feeder and describes any limitations
regarding the cross-tie use. Refer to the electrical layout drawings for cross-tie locations; refer to
the electrical one-line drawings for connection details. The Location listed in Table 7-3 is the
location where the open point between the feeders is located.
Table 7-3
Primary Distribution System Cross-Connect Capability
Feeders
Location
Comments
A/B
SW-B1
Feeder A is capable carrying Feeder B via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder A’s
capability.
Feeder B is capable carrying Feeder A via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder B’s
capability.
7-4
Charleston AFB
System Cross-Connect Capability
Feeders
Location
Comments
A/B
SW-B22
Feeder A is capable carrying Feeder B via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder A’s
capability.
Feeder B is capable carrying Feeder A via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder B’s
capability.
Note: This switch was originally named “SW-A19”, but was
replaced and renamed as part of a Feeder B upgrade.
A/D
SW-D2
Feeder D is capable of carrying Feeder A via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder D’s
capability.
Feeder A is capable of carrying Feeder D via this cross-tie point.
But, the total peak demand load on the Flagpole Feeder would be
over 600 amperes, which is limiting at the first switch on the circuit:
SW-FP-1. Even though Flagpole Feeder has been configured with
two circuits leading to the Flagpole Feeder Switching Station, it is
still limited to a maximum of 465 amperes at the start.
Also, the VFI in SW-D2 used to cross-connect to Feeder A is rated
for only 200 amperes, which could carry a portion but not all of the
Feeder D load during periods of peak demand.
B/C
SW-B6
Either feeder is not capable of carrying the other feeder via this
cross-tie point; the combined peak demand load will exceed the
ampacity of the #2 copper conductors used in this area. Instead, this
cross is intended as an alternate supply for this local area only.
B/C
SW-C4
Feeder C is not capable of carrying Feeder B via this cross-tie point;
the combined peak demand load will exceed the ampacity of the 1/0
copper conductors used on Feeder C.
Feeder B is capable of carrying Feeder C via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder B’s
capability.
C/D
SW-C2
Feeder C is not capable of carrying Feeder D via this cross-tie point;
the combined peak demand load will exceed the ampacity of the 1/0
copper conductors used on Feeder C. The total peak demand load on
the Flagpole Feeder would be over 600 amperes, which is limiting at
the first switch on the circuit: SW-FP-1. Even though Flagpole
Feeder has been configured with two circuits leading to the Flagpole
Feeder Switching Station, it is still limited to a maximum of 465
amperes at the start.
Feeder D is not capable of carrying Feeder C via this cross-tie point.
The total peak demand current at SW-D2 will exceed the capability
of the 1/0 copper conductors at this location.
7-5
Charleston AFB
System Cross-Connect Capability
Feeders
Location
Comments
C/D
Pole C56
Feeder C is not capable of carrying Feeder D via this cross-tie point;
the combined peak demand load will exceed the ampacity of the 1/0
copper conductors used on Feeder C. The total peak demand load on
the Flagpole Feeder would be over 600 amperes, which is limiting at
the first switch on the circuit: SW-FP-1. Even though Flagpole
Feeder has been configured with two circuits leading to the Flagpole
Feeder Switching Station, it is still limited to a maximum of 465
amperes at the start.
Feeder D is not capable of carrying Feeder C via this cross-tie point.
The total peak demand current at SW-D2 will exceed the capability
of the 1/0 copper conductors at this location.
E/F
S-19EF
Either Feeder E or Feeder F can carry all of the Feeder E/F housing
load via this cross-tie point. The system is currently operating with
Feeder F carrying Feeder E via this cross-connect.
E/A
SW-A9
This cross-tie is intended as an alternate supply for the Flagpole
Feeder and Feeder E is capable of supplying Feeders A, B, and C via
this route.
With some creative switching, this cross-tie can also be used to have
Feeder E supply Feeder D via Feeder A. By transferring a portion of
the Feeder D load onto Feeder C, the 200-ampere limitation at SWD2 can be managed also.
D/HP
SW-N4
Feeder D is capable of carrying Feeder HP via this cross-tie point;
voltage drop is acceptable and the total current is within Feeder D’s
capability.
Feeder HP is not capable of carrying Feeder D via this cross-tie
point. The total peak demand current at SW-N4 will exceed the
capability of the 1/0 copper conductors at this location.
As can be seen in Table 7-3, some installed cross-tie points are not capable of carrying an entire
feeder; many cross-tie points are only suitable for carrying a portion of another feeder. The
cross-tie capability has continued to improve with the completion of recent infrastructure
projects.
7-6
8
SHORT CIRCUIT ANALYSIS
Section 8 provides the short circuit analysis for the Charleston AFB electrical system.
8.1
Purpose of Short Circuit Analysis
A short circuit study is an integral and necessary part of selecting and sizing electrical
distribution components. Even the best and most reliable electrical distribution system is not
immune to occasional short circuits. The objectives of the short circuit analysis include:

Determine short circuit current levels throughout the system.

Confirm that system overcurrent protective device interrupting ratings are not exceeded.

Establish fault current levels for use in the coordination study.

Identify system lineups or configurations that result in unacceptably high levels of fault
current.
Section 1 provides additional background information regarding short circuit studies. This
section provides a summary of the EasyPower short circuit analysis. Short circuit levels are
provided for key locations throughout the primary distribution system. Equipment duty
evaluation results are provided for major equipment and any components that are over duty, i.e.,
operating beyond its short circuit rating. Volume 2 Appendix F contains short circuit summary
reports for the entire system, including:

Three-phase fault levels for all primary system buses.

Three phase fault levels for all low voltage buses.

Single-phase-to-ground fault levels for all primary system buses.

Single-phase-to-ground fault levels for all low voltage buses.
Comprehensive graphical and text reports containing short circuit and equipment duty
information for all system elements are readily available from the EasyPower model. Additional
fault types can also be viewed in EasyPower.
8-1
Charleston AFB
Short Circuit Analysis
8.2
Interpreting Short Circuit Analysis Results
Short circuit analysis results can be viewed directly on the EasyPower one-line diagram. A
typical EasyPower short circuit display is shown on Figure 8-1. The user controls the type of
fault applied to the system and which elements of fault currents are to be displayed. Options
include: ½, 5, and 30 cycle fault current; symmetrical, asymmetrical, or equipment duty fault
current elements; and three-phase, single line-to-ground, line-to-line, or double line-to-ground
faults.
Figure 8-1
Typical EasyPower Short Circuit Result
Referring to Figure 8-1, the interpretation of a typical EasyPower short circuit display is as
follows:

The maximum available feeder short circuit current into Transformer T519 is 4,760
symmetrical amperes and 5,110 asymmetrical amperes.

The maximum available short circuit current out of Transformer T519 is 9,760 symmetrical
amperes and 11,960 asymmetrical amperes.

The short circuit current at the service entrance panel for Transformer T519 is 9,340
symmetrical amperes and 11,210 asymmetrical amperes. The short circuit current
contribution from the transformer at the service entrance is less than that at the transformer
secondary because of the added cable conductor resistance between the transformer and the
service entrance.
8-2
Charleston AFB
Short Circuit Analysis
Different types of faults produce different levels of short circuit current. The most common type
of fault considered is a three-phase bolted fault. A three-phase bolted fault generally bounds
other types of faults in terms of maximum fault current. Line to ground fault current levels are
also important to determine. In some cases, ground fault current can be higher than the threephase bolted fault current. Additionally, ground fault current levels are important for evaluating
coordination of ground fault protective devices.
The fault current magnitude changes over the first several cycles after a short circuit occurs in an
AC power system. The change is due to 1) the decaying contribution of motors and generators,
and 2) a phenomenon known as DC offset. DC offset causes the symmetrical current waveform
to shift above the zero-axis, producing an asymmetrical waveform – refer to Figure 8-2 and
Figure 8-3. This effect decays away exponentially; however, it has the effect of increasing the
peak fault current seen by system equipment. All of these factors are considered in determining
equipment short circuit ratings. The practical consequence of decaying fault current levels is that
the highest current to which the equipment is exposed occurs within about the first ½ cycle. This
fault current quantity is called the momentary fault current.
Zero Axis
Figure 8-2
Symmetrical Current Waveform
Zero Axis
Figure 8-3
Asymmetrical Current Waveform
The most commonly used fault current quantities are momentary symmetrical and asymmetrical
fault current for three-phase and ground faults. Because of the importance of asymmetrical fault
current values to the overall analysis, it is generally advisable to set the EasyPower display
parameters to show both symmetrical and asymmetrical fault current at each bus.
8-3
Charleston AFB
Short Circuit Analysis
8.3
Modeling Considerations
8.3.1 Utility Fault Contribution
Santee Cooper provided the short circuit currents available at the substation input at 115 kV.
Refer to Table 8-1 for a summary of the available short circuit currents. These values have been
used as the basis for the EasyPower short circuit study.
Table 8-1
Short Circuit Current Available at Substation Input
Voltage
Short Circuit Current
(amperes)
X/R Ratio
Three phase
115
11,632
5.731
Single phase to ground
115
7,824
4.0357
Fault Type
8.3.2 Pre-Fault Voltage
Pre-fault voltage affects the short circuit results, with a higher pre-fault voltage providing an
incrementally higher fault current. The driving point pre-fault voltage for the short circuit study
has been increased to 1.02 per unit to ensure conservative results.
8.3.3 Transformers
Although transformers are not a source of short circuit current, their kVA rating and impedance
have a significant effect on the fault current available at the secondary. Fault current magnitudes
are very sensitive to transformer ratings and relatively insensitive to the available fault current at
the transformer primary. For example, a decrease in the transformer impedance from 4 percent
to 2 percent might result in a 75 percent increase in transformer secondary fault current, yet
doubling the available fault current supplied by the utility might result in only a 4 percent
increase in transformer secondary fault current.
Because of the impact that transformers have on the short circuit analysis results, great care has
been taken to model the transformers accurately, as discussed in Section 2.5.4. Wherever
possible, the conductors on the secondary side of the transformer have been included in the
model to ensure accurate short circuit predictions at the service entrance panel.
8.3.4 Motors
Motors contribute to a short circuit. This study was performed with the largest identified motors
running. These motors have a minor effect at the primary distribution system level.
Smaller motors have a negligible effect on short circuit currents in the primary distribution
system and have been neglected. Applying a pre-fault voltage of 1.02 per unit ensures that any
contribution of these negligible motors has been bounded.
8-4
Charleston AFB
Short Circuit Analysis
8.4
Short Circuit Analysis Results
The EasyPower model has been provided separately, with the name Charleston AFB [Rev 0].dez.
The short circuit results are best viewed in EasyPower. A tabular printout is provided in Volume
2 Appendix F.
Table 8-2 provides a summary of the expected short circuit current ranges. This table provides
what is considered the base case for Charleston AFB for the following configuration:

Main Substation operating with one transformer in service. Santee Cooper has stated that the
two substation transformers will not be operated in parallel.

Low voltage motors throughout the system are allowed to contribute to the fault.
Table 8-2
Charleston AFB Short Circuit Currents On Feeders – Normal Operation
3-Phase Fault Current
(Momentary Symmetrical
RMS kA)
Line-to-Ground Fault Current
(Momentary Symmetrical
RMS kA)
Main Switching Station
7.57 kA
8.36 kA
Flagpole Feeder Switching Station
6.27 kA
6.52 kA
Typical range for feeders – 12.47 kV
3 – 7 kA
2 – 8 kA
Location
The following observations are provided regarding the available short circuit currents:

The fault current available on the primary distribution system is well within the interrupting
rating of typical distribution system equipment and protective devices during normal
operation.

As a general rule, ground fault current decreases rapidly as the distance from the source
increases. Ground fault currents near the substation are larger than the three phase fault
currents. However, three phase fault currents are larger than ground fault currents further
from the substation.

A fault impedance will cause a further decrease in the available short circuit current. The
largest fault impedance typically considered is 40 ohms, which would result in a ground-fault
current of about 180 amperes. IEEE C37-230, IEEE Guide for Protective Relay Applications
to Distribution Lines, states that fault impedances will usually be well below this amount.

The fault current range on the secondary side of distribution transformers varies widely,
depending mainly on the transformer size and impedance in each case. Service entrance
conductor size and length causes an additional reduction of the fault current available at the
service entrance panel.
8-5
Charleston AFB
Short Circuit Analysis
8.5
Equipment Fault Current Duty
8.5.1 Analysis Terms
System overcurrent protective devices must be designed to isolate faults safely with minimal
equipment damage and minimal disruption to otherwise unaffected portions of the electrical
power system. All equipment exposed to the short circuit current must be capable of
withstanding the mechanical and thermal stresses caused by the current until the short circuit is
isolated. This capability is termed the equipment’s Withstand Rating.
Circuit breakers must be capable of withstanding and interrupting the short circuit current. The
amount of current that a breaker can safely interrupt is termed its Interrupting Rating. Circuit
breaker interrupting ratings can be confusing and are not entirely straightforward. Consequently,
breaker ratings are often misunderstood, particularly for low voltage circuit breakers. Volume 2
Appendix H provides additional background information regarding low voltage circuit breaker
interrupting ratings.
The most important aspect of a short circuit study is the Equipment Duty evaluation. This
evaluation compares the equipment’s short circuit ratings to the calculated fault duty currents.
This comparison is performed automatically by EasyPower.
8.5.2 Analysis Requirements
The consequences of applying electrical equipment, particularly circuit breakers, beyond their
rating can have dramatic consequences, including catastrophic failure, fire, and explosion. An
unsafe condition might go undetected for years, or even decades, until the system experiences a
heavy fault. Then, upon being subjected to a fault current beyond its rating, the device fails. In
many instances such failures result in significant damage, prolonged outages, fires, and
personnel injury or death. For this reason, all applicable governing codes and standards (NEC,
ANSI, NFPA, IEEE, NEMA, and UL) clearly specify that equipment must be applied within its
short circuit ratings. Circuit breakers are the focus of attention from a code compliance point of
view because they are the devices counted upon to quickly isolate damaging faults.
The National Electrical Code (NEC), Article 110-9, establishes the interrupting rating criterion
for electrical protection as follows:
110-9. Interrupting Rating. Equipment intended to interrupt current at fault levels shall
have an interrupting rating sufficient for the nominal circuit voltage and the current that is
available at the line terminals of the equipment.
Performing an equipment duty evaluation is straightforward in concept but complicated in
practice. Ideally, one would only need to compare the calculated short circuit value to a
component’s rating. Unfortunately, different types of components are rated differently, making a
straightforward comparison impractical. Additionally, system operating variables influence the
evaluation. For example, the interrupting rating of high voltage breakers can be scaled based on
the nominal system voltage. Another factor that often limits equipment capability is the system
X/R ratio. High X/R ratios can exceed the limits to which breakers and fuses are rated. In this
case, a derating multiplying factor must be applied to the actual fault current to compensate for
8-6
Charleston AFB
Short Circuit Analysis
the high system X/R ratio. EasyPower automatically performs equipment duty evaluations. The
software applies all applicable correction factors and adjustments based on ANSI codes and
standards. For this reason, protective device duty currents can be different than the actual
calculated current at the device location.
8.5.3 Equipment Duty Evaluation Criteria
Two criteria are established for evaluating equipment duty:
RATING VIOLATION
Device is operating beyond its short circuit rating, termed
Over Duty.
RATING WARNING
Device is operating within 10 percent of its short circuit
rating.
The 10 percent rating warning is a customary target that is desirable not to exceed to account for
system changes, inaccuracies in the model, and design margin.
8.5.4 Equipment Fault Duty Analysis Results
As noted previously, the fault current levels for the primary system are relatively low. All
components in the primary system are operating well within their short circuit ratings, as shown
in Table 8-3.
Table 8-3
Primary System Fault Current Duties and Equipment Ratings
Location
Primary system switches (switchgear)
Equipment Rating
Fault Duty
12.5 – 22.0 kA
<8.0 kA
Primary system fuses (switchgear) – SMU-20
14.0 kA
Load junctions and elbows
10.0 kA
Overhead distribution fused cutouts
7.1 kA sym
10.0 kA assym
The voltage regulators at the Main Switching Station are rated to withstand through faults for 25
times the self-cooled (OA) rated current for 2 seconds or 40 times the OA rated current for 0.8
seconds to a maximum of 20,000 amperes RMS symmetrical. The voltage regulators are suitable
for use with the available short circuit current, but the voltage regulator ratings do affect any
allowed time delays for the feeder overcurrent relays.
The study performed was a distribution-level study, not intended to model the interior electrical
system of Base facilities. The service entrance breakers were inspected and included in the
model in many cases. In some instances, the breaker interrupting rating could not be determined
by a visual examination of the exposed breaker parts. In the future, it is recommended that the
breaker interrupting rating be checked whenever performing work on interior panels and
switchgear.
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Charleston AFB
Short Circuit Analysis
8.6
Transformer Effects on Short Circuit Current Magnitude
Although transformers are not a source of short circuit current, their kVA rating and impedance
have a significant effect on the fault current available on the secondary side. Although
Charleston AFB has only a small number of low impedance transformers, this should continue to
be a design consideration whenever a transformer is installed (refer to Volume 2 Appendix B for
a list of transformers and their data). The problem that potentially arises here is that low
transformer impedance can substantially increase the downstream fault current magnitude.
Charleston AFB has many distribution transformers with an impedance of less than 2 percent,
which can produce a relatively large secondary side short circuit current. Figure 8-4 and Figure
8-5 show the effect of impedance on short circuit current magnitude as a function of transformer
kVA rating. As can be seen, low transformer impedance can result in a high fault current, which
might exceed the interrupting rating of downstream protective devices. Figure 8-5 includes
larger transformers (>500 kVA), which often have an impedance greater than 5.75 percent, but
lower impedances are occasionally observed.
Asymmetrical Short Circuit Current
100
80
60
40
20
0
45
75
112.5
150
225
300
500
Transformer Size (kVA)
1%
2%
3%
4%
5%
6%
Figure 8-4
Short Circuit Current as a Function of Transformer Impedance – 208 Volt Secondary
8-8
Charleston AFB
Short Circuit Analysis
Asymmetrical Short Circuit Current
100
80
60
40
20
0
150
225
300
500
1000
2000
Transformer Size (kVA)
1%
2%
3%
4%
5%
6%
Figure 8-5
Short Circuit Current as a Function of Transformer Impedance – 480 Volt Secondary
Figure 8-4 and Figure 8-5 are based on the available fault current, but do not include the effect of
conductor resistance on the transformer secondary. The values provided are the asymmetrical
short circuit currents rather than the symmetrical currents. These figures should be used as a
simple guide to assess the likelihood of exceeding a breaker’s interrupting rating. An EasyPower
analysis is recommended to evaluate a specific configuration.
8.7
Short Circuit Effects on Primary System Voltage
When a fault occurs on the primary distribution system, voltage tends to drop to near zero at the
fault location, varying mainly with the resistance at the point of fault. For the relatively compact
distribution system installed for the main base, a primary distribution system fault on a feeder
tends to affect the other feeders also for the period of time that the fault is allowed to persist.
Figure 8-6 shows the expected voltage at the substation as a function of the magnitude of short
circuit current on a single feeder.
8-9
Charleston AFB
Short Circuit Analysis
100%
80%
)l
a
n
i
m
o
n 60%
f
o
t
n
e
c
r
e
(p 40%
e
g
a
lt
o
V
20%
0%
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
Short Circuit Current (amperes)
Figure 8-6
Substation Voltage as a Function of Short Circuit Magnitude
Referring to Figure 8-6, the following observations can be made:

A short circuit on the primary distribution system will cause voltage at the Main Switching
Station to drop by an amount proportional to the magnitude of the short circuit current.

A lower-than-normal voltage at the substation means that a lower-than-normal voltage will
be experienced throughout all of the feeders for the period of time that the fault is allowed to
persist.

High-level faults (above 5,000 amperes) can cause system voltage to fall to less than half of
the normal voltage.

Faults above about 2,500 amperes can cause voltage to fall enough to cause lights to dim or
flicker, equipment to drop out on low voltage, and emergency generators to start. The extent
to which this occurs depends on the fault magnitude and the fault duration.
8-10
9
ARC FLASH ANALYSIS
Section 9 provides a summary of the EasyPower arc flash analysis results. Comprehensive
graphical and text reports containing arc flash information for all system buses are readily
available from the EasyPower model. An arc flash summary is provided in Volume 2 Appendix
F for the primary distribution system.
9.1
Purpose of Arc Flash Analysis
The nature of arcing equipment failures and the rate of serious burn injuries in the electrical
industry led the NFPA to develop arc flash electrical safety guidelines in NFPA 70E, Electrical
Safety in the Workplace, for work on or near energized electrical equipment. IEEE 1584, IEEE
Guide for Performing Arc-Flash Hazard Calculations, was issued in 2002 to provide an
empirically-derived calculation methodology and associated equations for determining arc flash
energies at a fault location. Together, these industry standard documents provide guidance
regarding how to assess arc flash hazards and add a new dimension to traditional electrical power
analysis.
For the Air Force, additional criteria related to arc flash hazards are provided in the following
documents:

AFI 32-1064, Electrical Safe Practices.

UFC 3-560-01, Electrical Safety, O&M.

Engineering Technical Letter (ETL) 06-1, Arc Flash Personal Protective Equipment (PPE)
Requirements for High-Voltage Overhead Line Work at 69 kV (Nominal) or Less.

ETL 11-9, Electrical Manhole Entry and Work Procedures.
An arc flash analysis typically accomplishes the following:

Calculates arc flash incident energy levels at key locations throughout the system.

Determines the personal protective equipment (PPE) requirements based on arc flash analysis
results for specific work locations.

Identifies potential equipment line-ups or protective device setting changes that can reduce
the arc flash hazard at specific locations.
9-1
Charleston AFB
Arc Flash Analysis

Identifies locations in which energized work cannot be conducted safely regardless of
available PPE due to exceptionally high arc flash energy levels.

Considers whether the upstream overcurrent protective device is capable of performing its
safety function of clearing the fault based on past maintenance and testing, as applicable.
The end purpose of conducting an arc flash study is to define the arc flash hazard associated with
energized electrical work so that workers can select and wear the appropriate PPE for the
anticipated energized work hazard. PPE categories are specified in NFPA 70E. Table 9-1 lists
the typical PPE clothing given the specified arc flash incident energy levels; additional PPE
requirements are provided in NFPA 70E and UFC 3-560-01.
Table 9-1
Arc Flash PPE Categories
Category
Max Energy Level
2
Typical Clothing PPE
0
2 cal/cm
Long-sleeve non-melting shirt and pants
1
4 cal/cm2
Arc rated (AR) shirt and AR pants, or AR coveralls
2
8 cal/cm2
AR shirt and AR pants, face-shield
3
25 cal/cm2
Two layers of AR clothing, flash-suit hood
4
40 cal/cm2
AR shirt, AR pants, multilayer flash suit
Extreme
Danger
> 40 cal/cm2
PPE requirements not specified; considered unsafe
to work on associated energized equipment
9.2
Arc Flash Analysis Basics
Arc flash hazard studies require knowledge of both the electrical power system and the system’s
electrical protection. Arc flash studies can be considered a continuation of the short circuit and
coordination analysis of a power system, since the results of each are required to determine the
incident energy associated with an arc flash event at any specific location in the power system.
Numerous design and configuration factors can affect the calculated arc flash energy levels. For
this reason, development of the electrical analysis model for the purpose of arc flash calculations
requires a level of detail not generally included in past electrical modeling efforts for traditional
power system studies.
Data collection is the greatest effort in performing an arc flash analysis. For a system with up to
date one-line diagrams and readily available as-built information, data collection can take from
20 to 40 percent of the analysis effort. For poorly documented systems, the effort will be much
more. The main difference between an arc flash hazard assessment and traditional power system
studies is that the system must be modeled in more detail, thereby increasing the data collection
time and analysis effort. In years past, traditional electrical modeling often involved significant
simplifications to reduce the time and cost of analysis. These simplifications were generally
considered conservative. For example, it was common practice for some engineers to exclude
some cable impedances, and sometimes equipment resistance in the system model to ensure the
9-2
Charleston AFB
Arc Flash Analysis
highest possible short circuit values when calculating withstand duties for equipment.
Unfortunately, this approach can produce non-conservative results when determining arc flash
hazards, resulting in decreased worker safety.
The arc flash boundary and associated protection requirements are based on the incident energy
levels available to the person’s chest or face, not the hands or arms. The degree of injury
depends on the percentage of the person’s skin that is burned, and the degree of the burn.
Appropriate working distances for operations that do not involve live-line tools can be calculated
by placing your elbow at your side and extending your hand to the equipment. A typical average
for this distance is 18 inches (1½ ft). By extending the arm to the full out position, this can be
increased to 24-28 inches for most people.
9.3
Interpreting Arc Flash Analysis Results
Arc flash analysis results can be viewed directly on the EasyPower one-line diagram; a typical
EasyPower arc flash display is shown in Figure 9-1. Analysis parameters are set by the user and
include many options. Recommended analysis settings are discussed in Section 9.4.
Figure 9-1
Typical EasyPower Arc Flash Result
Referring to Figure 9-1, the interpretation of a typical EasyPower arc flash display is as follows:

The arc flash value at pad-mounted switchgear SW-A10 is 0.8 cal/cm2. Accordingly, the
PPE requirements are Category 0 for this location.
9-3
Charleston AFB
Arc Flash Analysis

The arc flash value on the primary side of distribution transformer T214 is 0.6 cal/cm2.
Accordingly, the PPE requirements are for Category 0 for this location. The results are less
than for SW-A10 because of the fuses in the circuit to T214.

The arc flash value for the secondary of Transformer T214 is 194.7 cal/cm2, which is
classified as Extreme Danger. Even Category 4 PPE is not considered safe for this location.

The arc flash value at the service entrance of Building 215 is 5.5 cal/cm2. Accordingly, the
PPE requirements are for Category 0 for this location. This particular result took credit for
the main breaker.

The arc flash value at the service entrance of Building 214 is 132.4 cal/cm2. Accordingly,
the PPE requirements are for Category 4 for this location. This particular result took credit
for the main breaker, but its settings are higher than for the breaker in Building 215, which
results in the higher PPE result.
The EasyPower arc flash analysis provides additional information in its arc flash spreadsheet.
Figure 9-2 shows an example of this display.
Figure 9-2
Typical EasyPower Arc Flash Spreadsheet
9.4
Arc Flash Analysis Parameters
When conducting an arc flash analysis, the user must define several parameters. There are not
“right” or “wrong” selections for these settings. Rather, the settings are dependent upon the
circumstances of the analysis and what specific information the user is trying to obtain. Within
EasyPower, the arc flash analysis parameters are set within the Short Circuit Options dialog box,
shown in Figure 9-3.
9-4
Charleston AFB
Arc Flash Analysis
Figure 9-3
Arc Flash Analysis User Settings Dialog Box
The various analysis parameters and the settings used for an arc flash analysis are described
below:

Standard – Options include EasyPower specific methods, NFPA 70E, and IEEE 1584.
IEEE 1584 is recommended as the basis for any calculations and the analysis results are
based on IEEE 1584. With a detailed model, the IEEE computations should provide the most
realistic values. The NFPA 70E method is based on low voltage applications and is overly
conservative for medium voltage analyses. NFPA 70E recognizes IEEE 1584 as an
acceptable approach for conducting the calculations.

Use Worst Case Arcing Current – The user can adjust the assumed arcing current upon
which the arc flash calculations are based. In general, the values should be left at their
default setting unless very specific information about the application can justify alternate
settings. IEEE 1584 recommends the 100% and 85% settings.

Worst-Case Arc Flash Hazards – Output – This is one of the most important and useful
fields for conducting the arc flash calculations. Output results for main buses can be
produced with or without the main bus incoming breaker included in the calculation.
Additionally, an option exists to provide “detailed” output results, which provide arc flash
quantities downstream of the bus feeder breakers. It is very important to think through the
intended energized work tasks and decide whether arc flash values should or should not take
credit for the bus incoming breaker.

Max Times – User defined times are specified to establish maximum arcing times for the
different voltage classes. The values established for this analysis are based on engineering
judgment for the voltage levels involved. These values will generally not influence the
9-5
Charleston AFB
Arc Flash Analysis
analysis results when the arc flash values are based upon the time-current response time of
upstream protective devices.

Calculating Arc Flash Using – When determining arc flash values associated with
personnel safety, it is generally advisable to use momentary current, which is the default
setting. Refer to Section 9.5 for additional guidance for a distribution system.

Working Distances – Working distances can be specified in different units. This analysis
specifies working distances in inches. EasyPower provides up to five working distances for
each voltage level. This allows the user to adjust distances based on the tasks of interest.
Default working distances can be changed for enclosed and open air circumstances. This
analysis uses the EasyPower default working distances, which are generally appropriate for
typical tasks that do not involve live-line tools. There may, however, be times when the
default worst-case distance is not appropriate. For example, if a particular operation is being
conducted using a 6-foot hot stick, the arc flash PPE requirements can be based on the known
working distance and not the default worst-case distance.
9.5
Modifying EasyPower Arc Flash to Work on a Distribution System
During arc flash analysis, EasyPower evaluates upstream buses at each fault location and
determines which protective device provides arc flash protection. This evaluation process is
referred to as the upstream traverse evaluation. This is a time consuming process and the
EasyPower default is a traverse number of 12, or 12 upstream buses are checked for the
protective device responses. This number tends to be too low for a primary distribution system
and must be modified before using the model to perform arc flash analysis.
The following sections provide two ways to modify the arc flash analysis to recognize distant
protective devices.
9.5.1 Changing Traverse Number
Changing the EasyPower traverse number changes the number of upstream buses that are
evaluated for a protective device for an arc flash analysis. The traverse count variable is changed
by selecting Advanced in the Short Circuit Options dialog.
9-6
Charleston AFB
Arc Flash Analysis
Figure 9-4
Arc Flash Analysis Traverse Number
If the value is set too high, fault analysis can run slowly on slow machines. The EasyPower
model was created with the variable set to 50 to ensure that arc flash works normally out to the
end of longer feeders.
9.5.2 Changing the Short Circuit Analysis Options
Another way to change the arc flash analysis traverse method is to change the Short Circuit
Options within the Calculate Arc Flash Using selection from Momentary to Integrated. This
changes the arc flash analysis to evaluate all protective devices in the model for each bus. The
Integrated method will identify and calculate arc flash effects for closed cross-tie configurations.
This particular approach is more calculation intensive than simply changing the traverse number
because it forces the analysis to evaluate protective device effects in every potential direction.
Figure 9-5 shows the selection location in the Short Circuit Options dialog box.
9-7
Charleston AFB
Arc Flash Analysis
Change
Calc
Method
Figure 9-5
Arc Flash Analysis User Settings Dialog Box – Integrated Analysis
9.6
Practical Considerations
An arc flash analysis determines the incident energy at a specified location and the required PPE
is selected for working on energized electrical equipment at that location. Several items should
be carefully considered with respect to this simple statement:

AFI 32-1064 and UFC 3-560-01 clearly state that working on or near energized electrical
equipment is prohibited except in rare circumstances, and then only when justified and
approved by the BCE or equivalent in accordance with the criteria established in these
documents. For most day-to-day work activities, the results of an arc flash analysis should
not be needed because the work will be performed on deenergized equipment.
AFI 32-1064 clarifies the energized work criteria for primary distribution with the following
statements:
Work on or near energized overhead distribution lines is prohibited except in rare
circumstances and then only when approved by the BCE or equivalent in accordance with
procedures outlined in the following paragraphs. Authorization is not required for tasks
such as voltage measurement or phasing tests, as long as maintenance or repair is not
performed and safe practices and appropriate PPE are used.
Conventional circuit de-energizing/re-energizing methods (i.e., turning off/on a switch,
opening and closing hook switches, or operating circuit breakers/disconnects) for the
purpose of isolating circuits needing work are not considered performing “maintenance on
9-8
Charleston AFB
Arc Flash Analysis
energized circuits,” and consequently do not require BCE approval; however, proper PPE
shall be used when performing de-energizing/re-energizing procedures.

The PPE requirements are based on working on or near energized exposed electrical
equipment. If the equipment is deenergized, then the PPE requirements do not apply.
Note: UFC 3-560-01 specifies minimum PPE requirements for qualified electrical workers
regardless of any arc flash result.

The calculated incident energy depends on how long it takes an upstream protective device to
sense, respond to, and eventually clear the arcing fault. If the upstream protective device is a
set of fuses, they likely will respond as intended. If the upstream protective device is a
circuit breaker that has not been checked or maintained for the last 30 years, there is no
assurance whatsoever that it will respond as intended.

Even if the trip device is functional, can the circuit breaker actually open? Has it ever been
operated? For medium voltage and low voltage power circuit breakers, has the lubricant
hardened or have any required moving parts broken? Once again, it is hard to envision
taking credit for an arc flash analysis on a system that has received little or no periodic
maintenance.
“The arc flash hazard analysis shall take into consideration the design of the overcurrent
protective device and its opening time, including its condition of maintenance.”

The EasyPower arc flash settings in the Short Circuit Options dialog box are critical to
consider. In particular, an arc flash analysis intended to allow energized work on a service
entrance panel has to determine whether or not credit can be taken for the main service
disconnect.

All calculated arc flash incident energy levels should be considered only a best estimate of
the available arc fault energy and we hope that the results are conservative with respect to
personnel safety requirements. The following summarizes some of the accuracy issues
regarding arc flash calculations:
 Fifty arc flash calculations for the same location will produce fifty identical results; real
life arcing faults are probably not that repeatable.
 The results are based on a very specific electrical system configuration and response to an
overcurrent condition, the accuracy of which might not be guaranteed.
 Even properly maintained equipment sometimes breaks or fails to operate when needed.
If this happens, an arcing fault would be cleared by a different upstream protective
device, likely with a longer time delay. If the energized work is performed at the service
entrance panel, the next upstream device is usually upstream of the distribution
transformer and will take anywhere from several seconds to hundreds of seconds to
respond to a secondary-side overcurrent event.
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Charleston AFB
Arc Flash Analysis
 The IEEE 1584 equations are based on radiant energy generated by the arcing event.
Industry experience confirms that the associated plasma cloud also delivers a substantial
amount of energy. At 480 volts, the IEEE 1584 method might underestimate the total
energy deposition by an arcing fault. Further industry research is needed in this area.
 The equations used for the calculations have been empirically determined and do not
apply equally to all voltage ranges. For example, the calculations can produce four times
the incident energy at 15,001 volts compared to the same calculations performed at
14,999 volts. The IEEE 1584 and the NFPA 70E working groups are currently working
together to improve the calculation approaches. We should expect ongoing changes in
this area that will affect how we calculate, view, and interpret the results.

Arc flash warning labels should be kept simple; Figure 9-6 shows the example recommended
by UFC 3-560-01 and UFC 3-501-01. Despite the requirements of the 2012 edition of NFPA
70E, we believe that detailed labels that provide analysis values can easily be incorrect. The
following points should be considered if providing detailed warning labels:
 A detailed warning label will not recognize system configuration changes that affect the
analysis results. For example, suppose a relatively new facility has its service entrance
breaker trip in response to some downstream fault. As part of facility power restoration,
the electrician might decide that the service entrance breaker trip settings are too low and
then raise the trip settings. This single act at this location can change the arc flash results
from Category 0 to Category 4 or higher.
 An arc flash analysis performed for an entire system has to make some analysis
assumptions that might not match the actual energized work practice. If an arc flash
analysis takes credit for the main breaker, particularly at the service entrance, then the arc
flash result might be as low as Category 0. If the arc flash analysis does not take credit
for the main breaker, then the arc flash result can be Category 4 or higher. Protective
devices upstream of the service entrance transformer typically sense through the
transformer with a long time delay.
 Even a detailed arc flash label will not describe the assumed working conditions that
formed the basis for the calculated arc flash levels. Personnel should not rely on the label
for their PPE requirements. Instead, an energized work permit should establish the PPE
levels based on the intended work approach.
 The 2012 edition of NFPA 70E states, “The arc flash hazard analysis shall take into
consideration the design of the overcurrent protective device, including its condition of
maintenance.” Facility studies performed at the low voltage level will need to determine
if historic maintenance practices have been adequate to rely on circuit breakers as
upstream protective devices with respect to electrical safety. It would be negligent for an
engineer to assume that old molded case circuit breakers that have never been maintained
in accordance with NETA MTS or NFPA 70B will trip per their overcurrent time-current
curves. And, such a critical assumption would likely not be included on the label.
Note: The NFPA 70E-2012 Handbook refers to Section 21.10 of NFPA 70B for
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Charleston AFB
Arc Flash Analysis
maintenance of protective devices; this section includes overcurrent time current testing
of the protective devices.
 The analysis methods defined by NFPA 70E and IEEE 1584 are expected to be modified
over the next several years, which also might result in different calculated values. The
IEEE 1584 working group is already conducting additional testing in support of the
analysis methods. If the analysis methods change, the analysis results will likely change.
This means that very detailed labels will no longer match the new analysis results –
relabeling will be necessary.
! WARNING
Figure 9-6
Recommended Arc Flash Warning Label

An EasyPower arc flash result of “Extreme Danger” means that the calculated energy is
greater than 40 cal/cm2. One approach suggested for these locations is to purchase flash
protection suits rated for 65 cal/cm2, 100 cal/cm2, or maybe even 140 cal/cm2. An arc flash
suit provides thermal protection from an arcing fault event; it is not certified to provide blast
protection also. An arc flash result of “Extreme Danger” means that the equipment must be
deenergized before work is allowed.

One approach used to improve arc flash results for a specific work task is to temporarily
lower the trip settings for an upstream protective device. This is particularly valid for
molded case circuit breakers where the difference between an instantaneous trip and a time
delay trip might mean the difference between Category 0 and Category 4 PPE.
9.7
Arc Flash Analysis Results
9.7.1 Results
An arc flash summary is provided in Volume 2 Appendix G for the primary distribution system
for the following configurations:
9-11
Charleston AFB
Arc Flash Analysis

Existing protective device settings throughout the system.

Recommended protective device settings.
The recommended method for evaluating arc flash requirements for a specific work location and
setup is by the EasyPower model. Refer to UFC 3-560-01 for arc flash criteria and personal
protective equipment (PPE) requirements for energized line work. Refer also to Engineering
Technical Letter (ETL) 06-1, Arc Flash Personal Protective Equipment (PPE) Requirements for
High-Voltage Overhead Line Work at 69 kV (Nominal) or Less, which emphasizes that “Working
on energized electrical equipment is prohibited except in rare circumstances, and then only when
justified and approved by the BCE or equivalent in accordance with AFI 32-1064.”
The arc flash protective clothing requirements for energized work vary from Category #0 to
Category #1 throughout the primary distribution system. Along the main portion of each feeder,
the substation relays are credited in the arc flash analysis as the protective devices that clear the
arcing fault. Fuses and VFIs are usually the recognized arc-fault clearing device along
downstream laterals.
The PPE requirements are specified for an unrealistically low working distance of 18 inches on
the primary distribution system. Lower arc flash values would apply to a reasonable hot-stick
working distance of 60 inches, or greater. The EasyPower model should be used to evaluate a
specific work location and working distance.
Although this power system analysis extends to the service entrance of each facility, the analysis
is mainly an evaluation of the primary distribution system. Arc flash results for the service
entrance panel of any facility should be applied with care. The model was prepared in a manner
that allows the service entrance protective device (fuses or breaker) to be used in the arc flash
calculations. These results only apply if the connections and buswork electrically upstream of
the service entrance disconnect are not accessible while performing energized line work.
9.7.2 Periodic Maintenance and Testing
An arc flash PPE level depends in part on the expected clearing time of an upstream protective
device. Maintenance and testing are both necessary to ensure a device is functional and can be
credited by an arc flash study. With respect to circuit breakers, maintenance confirms that the
circuit breaker is capable of operating as designed and testing confirms that a trip signal will be
initiated as designed. NFPA 70E-2012 addresses this by requiring:
“The arc flash hazard analysis shall take into consideration the design of the overcurrent
protective device and its opening time, including its condition of maintenance.”
The term “condition of maintenance” refers to maintenance and testing of sufficient quality that
the upstream protective device can be expected to operate as intended and within the analyzed
operating time.
For this primary distribution study, periodic maintenance and testing of the switching station
circuit breakers and protective relays is necessary to use the arc flash results. Refer to Section
14.8 for recommendations regarding periodic maintenance and testing.
9-12
10
ELECTRICAL PROTECTION AND COORDINATION
CRITERIA
Section 10 provides the criteria applied to this power system study. Proper electrical protection
and coordination are essential for electrical distribution system reliability. The fundamental
objectives of system protection are to:

Isolate permanent faults with minimum disruption of power to unaffected portions of the
system.

Limit damage to faulted equipment and minimize hazards to personnel.

Minimize the possibility of fire or catastrophic damage to adjacent equipment.
Ideally, the protection scheme design is fully coordinated. A fully coordinated system
accomplishes the above objectives over the entire range of possible fault current. A partially
coordinated system has gaps in coverage, i.e., coordination is achieved only for a portion of the
fault current range. Lack of coordination can result in an undesired protective action and the
unnecessary removal from service of portions of the distribution system.
10.1
Scope of Electrical Coordination Review
This study represents a review of the primary distribution system, which starts at the local utility
supply to the substations. The scope of the coordination review extends throughout the primary
distribution system. The following summarizes the analysis scope:

Protection and coordination along the primary distribution system were evaluated fully.

The secondary side of each distribution system transformer was evaluated up to and
including the main service disconnect point (circuit breaker or fuse) wherever service
entrance data was acquired.

Because the electrical model typically stops at the facility service entrance disconnect, the
coordination criteria applied to low voltage equipment within a facility consisted of a
confirmation that it cannot cause the complete loss of a primary distribution feeder for the
defined settings or size.
10-1
Charleston AFB
Electrical Protection and Coordination Criteria

Branch breakers downstream of the service entrance disconnect are not included in the scope
of this analysis. The EasyPower model provides an excellent starting point for the modeling
of individual facilities, if needed.
10.2
Electrical Protection and Coordination Criteria
Electrical coordination was evaluated using standard industry methods and criteria. Timecurrent coordination plots were developed for the system. The time-current curves for related
devices are graphically depicted on a common plot. The curves are then compared using the
specified criteria to confirm that the nearest protective device upstream from the fault will open
before other upstream devices. This comparison is made over the entire possible fault current
range. The postulated fault current ranges from a very light overload at the low end up to the
maximum predicted fault current for the fault location (based on short circuit study values). The
maximum predicted fault current represents the worst-case 3-phase momentary asymmetrical
fault current (line faults) or worst-case line-to-ground momentary asymmetrical fault current
(ground faults). Table 10-1 provides the criteria applied in this study.
Table 10-1
Desired Electrical Protection and Coordination Criteria
Upstream
Device
Downstream
Device
TOC Relay or
Recloser
TOC Relay
TOC Relay or
Recloser
Switchgear
Breaker, Fuse,
and MCCB
Switchgear
Breaker
Switchgear
Breaker
MCCB
Switchgear
Breaker
MCCB
MCCB
MCCB
Fuse
(Non-Current
Limiting)
MCCB
Fuse
(Current
Limiting)
Criteria
A minimum margin of 0.4 seconds between TC curves in the TOC
region. No overlap between the TC curves for instantaneous
elements with 10% margin.
A minimum margin of 0.3 seconds between the TC curve and the
switchgear breaker/MCCB/fuse curve in the TOC region. No
overlap between the TC curves for instantaneous elements with 10%
margin.
No overlap between TC curves. All tolerances are accounted for in
the curves.
No overlap between TC curves. All tolerances are accounted for in
the curves.
No overlap between TC curves. All tolerances are accounted for in
the curves.
Total clearing time of fuse must be below the minimum trip time of
breaker in the TOC region. Alternatively, the fuse average clearing
time must be below the minimum trip time of breaker with 10%
margin. Maximum fault current sensed by MCCB must be limited to
below the MCCB instantaneous pickup.
Total clearing time of fuse must be below the minimum trip time of
breaker in the TOC region. Alternatively, the fuse average clearing
time must be below the minimum trip time of the breaker with 10%
margin. Peak let-through current of fuse must be below the MCCB
instantaneous pickup.
10-2
Charleston AFB
Electrical Protection and Coordination Criteria
Upstream
Device
Downstream
Device
Fuse
Fuse
Fuse
MCCB
Transformers
Cables
10.3
Criteria
Total clearing time of downstream fuse must be below the minimum
melt time of upstream fuse. Alternatively, the average clearing times
of the fuses must not overlap with a 10% margin applied to each
fuse. Alternatively, the I2t of the downstream fuse must be lower
than the I2t of the upstream fuse. The I2t requirement is considered
satisfied if fuse manufacturer’s selectivity ratio is maintained.
No overlap between MCCB TC curve and minimum melt time curve
for fuse. Alternatively, no overlap between MCCB TC curve and
average clearing time curve for fuse with 10% margin. No
coordination above intersection of fuse TC curve and MCCB
instantaneous curve.
Protective device must clear the fault before the transformer damage
curve is exceeded. Conservatively use frequent fault damage curves.
Upstream protective device setting must allow for transformer inrush
without nuisance trip.
Protective device must clear the fault before cable I2t damage curve
is exceed.
Selection Considerations for Cutout Fuse Links
The overhead distribution system contains fused cut-outs in a variety of locations, usually
intended to protect riser conductors, pole-mounted transformers, and pad-mounted transformers.
A coordination study typically has difficulty determining fuse link size for overhead cutouts.
The fuse size can rarely be confirmed without requiring electrical shop personnel isolate each
cutout for a visual inspection, which tends to be a complex and time-consuming undertaking.
For these reasons, the following approach is taken with respect to fuse sizing for overhead
cutouts:
1. The optimal fuse size is determined for each location. Future system outages can then
include a fuse link check, with replacements as necessary.
2. The selected fuse link size is based on standard industry guidance. Table 10-2 provides the
fuse selection criteria applied to this study.
3. The fuse link type used in the analysis is selected based on the predominant type in service
throughout the primary distribution system (Type QA).
4. If the fused cutouts supply more than one pad-mounted transformer in a looped
configuration, the selected fuse link size is based on the combined kVA rating of the
transformers, and possibly downsized by one fuse size to account for typical less than full
load conditions. Note that the fused cutouts often do not provide adequate protection for any
transformer in this configuration; each transformer must have its own set of fuses for
adequate protection.
10-3
Charleston AFB
Electrical Protection and Coordination Criteria
5. In-line fuses must be capable of carrying the entire expected load of the downstream feeder.
If the feeder must be capable of carrying another feeder via a downstream cross-connect
switch, the in-line fuse size must take this additional loading into account or else this crossconnect path might not be suitable for use.
Table 10-2
Fuse Link Sizing Chart for Individual Transformers
Transformer
Single-Phase
(kVA)
Transformer
3-Phase Rating
(kVA)
Full Load
Line Current
Fuse Size (1)
15
45
2.08
5
25
75
3.47
10
37.5
112.5
5.21
15
50
150
6.94
20
75
225
10.42
25
100
300
13.89
30
167
500
23.15
50
250
750
34.72
75
333
1000
46.30
100
500
1500
69.45
150
---
2000
92.60
200
Charleston AFB uses Type QA fuse links throughout the system. Figure 10-1 shows the
overcurrent response for different fuse link types; notice that there is a significant difference in
time-current response between various fuse types.
10-4
Charleston AFB
Electrical Protection and Coordination Criteria
1000
4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
3 4 5 67
1000
700
700
500
400
300
500
400
300
200
200
100
100
70
70
50
40
30
50
40
30
20
TYPE T
Fuse Link
50
10
10
7
7
5
4
3
5
4
3
2
2
TYPE K
Fuse Link
50
1
.7
.5
.4
.3
1
TYPE QA
Ke arne y
Fuse Link
50
.7
.5
.4
.3
.2
.1
.2
TYPE H
Fuse Link
50
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
.01
TIM E IN SECONDS
TIM E IN SECONDS
20
4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000
2
3 4 5 6 7 8 9 10000 2
3 4 5 67
.01
CURRENT IN AMPERES AT 12470 VOLTS
Figure 10-1
Various Fuse Link Type Time-Current Response
Figure 10-2 shows an example of the time-current response for a range of Type QA fuse link
sizes. One goal of this study was to determine the optimal fuse size for each location, including
a confirmation of coordination with upstream protective devices.
10-5
Charleston AFB
Electrical Protection and Coordination Criteria
.5 .6 .8 1
1000
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 10
2 3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000
2
3 4 5 6 7 8 9 10000
1000
700
700
500
400
300
500
400
300
200
200
10 ampe re s
100
70
70
50
40
30
50
40
30
25 ampe re s
20
TIM E IN SECONDS
10
20
50 ampe re s
10
7
7
5
4
3
5
4
3
75 ampe re s
2
1
2
100 ampe re s
1
.7
.7
.5
.4
.3
.5
.4
.3
.2
150 ampe re s
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
.01
.5 .6 .8 1
2
TIM E IN SECONDS
100
3 4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000
2
.01
3 4 5 6 7 8 9 10000
CURRENT IN AMPERES AT 12470 VOLTS
Figure 10-2
Various Fuse Time-Current Characteristics – Type QA Fuse Links
10.4
Substation Feeder Relay Instantaneous Trips
The decision of whether or not to include an instantaneous trip on a particular feeder breaker
relay often depends on 1) the downstream devices with which it has to coordinate, 2) the line
10-6
Charleston AFB
Electrical Protection and Coordination Criteria
length, and 3) the presence of automatic circuit breaker reclosing. Depending on the circuit
design, it might be very difficult to coordinate with downstream fusing unless the instantaneous
trip is set very high or is disabled.
With respect to instantaneous trips, IEEE 242-2001, IEEE Recommended Practice for Protection
and Coordination of Industrial and Commercial Power Systems (IEEE Buff Book), Section
14.4.1, Group A Supply-Line Protection, provides the following guidance:
“Instantaneous relays (Device 50) should be employed only where downstream
coordination is not required. These relays should be set to pick up at a current level high
enough so that they do not operate for the maximum asymmetrical fault at the location of
the next downstream overcurrent protective device, i.e., typically 1.6 times the
symmetrical fault current at that location. However, instantaneous line relays often reach
into, but not through, load transformers connected to that line. In some applications
involving short lines, instantaneous relays cannot be coordinated and should not be
used.”
Most feeders are short in terms of electrical distribution system line length. For a short line (a
line whose impedance is low compared to the source impedance), the fault currents for the closein and far-end faults are essentially the same.
10.5
Substation Circuit Breaker Automatic Reclosing
Reclosing should only be applied on circuits where there is a reasonable expectation that faults
will be temporary in nature. Reclosing should be disabled if there is not a reasonable expectation
that temporary faults will occur.
The purpose of circuit breaker reclosing is to automatically restore power whenever a short
circuit is only temporary. Industry experience with overhead lines is that 80 to 90 percent of
faults are temporary, typically caused by lightning, wind-blown tree branches, wind-blown
wires, birds, and animals. If the fault is temporary, the reclose feature allows power to be
restored without requiring power system line crews to respond.
An underground distribution system is different than an overhead distribution system in the types
of short circuits that can occur. An underground distribution system does not experience the
types of temporary faults described above. Instead underground distribution faults tend to be
permanent, caused by cable faults, termination failures, or improper excavation (another type of
cable fault). If the reclosing feature is active when these types of faults occur, the faulted
location is repeatedly reenergized until the reclosing device eventually locks out, thereby causing
further damage to the fault location and unnecessarily stressing system equipment, including the
substation transformer.
In instances of cable damage caused by excavation, the reclose feature is an electrical safety
hazard in that exposed damaged cable is reenergized with workers nearby.
IEEE 242-2001 supports this view in a Caution Note associated with Table 14-6, which states:
10-7
Charleston AFB
Electrical Protection and Coordination Criteria
“Automatics or remote reclosing should not be applied on circuits consisting of cables or
transformer where reclosing reinitiates the permanent faults associated with such
equipment.”
Protective Relaying, Principles and Applications, by J. Lewis Blackburn, supports this view, as
follows:
“Reclosing is generally not used for underground feeders, because cable faults are more
inclined to be permanent. Reclosing is used in practice for combination overheadunderground circuits, with more inclination to use it when the percentage of overhead to
underground is high.”
The Electric Power Distribution Handbook, by T.A. Short, also supports this view as follows:
“Temporary faults are unusual in underground facilities. Faults are normally bolted,
permanent short circuits. Reclosing will just do additional damage to the cable.
On underground circuits, since virtually all faults are permanent, we do not reclose. A
circuit might be considered underground if something like 60 to 80% of the circuit is
underground. Utility practices vary considerably relative to the exact percentage (IEEE
Working Group on Distribution Protection, 1995). A significant number of utilities treat a
circuit as underground if as little as 20% is underground while some others put the
threshold over 80%.”
Other IEEE standards also support this position. IEEE C37.104, IEEE Guide for Automatic
Reclosing of Line Circuit Breakers for AC Distribution and Transmission Lines, states that
reclosing should be applied only when there is a reasonable likelihood of a temporary fault.
IEEE C37-230, IEEE Guide for Protective Relay Applications to Distribution Lines, states that
reclosing is generally not applied on feeders with no overhead exposure, because faults on
underground feeders are generally permanent.
10.6
Cold Load Inrush
Another consideration for distribution feeder relay settings is the effect of cold load pickup. A
high transient current inrush can occur after a feeder is reenergized after an outage. IEEE
C37-230, IEEE Guide for Protective Relay Applications to Distribution Lines, is used as a guide
for this evaluation.
10.6.1 Transformer Magnetizing Inrush
Transformer magnetizing inrush does not present a problem on feeders with smaller sized
transformers as the diversity of inrush between the individual transformers typically cancels out
rather than adding in magnitude that would result in a trip. It does present a problem when large
transformers for commercial or industrial loads are connected and should be considered for the
largest transformer. Feeder protective devices are typically three-phase tripping and closing
mechanisms. When large transformers attached to a feeder are energized by the closing of a
three-pole breaker it, is almost assured that one phase will be closed near a low voltage point that
10-8
Charleston AFB
Electrical Protection and Coordination Criteria
results in a large inrush to that phase of the transformer. Transformer magnetizing inrush can be
8 to 30 times the magnitude of the rated transformer current.
The magnitude of this current is dependent on several factors such as size and location of the
transformer bank, residual flux, type of iron used in the transformer core, and the voltage of the
closing pole (0 voltage induces maximum inrush). Magnetizing inrush is not a symmetrical
phenomenon, and the currents are very different between phases. Transformer inrush contains
several harmonics with the second harmonic being the highest in magnitude. The duration of the
inrush is dependent on the system and the transformer size. Inrush current magnitude typically
decays rapidly over a period of time and for relay coordination purposes it is general practice to
assume that the inrush is 10 times the transformer base rated current for 100 ms.
10.6.2 Load Inrush
In addition to the magnetizing (exciting) inrush current of distribution transformers, a load inrush
can occur as facilities are reenergized. The current inrush magnitude varies with feeder design
and connected equipment.
A significant portion of a distribution feeder’s load will be intermittent loads, such as air
conditioners, electric heaters, and refrigerators. These loads will cycle on and off at differing
intervals, so that, under normal conditions, only a portion are on at any given time. After
extended feeder outages, however, this load diversity is lost. Consequently, when the feeder is
reenergized, all (or most) of these loads will be switched on. This can cause a significant surge in
load current, which may be in excess of time overcurrent pickup levels. This condition is known
as cold load pickup. The additional load will decay over a comparatively long time (by relaying
standards), perhaps 30 minutes or more.
Distribution relay schemes should take cold load surges into consideration. The simplest method
is to set overcurrent pickups above the worst case cold load current, to ensure security. This
decreases sensitivity, however, and may limit the ability to see end-of-zone faults. Alternately,
the feeder can be segmented, to pick up load in portions. This allows the overcurrent relays to be
set sensitively, but extends outages. Numeric-based relay schemes can use adaptive capabilities
to switch into alternate setting groups when cold load conditions are detected. This allows more
sensitive overcurrent settings during low load conditions, while allowing security for cold load
situations.
10.7
Conductor Protection
IEEE 242-2001 is used as the principal reference for conductor protection for short circuit
current considerations. As an example, Figure 10-3 shows conductor short circuit capability as a
function of conductor size. The curves provided here are based on an initial conductor
temperature of 75°C and a final conductor temperature of 200°C. The x-axis scale is 10x.
10-9
Charleston AFB
Electrical Protection and Coordination Criteria
Figure 10-3
Maximum Short-Circuit Current for Insulated Copper Conductors
10-10
11
ELECTRICAL PROTECTION AND COORDINATION –
MAIN SUBSTATION AND SWITCHING STATION
Section 11 addresses electrical protection and coordination for the Charleston AFB Main
Substation and Main Switching Station. This analysis is limited to Charleston AFB and does not
extend upstream into the Santee Cooper system.
11.1
Santee Cooper Substation
The substation transformers have primary protection provided by differential protection
(IJD53C) and sudden pressure (12HAA 15A4F) relays. The primary side overcurrent relays
provide backup transformer protection as well as backup overcurrent protection to the Charleston
AFB feeder breaker overcurrent relays. The secondary side relays provide backup ground fault
protection. These relays are GE IAC53 relays. Table 11-1 provides the relay settings for the
transformers’ overcurrent protection. Phase overcurrent protection is provided on the primary
side of each transformer and neutral overcurrent protection is provided on the secondary side of
each transformer.
Table 11-1
Existing Santee Cooper Substation Overcurrent Relay Settings
Relay Settings
Transformer #1
Transformer #2
IAC53
IAC53
Tap
4
4
Time dial
6
6
Instantaneous pickup
None
None
CT ratio
200:5
200:5
IAC53
IAC53
Tap
5
5
Time dial
7
7
Instantaneous pickup
None
None
CT ratio
1000:5
1000:5
Phase Settings
Relay type
Neutral Settings
Relay type
All Santee Cooper protective relays trip the primary-side circuit interrupter – an S&C Model
2040 circuit switcher. Figure 11-1 shows the time-current curves for these relays.
11-1
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2 3 4 5 6 7 8 9 1000002
700
100
500
400
300
T-SUB 2 - PRI
200
T-SUB 2
12000 / 17920 kVA
7.51%
100
70
70
50
40
30
50
40
30
20
20
T-SUB 2 - PRI
GE IAC 53
51/50
Very Inverse
CT Ratio = 200/5
Tap = 4 (160A)
Time Dial = 6
10
TIME IN SECONDS
1000
700
T-SUB 2 - SEC
500
400
300
200
3 4 5
T-SUB 2
FLA
7
5
4
3
10
7
5
4
3
T-SUB 2 - SEC
GE IAC 53
51/50
Very Inverse
CT Ratio = 1000/5
Tap = 5 (1000A)
Time Dial = 7
2
1
2
1
.7
.7
.5
.4
.3
.5
.4
.3
.2
.2
T-SUB 2
12000 / 17920 kVA
INRUSH
.1
.07
.1
.07
.05
.04
.03
.05
.04
.03
.02
.01
TIME IN SECONDS
1000
3 4 5 6 7 8 9 100
T-SUB 2 - SEC
11066A
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
T-SUB 2 - PRI
9610A
3 4 5 6 7 8 9 1000002
3 4 5
.02
.01
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-1
Santee Cooper Overcurrent Relay Time-Current Curves
11.2
Main Switching Station – Existing Settings
Figure 11-2 provides a simplified one-line drawing of the Main Switching Station. As shown, a
main circuit breaker and five feeder breakers are installed.
11-2
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Santee Cooper
Substation
5319
200/5
CI
5318
Circuit
Interrupter
1200/5
1000/5
5311
5313
51
51N
Substation
Transformer T2
200/5
M3
Blades
51
52
Main
5333
51N
12.47 kV Main Bus
M1
Blades
Transfer Bus
51N
Station
Service
F1 - Blades
1000/5
5331
51
5320
12.47 kV Bus
5301
115 kV Bus
5317
M5
Bypass
Switch
Substation
Transformer T1
50/
51
500/5
F7
Switch
Charleston AFB
Switching Station
52
D1 - Blades
E1 - Blades
50/
51N
50/
51
500/5
E7
Switch
F
52
50/
51N
E
500/5
D7
Switch
50/
51
C1 - Blades
50/
51N
52 D
50/
51
500/5
C7
Switch
52
A1 - Blades
50/
51N
Flagpole
50/
51
500/5
A7
Switch
52
50/
51N
Hunley Park
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
Voltage
Regulator
F3 - Blades
E3 - Blades
D3 - Blades
C3 - Blades
A3 - Blades
F Feeder
E Feeder
D Feeder
Flagpole
Feeder
To Flagpole Feeder
Switching Station
Figure 11-2
Electrical Distribution System Simplified One-Line
11-3
Hunley
Park
Feeder
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Bus differential protection is provided by GE PVD21B1A relays. The PVD21 relay is a single
phase, high-speed, high-impedance, voltage-operated relay designed to provide protection in bus
differential schemes. The PVD21 utilizes the same operating principle (high impedance voltage)
as the earlier PVD models, but provides faster operating speeds and higher seismic capabilities.
The CT inputs to the relays are all 1,200:5 ratio and the relays are set on low.
Figure 11-3
Bus Differential Protection Relays
Overcurrent protective relays provide phase and ground fault protection for the main and feeder
breakers. The relays are GE IFC53 relays for the main breaker and GE IFC77 relays for the
feeder breakers. Figure 11-4 shows the relays and Table 11-2 provides the relay settings.
11-4
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Figure 11-4
Overcurrent Relays
Table 11-2
Overcurrent Relay Settings – Existing
Relay Setting
Main
Feeder F
(NCO)
Feeder E
(Officers)
Feeder D
Flagpole
Feeder
Hunley
Park
Feeder
IFC53A1A
1 – 12
5
5
IFC77B1A
1 – 12
5
3
IFC77B1A
1 – 12
5
3
IFC77B1A
1 – 12
6
5
IFC77B1A
1 – 12
7
5
IFC77B1A
1 – 12
5
3
None
Disabled
Disabled
63
56
35
IFC53A1A
1 – 12
1.5
4
None
1200:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
38
500:5
IFC77B2A
0.5 – 4
2.0
8
35
500:5
IFC77B2A
0.5 – 4
1.2
4
28
500:5
Phase Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
Ground Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
CT ratio
Notes:
1. Relay settings were obtained from the CEMIRT 2011 calibration report, which is available in
the enclosed DVD.
11-5
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
2. The IFC53 relay has very inverse characteristics. The A1A version used for phase and
ground protection has a tap range of 1 to 12, with no instantaneous trip unit.
3. The IFC77 relay has extremely inverse characteristics. The B1A version used for phase
protection has a tap range of 1 to 12, with an instantaneous trip range of 6 to 150. The B2A
version used for ground protection has a tap range of 0.5 to 4, with an instantaneous trip
range of 2 to 50.
The existing relay settings were established as part of the new switching station installation in
2007. The following summarizes the bases for these settings as established in 2007:
1. The main breaker relays do not include instantaneous trip capability. The curve shape is
Very Inverse. The settings are high enough to ensure coordination with downstream feeders
and also carry the base peak power demand with margin. The ground trip pickup is relatively
high to enable coordination of the Very Inverse curve with the Extremely Inverse curves of
the downstream feeder relays.
2. The settings for the Flagpole Feeder are intended to ensure coordination with the downstream
relays at the Flagpole Feeder Switching Station. The instantaneous trips for Flagpole Feeder
are intended to reach to the Flagpole Feeder Switching Station for Feeders A, B, and C. The
time delays are set relatively high to allow coordination with Feeders A, B, and C.
3. The instantaneous trips are disabled for Feeders E and F. These feeders are entirely
underground and have a large number of pad-mounted switchgear fused with SMU-20 fuses,
typically sized at 150E or 200E. By disabling the relay instantaneous trips, this provides
some coordination time for fuse clearing, which will minimize the extent of an outage and
simplify cable fault locating. The time delay is reduced for the phase relays without
compromising coordination with the larger downstream fuses.
4. The Hunley Park Feeder instantaneous trips are intended to reach close to, but not
significantly beyond, the Hunley Park pad-mounted switchgear.
5. Feeder D has the largest power demand. Its pickup settings are higher for this reason.
Figure 11-5 shows the time-current curves for the main breaker and the upstream Santee Cooper
overcurrent relays. The difference in time between the two sets of time current curves should
ensure that the main breaker trips before the upstream Santee Cooper circuit switcher. The main
breaker is only intended to provide backup overcurrent protection for the feeder breaker
overcurrent relays.
11-6
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
1000
3 4 5 6 7 8 9 100
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2 3 4 5 6 7 8 9 1000002
MAIN-N
3 4 5
T-SUB 2 - SEC
700
1000
700
MAIN-P
500
400
300
500
400
300
T-SUB 2 - PRI
200
200
100
100
70
70
50
40
30
50
40
30
20
20
T-SUB 2 - PRI
GE IAC 53
51/50
Very Inverse
CT Ratio = 200/5
Tap = 4 (160A)
Time Dial = 6
7
5
4
3
2
MAIN-P
GE IFC 53
51/50
Very Inverse
CT Ratio = 1200/5
Tap = 5 (1200A)
Time Dial = 5
1
.5
.4
.3
5
4
3
2
T-SUB 2 - SEC
GE IAC 53
51/50
Very Inverse
CT Ratio = 1000/5
Tap = 5 (1000A)
Time Dial = 7
MAIN-N
GE IFC 53
51N/50N
Very Inverse
CT Ratio = 1200/5
Tap = 1.5 (360A)
Time Dial = 4
.7
10
7
1
.7
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
MAIN-P
11446A
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-5
Main Breaker Coordination With Santee Cooper Relays
11-7
3 4 5 6 7 8 9 1000002
3 4 5
.01
TIME IN SECONDS
TIME IN SECONDS
10
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Figure 11-6 shows the expected coordination for the main breaker and the Flagpole Feeder. The
instantaneous trips for the Flagpole Feeder ensure coordination for high-level faults; this region
extends to the Flagpole Feeder Switching Station and Feeders A, B, and C provide additional
overcurrent protection beyond this point.
1000
10
2
3 4 5 6 7 89 100
CURRENT IN AMPERES AT 12470 VOLTS
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
FP FDR - N
MAIN-N
700
3 4 5 6 7 89 100000
MAIN-P
1000
700
FP FDR - P
500
400
300
500
400
300
200
200
100
100
70
70
50
40
30
50
40
30
20
20
10
MAIN-P
GE IFC 53
51/50
Very Inverse
CT Ratio = 1200/5
Tap = 5 (1200A)
Time Dial = 5
7
FP FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 7 (700A)
Time Dial = 5
Instantaneous = 56 (5600A)
5
4
3
2
MAIN-N
GE IFC 53
51N/50N
Very Inverse
CT Ratio = 1200/5
Tap = 1.5 (360A)
Time Dial = 4
FP FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 2 (200A)
Time Dial = 8
Instantaneous = 35 (3500A)
.5
.4
.3
5
4
3
2
1
.7
7
1
.7
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
FP FDR - N
7107A
10
2
3 4 5 6 7 89 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-6
Flagpole Feeder Coordination With Main Breaker
11-8
3 4 5 6 7 89 100000
.01
TIME IN SECONDS
TIME IN SECONDS
10
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Figure 11-7 shows the coordination with between the main breaker and the HP Feeder (Hunley
Park). The coordination is acceptable. At the time that the HP Feeder overcurrent relay settings
were established, the feeder was still overhead between the substation and the Hunley Park area.
The instantaneous trip settings were intended to reach to Hunley Park, but not significantly
beyond. Now that Feeder HP is entirely underground, the settings should be changed (refer to
Section 11.3).
1000
10
2
3 4 5 6 7 8 9 100
CURRENT IN AMPERES AT 12470 VOLTS
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
HP FDR - N
3 4 5 6 7 8 9 100000
MAIN-P
MAIN-N
700
1000
700
HP FDR - P
500
400
300
500
400
300
100
100
70
70
50
40
30
50
40
30
20
20
10
10
7
7
5
4
3
MAIN-P
GE IFC 53
51/50
Very Inverse
CT Ratio = 1200/5
Tap = 5 (1200A)
Time Dial = 5
HP FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 5 (500A)
Time Dial = 3
Instantaneous = 35 (3500A)
2
1
HP FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 1.2 (120A)
Time Dial = 4
Instantaneous = 28 (2800A)
.2
2
1
MAIN-N
GE IFC 53
51N/50N
Very Inverse
CT Ratio = 1200/5
Tap = 1.5 (360A)
Time Dial = 4
.7
.5
.4
.3
5
4
3
.7
.5
.4
.3
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
MAIN-N
6794A
10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-7
HP Feeder Coordination With Main Breaker
11-9
3 4 5 6 7 8 9 100000
.01
TIME IN SECONDS
200
TIME IN SECONDS
200
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Feeders E and F have the same overcurrent relay settings. Figure 11-8 shows the time-current
curves and the coordination is acceptable. The instantaneous trips are disabled for Feeders E and
F because these feeders are entirely underground. By disabling the relay instantaneous trips, this
provides some coordination time for fuse clearing, which will minimize the extent of an outage
and simplify cable fault locating. The time delay is reduced for the phase relays without
compromising coordination with the larger downstream fuses. Refer to Section 11.3 for other
recommendations.
1000
10
2
3 4 5 6 7 8 9 100
CURRENT IN AMPERES AT 12470 VOLTS
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
E FDR - N
3 4 5 6 7 89 100000
MAIN-P
MAIN-N
700
1000
700
E FDR - P
500
400
300
500
400
300
200
200
100
100
70
70
50
40
30
50
40
30
20
20
10
7
MAIN-P
GE IFC 53
51/50
Very Inverse
CT Ratio = 1200/5
Tap = 5 (1200A)
Time Dial = 5
E FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 5 (500A)
Time Dial = 3
Instantaneous = Disabled
5
4
3
2
.7
.5
.4
.3
5
4
3
2
MAIN-N
GE IFC 53
51N/50N
Very Inverse
CT Ratio = 1200/5
Tap = 1.5 (360A)
Time Dial = 4
E FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 1.2 (120A)
Time Dial = 4
Instantaneous = Disabled
1
7
1
.7
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
E FDR - N
8359A
10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-8
Feeder E/F Coordination With Main Breaker
11-10
3 4 5 6 7 89 100000
.01
TIME IN SECONDS
TIME IN SECONDS
10
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Feeder D has the largest power demand of any single feeder and its pickup settings are somewhat
higher for this reason. The instantaneous trip is active because reclosing is enabled for this
feeder. The coordination with the upstream main breaker is acceptable. Refer to Section 11.3
for other recommendations.
1000
10
2
3 4 5 6 7 89 100
CURRENT IN AMPERES AT 12470 VOLTS
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
700
3 4 5 6 7 89 100000
D FDR - P
D FDR - N
MAIN-N
1000
700
MAIN-P
500
400
300
500
400
300
200
200
100
100
70
70
50
40
30
50
40
30
20
20
MAIN-P
GE IFC 53
51/50
Very Inverse
CT Ratio = 1200/5
Tap = 5 (1200A)
Time Dial = 5
7
5
4
3
MAIN-N
GE IFC 53
51N/50N
Very Inverse
CT Ratio = 1200/5
Tap = 1.5 (360A)
Time Dial = 4
2
D FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 6 (600A)
Time Dial = 5
Instantaneous = 63 (6300A)
1
.7
D FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 1.2 (120A)
Time Dial = 4
Instantaneous = 38 (3800A)
.5
.4
.3
.2
10
7
5
4
3
2
1
.7
.5
.4
.3
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
MAIN-N
6794A
10
2
3 4 5 6 7 89 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 11-9
Feeder D Coordination With Main Breaker
11-11
3 4 5 6 7 89 100000
.01
TIME IN SECONDS
TIME IN SECONDS
10
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
11.3
Main Switching Station – Recommended Settings
Setting changes are recommended for the following reasons:

The original design documents on which the relay settings are based indicated identical 250
kVA voltage regulators on all feeders. Instead, Feeders E, F, and HP have 167 kVA voltage
regulators installed, with only 2/3 the capacity originally expected. The specified relay
settings should not allow overloading these voltage regulators. The recommended relay
settings will be based on Feeders E, F, or HP supplying a cross-tie to another feeder with the
voltage adjustment range reduced to ±5%. The maximum allowed current through the
voltage regulator for this configuration is 371 amperes. Note: the pickups can be left at 5
rather than reset to 4 if the voltage regulators are upgraded.

The instantaneous trip settings for the Flagpole Feeder were based on an overhead
distribution between the Main Substation and the Flagpole Feeder Switching Station, which
has changed. The available short circuit current at the Flagpole Feeder Switching Station is
now higher than it previously was for an overhead distribution supply. For this reason, the
Flagpole Feeder relay instantaneous trips now reach well into Feeders A, B, and C. A
complete loss of the Flagpole Feeder is not desired for a fault on Feeder A.

The instantaneous trip settings for Feeder HP were based on an overhead distribution
between the Main Substation and the Hunley Park area, which has changed. Feeder HP is
entirely underground now and this feeder should be set up similar to Feeders E and F.
Table 11-3 provides the recommended settings; changes are highlighted in yellow. The setting
changes should be made as part of the next relay calibration. CEMIRT is recommended as a
source for these setting changes.
Table 11-3
Overcurrent Relay Settings – Recommended
Relay Setting
Main
Feeder F
(NCO)
Feeder E
(Officers)
Feeder D
Flagpole
Feeder
Hunley
Park
Feeder
IFC53A1A
1 – 12
5
5
IFC77B1A
1 – 12
4
3
IFC77B1A
1 – 12
4
3
IFC77B1A
1 – 12
5
5
IFC77B1A
1 – 12
7
4
IFC77B1A
1 – 12
4
3
None
Disabled
Disabled
63
Disabled
Disabled
IFC53A1A
1 – 12
1.5
4
None
1200:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
Disabled
500:5
IFC77B2A
0.5 – 4
1.2
4
38
500:5
IFC77B2A
0.5 – 4
2.5
4
IFC77B2A
0.5 – 4
1.2
4
Disabled
Disabled
500:5
500:5
Phase Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
Ground Settings
Relay type
Tap Range
Tap
Time dial
Instantaneous pickup
CT ratio
11-12
Charleston AFB
Electrical Protection and Coordination – Main Substation and Switching Station
Notes:
1. The IFC53 relay has very inverse characteristics. The A1A version used for phase and
ground protection of the main breaker has a tap range of 1 to 12, with no instantaneous trip
unit.
2. The IFC77 relay has extremely inverse characteristics. The B1A version used for phase
protection has a tap range of 1 to 12, with an instantaneous trip range of 6 to 150. The B2A
version used for ground protection has a tap range of 0.5 to 4, with an instantaneous trip
range of 2 to 50.
11-13
12
ELECTRICAL PROTECTION AND COORDINATION –
PRIMARY DISTRIBUTION
Section 12 evaluates relay coordination with downstream pad-mounted switchgear and primary
distribution system fusing. The figures provided in this section are based on the recommended
relay settings provided in Section 11.3.
12.1
G&W VFI Pad-Mounted Switchgear
G&W VFI switchgear are installed in several locations around the base and have also been used
to replace the Flagpole Feeder Switching Station.
12.1.1 G&W VFI Trip Setting Recommendations
The following summarizes the desired goals for selection of G&W switchgear VFI trip settings:
1. Provide adequate protection throughout the system, taking into account the unique system
features downstream of each switchgear compartment.
2. Select settings that are as small as possible, while considering the constraints of downstream
circuit full-load and inrush capability. The goal here is to encourage each VFI to respond to
a downstream fault rather than just have the main feeder relaying respond to the fault.
Based on the above goals, the following criteria will be applied:
1. If only one transformer is supplied and it does not have internal fuses:

Select a trip setting that provides transformer protection. Refer to Table 12-1.

Note that very few transformers fall into this category.
2. If only one transformer is supplied and it does have internal fuses:

Select a trip setting that is approximately one size larger than the internal fuses that
typically provide transformer protection. Refer to Table 12-2.

The purpose of this selection is to possibly allow the transformer fusing to respond to an
internal fault. But, more importantly, this lateral will be removed from service as soon as
possible to minimize any effect on the main feeder.
12-1
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
3. If multiple transformers are supplied from a single compartment:

Ensure selected trip settings can carry the full-load current of downstream transformers.

Ensure selected trip settings can withstand the inrush current of simultaneously
energizing the downstream transformers.

Provide conductor protection.

Coordinate as well as possible with upstream phase and neutral relaying.

Allow for cross-ties if the downstream loads allow cross-connect to another feeder.

A table is not provided for this case. Each configuration requires a specific review. For
relatively small laterals with limited load, the settings will tend to be set low so that the
lateral will be removed from service as soon as possible to minimize any effect on the
main feeder.
Table 12-1
G&W Trip Setting Selection Chart to Provide Primary Protection for Individual Transformers
Transformer
1-Phase
Rating (kVA)
Transformer
3-Phase
Rating (kVA)
3-Phase
Full Load
Line Current
E-Speed
Setting
(amperes)
15
45
2.08
15
25
75
3.47
15
37.5
112.5
5.21
15
50
150
6.94
20
75
225
10.42
25
100
300
13.89
35
167
500
23.15
60
---
750
34.72
100
---
1000
46.30
125
---
1500
69.45
175
---
2000
92.60
225
Note: Minimum setting is either 15 or 30 amperes, and varies with the style. Select nearest
available setting is trip unit configuration does not include the above settings.
12-2
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Table 12-2
G&W Trip Setting Selection Chart to Provide Backup Protection for Individual Transformers
Transformer
1-Phase
Rating (kVA)
Transformer
3-Phase
Rating (kVA)
3-Phase
Full Load
Line Current
E-Speed
Setting
(amperes)
15
45
2.08
15
25
75
3.47
20
37.5
112.5
5.21
25
50
150
6.94
25
75
225
10.42
35
100
300
13.89
45
167
500
23.15
75
---
750
34.72
100
---
1000
46.30
125
---
1500
69.45
175
---
2000
92.60
225
12.1.2 G&W Flagpole Feeder Switching Station
The new Flagpole Feeder Switching Station uses G&W switchgear containing a combination of
switches and VFIs. The VFIs supplying each feeder have been set up with E-speed trips at 450
amperes. Figure 12-1 shows these settings with respect to the recommended switching station
settings for the upstream relays. As shown, the VFI should always trip before the upstream relay
except for a very low level sustained ground fault, which is not expected for an underground
distribution.
12-3
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1000
10
2
3 4 5 6 7 89 100
CURRENT IN AMPERES AT 12470 VOLTS
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 8 9 10000 2
FP FDR - N
3 4 5 6 7 89 100000
SW-A0-3 - 2
700
1000
700
SW-A0-3 - 1
500
400
300
500
400
300
FP FDR - P
200
200
100
100
70
70
50
40
30
50
40
30
20
20
SW-A0-3 - 2
G&W PVI
51
E-Speed Std Max
CT Ratio = 1/1
Pickup = 450 (450A)
Curves = 1
7
5
4
3
10
7
5
4
3
FP FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 7 (700A)
Time Dial = 4
Instantaneous = Disabled
2
1
.7
.5
.4
.3
FP FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 2.5 (250A)
Time Dial = 4
Instantaneous = Disabled
.2
2
1
.7
.5
.4
.3
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
SW-A0-3 - 1
6397A
10
2
3 4 5 6 7 89 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 8 9 10000 2
3 4 5 6 7 89 100000
.01
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-1
Recommended Flagpole Feeder Relay and G&W Switchgear VFI Coordination
Figure 12-2 shows the Flagpole Feeder Switching Station VFI settings with respect to
downstream fusing. The coordination should be acceptable for all but the largest fuses. Many
S&C SMU-20 200E fuses have been inappropriately installed in the system and they might not
clear before the VFI trips.
12-4
TIME IN SECONDS
TIME IN SECONDS
10
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
3 4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 89 1000 2
3 4 5 6 7 8 9 10000 2
SW-B0-3 - 2
700
700
SW-B0-3 - 1
500
400
300
500
400
300
200
200
100
100
SW-B5A-3
S&C
SMU
SMU-20
125E
70
50
40
30
SW-B10-1
S&C
SMU
SMU-20
200E
70
50
40
30
SW-B5-3
S&C
SMU
SMU-20
80E
20
10
TIME IN SECONDS
1000
20
10
SW-B0-3 - 2
G&W PVI
51
E-Speed Std Max
CT Ratio = 1/1
Pickup = 450 (450A)
Curves = 1
7
5
4
3
SW-B19-3
S&C
SMU
SMU-20
40E
2
.7
.5
.4
.3
5
4
3
2
SW-B18-3
S&C
SMU
SMU-20
10E
1
7
1
.7
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
SW-B5A-3
6404A
2
3 4 5 6 7 8 9 10
TIME IN SECONDS
1000
2
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 89 1000 2
3 4 5 6 7 8 9 10000 2
.02
.01
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-2
G&W Switchgear VFI Coordination With Downstream Switchgear Fusing
12.2
S&C VFI Pad-Mounted Switchgear
S&C Vista switchgear are installed in Hunley Park. The following summarizes the desired goals
for selection of S&C Vista switchgear VFI trip settings:
12-5
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1. Provide adequate protection throughout the system, taking into account the unique system
features downstream of each switchgear compartment.
2. Select settings that are as small as possible, while considering the constraints of downstream
circuit full-load and inrush capability. The goal here is to encourage each VFI to respond to
a downstream fault rather than just have the main feeder relaying respond to the fault.
Based on the above goals, the following criteria will be applied:
1. If only one transformer is supplied and it does not have internal fuses:

Select a trip setting that provides transformer protection. Refer to Table 12-3.

Note that very few transformers fall into this category.
2. If only one transformer is supplied and it does have internal fuses:

Select a trip setting that is approximately one size larger than the internal fuses that
typically provide transformer protection. Refer to Table 12-4.

The purpose of this selection is to possibly allow the transformer fusing to respond to an
internal fault. But, more importantly, this lateral will be removed from service as soon as
possible to minimize any effect on the main feeder.
3. If multiple transformers are supplied from a single compartment:

Ensure selected trip settings can carry the full-load current of downstream transformers.

Ensure selected trip settings can withstand the inrush current of simultaneously
energizing the downstream transformers.

Provide conductor protection.

Coordinate as well as possible with upstream phase and neutral relaying.

Allow for cross-ties if the downstream loads allow cross-connect to another feeder.

A table is not provided for this case. Each configuration requires a specific review. For
relatively small laterals with limited load, the settings will tend to be set low so that the
lateral will be removed from service as soon as possible to minimize any effect on the
main feeder.
4. If the VFI serves as a higher ampacity cross-tie point between feeders:

Do not use Table 12-3 or Table 12-4.

Select a 51 relay curve, including ground trip, and coordinate the cross-tie location with
the upstream feeder.
12-6
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Table 12-3
S&C Vista Trip Setting Selection Chart to Provide Primary Protection for Individual Transformers
Transformer
1-Phase
Rating (kVA)
Transformer
3-Phase
Rating (kVA)
3-Phase
Full Load
Line Current
E-Speed
Setting
(amperes)
15
45
2.08
25
25
75
3.47
25
37.5
112.5
5.21
25
50
150
6.94
25
75
225
10.42
25
100
300
13.89
25
167
500
23.15
30
---
750
34.72
50
---
1000
46.30
65
---
1500
69.45
100
---
2000
92.60
125
Notes:
1. The S&C Vista switchgear typically have CT ratios of 660:1, which should be confirmed.
Minimum trip setting is 25 amperes.
2. Available E-speed settings are 25E, 30E, 40E, 50E, 65E, 80E, 100E, 125E, 150E, 175E,
200E, 250E, 300E, and 400E.
12-7
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Table 12-4
S&C Vista Trip Setting Selection Chart to Provide Backup Protection for Individual Transformers
Transformer
1-Phase
Rating (kVA)
Transformer
3-Phase
Rating (kVA)
3-Phase
Full Load
Line Current
E-Speed
Setting
(amperes)
15
45
2.08
25
25
75
3.47
25
37.5
112.5
5.21
25
50
150
6.94
25
75
225
10.42
25
100
300
13.89
25
167
500
23.15
40
---
750
34.72
65
---
1000
46.30
80
---
1500
69.45
125
---
2000
92.60
150
12.3
Comparison of S&C Vista and G&W Switchgear
The VFI trip settings for S&C and G&W switchgear are not equivalent. Although both types of
VFIs can follow an E-speed curve, the S&C settings emulate S&C fuses, whereas the G&W
settings do not. Figure 12-3 provides an example for a trip setting of 100 amperes. Notice that
the G&W VFI will trip at 100 amperes, but the S&C Vista VFI will not trip until about 200
amperes. This difference in trip characteristic should be considered when establishing trip
settings.
12-8
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1000
4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 13200 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 89 10000 2
3 4 5 67
SG-HL04-5-3 - 2
700
1000
700
SG-HL04-5-3 - 1
500
400
300
500
400
300
200
200
100
100
70
20
70
SG-HL01-5 - 2
S&C Vista
E-Speed Tot Cl
E100
CT Ratio = 1/1
Tap = 1 (1A)
Curve = Tot Clear
SG-HL04-5-3 - 2
G&W PVI
51
E-Speed Std Max
CT Ratio = 1/1
Pickup = 100 (100A)
Curves = 1
50
40
30
20
10
7
7
5
4
3
5
4
3
2
2
1
1
.7
.7
.5
.4
.3
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
TIME IN SECONDS
10
.01
4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 89 10000 2
3 4 5 67
.01
CURRENT IN AMPERES AT 13200 VOLTS
Figure 12-3
Comparison of S&C Vista and G&W Switchgear VFI Settings
12.4
Fused Pad-Mounted Switchgear
Fused pad-mounted switchgear normally use a combinations of switches and fuses. The switch
compartments usually supply the in and out for the main circuit run, with the fused
12-9
TIME IN SECONDS
50
40
30
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
compartments used for lateral supplies to individual transformers. A conductor fault
downstream of the switchgear should preferentially be cleared by the switchgear fusing. Figure
12-4 shows the time-current characteristics of SMU-20 fuses that are typically used in fused
switchgear.
3 4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000
2
3 4 5 6 7 8 9 10000 2
700
700
500
400
300
500
400
300
SM U-20
15E
200
200
SM U-20
40E
100
100
SM U-20
65E
70
50
40
30
70
50
40
30
SM U-20
100E
20
10
TIM E IN SECONDS
1000
20
10
SM U-20
125E
7
5
4
3
7
5
4
3
SM U-20
150E
2
2
1
1
SM U-20
175E
.7
.5
.4
.3
.7
.5
.4
.3
SM U-20
200E
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
.01
2
3 4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-4
Various Fuse Time-Current Characteristics – Type SMU-20
12-10
2
3 4 5 6 7 8 9 10000 2
.01
TIM E IN SECONDS
1000
2
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
The following summarizes the desired goals for fusing of pad-mounted switchgear:
1. Provide adequate protection throughout the system, taking into account the unique design
features downstream of each switchgear compartment.
2. Select fuses that are as small as possible, while considering the constraints of downstream
circuit full-load and inrush capability. The goal here is to encourage the fuses to clear for a
downstream fault, if possible, rather than just have the main feeder relaying respond to the
fault.
Based on the above goals, the following criteria will be applied to fusing evaluations:
1. If only one transformer is supplied and it does not have internal fuses:

Select a fuse size that provides transformer protection.
2. If only one transformer is supplied and it does have internal fuses:

Select a fuse size that is at least one size larger than the internal fuses that provide
transformer protection.
3. If multiple transformers are supplied from a single switch compartment:

Ensure selected fuse size can carry the full-load current of downstream transformers.

Ensure selected fuse size can withstand the inrush current of simultaneously energizing
the downstream transformers.

Provide conductor protection.

Coordinate as well as possible with upstream phase and neutral relay settings.
When a fault occurs on the system, these fuses are often the last line of defense before an
upstream feeder circuit breaker will respond and open to deenergize the entire feeder.
Table 12-5 provides the recommended fuse size for any pad-mounted switchgear compartment
that is supplying a single unfused transformer. Table 12-6 provides the recommended fuse size
for any pad-mounted switchgear compartment that is supplying a single fused transformer, which
in this case would be backup protection. All fuses are identified as “E” speed, which is the
standard speed.
12-11
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Table 12-5
Fuse Sizing Chart to Provide Primary Protection for Individual Transformers
Transformer
1-Phase Rating
(kVA)
Transformer
3-Phase Rating
(kVA)
3-Phase
Full Load
Line Current
Recommended
Fuse Size
15
45
2.08
3E
25
75
3.47
5E
37.5
112.5
5.21
7E
50
150
6.94
10E
75
225
10.42
15E
100
300
13.89
20E
167
500
23.15
30E
250
750
34.72
50E
—
1000
46.30
65E
—
1500
69.45
100E
—
2000
92.60
125E
Table 12-6
Fuse Sizing Chart to Provide Backup Protection for Individual Transformers
Transformer
1-Phase Rating
(kVA)
Transformer
3-Phase Rating
(kVA)
Full Load
Line Current
Recommended
Fuse Size
15
45
2.08
5E
25
75
3.47
7E
37.5
112.5
5.21
10E
50
150
6.94
15E
75
225
10.42
20E
100
300
13.89
30E
167
500
23.15
40E
250
750
34.72
65E
—
1000
46.30
80E
—
1500
69.45
125E
—
2000
92.60
150E
12-12
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Many of the fused switchgear have been installed with oversized fuses; this observation applies
to the most recent construction also. Either 150E or 200E fuses have been installed. Although
these fuses offer conductor overcurrent protection, no attempt has been made to coordinate with
the upstream feeder breaker relays.
Feeders E, F, and HP have the same recommended relay settings. Figure 12-5 shows that the
relays coordinate with larger fuses for faults above 2,000 amperes. If the fault current is lower
than 2,000 amperes, the relay might trip the feeder breaker without causing fuse damage or
clearing, which will complicate feeder recovery efforts.
12-13
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1000
10
2
3 4 5 6 7 89 100
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 89 1000 2 3 4 5 6 7 8 9 10000 2
E FDR - N
3 4 5 6 7 8 9 100000
E FDR - P
1000
700
700
500
400
300
500
400
300
200
200
S-3H-3
S&C
SMU
SMU-20
200E
70
50
40
30
70
50
40
30
S-6H-3
S&C
SMU
SMU-20
150E
20
TIME IN SECONDS
100
20
10
10
7
7
5
4
3
E FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 4 (400A)
Time Dial = 3
Instantaneous = Disabled
2
1
5
4
3
2
1
.7
E FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 1.2 (120A)
Time Dial = 4
Instantaneous = Disabled
.5
.4
.3
.2
.7
.5
.4
.3
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.02
.01
TIME IN SECONDS
100
10
2
3 4 5 6 7 89 100
2
3 4 5 6 7 89 1000 2
3 4 5 6 7 8 9 10000 2
3 4 5 6 7 8 9 100000
.01
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-5
Feeder E, F, and HP Coordination With Downstream Fused Switchgear
12.5
Overhead Distribution Fusing
The overhead distribution system contains fused cut-outs in a variety of locations, usually
intended to protect riser conductors, pole-mounted transformers, and pad-mounted transformers.
12-14
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
A coordination study typically has difficulty determining fuse link size for overhead cutouts.
The fuse size can rarely be confirmed without requiring electrical shop personnel isolate each
cutout for a visual inspection, which tends to be a complex and time-consuming undertaking.
For these reasons, the following approach is taken with respect to fuse sizing for overhead
cutouts:
1. The optimal fuse size is determined for each location. Future system outages can then
include a fuse link check, with replacements as necessary.
2. The selected fuse link size is based on standard industry guidance. Table 12-7 provides the
fuse selection criteria applied to this study.
3. The fuse link type used in the analysis is selected based on the predominant type in service
throughout the primary distribution system (Type QA).
4. If the fused cutouts supply more than one pad-mounted transformer in a looped
configuration, the selected fuse link size is based on the combined kVA rating of the
transformers, and possibly downsized by one fuse size to account for typical less than full
load conditions. Note that the fused cutouts often do not provide adequate protection for any
transformer in this configuration; each transformer must have its own set of fuses for
adequate protection.
5. In-line fuses must be capable of carrying the entire expected load of the downstream feeder.
If the feeder must be capable of carrying another feeder via a downstream cross-connect
switch, the in-line fuse size must take this additional loading into account or else this crossconnect path might not be suitable for use.
12-15
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
Table 12-7
Fuse Link Sizing Chart for Individual Transformers
Transformer
Single-Phase
(kVA)
Transformer
3-Phase Rating
(kVA)
Full Load
Line Current
Fuse Size (1)
15
45
2.08
5
25
75
3.47
10
37.5
112.5
5.21
15
50
150
6.94
20
75
225
10.42
25
100
300
13.89
30
167
500
23.15
50
250
750
34.72
75
333
1000
46.30
100
500
1500
69.45
150
---
2000
92.60
200
Whenever a permanent fault occurs downstream of overhead fusing, it is preferred that the fusing
clear before the upstream relays respond to the fault. Feeders A, B, E, F, and HP are entirely
underground. Accordingly, this consideration applies only to Feeders C and D. Figure 12-6 and
Figure 12-7 show the expected response for a range of fuse sizes. Feeder C coordinates well
with downstream overhead fusing. Feeder D also coordinates well even with its instantaneous
trips. Reclosing is active for Feeder D; its circuit breaker will reclose following a fault and the
downstream fusing should clear except for the highest level faults near the Main Switching
Station.
12-16
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1000
4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000 2 3 4 5 6 7 89 10000 2
FP FDR - N
3 4 5 67
FP FDR - P
700
1000
700
SW-C0-3 - 2
500
400
300
500
400
300
SW-C0-3 - 1
200
200
100
100
70
70
20
50
40
30
SW-C0-3 - 2
G&W PVI
51
E-Speed Std Max
CT Ratio = 1/1
Pickup = 350 (350A)
Curves = 1
P-C47
Kearney
Fuse Links
QA
150
20
TIME IN SECONDS
10
7
5
4
3
2
1
10
7
P-C44
Kearney
Fuse Links
QA
100
FP FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 7 (700A)
Time Dial = 4
Instantaneous = Disabled
P-C36
Kearney
Fuse Links
QA
75
2
1
FP FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 2.5 (250A)
Time Dial = 4
Instantaneous = Disabled
.7
.5
.4
.3
5
4
3
P-C21
Kearney
Fuse Links
QA
30
.7
.5
.4
.3
.2
.2
.1
.1
.07
.07
.05
.04
.03
.05
.04
.03
.02
.01
.02
P-C47
3728A
4 5 6 7 8 9 10
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
3 4 5 6 7 89 10000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-6
Feeder C Relay Coordination With Overhead Fusing
12-17
3 4 5 67
.01
TIME IN SECONDS
50
40
30
Charleston AFB
Electrical Protection and Coordination – Primary Distribution
1000
2
3 4 5 6 7 8 9 10
2
CURRENT IN AMPERES AT 12470 VOLTS
3 4 5 6 7 8 9 100
2 3 4 5 6 7 8 9 1000 2
D FDR - N
3 4 5 6 7 8 9 10000 2
D FDR - P
1000
700
700
500
400
300
500
400
300
200
200
70
50
40
30
20
P-D20
Kearney
Fuse Links
QA
150
100
70
50
40
30
P-D22
Kearney
Fuse Links
QA
75
20
TIME IN SECONDS
10
7
5
4
3
2
1
.7
.5
.4
.3
.2
.1
.07
.05
.04
.03
.02
.01
10
D FDR - P
GE IFC 77
51/50
Extremely Inverse
CT Ratio = 500/5
Tap = 5 (500A)
Time Dial = 5
Instantaneous = 48 (4800A)
P-D84
Kearney
Fuse Links
QA
50
P-D57
Kearney
Fuse Links
QA
30
D FDR - N
GE IFC 77
51N/50N
Extremely Inverse
CT Ratio = 500/5
Tap = 1.2 (120A)
Time Dial = 4
Instantaneous = 30 (3000A)
P-D52
Kearney
Fuse Links
QA
25
2
1
.7
.5
.4
.3
.1
.07
.05
.04
.03
P-D14
Kearney
Fuse Links
QA
10
3 4 5 6 7 8 9 10
5
4
3
.2
P-D15
Kearney
Fuse Links
QA
20
2
7
.02
2
3 4 5 6 7 8 9 100
2
3 4 5 6 7 8 9 1000 2
CURRENT IN AMPERES AT 12470 VOLTS
Figure 12-7
Feeder D Relay Coordination With Overhead Fusing
12-18
3 4 5 6 7 8 9 10000 2
.01
TIME IN SECONDS
100
13
ADDITIONAL EVALUATIONS
Section 13 provides additional evaluations performed as part of this power system study. The
evaluations address:

Energy security

Aurora vulnerability assessment.

Primary distribution power factor.

Harmonic distortion.
13.1
Energy Security Assessment
An energy security assessment is provided as a separate stand-alone document.
13.2
Aurora Vulnerability Assessment
13.2.1 Overview
Aurora is a term applied to a particular type of power system vulnerability in which rotating
electrical equipment (motors and generators) are deliberately subjected to an out-of-phase
connection, which can be damaging to the equipment. An Aurora event consists of three distinct
parts:

Opening of the power supply to a system, facility, or specific equipment.

A short period of time during which the deenergized portion of the system is changing its
phase relationship with the upstream energized system. This interval is referred to as the
time delay. For purposes of this discussion, the term deenergized simply means that the
commercial utility system is disconnected from the downstream system, which may or may
not contain its own generation sources.

A reenergization by closing an upstream power supply before downstream voltage has fully
decayed to zero or before protective devices have isolated the equipment of interest. This
out-of-phase reenergization can be damaging to connected generators or large motors.
Utility switching has long been a concern near power plants and industrial facilities with large
motors, and industry standards provide guidance regarding safe switching practices. An Aurora
event is unusual in that it is a deliberate attempt to damage equipment by high-speed switching.
13-1
Charleston AFB
Additional Evaluations
The assumed method by which this switching is accomplished is generally by remote cyber
attack, although it is also possible to accomplish this switching by manual switching means if
access to utility equipment is possible.
ETL 09-10, Aurora Electrical System Vulnerability Assessment and Mitigation Actions, was
issued in May 2009 and requires an assessment for each Air Force installation regarding its
vulnerability to an Aurora event. Figure 13-1 summarizes the ETL 09-10 evaluation process.
Figure 13-1
Aurora Vulnerability Assessment Flowchart
13-2
Charleston AFB
Additional Evaluations
13.2.2 Evaluation
Referring to Figure 13-1 and using it as the analysis tool, Charleston AFB is not vulnerable to an
Aurora event. The following summarizes the bases for this conclusion:

The Charleston AFB Main Switching Station design does not include remote access
capability for monitoring or control. The circuit breakers are manually controlled at the
switching station. Any Aurora event would be initiated upstream of the Charleston AFB
Main Switching Station at the Santee Cooper level or beyond.

Prime power capability is not installed. No generators are designed for parallel operation
with the local utility.

Synchronous motors are not installed.

No induction motors are larger than 800 Hp. All motors are low voltage and are relatively
small. The largest identified motors are rated in the range of 225 to 425 Hp; many of the
larger motors are controlled by adjustable speed drives.
13.2.3 Analysis
The EasyPower model was designed for an Aurora analysis by modeling all motors dynamically
so that their behavior during an Aurora event is included. A total of 128 motors are included in
the model, with a combined size of 5,860 Hp.
An analysis was performed for a 325 Hp chiller motor at Building 204. The analysis used the
EasyPower dynamic stability module for the system modeling. The Aurora event was initiated at
time t=0.1 second by opening the utility supply to the substation and reclosing the supply after
0.2 seconds. Figure 13-2 shows that the initial system outage results in a very rapid voltage
decay; these modeling results are similar to test results obtained at Tyndall AFB in early 2009.
The voltage quickly falls below safe motor reenergization levels. Figure 13-3 shows the
transient torque upon reenergization, which is near the normal motor starting transient. Figure
13-4 shows the motor current.
13-3
Charleston AFB
Additional Evaluations
Figure 13-2
Aurora Analysis for Building 204 Motor – Voltage Decay
Figure 13-3
Aurora Analysis for Building 204 Motor – Transient Torque Upon Reenergization
13-4
Charleston AFB
Additional Evaluations
Figure 13-4
Aurora Analysis for Building 204 Motor – Motor Current Upon Reenergization
13.3
Power Factor
Power factor varies from 0.89 to 0.98 for the main base; Figure 13-5 shows the power factor
variation. The power factor has improved in recent years as the total base power demand has
declined. Transformer secondary-side values typically range from 0.80 to 0.99. No system
changes, such as the installation of power factor correction capacitors are recommended.
1.00
Power Factor
0.98
0.96
0.94
0.92
0.90
0.88
0.86
Jan‐04
Jan‐06
Jan‐08
Date
Figure 13-5
Power Factor Variation – Total Base Demand
13-5
Jan‐10
Jan‐12
Charleston AFB
Additional Evaluations
13.4
Harmonic Distortion
13.4.1 Purpose of Harmonic Distortion Evaluation
The ideal voltage or current is provided as a 60 Hz sinusoidal waveform, often referred to as the
fundamental frequency. The term harmonics refers to other frequency signals that are
superimposed onto the fundamental frequency. Figure 13-6 shows the waveform of the second
through fifth harmonics superimposed onto the fundamental frequency. Figure 13-7 shows an
example of the resultant waveform when the fundamental frequency is combined with a large
third harmonic.
Fundamental - 60 Hz
Fundamental - 60 Hz
Second Harmonic - 120 Hz
Third Harmonic - 180 Hz
Fundamental - 60 Hz
Fundamental - 60 Hz
Fifth Harmonic - 300 Hz
Fourth Harmonic - 240 Hz
Figure 13-6
Harmonics of the Fundamental Frequency
13-6
Charleston AFB
Additional Evaluations
Figure 13-7
Distorted 60 Hz Waveform (1st and 3rd Harmonics)
Certain types of equipment can introduce harmonics into the electrical power distribution
system. The cumulative effect can eventually cause problems, including transformer
overheating, excessive neutral conductor current, equipment malfunction, and inaccurate
protective relay performance. The objective of the harmonics evaluation is to determine if
potentially harmful levels of harmonic distortion exist in the system.
Power electronics devices are the most significant source of harmonic distortion. Harmonic
distortion problems are usually amplified when the facility has nonlinear loads and also has
power factor correction capacitors installed; resonance conditions can magnify the harmonic
distortion. Nonlinear loads tend to draw current in a manner that causes distorted current
waveforms which can be represented as the summation of the fundamental frequency and
additional harmonic frequencies. Figure 13-8 shows the resultant waveform for a load with
significant third and fifth harmonics. Notice that the addition of harmonics causes the desired
sinusoidal wave to assume more of a square wave appearance.
Fundamental - 60 Hz
Third Harmonic - 180 Hz
Resultant Waveform
Containing Fundamental,
Third, and Fifth Harmonics
Fifth Harmonic - 300 Hz
Figure 13-8
Effect of Harmonics on the Sinusoidal Waveform
13-7
Charleston AFB
Additional Evaluations
13.4.2 Harmonic Measurements
Unlike the other analyses conducted in this engineering study, the harmonics evaluation is based
on measured rather than analytical values. Measurements were taken throughout the system as
part of the field surveys and were generally acquired at the secondary side of each distribution
system transformer.
Snapshot harmonic distortion levels were recorded with a Fluke 43B power quality analyzer and
longer term recording of larger transformers was performed using a Fluke 1744 power quality
logger. These instruments measure the true RMS content of harmonics in the power waveform.
The measurement is specified as a percent THD, which represents the percentage of Total
Harmonic Distortion in the power signal at the point of measurement. THD was measured for
both the voltage and current waveforms.
The point of common coupling (PCC) was not monitored as part of this review because of test
equipment limitations (600 volt limit). The PCC is the location in the electrical system where
the facility can be connected in parallel with other utility users. Typically, the PCC will be the
high side of the service entrance transformer(s) supplying the facility. By measuring the
harmonic content on the secondary of the transformer, a facility will tend to have greater
influence on the recorded values than actually is present at the PCC.
Neutral current was also measured to determine if load unbalance or zero sequence harmonics
are causing excessive current flow in the neutral conductor.
13.4.3 Evaluation Criteria
IEEE 519, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical
Power Systems, provides recommended distortion limits for a low voltage system. Figure 13-9
and Figure 13-10 show Tables 11-1 and 10-3 of IEEE 519. General purpose applications are
allowed up to 5 percent voltage THD. Hospitals are classified as special applications and have
the most stringent requirements with a voltage (THD) limit of 3 percent at the PCC. Current
(ampere) THD requirements are not as stringent as the voltage THD limits and 20 percent
current THD is often acceptable at the PCC.
Figure 13-9
Voltage Distortion Limits Specified in IEEE 519
13-8
Charleston AFB
Additional Evaluations
Figure 13-10
Current Distortion Limits Specified in IEEE 519
13.4.4 Results
Voltage harmonic distortion generally varied from 0.8 percent to 2.0 percent on the secondary
side of distribution system transformers throughout the Base, with a median value of about 1.2
percent.
Current harmonic distortion typically varied from less than 3 percent to over 16 percent on the
secondary side of distribution system transformers throughout the Base. Current harmonic
distortion varies considerably, which is typical.
No changes are recommended with respect to harmonic distortion.
13-9
14
MASTER PLANNING AND SYSTEM
RECOMMENDATIONS
Section 14 addresses a variety of issues intended to improve the primary distribution system.
14.1
Planned Infrastructure Changes
Charleston AFB has an active master plan for upgrading the primary distribution system.
Several projects have been completed and more are planned in support of the base infrastructure
improvements. The following summarizes the status of primary distribution system projects.
Table 14-1
Planned Infrastructure Changes
Area
Description
Status
N/A
Switching station replacement
Complete
A
Feeder A by Bowling Alley
Complete
B
Feeder A along S. South Davis Drive
Complete
C
Feeders Flagpole and D along Hill Blvd
Complete
D
Feeder B along E. McCaw Street
Complete
E
Feeder B continuation along Bates Street
Complete
F
Feeder B continuation along Bates Street
Complete
G
Feeder B continuation along Bates Street
Complete
H
Flagpole switching station replacement and flightline
underground distribution
Complete
I
Feeder C – first portion of overhead distribution
J
Feeder C – remaining overhead distribution
Designed
K
Feeder D overhead distribution
Designed
Starting construction
The Area “H” construction project completed in 2012. Field verification of the primary
distribution system was deferred until construction was complete in early summer so that the
power system study included the latest system configuration. The replacement of the original
Flagpole switching station has improved the system capability.
14-1
Charleston AFB
Master Planning and System Recommendations
Figure 14-1
New Flagpole Feeder Switching Station
As of the issuance of this report, construction has started on the Area “I” project. This project
improves Feeder C by converting some overhead distribution to underground distribution and
also increases the feeder ampacity by installing 4/0 awg conductors. The use of 4/0 awg for the
feeder size is considered adequate given the feeder demand.
The Area “J” project is designed and addresses the remainder of Feeder C. The Area “K” project
is designed and addresses Feeder D. No additional recommendations are provided with respect
to the current plans for infrastructure upgrades.
14.2
Recommended Primary Distribution Design Criteria
Compared to overhead distribution, underground distribution can better survive damage from
storms, wind, and motor vehicles. But, an overhead distribution system has one significant
advantage over underground distribution: it is easy to modify. Overhead distribution systems are
very flexible; a new pole and riser to a new facility can be added in a single day. Switching
between feeders is also relatively easy to add. Whenever Charleston AFB converts overhead
distribution to underground, one key goal should be to retain as much as possible the flexibility
that the overhead distribution provided. At the same time, the design should be cost-effective.
The new underground distribution that has been installed in recent years and the new work in
progress were reviewed and documented as part of this power system study. The following areas
are recommended for improvement as part of future work:

The new underground system along Feeder A replaced a radial overhead system with a radial
underground system. In general, a pad-mounted switchgear was located at almost every pole
location that had a riser or lateral. The impact of this design approach is that there are almost
as many pad-mounted switchgear as there were poles.
14-2
Charleston AFB
Master Planning and System Recommendations

Many of the pad-mounted switchgear only have three compartments, which limits future
system flexibility. Three compartment switchgear should not be allowed; specify only four
compartment switchgear so that spare compartments are available for future use.

Parallel 500 kcmil circuits to Hunley Park provide more ampacity than will ever be needed.
Similarly, cross-tie locations between feeders in outlying areas do not require 500 kcmil
copper conductors. The conductor size should be based on a real analysis of the circuit
requirements, including future expansion plans.

There is no reason to install 500 kcmil copper conductors if the Main Switching Station
voltage regulators are only rated for half that ampacity. Refer to Section 14.3 for more
information.

Lateral circuits to supply smaller single transformers do not require the use of 4/0 awg
conductors. Unless there is a plan involving an extensive loop-feed design approach, 1/0
awg conductors are large enough.

Fuses inside pad-mounted switchgear should be sized to coordinate with the downstream
load(s) and the upstream protective devices.
Additional recommendations are provided in the following sections.
14.2.1 Tri-Service Design Criteria and Industry Standards
Unified Facilities Criteria (UFC) are developed by the Army, Navy, and Air Force (Tri-Service)
to specify minimum design standards for electrical distribution systems. These UFCs provide
the minimum design requirements and supplement existing industry standards. The following
UFCs provide the principal requirements:

UFC 3-501-01, Electrical Engineering.

UFC 3-520-01, Change 1, Interior Electrical Systems.

UFC 3-550-01, Exterior Electrical Power Distribution.

UFC 3-560-01 Change 3, Electrical Safety, O&M.
In particular, UFC 3-550-01 provides design criteria for primary distribution systems. It states
that its applicability is as follows:
The information provided here must be utilized by electrical engineers in the development of
the plans, specifications, calculations, and Design/Build Request for Proposals (RFP) and
must serve as the minimum electrical design requirements. It is applicable to the traditional
electrical services customary for Design-Bid-Build construction contracts and for DesignBuild construction contracts. Project conditions may dictate the need for a design that
exceeds these minimum requirements.
14-3
Charleston AFB
Master Planning and System Recommendations
The design criteria and standards contained within are the minimum requirements
acceptable for military installations for efficiency, economy, durability, maintainability, and
reliability of electrical power supply and distribution systems. The criteria and standards
herein are not intended to be retroactively mandatory.
There are no real industry standards that address how to design and build an efficient, resilient,
reliable, and maintainable primary distribution system. That is why UFC 3-550-01 was issued.
Charleston AFB has demonstrated in recent projects that they have good control over the
electrical distribution design. Pad-mounted switchgear, transformers, and manholes installed in
the last two years have generally met Tri-Service design criteria. Check all future designs against
the approved Tri-Service criteria to assure compliance.
14.2.2 Distribution Transformers
Charleston AFB has recently installed transformers with different configurations. The preferred
configuration should include dead-front, fused, and feed-through capable, as shown in Figure
14-2.
Figure 14-2
Preferred Transformer Configuration
The following summarizes the recommended specification requirements for future transformers.
Design Recommendations

Delta-wye connection (required by UFC 3-550-01).

Dead front, loop feed, pad-mounted, 2-winding, front access only, Class OA (ONAN) self
cooled.
14-4
Charleston AFB
Master Planning and System Recommendations

Bayonet oil-immersed, expulsion fuses in series with oil-immersed, partial-range, currentlimiting fuses.

For three-phase transformers, primary terminations should be configured with six (6) bushing
wells configured for loop-feed capability. For single-phase transformers, primary
terminations should be configured with four (4) bushing wells configured for loop-feed
capability. Bushing wells should be rated at 15 kV, 95 kV BIL, 200 amperes continuous
current, and 10,000 amperes rms symmetrical for a minimum time duration of 0.17 seconds
per IEEE 386.

Surge arresters: use IEEE C62.11, rated 9 kV, fully shielded, dead-front, metal-oxidevaristor, elbow type with resistance-graded gap, suitable for plugging into inserts.

Loop feed sectionalizer switches for three-phase transformers. Provide three, two-position,
oil-immersed type switches (or a 4-way switch) to permit closed transition loop feed and
sectionalizing. Each switch should be rated at 15 kV and 95 kV BIL, with a continuous
current rating and load-break rating of 200 amperes, and a make-and-latch rating of 10,000
rms amperes symmetrical. Locate the switch handles in the high-voltage compartment.
Operation of the switches should be as follows:

1.
Switch 1: Transformer on/off.
2.
Switch 2: Transformer connected to Line A – open/closed.
3.
Switch 3: Transformer connected to Line B – open/closed.
Two-position switches for single-phase transformers. Provide one, two-position, oilimmersed type switch to permit isolation of the transformer without affecting the loop-feed
capability. The switch should be rated at 15 kV and 95 kV BIL, with a continuous current
rating and load-break rating of 200 amperes, and a make-and-latch rating of 10,000 rms
amperes symmetrical.
Installation Recommendations

Provide a spare duct in the medium voltage side of the transformer.

Provide a ground loop around the entire pad, similar to that shown in Figure 14-3 and Figure
14-4. The grounding principles shown in these figures apply to pad-mounted switchgear and
sectionalizing cubicles also.
14-5
Charleston AFB
Master Planning and System Recommendations
Figure 14-3
Recommended Equipment Pad Ground Loop – Plan View
Figure 14-4
Recommended Equipment Pad Ground Loop – Elevation View
14.2.3 Pad-Mounted Switchgear
Discontinue installation of three-way pad-mounted switchgear. Use four-way switchgear instead
and include the fourth compartment as a spare. Figure 14-5 shows a portion of the underground
14-6
Charleston AFB
Master Planning and System Recommendations
installation along Feeder A. Notice that no spare compartments have been included. The
difference in total cost for a three-way versus a four-way switch is very little.
Figure 14-5
Pad-Mounted Switch Design Without Spare Compartments
14-7
Charleston AFB
Master Planning and System Recommendations
Discontinue use of SF6-insulated pad-mounted switchgear unless a program is implemented to
monitor gas pressure and aggressively repair/replace switches with low gas pressure. Charleston
AFB currently has some SF6-insulated pad-mounted switchgear with low gas pressure, which is
an equipment and personnel safety issue.
Include fault indicators on all pad-mounted switchgear. Troubleshooting conductor faults on an
underground distribution system is difficult and fault indictors will help facilitate locating the
fault.
14.2.4 Primary Distribution System Conductor Sizes
Use conductor sizes appropriate for the circuit. Do not use 4/0 awg copper conductors for
laterals to single transformers.
Future upgrades to the primary distribution system should consider the following:

500 kcmil conductors should be used for the main run of the main base feeders.

Conductors located near the end of a feeder can use 4/0 awg or 250 kcmil conductors.
14.2.5 Design Review Checklist
The following table provides a design review checklist to use when evaluating new projects
affecting the primary distribution system. Any items marked as “No” should be explained.
Refer to ETL 01-1, Reliability and Maintainability Design Checklist, for additional
considerations.
Table 14-2
Design Review Checklist
Review Item
Yes
Analysis Requirements
Have analysis requirements been defined?

Short circuit and arc flash

Electrical coordination

Power flow

Voltage drop
Note: Refer to UFC 3-500-01 for analysis requirements.
Primary Distribution Excavation
Have directional bore locations been defined?
Directional boring per ETL 07-01?
Concrete encasement specified for excavated ducts?
14-8
No
N/A
Charleston AFB
Master Planning and System Recommendations
Review Item
Yes
Duct size and type specified?
Spare ducts in all locations?
Equipment Concrete Pads
Equipment concrete pads specified?

Adequate work space around all equipment?

Traffic barrier locations identified?

Minimum of six inches thick?

Minimum of six inches beyond enclosure boundary?

Grounding requirements shown?

Spare ducts extended at least beyond pad?
Distribution Transformers
Dead front, loop feed, with switches?
Fused, bayonet in series with partial current limiting?
Surge arrester locations and ratings specified?
Delta-wye configuration (for 3-phase) unless otherwise
justified?
Minimum impedance requirements?
Basis for kVA size defined?
Metering requirements identified?
Stainless steel construction?
Pad-Mounted Switchgear
VFI type used for feeder cross-tie locations?
4-compartment style (or more) specified in all locations?
Load-break capable?
600 ampere-rated switches?
Stainless steel construction?
Equipment concrete pad specified?
Sectionalizing Cubicles
Used in appropriate location?

Periodic switching not expected?

Downstream protection not required.
14-9
No
N/A
Charleston AFB
Master Planning and System Recommendations
Review Item
Yes
No
N/A
Stainless steel construction?
Equipment concrete pad specified?
Manholes
Construction suitable for location (roadways)?
Manhole size suitable for conductor bend radii?
Cable racks and fireproofing specified?
Spare ducts included?
No load junctions or separable splices?
No T-splices or Y-splices?
Drainage and elevation addressed?
Grounding
Grounding addressed?

Around each equipment pad?

Along each duct bank?

At each equipment enclosure?
Overhead Distribution
Fused cutouts (FCO) specified at each load riser?
Surge arresters used at each FCO location?
Overhead conductor size/type match base criteria?
Pole-mount transformers 50 kVA or less?
14.3
Main Switching Station Voltage Regulators
Note: This section was included in the 2009 power system study. Replacement voltage
regulators have been received on base and are stored in the switching station area. This
section has been left in this report pending the eventual installation of these replacement
voltage regulators.
Single phase voltage regulators are installed on the output of each feeder breaker at Main
Switching Station. The voltage regulators for the Flagpole Feeder are properly sized. The other
voltage regulators are undersized based on 1) the installed circuit ampacity (500 kcmil copper
conductors) and 2) feeder peak demand loading during periods of cross-tie operation.
As an example, throughout this project, Feeder F also carried Feeders D and E. Feeder D was
carried by Feeder F via the transfer bus at the Main Switching Station. Feeder E was carried by
Feeder F via the cross-tie in pad-mounted switch S-19EF. The total load of Feeder F in this
14-10
Charleston AFB
Master Planning and System Recommendations
configuration exceeded the capability of the associated voltage regulators for their full
adjustment capability. The following sections address the limitations of these undersized voltage
regulators and provide guidance during periods of feeder cross-tie operation.
14.3.1 Installed Configuration
Table 14-3 provides the nameplate information and the voltage regulation settings. Figure 14-6
shows the voltage regulators and Figure 14-7 shows a typical nameplate.
Table 14-3
Voltage Regulators
Item
Feeder F
(NCO)
Feeder E
(Officers)
Feeder
D
Flagpole
Feeder
Hunley Park
Feeder
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
Siemens
JFR
3-1 phase
250
7620 ± 10%
7200
Siemens
JFR
3-1 phase
333
7620 ± 10%
7200
Siemens
JFR
3-1 phase
167
7620 ± 10%
7200
219/232 (1)
219/232 (1)
328/347 (1)
437/463 (1)
219/232 (1)
OA, 55°C
OA, 55°C
OA, 55°C
OA, 55°C
OA, 55°C
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Siemens
Accu/Stat
MJ-XL
122
2.0
30
Voltage Regulator
Manufacturer
Model
Type
Rating (kVA)
Voltage
Voltage setting (nominal)
Maximum rated current for
full 10% adjustment range
(amperes)
Class
Voltage Control Unit
Manufacturer
Model
Voltage setting
Bandwidth setting
Time delay (seconds)
Note (1): The higher value applies to the Charleston AFB configuration of 7200 volts grounded
wye operation.
14-11
Charleston AFB
Master Planning and System Recommendations
Figure 14-6
Voltage Regulators
Figure 14-7
Voltage Regulator Nameplate
14.3.2 Voltage Regulator Sizing
Voltage regulators are typically sized to allow a voltage adjustment range of ±10%. Charleston
AFB has recently upgraded the Flagpole, Hunley Park, and D feeders with 500 kcmil copper
conductors. Feeders E and F were already configured with 500 kcmil copper conductors along
14-12
Charleston AFB
Master Planning and System Recommendations
the main run. And, work in progress includes upgrading Feeders A and B with 500 kcmil copper
conductors. Section 5.6 provides the reference ampacity of 500 kcmil copper conductors, which
is about 465 amperes.
If the feeder ampacity was used as the basis for voltage regulator sizing, the required kVA rating
would be as follows:

Use 465 amperes as the minimum desired capability.

Given a line-to-neutral voltage of 7.2 kV and a desired voltage adjustment range of 10%, the
voltage regulator voltage range will be 0.72 kV.

Therefore, the minimum required voltage regulator kVA is 465 amperes x 0.72 kV, or 335
kVA. This assumes that the voltage regulators will be connected in a grounded-wye
configuration.

On this basis, select a 333 kVA size because it is closest to the desired capability.
Referring to Table 14-3, the voltage regulators for Feeders E, F, and HP are only rated for 167
kVA and the Feeder D voltage regulators are rated for 250 kVA. The voltage regulators are too
small to enable the full ±10% voltage adjustment range and also be capable of supplying the full
circuit ampacity. For a ±10% voltage adjustment range, the voltage regulators have the
following limits:

Feeders E, F, and HP – 232 amperes

Feeder D – 347 amperes
Although the voltage regulators are large enough to satisfy the peak demand for each feeder, the
smaller size raises some issues:

Why install 500 kcmil copper conductors on each feeder if the installed voltage regulators
cannot support this capability?

Electrical shop personnel will need to take additional steps whenever using a cross-tie to
ensure that the voltage regulator ratings are not exceeded. Refer to the following section for
details.

Feeder overcurrent protection is normally based on feeder conductor size, feeder load, and
potential feeder load during cross-tie operation. The voltage regulators are now the limiting
component and relay settings need to consider the voltage regulator ampacity also.
14.3.3 Increasing the Load Capability
The voltage regulator design includes an adjustment knob, located on each side of the position
indicator that allows increased loading capability by reducing the allowed voltage adjustment
range. Figure 14-8 shows the knob location and Figure 14-9 provides a close-up view.
14-13
Charleston AFB
Master Planning and System Recommendations
Adjustment
Knob
Figure 14-8
Voltage Regulator Load Adjustment
Figure 14-9
Voltage Regulator Load Adjustment – Close-Up
The adjustment knobs are currently set on ±10%. Table 14-4 provides the limitations of each
voltage regulator size as a function of allowed adjustment range. Before performing another
feeder cross-tie, evaluate the circuit requirements, review Table 14-4, and adjust the allowed
voltage range accordingly. For the currently operating configuration with Feeder F carrying
Feeders D and E, lower the adjustment range from ±10% to ±5%. This adjustment can be made
with the voltage regulator energized, but wait until the tap changer motor is off.
14-14
Charleston AFB
Master Planning and System Recommendations
Table 14-4
Voltage Regulator Current Capability Versus Adjustment Range
Voltage
Regulator kVA
167
250
333
Adjustment Range – Current Rating for 7.2 kV Operation
±10%
±8¾%
±7½%
±6¼%
±5%
232
347
463
255
381
509
278
416
556
313
468
625
371
555
668
14.3.4 Cross-Tie Limitations Associated With Voltage Regulators
Do not use Feeders E, F, or HP to supply a cross-tie to Feeder D or to energize the Main
Switching Station transfer bus without first reducing the allowed voltage adjustment range from
±10% to ±5%.
14.3.5 Long-Term Voltage Regulator Recommendations
Housing Feeders E and F are currently supplied by the Feeder F circuit breaker; these feeders are
lightly loaded and improved voltage regulator performance was achieved by placing all load on
one circuit. For the future, the following Main Switching Station configuration is recommended:

Replace the 167 kVA voltage regulators for Feeder F with 333 kVA voltage regulators.

Supply Feeders E and F by the Feeder E circuit breaker. The cross-tie between Feeders E
and F would be maintained closed at pad-mounted switchgear S-19EF. The start of Feeder F
at the Main Switching Station would be opened at pad-mounted switchgear S-1F, which is
located inside the Main Switching Station boundary. Feeder F was selected because this
open point is located at the Main Switching Station.

Designate Feeder F as the normally open circuit breaker that can serve as the supply to the
transfer bus at the Main Switching Station. This will allow this circuit breaker to serve as a
backup supply to any of the other circuit breakers.

All feeder circuit breakers in the Main Switching Station use 500:5 current transformer ratios
for the associated protective relays. If the Feeder F circuit breaker is used to supply a
different feeder via the transfer bus, the protective relays can be swapped between the two
circuit breakers to maintain the equivalent protection. If the Feeder F circuit breaker is used
to supply Feeder D, reclosing should be activated also.
14.4
Live-Front Transformers
Live front transformers can be an electrical safety hazard and their use is not recommended. The
requirements for electrical safety are becoming more stringent and the UFC 3-560-01, Electrical
Safety, O&M, requirements for arc-flash protection make live-front transformers even more
difficult to work around.
14-15
Charleston AFB
Master Planning and System Recommendations
Table 14-5 provides a list of live front pad-mounted transformers; the subsequent figures show
examples of live front transformers. Refer to the equipment photograph files for photographs of
each transformer for more examples. Any infrastructure improvements should consider the
eventual replacement of these transformers.
Table 14-5
Live Front Transformers Recommended for Eventual Replacement
Transformer ID
Facility
Feeder
kVA Rating
Secondary
Volts
T96
Bldg 96
B
75
208Y/120
T164
Bldg 164
B
500
208Y/120
T211B
Bldg 211
A
300
480Y/277
T224
Bldg 224
D
112.5
208Y/120
T539
Bldg 539
B
150
480Y/277
T630
Bldg 630
D
112.5
208Y/120
T637
Bldg 637
D
500
480Y/277
T-Ramp6
Ramp Lighting
B
30
480Y/277
Figure 14-10
Live-Front Transformers
14-16
Charleston AFB
Master Planning and System Recommendations
Figure 14-11
Live-Front Transformers
Typical three phase transformer prices are provided below; the installed price will be
approximately three times this amount, provided that the existing electrical cables and conduit
system can be used.

75 kVA – $10,877

112.5 kVA – $11,144

150 kVA – $11,637

225 kVA – $13,085

300 kVA – $14,390

500 kVA – $17,516

750 kVA – $20,265

1,000 kVA – $23,818
14.5
Unfused Transformers
Electrical protection is a fundamental design requirement for electrical equipment. This includes
pad-mounted distribution transformers. The following transformers do not contain internal
fusing; in most cases, this is an acceptable configuration because of upstream protection.
14-17
Charleston AFB
Master Planning and System Recommendations
Table 14-6
Unfused Pad-Mounted Distribution Transformers
Transformer
Facility
Feeder
Rated
kVA
Secondary
Voltage
T164
Bldg 164
B
500
208Y/120
Partially protected by upstream
pad-mounted switch.
T256
Bldg 256
B
150
208Y/120
Partially protected by upstream
pad-mounted switch.
T325
Bldg 325
D
1000
480Y/277
Protected by pole FCOs.
T407
Bldg 407
D
300
208Y/120
Protected by pole FCOs.
T501
Bldg 501
C
300
480Y/277
Protected by pole FCOs.
T503
Bldg 503
C
750
480Y/277
Protected by pole FCOs.
T517
Bldg 517
C
300
480
Protected by pole FCOs.
T1951
Bldg 1951
D
112.5
208Y/120
Protected by pole FCOs.
T1990
Bldg 1990
D
750
480Y/277
Protected by pole FCOs.
T1991
Bldg 1991
D
1500
480Y/277
Protected by pole FCOs.
T4450
Bldg 4450
HP
112.5
208Y/120
Protected by upstream padmounted switch.
D
112.5
208Y/120
Partially protected by Pole FCOs.
T-JD11
Comments
Referring to Table 14-6, the following comments are provided:

Unfused and unprotected transformers are a safety hazard. An internal transformer fault will
not be adequately protected by the upstream feeder relays or other upstream equipment.
Catastrophic transformer failure is the expected result for an internal fault.

The unfused transformers that are currently protected by fused cutouts on the pole riser are
identified so that a future conversion to underground does not make the mistake of leaving
them unprotected with the new system design.
14.6
SF6 Switches With Low Gas Pressure
Some installed pad-mounted switchgear is based on an SF6 insulation design. The SF6 gas
provides an excellent insulator and aids in arc extinguishing when contacts open. But, the safe
operation of the switch depends on adequate SF6 gas pressure. The following switchgear have
low SF6 gas pressure and require correction or monitoring:

SW-B2 – low gas pressure, but still within the green band. Recharge gas.
14-18
Charleston AFB
Master Planning and System Recommendations

SW-B3 – gas pressure in red band. Operation of this switch is dangerous. Danger-tag the
switchgear until gas can be recharged.

SW-B4 – gas pressure in red band. Operation of this switch is dangerous. Danger-tag the
switchgear until gas can be recharged.

SW-C2 – low gas pressure, but still well within the green band. Monitor.

SW-C3 – gas pressure in red band. Operation of this switch is dangerous. Danger-tag the
switchgear until gas can be recharged. Note: This switch is a cross-tie to Feeder B at SW-B6;
only the switch at SW-B6 can be operated until gas is recharged into SW-C3.

SW-C4 – low gas pressure, but still just within the green band. Monitor.

SW-D1 – gas pressure in red band. Operation of this switch is dangerous. Danger-tag the
switchgear until gas can be recharged.
Figure 14-12
Example of Low SF6 Gas
14.7
Main Switching Station Relay Settings
Section 11.3 provides recommended relay settings. The bases for the recommended changes are
also provided in Section 11.3.
14.8
Switching Station Equipment Periodic Maintenance
The Main Switching Station and the Flagpole Feeder Switching Station require periodic
inspection and maintenance. The following equipment should receive maintenance checks:

Medium voltage circuit breakers.

Protective relays.

Panel meters.

Switches.

Voltage regulators.
14-19
Charleston AFB
Master Planning and System Recommendations
NETA Maintenance Testing Specifications for Electrical Power Distribution Equipment and
Systems (MTS) is recommended as a guide for the scope of maintenance. Review the Siemens
JFR Instruction Manual for voltage regulator maintenance criteria. Review the Square D Type
FVR Instruction Manual for outdoor circuit breaker recommendations. The recommended
maintenance for the above equipment is complex, and requires specialized skills and training.
This periodic maintenance and testing typically requires a contract with a NETA accredited
company.
The Main Switching Station was placed in service in 2007 and it should receive its first
maintenance review soon.
14-20
15
CONCLUSIONS AND OBSERVATIONS
Section 15 summarizes the projects results and observations.
15.1
Deliverables
The following deliverables are provided in support of this power system study:

Analysis report summarizing project findings and results.

Field walkdown data files – on DVD.

EasyPower electrical model for the primary distribution system.

Electronic copies of photographs taken of electrical equipment during field walkdowns – on
DVDs.

EasyPower software and associated training.

New electrical distribution system single-line drawings.

New electrical distribution system layout drawings.

Geobase documentation for the primary distribution system and airfield – on DVD.
15.2
Conclusions and Observations for the Power System Study
15.2.1 Power Flow Study
The following summarizes the power flow results:
General Comments Regarding Primary Distribution System Capability
Feeders use 500 kcmil copper conductors for the main run for each feeder originating at the Main
Switching Station. With the completion of the recent underground construction, Feeder A and B
use 500 kcmil copper conductors for the main run. Feeder C is limiting with 1/0 awg copper
conductors for the underground distribution. Smaller conductors, #2 to 1/0 awg, are typically
used on lateral circuits.
The overhead distribution uses 1/0 copper or 3/0 ACSR for the main runs on each circuit. These
conductors in air are not limiting with respect to feeder capability.
15-1
Charleston AFB
Conclusions and Observations
Charleston AFB Power Consumption
The following summarizes the Charleston AFB total base power demand:

The base experienced a reduction in load for several years, followed by relatively consistent
peak demand in recent years. The peak demand for each year has been:
2004: 17,733 kVA
2005: 16,779 kVA
2006: 16,519 kVA
2007: 15,208 kVA
2008: 14,292 kVA
2009: 14,118 kVA
2010: 14,152 kVA
2011: 14,152 kVA
2012: 13,852 kVA

The year-by-year reduction in total power usage up to 2008 can likely be attributed to
a) removal of housing and b) base-wide energy conservation efforts.

For the Charleston area, the difference between peak demand and non-peak demand is mostly
air conditioning loads.

Given the above considerations, a reasonable upper bound for the total base peak demand is
about 15,000 kVA, or 700 amperes at 12.47 kV. This provides some margin to allow for
housing loads that are expected to increase in the near future.

The daily variation in power demand is about 25 percent.

Power factor varies from 0.90 to 0.96.
15-2
Charleston AFB
Conclusions and Observations
20,000
Total Power (kVA)
16,000
12,000
8,000
4,000
0
Jan‐04
Jan‐06
Jan‐08
Jan‐10
Jan‐12
Date
Figure 15-1
Charleston AFB Power Demand – kVA
Individual Feeders
Table 15-1 summarizes the load on each feeder that has been used in the EasyPower power flow
analysis. Table 15-2 provides additional information regarding the Flagpole Feeders sub-feeders
(A, B, and C). This forms the basis for the system analysis.
Table 15-1
Individual Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
Comments
FP
8,132
369
Flagpole Feeder splits into Feeders A, B, and
C. Refer to Table 15-2 for these feeders.
D
5196
236
E
633
29
F
713
32
HP
1,089
49
Totals:
15,763
715
15-3
Charleston AFB
Conclusions and Observations
Table 15-2
Flagpole Feeder Load Data for EasyPower Model – Peak Demand
Feeder
EasyPower
Peak Load
(kVA)
EasyPower
Peak Load
(amperes)
A
900
41
B
3,448
158
C
3,732
171
Totals:
8,077
370
Comments
This is the total Flagpole Feeder load as
predicted at the Flagpole Feeder Switching
Station.
Table 15-1 provides the overall power flow results for normal operation during peak load
conditions. The term normal operation means that all feeders are in service.
The following summarizes the normal operation power flow results:

All lines are operating within their rated limits.

Voltage drop is acceptable throughout the primary distribution system; the voltage drop is
less than 2% for all feeders.

The Charleston AFB peak power demand is within the capability of the Main Substation.
Distribution Transformer Loading
Distribution transformers are generally lightly loaded. Most transformers are loaded to less than
20 percent of their rated kVA, even during periods of peak demand. Figure 15-2 provides a
histogram of the distribution transformers with respect to their typical peak loading; during offpeak times, the loading will be somewhat less. Almost 85 percent of these transformers are
loaded to less than 30 percent of their rated kVA. Over 95 percent of these transformers are
loaded to less than 50 percent of their rated kVA during periods of peak demand.
15-4
Charleston AFB
Conclusions and Observations
175
Number of Transformers n
150
125
100
75
50
25
0
0 - 10%
10 - 20%
20 - 30%
30 - 40%
40 - 50%
50 - 60%
60 - 70%
70 - 80%
80 - 90%
90 - 100%
Loading (Percent of Rated Value)
Figure 15-2
Distribution Transformers – Average Loading Histogram
The combined rating of all distribution transformers, including housing, is about 77,500 kVA.
The historical Charleston AFB peak demand is about 15,000 kVA, or just over 20 percent of the
combined kVA rating.
15.2.2 Cross-Connect Capability
Cross-connect capability is evaluated in Section 7 for each point of potential cross-connect
between feeders. Cross-connection might be necessary under any of the following conditions:

Upon failure of a switching station feeder breaker or associated equipment.

Upon loss of a single feeder by feeder conductor damage.

To take equipment out of service for maintenance or repair.

While upgrading a feeder or replacing an underground distribution cable.
The term cross-connect is used here to mean that one feeder picks up all or part of another feeder
in addition to carrying its own load.
The cross-connect analysis results provided in this section are based on peak or near-peak
loading. During periods of less power demand, the cross-tie capability will be better than
discussed here.
This evaluation is based on the ability of a single feeder to supply power to one additional feeder.
The ability of one feeder to supply even more feeders simultaneously was not evaluated. This
type of evaluation would need to be completed using the EasyPower model for a specific
configuration.
15-5
Charleston AFB
Conclusions and Observations
It is assumed that phasing is identical between feeders at all potential points of cross-connection.
The exterior electrical shop should always confirm phasing at normally open points in the system
before closing a cross-tie. Whenever a new cross-tie is installed as part of a future construction
project, exterior electrical shop personnel should visually observe the construction contractor
verify that phase rotation is identical on each side of the switch, including closing of the switch.
Whenever a system cross-connect is considered, the EasyPower model should be reviewed.
Loads in the model can be adjusted for seasonal variations to reflect currently measured feeder
loading and entire buildings can be removed from the model by allowing these buildings to be
carried by their emergency generators. By this approach, the EasyPower model can provide a
cross-connect prediction capability for the specific distribution system configuration.
Regardless of model predictions, affected feeders should be monitored closely whenever a crossconnect is performed.
The availability of emergency generators for individual facilities is not considered as part of this
cross-connect capability evaluation. This evaluation only applies to the capabilities of the
primary distribution system, with all normal loads connected. For each feeder, the evaluation is
based on the capability of a different feeder to provide power to that feeder.
The switch lineups in the following sections are readily evaluated by EasyPower. The evaluated
normally open switch is shut and other related breakers or switches are opened to determine the
cross-tie effect. The following sections summarize the EasyPower analyses.
Table 15-3 provides a summary of the cross-connects available for each feeder.
Table 15-3
Feeder Cross-Connect Summary
Feeder
Flagpole
Can Supply Feeders
None – it is the source for Feeders A, B, and C
A
B
C
D
B
A
C
C
A
B
C
D
A
C
HP
E
F
F
A
HP
D
E
Although the system has improved in recent years, some installed cross-tie points are not capable
of carrying an entire feeder; many cross-tie points are only suitable for carrying a portion of
another feeder. As more underground distribution projects are completed, the cross-tie capability
15-6
Charleston AFB
Conclusions and Observations
should improve. Refer to Section 7 for a discussion of the limitations for each cross-connect
location.
15.2.3 Short Circuit Study
An evaluation of the system’s short circuit capability was conducted. The purpose of the short
circuit study was to confirm that critical system components (e.g., circuit breakers, fuses,
switchgear, transfer switches, and distribution panels) are operating within their nameplate short
circuit rating. The fundamental concern here is that a short circuit somewhere in the system
might produce high levels of fault current that exceed a component’s rating. The underrated
component might fail under this condition, potentially causing a fire, explosion, or unnecessary
outage. This aspect of system performance can only be determined through design analysis since
day-to-day operation offers no clues about the system’s ability to handle short circuits. Faults
are an infrequent event; thus, an underrated system can operate for years or even decades without
any apparent problems. The shortcoming only becomes evident when the system is subjected to
a fault. Electrical equipment used in applications that exceed the equipment’s nameplate short
circuit rating is a violation of the National Electrical Code (NEC), as well as other governing
ANSI, IEEE, and NFPA codes and standards. Circuit breakers are the focus of attention from a
code compliance point of view because they are the system’s primary line of defense against
hazardous and damaging electrical faults.
Table 15-4 provides a summary of the expected short circuit current ranges.
Table 15-4
Charleston AFB Short Circuit Currents On Feeders – Normal Operation
3-Phase Fault Current
(Momentary Symmetrical
RMS kA)
Line-to-Ground Fault Current
(Momentary Symmetrical
RMS kA)
Main Switching Station
7.57 kA
8.36 kA
Flagpole Feeder Switching Station
6.27 kA
6.52 kA
Typical range for feeders – 12.47 kV
3 – 7 kA
2 – 8 kA
Location
The following observations are provided regarding the available short circuit currents:

The fault current available on the primary distribution system is well within the interrupting
rating of typical distribution system equipment and protective devices during normal
operation.

As a general rule, ground fault current decreases rapidly as the distance from the source
increases. Ground fault currents near the substation are larger than the three phase fault
currents. However, three phase fault currents are larger than ground fault currents further
from the substation.
15-7
Charleston AFB
Conclusions and Observations

A fault impedance will cause a further decrease in the available short circuit current. The
largest fault impedance typically considered is 40 ohms, which would result in a ground-fault
current of about 180 amperes. IEEE C37-230, IEEE Guide for Protective Relay Applications
to Distribution Lines, states that fault impedances will usually be well below this amount.

The fault current range on the secondary side of distribution transformers varies widely,
depending mainly on the transformer size and impedance in each case. Service entrance
conductor size and length causes an additional reduction of the fault current available at the
service entrance panel.
The fault current levels for the primary system are relatively low. All components in the primary
system are operating well within their short circuit ratings, as shown below.
Table 15-5
Primary System Fault Current Duties and Equipment Ratings
Location
Primary system switches (switchgear)
Equipment Rating
Fault Duty
12.5 – 22.0 kA
<8.0 kA
Primary system fuses (switchgear) – SMU-20
14.0 kA
Load junctions and elbows
10.0 kA
Overhead distribution fused cutouts
7.1 kA sym
10.0 kA assym
15.2.4 Arc Flash Results
An arc flash summary is provided in Volume 2 Appendix F for the primary distribution system.
The recommended method for evaluating arc flash requirements for a specific work location and
setup is by the EasyPower model. Refer to UFC 3-560-01 for arc flash criteria and personal
protective equipment (PPE) requirements for energized line work. Refer also to Engineering
Technical Letter (ETL) 06-1, Arc Flash Personal Protective Equipment (PPE) Requirements for
High-Voltage Overhead Line Work at 69 kV (Nominal) or Less, which emphasizes that “Working
on energized electrical equipment is prohibited except in rare circumstances, and then only when
justified and approved by the BCE or equivalent in accordance with AFI 32-1064.”
The arc flash protective clothing requirements for energized work is mostly Category #0 and
Category #1 throughout the primary distribution system. Along the main portion of each feeder,
the substation relays, fuses, or VFIs are credited in the arc flash analysis as the protective devices
that clear the arcing fault. Fuses and VFIs are usually the recognized arc-fault clearing device
along downstream laterals.
The PPE requirements are specified for an unrealistically low working distance of 18 inches on
the primary distribution system. Lower arc flash values would apply to a reasonable hot-stick
working distance of 60 inches, or greater. The Charleston AFB EasyPower model should be
used to evaluate a specific work location and working distance.
15-8
Charleston AFB
Conclusions and Observations
Although this power system study extends to the service entrance of each facility, the study is
mainly an evaluation of the primary distribution system. Arc flash results for the service
entrance panel of any facility should be applied with care. The model was prepared in a manner
that allows the service entrance protective device (fuses or breaker) to be used in the arc flash
calculations. These results only apply if the connections and buswork electrically upstream of
the service entrance disconnect are not accessible while performing energized line work.
An arc flash PPE level depends in part on the expected clearing time of an upstream protective
device. Maintenance and testing are both necessary to ensure a device is functional and can be
credited by an arc flash study. With respect to circuit breakers, maintenance confirms that the
circuit breaker is capable of operating as designed and testing confirms that a trip signal will be
initiated as designed. NFPA 70E-2012 addresses this by requiring:
“The arc flash hazard analysis shall take into consideration the design of the overcurrent
protective device and its opening time, including its condition of maintenance.”
The term “condition of maintenance” refers to maintenance and testing of sufficient quality that
the upstream protective device can be expected to operate as intended and within the analyzed
operating time.
For this primary distribution study, periodic maintenance and testing of the switching station
circuit breakers and protective relays is necessary to use the arc flash results. Refer to Section
14.8 for recommendations regarding periodic maintenance and testing.
15.2.5 Coordination Study
Proper electrical protection and coordination are essential for electrical distribution system
reliability. The fundamental objectives of system protection are to:

Isolate permanent faults with minimum disruption of power to unaffected portions of the
system.

Limit damage to faulted equipment and minimize hazards to personnel.

Minimize the possibility of fire or catastrophic damage to adjacent equipment.
Ideally, the protection scheme design is fully coordinated. A fully coordinated system
accomplishes the above objectives over the entire range of possible fault current. A partially
coordinated system has gaps in coverage, i.e., coordination is achieved only for a portion of the
fault current range. Lack of coordination generally results in an undesired protective action and
the unnecessary removal from service of portions of the distribution system.
Electrical coordination was evaluated using standard industry methods and criteria. Timecurrent coordination plots were developed for the system. The time-current curves for related
devices are graphically depicted on a common plot. The curves are then compared using the
specified criteria to confirm that the nearest protective device upstream from the fault will open
before other upstream devices. This comparison is made over the entire possible fault current
range. The postulated fault current ranges from a very light overload at the low end up to the
15-9
Charleston AFB
Conclusions and Observations
maximum predicted fault current for the fault location (based on short circuit study values). The
maximum predicted fault current represents the worst-case 3-phase momentary asymmetrical
fault current (line faults) or worst-case line-to-ground momentary asymmetrical fault current
(ground faults).
This study represents a review of the primary distribution system, which starts at the local utility
supply to each substation. The scope of the coordination review extends to the service entrance
disconnect of each evaluated facility. The following summarizes the analysis scope:

Protection and coordination along the primary distribution system, including the substations,
was evaluated fully.

The secondary side of distribution system transformers was evaluated up to and including the
main service disconnect.

The coordination criteria applied to low voltage equipment consisted of a confirmation that it
will not cause the complete loss of a substation feeder for the defined settings or size.

Branch breakers downstream of the service entrance disconnect are not included in the scope
of this analysis.
Section 10 provides the criteria applied to the coordination analyses. Section 11 provides the
coordination analysis for the switching stations. Relay setting changes are recommended in
Section 11.3. And, Section 12 addresses distribution system equipment. The following
summarizes the issues addressed in these sections:
Main Substation

The original design documents on which the relay settings are based indicated identical 250
kVA voltage regulators on all feeders. Instead, Feeders E, F, and HP have 167 kVA voltage
regulators installed, with only 2/3 the capacity originally expected. The specified relay
settings should not allow overloading these voltage regulators. The recommended relay
settings will be based on Feeders E, F, or HP supplying a cross-tie to another feeder with the
voltage adjustment range reduced to ±5%. The maximum allowed current through the
voltage regulator for this configuration is 371 amperes. Note: the pickups can be left at 5
rather than reset to 4 if the voltage regulators are upgraded.

The instantaneous trip settings for the Flagpole Feeder were based on an overhead
distribution between the Main Substation and the Flagpole Feeder Switching Station, which
has changed. The available short circuit current at the Flagpole Feeder Switching Station is
now higher than it previously was for an overhead distribution supply. For this reason, the
Flagpole Feeder relay instantaneous trips now reach well into Feeder A, B, and C. A
complete loss of the Flagpole Feeder is not desired for a fault on Feeder A.

The instantaneous trip settings for Feeder HP were based on an overhead distribution
between the Main Substation and the Hunley Park area, which has changed. Feeder HP is
entirely underground now and this feeder should be set up similar to Feeders E and F.
15-10
Charleston AFB
Conclusions and Observations
Pad-Mounted Switchgear

Fused switchgear often uses fuses oversized for the application.
The above items are addressed in the body of the report.
15.2.6 Motor Starting
A motor starting analysis was conducted to ensure that large motors can be started without any
expected voltage drop problems. The analysis did not identify any motor starting concerns for
the installed low-voltage motors.
15.3
Recommended Design Criteria
Section 14.2 provides recommended design criteria to apply to future projects.
15.4
Recommended Projects
Projects have been recommended in Section 14. The projects include the following:

Recommended actions arising from the power system study of the existing system.

Replace live-front transformers.

Replace or repair SF6 switchgear with low gas pressure.

Continue infrastructure improvements.
15.5
References
15.5.1 Military Criteria
1. AFI 32-1062, Electric Power Plants and Generators.
2. AFI 32-1063, Electric Power Systems.
3. ETL 09-10, Aurora Electrical System Vulnerability Assessment and Mitigation Actions.
4. ETL 09-11: Civil Engineering Industrial Control System Information Assurance Compliance.
5. UFC 3-501-01, Change 2, Electrical Engineering.
6. UFC 3-520-01, Change 2, Interior Electrical Systems.
7. UFC 3-550-01, Change 1, Exterior Electrical Power Distribution.
8. UFC 3-560-01 Change 4, Electrical Safety, O&M.
15-11
Charleston AFB
Conclusions and Observations
15.5.2 Industry Standards
1. ANSI/IEEE C37.13-1990™, IEEE Standard for Low-Voltage AC Power Circuit Breakers
Used in Enclosures.
2. IEEE C37-230, IEEE Guide for Protective Relay Applications to Distribution Lines.
3. IEEE 241-1990™ (R1997), Electric Power Systems in Commercial Buildings (IEEE Gray
Book).
4. IEEE 242-2001™, Protection and Coordination of Industrial and Commercial Power
Systems (IEEE Buff Book).
5. IEEE 399-1997™, Power System Analysis (IEEE Brown Book).
6. IEEE 446-1995™, IEEE Recommended Practice for Emergency and Standby Power Systems
for Industrial and Commercial Applications (IEEE Orange Book).
7. IEEE 519-1992™, IEEE Recommended Practices and Requirements for Harmonic Control
in Electric Power Systems.
8. IEEE 551-2006™, IEEE Recommended Practice for Calculating Short-Circuit Currents in
Industrial and Commercial Power Systems.
9. IEEE 1015-1997™, Applying Low-Voltage Circuit Breakers Used in Industrial and
Commercial Power Systems (IEEE Blue Book).
10. IEEE-1584-2002™, IEEE Guide for Performing Arc-Flash Hazard Calculations.
11. NETA ATS-2009, Acceptance Testing Specifications for Electrical Power Distribution
Equipment and Systems.
12. NETA MTS-2007, Maintenance Testing Specifications for Electrical Power Distribution
Equipment and Systems.
13. NFPA 70-2011, National Electrical Code.
14. NFPA 70E-2012, Standard for Electrical Safety in the Workplace.
15. NFPA 110-2005, Standard for Emergency and Standby Power Systems.
16. UL 489-1991, Molded-Case Circuit Breakers and Circuit-Breaker Enclosures.
15.5.3 Other Documents
1. The Lineman’s and Cableman’s Handbook, Eleventh Edition.
2. Protective Relaying, Principles and Applications, by J. Lewis Blackburn, Second Edition.
15-12
Charleston AFB
Conclusions and Observations
3. Electric Power Distribution Handbook, by T.A. Short.
15-13