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P1818™/D1.3
Draft Guide for the Design of Low Voltage Auxiliary Systems for Electric Power Substations
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Introduction
This introduction is not part of P1818/D1.3, Draft Guide for the Design of Low Voltage Auxiliary Systems for Electric Power Substations .
Contents
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Draft Guide for the Design of Low Voltage Auxiliary Systems for Electric Power Substations
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Overview
Scope
This guide will consider the components of both the AC and DC systems and provide guidelines and recommendations for designing the appropriate systems for the substation under consideration. This guide includes the low voltage auxiliary systems from the source(s) to the distribution point(s). Reliability requirements and load characteristics are discussed and distribution methods are recommended.
Purpose
The low voltage AC and DC auxiliary systems comprise very important parts of the substation equipment. The design of the AC and DC auxiliary systems facilitates the safe and reliable operation of the substation. This guide considers various factors that affect the design of the AC and DC auxiliary systems such as reliability, load requirements, system configurations, personal safety and protection of auxiliary systems equipment.
Normative references
The following referenced documents are indispensable for the application of this document (i.e., they must be understood and used, so each referenced document is cited in text and its relationship to this document is explained). For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments or corrigenda) applies.
Coming soon
NESC?
NEC?
Definitions
For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary Online should be consulted for terms not defined in this clause. [1]
Coming soon
Design of substation AC systems
The objective of this section is to provide the required information for the substation engineer to design safe and economical AC station auxiliary system as applicable for each substation. The station power for most substations can be represented by the block diagram shown in figure 4-1 below. Detailed information is given in the section given next to each part.
Figure 1 represents an ultimate station power configuration that can be applied to any substation depending on substation size reliability and load requirements. One source is designated as the normal feed, and a second and/or third source is designated as a backup. A loss of the normal or preferred source will result in transferring the load to the backup source. In substations with multiple sources, the sources are normally connected to a transferring scheme. One or more AC panels are used to serve the substation load as required.
As a first step to the design process, the design engineer must review the design criteria for the station power; the number of sources, source type: three phase or single phase, required transformer rating, connection and other factors that may affect the final configuration of the station power for the applicable substation. The design criteria is discussed in 4.1.
[pic]
— Block Diagram for Typical Substation AC Station Power
Design criteria
In general, the design criteria of the AC auxiliary system are determined by the demand load of the connected KVA of the substation loads, as well as the voltage ratings and number of phases of the substation equipment to be supplied. Auxiliary transformers and other station power components should consider substation expansion and/or anticipated growth rate. Timing of any proposed expansion may dictate initial installation or deferral of station power components. Some loads may be identified as critical, which requires AC service to be maintained at all times. Depending upon such critical loads, the substation may require two or three AC station service sources with the ability to transfer loads between sources.
Due to the importance of the station power to the operation and reliability of the substation, the following factors must be considered in order to determine the required station power configurations:
System stability
System stability considerations are important for the reliability requirements of the station power. If the loss of a certain substation will result in system disturbance not only within the owner utility system but might also have a cascading effect on neighboring utilities which may result in a blackout condition in the area.
Customer service and loss of revenue
Some substations serve critical loads such as hospitals, manufacturing complexes, government offices, schools and others, or serve large blocks of load where the substation reliability requirements are high. Some substations are connected to power plants where the loss of the substation equipment may result in tripping the plant which results in loss of revenue for the utility. More than one station power source may be warranted for these types of substations. Other less critical substations may have limited effect on the customers’ service and one source for the station power may be justified.
Equipment protection
Substation equipment protection considerations must be given to all substations regardless of the size, however high and extra high voltage substations contain high cost equipment such as transformers where the cooling system is considered very important to the operation of this equipment and therefore a backup source is generally required. Protective relays or other electronic control equipment located in high temperature areas may require a continuous cooling system and therefore the second source is generally required.
Design considerations
The designer may consider the following list when designing an AC system for Substation:
a) Location of AC equipment – indoor or outdoor
b) Number of AC panels
c) Essential loads connections
d) Non-essential load connections
e) Conductor type and size
f) Voltage drop calculations
g) National Electrical Code® (NEC®) [B14] requirements.
Selection of auxiliary system voltage
Several secondary voltage levels are available for AC auxiliary systems. When determining the voltage level needed, the designer may use a standard voltage level determined by the designer’s power system or use a variation to maintain the voltage levels of the equipment being supplied. Either way, the designer needs to consider the factors in 4.3.
Station power source requirements
Three sources are represented in Figure 1. One source, preferably the most reliable source, is designated and used as the primary or normal source. The second source is designated as a backup source and is typically used only when the primary source has been lost. The third source if used will be used as a second back up and is connected typically only if both the primary and secondary sources have been lost. There are four sources that are commonly used as substation AC auxiliary power sources:
a) Power transformer tertiary
b) Substation bus
c) Distribution line
d) Standby generators
Each source has advantages and disadvantages. Substation location, substation equipment, and bus configurations may dictate which source is preferred.
Power transformer tertiary:
When used in substations, the tertiary of a three winding or autotransformer can provide a good source for station power applications. When the primary and secondary windings are connected “wye”, a third winding connected in delta is typically used for stabilizing purposes. A tertiary winding presents a low impedance path to zero sequence currents and harmonics, thereby reducing the zero sequence impedance presented to the outside world, while avoiding the problem of tank heating. The tertiary winding typically has a volt-ampere rating between 20-30% of the volt-ampere rating of the primary winding, and typically has a medium voltage rating up to 34.5 kV. If there are plans to use the transformer tertiary for station power purposes, the tertiary winding is brought out of the transformer otherwise, the tertiary winding is buried. See figure 4-2 for transformer connection.
The volt-ampere rating of the tertiary winding typically exceeds the maximum volt-ampere requirement of a substation’s AC auxiliary power load and is an adequate AC auxiliary power source.
Consideration should be given to the available fault current at the tertiary bus. In the case that the fault current magnitude exceeds the interrupting rating of the protective equipment such as fuses or circuit breakers, several options can be employed to mitigate the fault current. These options include installing, current limiting fuses, resistors, or reactors or increasing the transformer tertiary impedance.
Another consideration should be given to the detection of the ground fault on the tertiary bus. The tertiary buses on three phase power transformers are generally short and typically do not require any ground fault protection. However, when single phase power transformers are used to construct a three phase bank, bus runs that connect and form the tertiary bus become much longer and are more likely to be subject to a phase to ground fault. A single phase to ground fault on the tertiary will not generate fault current in the delta and will not trip the distribution transformer high side protection, nor will the fault trip a typical power transformer bank differential scheme. Some utilities choose to install a ground detection network on the tertiary delta to detect this single line to ground fault to either signal an alarm or trip the power transformer bank. A common method for constructing this ground detection network is to install three small delta connected transformers with a grounding resistor. There will be zero voltage drops across this grounding resistor under normal operating conditions. There will be a voltage drop across this grounding resistor during a phase to ground fault and that indicates that a phase to ground fault on the delta tertiary has occurred.
Substation bus:
Another available source for station power is to use the substation voltage bus as a source. This possible source is normally used when other sources are not available due to its relatively high cost. A Power Voltage Transformer (PVT), sometimes known as a Station Service Voltage Transformer (SSVT), is the device that may be used to transform the bus voltage to the AC auxiliary voltage. These devices are available for voltages between 34.5 to 230 kV. One or more SSVT’s might be required as required by the station power load. See Figure 2 for possible connections.
[pic]
—Possible SSVT locations
The SSVT is normally located within the line or bus relays zones of protection. A fault on the SSVT will be cleared by the protective relay faster than any high side fuse. Also the size of the required fuse may not be available for certain voltage levels. The protection engineer must be consulted for the final when determining the required SSVT protection. Low side over current protection of the secondary conductors used for auxiliary station service are typically applied as close to the secondary terminals as possible. Surge protection is typically needed on the high side connection of the SSVT. If arresters protecting other equipment in the station are close enough to protect the SSVT, a dedicated arrester for the PVT may not be required. Guidance on surge protection and separation effects can be found in IEEE C62.22, Guide for the Application of Metal-Oxide Surge Arresters for Alternating-Current Systems.
Distribution feeders:
Another source for the station power is the use of nearby distribution feeders. The feeder primary, if owned by the substation owner, is normally brought into the substation underground and is connected to a step-down transformer located inside the substation preferably near the control building. If the feeder is owned by another utility, a revenue meter is installed before it can be connected to the step down transformer. Since the feeder has more exposure to faults, it is normally used as a backup to the primary source.
Standby generators
Generators may also be used as an AC auxiliary power source. In substations, generators are typically used as an emergency power source instead of a permanent power source. This is due to the disadvantages of using generators as a permanent AC auxiliary source. Choosing to use generators as a permanent AC auxiliary source will require additional design considerations. Fire protection systems will need to be designed to protect the substation equipment from a generator file. Fuel storage systems will need to be installed to house the fuel needed to run the generators. The generators may also be housed in a separate building structure, which requires the installation of a ventilation system.
Generators used as an emergency AC auxiliary power source have more merit than as a permanent source. As an emergency source, there is not the same need for fire protection installation, fuel storage system, or building ventilation (if the generators are located outdoors in the switchyard).
Load requirements
In order to design a reliable and safe station service system, the AC load must be defined and calculated. The calculated load current is used to select the station service transformer size and the conductor rating. These loads consist but not limited to the following:
In order to design a reliable and safe station service system, the AC load must be defined and calculated. The calculated load current is used to select the station service transformer size and the conductor rating. These loads consist but not limited to the following:
a) Substation ultimate plan: In order to account for the ultimate load of the substation, any future loads must be considered and included in calculating the maximum station load. This include the loads for additional power transformers, additional cooling and heating, additional breakers of all voltage level.
b) Maintenance equipment load: For large substations, maintenance crews may select to use a diesel generator as a source for the maintenance equipment. This generator can be permanently installed in a convenient location in the substation or can be carried on a truck as required. If on the other hand, the maintenance equipment will be serviced from the station power transformer, the load of the maintenance equipment must be included in the calculations of the station power transformer rating.
c) External load: Loads that are not associated with the substation equipment but may be required to be serviced by the substation station service transformer. This can include external building heating or cooling loads, building lighting and any communication equipment loads associated with equipment other than substation load.
d) Substation maintenance and storage building: Large substations may require additional building for maintenance and or equipment storage. The load requirements for the building must be included in the station power transformer KVA calculations. The load for this building may include the heating/cooling equipment building light and any other machinery that might be required for performing maintenance.
e) Substation AC Loads: Substation load consists of the following loads:
1) Major equipment loads: This load is related to equipment operation and as a result is considered essential loads.
i) Transformer cooling fans
ii) Transformer pumps.
iii) Load tap changer motor drive
iv) Breaker AC charging motor
v) Equipment heaters.
2) Yard Loads - This load includes yard lighting and any receptacle load for equipment testing. Also transformer oil retention pit pumps load should be considered in the calculations of the Station Service KVA rating.
3) Control Building Loads: The control building is normally used to house critical equipment used for the protection and operation of the substation and also other elements of power system associated with the substation such as transmission lines connected to the substation. This equipment includes substation protective relays, metering, and the battery system and control equipment. For optimum operations of this equipment, the cooling and heating of the control building must be operated within a specified temperature. As a result the control building heating and cooling load is considered essential load. Other load such as battery chargers, control building lights and expected receptacle load must be considered in the transformer kVA rating.
4) Construction load: In both transmission and distribution substations, the substation AC auxiliary systems are typically used to supply loads such as, but not limited to:
i) Essential load
ii) Non-essential load
iii) Maintenance load
iv) Construction load
Essential load
These loads are related to equipment operation and are necessary to the proper function of the substation.
a) Transformer cooling, oil pumps, and load tap changers
b) Substation battery charging systems
c) Circuit breaker air compressors and charging motors
d) Power circuit breaker control circuits
e) Power equipment heating circuits
f) Communications equipment
g) Relaying, supervisory, alarm, and control equipment
h) AC/DC converter – uninterruptable power supplies
i) AC powered motor operated disconnect switches
Non-essential load
Provide description
a) Outdoor lighting, security systems and receptacles
b) Control building or switchgear building lighting, HVAC, and receptacles
Maintenance load
Construction load
Conductor selection
This section covers the selection of both line and load conductors. There are six main characteristics to consider when selecting a conductor – conductor type, insulation type, cable insulation voltage rating, cable insulation temperature rating, the terminations being connected to (temperature rating, ampacity, etc.), and conductor size; these are the topics that will be covered within this section. The engineer performing the conductor selection can use the process flow chart shown below in Figure 3 and this clause of the document for guidance on conductor selection based on these characteristics
[pic]
—Conductor selection process flow chart
For additional information on conductor selection, see IEEE Standard 525.
Conductor type
The first step in conductor selection is to determine the type of conductor to be used – aluminum or copper, stranded or solid. For safety reasons, the cable should always be insulated and jacketed. The engineer selecting the conductor type must consider characteristics such as its weight and conductivity, surrounding environmental conditions, and the application of the conductor. All of this information is typically available from cable vendors.
Cable insulation voltage rating
Cable insulation voltage rating is selected based on the phase to phase operating voltage and the expected fault clearing time. For further guidance on selecting the voltage rating of cables over 2000V, refer to NEC 2011 Table 310.104(E), or specific product literature provided by the vendor.
Cable insulation type
For jacketed conductors, the insulation type must be selected to meet the location condition - such as dry, wet or both. Typically, information on the application of different insulation types will be provided by the supplier. NEC 2011 Table 310.104(A) gives detailed information on cable insulations and applications for conductors rated 600V and less. This table, along with BS 7671-2008 Sections 412.2, 413.1.1, 414.4, and 416, can be used as a preliminary guideline for what cable insulation to select.
Cable temperature rating
The temperature rating of the conductor should be selected to withstand the ambient temperature of the environment in which it is installed, in addition to any self-heating that may occur. The engineer selecting the conductor should note that the conductor installation may cross multiple environments, all of which must be considered. Typical conductor temperature ratings are 60°, 75°, 90°, and 105° C.
Consideration for the characteristics of termination points & connected equipment
The temperature rating of the conductor may need to be derated in some cases, depending on the termination points that it is connected to. If the temperature rating of a conductor is higher than its connected termination point, the conductor must be rated to match the temperature of the termination point. The lowest temperature rating of any one component in a circuit is the temperature that should be used for design. This will affect the allowable ampacity of a conductor.
Example
An engineer is tasked with designing a load distribution scheme for station service in an electrical substation. The engineer completes a load study, and once finished, goes to an AC panel supplier to purchase their AC panel for the load distribution scheme. While waiting for specs back from the panel vendor, the engineer begins selecting the cables for the scheme. For one of the branch circuits supplying a 120V, 200A single phase load, the engineer selects a 75°C, 4/0, THHW Conductor, per NEC 2011 Table 310.15(B)(16). Upon receiving specs back from the panel supplier, the engineer discovers that the branch circuit breaker terminations on the panel are only rated for 60°C. The engineer must now find a different solution for the 200A load, as their cable must be derated to the 60°C temperature rating – 195A (see Table 310.15(B)(16)).
Conductor Size Calculations
The following factors must be considered when selecting the conductor size:
a) Required ampacity
b) Ambient temperature correction
c) Adjustment factors for multiple conductors in a raceway or cable
d) Voltage drop
Required ampacity (initial conductor size selection)
The preliminary selection of a conductor by required ampacity is based on the load assessment of the circuit that it is supplying. A design criterion (also known as a ‘load study’) must be completed, identifying and classifying all substation loads to be supplied, to determine the required ampacities of the conductors. For more information on load studies, refer to load calculation section 4.3
All conductors must be initially sized based on the ampacity of the load(s) they are supplying. Per the NEC, conductors can be classed as service, feeder, or branch circuit depending on their locations in the load distribution system. For definitions of each type of conductor, see NEC Article 100. For preliminary sizing of service conductors, see NEC 230.42. For preliminary sizing of feeder conductors, see NEC 215.2. For preliminary sizing of branch circuit conductors, see NEC 210.19 and 215.2 (B).
Once the initial conductor type and size selection is made, checks must be made to ensure that the conductor has been sized to avoid overheating and unacceptable levels of voltage drop in the circuit. These checks and any associated calculations will be discussed in the forthcoming sections. If the checks prove the conductor size to be inadequate, then the engineer must make an economically and practically sound decision to redesign the load distribution scheme. The redesign decision could involve any of the following options:
a) Resize the conductor
b) Reallocate loads to or rebalance loads among different circuits to adjust load distribution
c) Create additional circuits to accommodate loads (increase AC panel size)
d) Decrease the distance of circuit run (voltage drop)
Temperature, burial depth, and bundling corrections
The rating of a cable can decrease based on its ambient temperature, burial depth, and proximity to other current-carrying conductors.
If the ambient temperature at the substation location is different than the ambient temperature used for calculating the NEC ampacity tables, the selected conductor ampacity should be corrected for the new ambient temperature. NEC 2011 Tables 310.15(B)(16) through 310.15(B)(21) provide allowable ampacities for cables rated 30 & 40°C. For ambient temperatures other than 30 & 40°C, the ampacity of the conductor should be corrected based on NEC 2011 Tables 310.15(B)(2)(A) & 310.15(B)(2)(B). NEC 2011 310.60 (C) (4) also provides an equation can for calculating the ampacity rating of the conductor based on the new ambient temperature, as an alternative (and more accurate) option:
[pic]
where
I’ is the ampacity corrected for ambient temperature
I is the ampacity shown in the tables
Tc is the temperature rating of conductor (°C)
Ta’ is the new ambient temperature (°C)
Ta is the ambient temperature used in the table (°C)
The ampacity of conductors running through raceway or conduits is covered in NEC 2011 Tables 310.15(B)(16)-(21), and 310.60(C)(67)-(86). If the number of current-carrying conductors running through a raceway is more than what is listed in these tables, then temperature de-rating based on conductor bundling should be accounted for. NEC 2011 provides adjustment factors for conductor bundling, given in Table 310.15(B)(3)(a).
A conductor may need to be derated based on its burial depth due to temperature rise. NEC 2011 Section 310.60(C)(2) provides guidance for the de-rating of cables rated 2000 to 35,000V based on depth below ground; Annex B, Sections B.310.15(B)(3), B.310.15(B)(5) and B.310.15(B)(6) provide guidance for de-rating conductors based on their depth of installation below ground.
Voltage drop verifications
Losses by means of voltage drop across a conductor are directly proportional to the length of the conductor. By nature of Ohm’s law, it is apparent that the higher the current a conductor is carrying, and the higher the resistance of a conductor (ohm/kFT), the greater the voltage drop will be. Losses from voltage drop can cause substation equipment to have under-voltage issues, leading to various malfunctions, depending on the type of equipment.
Voltage drop calculation for a 1-Ø conductor or one phase of a 3-Ø circuit:
[pic]
Voltage drop calculation for a 3-Ø conductor:
[pic]
where
VD is the line to neutral voltage drop of the conductor expressed in Volts, for a 1-Ø conductor; or the line to line voltage drop of the conductor expressed in Volts, for a 3-Ø conductor.
V is the nominal voltage of the circuit
R is the Alternating-Current resistance in Ω to neutral per 1000 ft, per Table 9 of the NEC 2011
XL is the Alternating-Current reactance in Ω to neutral per 1000 ft, per Table 9 of the NEC 2011.
I is the Amperes: The load in amperes at 100 percent
L is the length of the conductor being considered for the voltage drop.
pf is the equivalent power factor being considered for the circuit. If this has already been accounted for in the load study, then a value of 1.0 should be used.
As recommended in NEC 2011 Section 210.19(A)(1), the voltage drop for any given path to a load in the distribution system (in the complete length of the circuit) should not exceed 5% of the nominal voltage. If it does, then the engineer will have to make design changes as described in Section 4.11.6.1.
Station Power Transformer:
The objective of this section is to provide information to help the substation engineer select the appropriate station service transformer for the substation under consideration. This section discusses the required number of transformers, transformer kVA rating, transformer connections, transformer short circuit rating and some other items of consideration.
Number of the Transformers Requirements:
The number of station power transformers required for a substation can be determined based on the design criterion discussed in section 4.xx,. One transformer can be acceptable for small low load substation, for substations with high reliability requirements; two or more station power transformers will be required. An important factor that can affect the number of station power transformers is the available sources for station power. For some sites locations such as remote switchyards only one source is available. In this case one transformer is connected to the high voltage bus and a Generator is used as a backup.
Many utilities and power producers have developed standards and guide lines that help determine the number of station power transformers that are required for a particular substation. These guide lines is based on the utility system conditions and reliability requirements.
Single or Three Phase Transformer Requirements
Station load dictate weather single phase or three phase transformers are required. In general single phase transformers have been used for distribution substations when the load is single phase and has a low current rating. Three phase transformers have been used for high voltage and extreme high voltage substations when the load is high and some station load requires three phase voltage input. Using a single phase transformer to serve large station load may result in a high level of secondary current. This will result in equipment with higher current rating as well as larger conductors due to excessive voltage drop. Other loads such as maintenance and construction equipment may also dictate if three phase transformers will be required for station power.
Station Service Transformer Rating:
Station service transformer ratings are specified by the kVA rating, transformer primary and secondary voltages, the short circuit rating and the BIL rating.
Transformer KVA and Voltage Rating:
The capacity of a transformer is determined by the amount of current it can carry continuously at rated voltage without exceeding the design temperature. Transformer rating is given in kilovolt-amperes (kVA) since the capacity is limited by the load current which is proportional to the kVA regardless of the power factor.
As a first step to determine the kVA rating of the transformer, the engineer must consider all possible loads that will be serviced by the transformer. The load can be calculated as described in 4.3 and is used to determine the transformer rating as described below:
Calculations of Transformer KVA Rating:
The kVA rating of the transformer must be selected to account for the maximum expected load which the transformer is required to serve. The following methods have been used to determine the transformer kVA rating:
Small substation with light load requirements:
For small substation with light load requirements, the kVA rating of the single phase transformer is determined by calculating the ultimate connected load and adding a safety margin of 20%.
Medium to Large Substations:
For large substations with high load requirements, the station must be classified as follows:
a) Continuous Loads: Loads that continue to operate for three hours and more are defined by the NEC as continuous loads. In substations the following loads can be considered continuous:
1) Control building HVAC and lightning.
2) Transformer fans and/or pumps
3) Battery chargers
4) Equipment heaters
5) Yard lighting
6) Illuminated signs
7) The Power Supply for Relays, SCADA and communication equipment
8) Receptacle loads.
b) Non continuous Loads: Loads that are momentary are considered non continuous loads. In substation the following loads can be considered non continuous:
1) Breakers AC motor spring chargers running current. Since this load type is momentarily and the possibility of more than one breaker charging motor starts at the same time is remote, it is suggested the load of only two motors loads are added to the transformer kVA rating calculations.
2) Maintenance loads including transformer and breaker processing equipment.
3) Construction loads including construction trailers and equipment.
The transformer kVA rating is then calculated by the following:
[pic]
Once the recommended transformer kVA rating is calculated, Table 1 can be used to select the appropriate transformer size for the application. Normally a transformer rating greater than the calculated value is selected.
—Standard kVA ratings for distribution transformers
|Overhead Type |Pad Mounted Type |
|Single Phase |Three Phase |Single Phase | |
|5 |15 |25 |Three Phase |
|10 |30 |37.5 |112.5 |
|15 |45 |50 |150 |
|25 |75 |75 |225 |
|37.5 |112.5 |100 |300 |
|50 |150 |167 |500 |
|75 |225 | |750 |
|100 |300 | |1000 |
|167 |500 | |1500 |
|250 | | |2000 |
|333 | | |2500 |
|500 | | | |
Transformer Voltage Rating:
The primary and secondary voltage of the transformer must be specified. The following factors affect both the primary and secondary voltage:
a) Available source
b) Transformer type single phase or three phase
c) Transformer connection
d) Load voltage requirements
For a single phase transformer, the phase to ground voltage is specified. For a transformer with a delta connected primary or for three wire system, a phase to phase voltage is specified. For a four wire source or for a transformer with a Wye connected transformer both phase to phase and phase to ground voltage is specified.
The following are some of the substation secondary voltage can be one of the following configurations to be considered:
a) For single phase system 480/240 or 240/120
1) 480/240 volts, three phase, four wire, mid-tap, delta.
When using this voltage configuration larger equipment loads such as three-phase transformer fans and oil pumps need to be specified at 480 volts. Other system loads can be specified at either 480 or 240 volts, single phase. This type of system is ungrounded and will require a ground detection system. If one phase of the system becomes grounded an alarm is initiated to indicate a ground. If a second phase becomes grounded then a phase to phase fault condition exists and a trip is initiated. This system has a high leg and requires that panelboards are labeled to identify that such a condition exists. This system is very uncommon.
2) 240/120 volts, single-phase, three wire.
This is basically a “residential” service but applicable to small to medium sized substations. Panelboards that combine both power and lighting requirements can be used with this system thus reducing the required number of panelboards.
b) For three phase system 480/277, 208/120 or 240/120 when a Delta connected secondary with center tap grounded.
1) 480/277 volts, grounded wye connected, three-phase, four-wire
When using this voltage configuration larger equipment loads such as three-phase transformer fans and oil pumps need to be specified at 480 volts. One advantage of this system is that luminaires can be equipped with 277 volt ballasts reducing voltage drop for larger runs over the use of the more common 120 volt lights. In this system receptacles are fed through dry-type 480-120/240 volt single phase transformers.
2) 208/120 volts, grounded wye-connected, three-phase, four-wire
In this system either 208 volts single phase and three-phase or 120 volt single-phase equipment can be used. Panelboards that combine both power and lighting requirements can be used thus reducing the required number of panelboards. The saving realized by using fewer panelboards may be offset by higher conductor costs caused by increased size due to voltage drop issues compared to a 480 volt system. In this type of system the receptacles can be served directly from 120 volts.
3) 240 volts, three-phase, three wire, delta
When using this voltage configuration, three-phase or single-phase transformer fans and oil pumps need to be specified at 240 volts. This type of system is ungrounded and will require a ground detection system. If one phase of the system becomes grounded an alarm is initiated to indicate a ground. If a second phase becomes grounded then a phase to phase fault condition exists and a trip is initiated.
4) 240/120 volts, three-phase, four-wire, mid-tap, closed delta
This voltage configuration is the most common for small to mid-sized substations. With this system one phase of the auxiliary transformer is center tapped to obtain 120 volts. Panelboards that combine both power and lighting requirements can be used thus reducing the required number of panelboards. This system has a high leg and requires that panelboards are labeled to identify that such a condition exists.
5) 240/120 volts, three-phase, four-wire, mid-tap, open delta
This is essentially the same as the closed delta system with the exception that with only two transformers the kVA rating is only 58 percent of the kVA capacity of when three transformers are used. This system is more economical for a medium-sized installation or when used for a temporary installation. This system uses single-phase transformers and the third transformer can be added in the future to increase the overall kVA capacity. This type of system is commonly used when there is a small three phase load and a large single phase 120/240 volt load. This system has a high leg and requires that panelboards are labeled to identify that such a condition exists.
[pic]
—Typical AC auxiliary secondary voltages (source?)
Example 4.5.1:
A small substation rated 69-12.47kV, a single transformer will be used for the station service load, the transformer rating can be specified as 12.47/7.2kV-240/120 0r 480/240
Transformer Short Circuit Rating:
The short-circuit ratings for distribution transformers are set by ANSI standard C57.12.00. The maximum magnitude required for units with secondary voltages rated less than 600 V is given in the table below:
—Distribution transformer short-circuit withstand capability
|Single Phase KVA |Three Phase KVA |Rating (times normal |
|5-25 |15-75 |40 |
|37.5-100 |112.5-300 |35 |
|167-500 |500 |25 |
| |750-2500 |1/ZT |
| | | |
| | | |
Two winding distribution transformers with secondary voltages rated above 600 volts are required to withstand short-circuits limited only by the transformer’s impedance.
The duration of the short-circuit current is determined by
For Transformer rated 500kVA or below:
[pic]
For transformer 750 to 2500kVA:
[pic]
where
t is the duration in seconds
I is the symmetrical short-circuit current (per unit)
*1/ZT = The short circuit current will be limited by the transformer impedance only. ZT is transformer per unit impedance.???
Transformer Impedance:
The station service transformer impedance should be considered when evaluating the AC system equipment rating. The AC equipment must withstand the maximum fault current and the circuit breakers must be capable of interrupting and clearing the fault. The impedance of a transformer has a major effect on system fault levels. It determines the maximum value of current that will flow under fault conditions.
The percentage impedance, can be specified as low as 2% for small distribution transformers and as high as 20% for large power transformers. Impedance values outside this range are generally specified for special applications.
Transformer BIL Rating:
The BIL rating of the transformer is its ability to withstand overvoltage conditions resulting due to fault condition, lighting surges or any over voltage due to switching surges. The table below meets ANSI standard 57.12.20 and can be used to specify the BIL rating of the transformer.
—no caption yet
|Voltage Range Volts |Insulation Class KV |BIL |
|480-600 |1.2 |30 |
|2160-2400 |5.0 |60 |
|4160-4800 |8.7 |75 |
|7200-12470 |15 |95 |
|13200-14400 |18 |125 |
|19920-22900 |25 |150 |
|34400 |34.5 |200 |
Transformer Types:
The following transformer types are used in the substation:
a) Pole or structure mounted transformer: The primary is connected overhead to the bus and the secondary can be brought to the main panel via conduit or trench. This transformer type is easiest used when the load is single phase and less than 100kVA and the required secondary voltage is 120/240V or 277/480V. However, three phase installations are common as well.
b) Pad Mounted Transformer: To limit the voltage drop and reduce the length of the secondary conductors, the transformers are best located near the control building. The location must not interfere with the vehicle movement within the substation and located near the cable for easy access to the control building. The primary cables are connected to the bus/ transformer tertiary and brought under ground to the transformer. The secondary cables are connected to the AC system as required. This transformer type is typically used when medium voltage is available, the connected load is predominantly three phase and the total load is greater than 100kVA.
c) Station Service Voltage Transformer (SSVT): This transformer type combines the characteristics of a voltage transformer with convenient power capability. Used in the substation application if no low or medium voltage bus is available or there is no nearby distribution feeder exists or the cost of installing the feeder is high. One or three transformers can be installed depending the required kVA rating. The primary is normally connected from phase to ground. Typical secondary ratings available 120/240V, 277/480V, 240/480V and 600 VAC.
Transformer Connections:
Depending on number of transformer selected for station power applications two types of connections are employed:
Single Phase Transformer Application:
Single-phase distribution transformers are manufactured with one or two primary bushings. The single-primary-bushing transformers can be used only on grounded wye systems. For this connection the H1 bushing is connected to one of the available phases while the other bushing is connected to ground as shown in Figure 5..
[pic]
—Single phase to ground connection
When a primary delta system is available, a phase to phase voltage is applied between the two bushings H1 and H2 as shown in Figure 6.
[pic]
—Single phase transformer with phase to phase connections
The secondary voltage can also be 480/240V if required.
Three Phase Transformer Connections:
Three phase transformer connection can be achieved by using two or three single phase transformers and connected as required. When a three phase transformer is required a pad mounted three phase transformer is normally used for the station power applications. A pad mounted three phase transformer is applicable to below grade connection from both the primary and the secondary’s sides. The following transformer connections have been used for the substation station service applications:
Delta –Delta Connection:
The delta-delta connection shown in Figure 7 is suitable for both ungrounded and effectively grounded sources. Phase to phase voltage is applied to H1, H2 and H3 terminals of the transformer. For substation application when the required voltage is 240 or 480, a 3- wire connection is used. When the required voltage is 240/120 or 480/240V a 4-wire service can be used. The Delta- Delta four 4-wire service is accomplished by grounding the midtap of one of the transformer windings. The single phase rating is normally 5% of the transformer rating, the three phase rating of the transformer will be derated also. As an example for 300kVA transformer, the single phase rating is .05*300 or 15kVA or 15000/120= 125A. The maximum rating of each transformer winding is equal to (300/(1.73*.48))/1.73 or 417A. The taped winding rating is equal to 417-125A= 292A or (292*.24) = 70kVA, for three windings 70*3=210kVA.
[pic]
—Delta-Delta connection
The advantages of the Delta- Delta Connection are as follows:
a) System voltages are more stable in relation to unbalanced load
b) When three single phase transformers are used to form the phase bank, If one transformer is failed, The remaining two transformer can be used at 58% of the total kVA rating.
c) The delta connection provides a closed path for circulation of third harmonic component of current. The flux remains sinusoidal which results in sinusoidal voltages.
The disadvantages of the Delta- Delta Connection are as follows:
The disadvantage of Δ/Δ connection is the absence of a neutral terminal on either side. Another drawback is that the electrical insulation is stressed to the line voltage. Therefore, a Δ-connection winding requires more expensive insulation than a Y-connected winding for the same power. The delta connection is susceptible to ferroresonance.
DELTA-WYE Connection
The delta-wye connection shown in Figure 8 is suitable for both ungrounded and effectively grounded sources. The transformer primary is connected Delta and therefore phase to phase voltage voltages are connected to H1, H2 and H3 transformer terminals. The secondary is suitable for 3-wire service or if neutral is grounded 4- wire grounded service. In substation application 4- wire service is normally used. Typical substation secondary voltages for this transformer connection are 480/277or 208/120V.
When the neutral is grounded the transformer acts as ground source for the secondary system. Fundamental and harmonic frequency zero-sequence currents in the secondary lines supplied by the transformer do not flow in the primary lines. Instead these zero-sequence currents circulate in the closed delta primary windings. When supplied from effectively grounded primary system, ground relay for primary system does not see load unbalances and ground faults in the secondary system.
[pic]
—Delta-wye connection
When used in 25 and 35 kV three-phase 4-wire primary systems, ferroresonance can occur when energizing or de-energizing the bank using single pole switches located at the primary terminals. With smaller kVA transformers in the bank, the probability of ferroresonance is higher.
WYE-WYE Connection
The wye-wye connection shown in Figure 9 is best applied at four wire primary and secondary were both the primary and secondary neutrals are grounded. The high voltage terminals H1, H2 and H3 are connected to the three phases and the H0 Neutral is connected to ground. In a grounded wye-wye 120 and 240 V or 480 and 240 V cannot be supplied, 208/120V or 480/277V can be supplied by this connection.
[pic]
—Grounded wye grounded wye transformer connection
The following operating conditions should be considered when this transformer connection is selected:
a) Excessive tank heating can result depending on the transformer construction. For three–legged core construction, excessive tank heating is probable. For five–legged transformers, tank heating is possible if the load unbalance is high. Tank heating can be limited if the transformer bank is made from three single phase transformers.
b) Zero sequence currents and harmonics will transfer to the primary. The secondary can act as high impedance ground source.
c) Ferroresonance condition is unlikely if the transformer bank is made from three single phase transformers but possible for a four or five legged construction transformer.
d) Coordination between the source ground protective device and the secondary ground protective device is required because the secondary current can pass to the primary.
Transfer Switch
General
The need for an auxiliary power system transfer switch is related to the criticality of the substation. If only one station service power source is available, a transfer switch may not be required. If there are no critical AC system requirements, the DC battery system may be sufficient to operate the critical DC systems until the AC station service power is restored.
Most substations are provided with two sources of station service AC power. The two sources of station service power are generally designated as the primary source and the alternate (or backup or secondary) source. Both sources should be of equal reliability.
To simplify the operation of the transfer between sources, a “break before make” operation is suggested. This will ensure that sources that are out of phase with one another do not operate in parallel. In the case of manual operation of the transfer switch, it may be desirable to disable or lock out one source while the other source is being used. In both cases, sufficient training should be provided to operators to ensure that sources are not paralleled.
Since the auxiliary power sources can be supplied at different voltages than the utilization voltage in the substation, the transfer switch can be applied at either the primary or secondary voltage. The higher voltage application results in lower current rated equipment. 13.8kV, 12.47kV, 4.16kV, 480V and 240/120V are common auxiliary power voltages and the transfer switch can be applied at any of these voltages. The auxiliary power source can be either three-phase or single-phase depending on the station service requirements. Transfer switches typically can be purchased with two, three or four poles. A four pole switch has the ability to switch the neutral and is necessary on a system that has separately derived system.
Smaller rated transfer switches can be wall mounted. Floor mounted switches are common. Transfer switches can be purchased for indoor or outdoor mounting.
The transfer switch may be as simple as two input sources with switching devices and one output to the load. The transfer system may be as elaborate as a unit switchgear consisting of two input switching devices, two transformers, two main circuit breakers, one tie circuit breaker and multiple branch circuit breakers.
—Simple transfer switch (Figure 4.9-1)
—Complex transfer System (Figure 4.9-2)
Another consideration when designing the transfer system is the reliability of the transfer switch. It may be prudent to make provisions to bypass the switch in the event of the switch’s failure, maintenance or replacement. This may be accomplished by having a third source routed to the substation AC load center that is left normally open and locked out until it is needed. It may be more cost effective to route another set of conductors from either or both of the primary and alternate source to the substation AC load center. Similar to the transfer operation, training and procedure should be provided to the operator so that it will be unlikely to parallel sources for a bypass option.
Manual Transfer Switch
For less critical substations a manual transfer switch will provide the capability of transferring from the primary to the alternate source. The manual transfer switch will be a much simpler and lower cost switch than an automatic transfer switch. However, the use of the manual transfer switch will require station alarms to alert operations personnel of the loss of the primary source and dispatching personnel to the substation to operate the manual transfer switch. Proper design of the DC battery system is required to provide continuous operation of critical systems (system protection functions, control and breaker tripping) while personnel responds and manually operates the transfer switch.
If the substation has only one source of AC power, a manual transfer switch may still be desirable as a connection point for a temporary AC alternate source, such as a portable generator.
The manual transfer switch consists of two manually operated switching devices (usually circuit breakers) capable of interrupting the load current of the transfer switch. The two switching devices are typically mechanically interlocked to prevent both AC sources from being connected in parallel. Fault current interruption capability is not required in the transfer switch, but could be included or provided separately. Indication of source status (hot or dead) is not typically provided. Some point of alarm is necessary to detect the loss of the primary AC source.
Automatic Transfer Switch
Critical substations or substations with critical AC loads will require a transfer switch that will automatically transfer from the primary source to the alternate source when the primary source is lost.
Transfer should occur under the following conditions:
a) There should be a time delay on loss of the primary source. This is to prevent transfer for momentary problems with the primary source.
b) The alternate source is available. This is to prevent transfer to a dead source.
Automatic return to the primary source should occur only after the primary source has been restored for a specified time period to prevent return to an unstable source.
The automatic transfer switch consists of two electrically operated switching devices (usually circuit breakers) capable of interrupting the load current of the transfer switch. The two switching devices can be electrically and/or mechanically interlocked to prevent both AC sources from being connected in parallel. Fault current interruption capability is not required in the transfer switch, but could be provided or added separately. Detection and indication of source status (hot or dead) is required. Time delays and control sequencing is necessary to prevent transferring to a dead alternate source or to prevent nuisance transferring to unstable sources. Indicating lights and relays are usually provided. Alarm indication of transfer should be provided. Close and latch capability must also be consider in equipment rating.
Alternate Methods
If both sources are designated as primary sources, the AC load can be divided between the two sources with the transfer switch system consisting of the two normally closed primary circuit breakers and a normally open transfer circuit breaker.
Bus layout and distribution circuits configuration
Simple radial system
In this system, a single primary service and station light and power transformer supply all auxiliary AC load. There is no duplication of equipment. System cost is the lowest of all the circuit arrangements.
The simplest version of this system is shown in Figure 12. It has panelboards supplied directly from station light and power transformer through a single main breaker. One of the panelboards (“A”) is used to connect a feed to another panelboard (”B”).
[pic]
—Simplest panelboards
A variation of this system is shown in Figure 13 where a power block is used to split a power supply coming from transformer breaker into cables feeding both panelboards “A” and “B”.
[pic]
—Variation of simplest panelboard
Another version of a simple radial system is shown in Fig. 4.7.3, where a main panelboard connected directly to a station light and power transformer breaker is cascading power supply through it’s breakers to sub-panelboards.
[pic]
—Sub-panelboard
The main deficiency of the systems shown in Figure 12, Figure 13, and Figure 14 is the fact that panelboards do not have independent feeds from the main system and are connected to a station light and power transformer breaker through a single common cable, which may be several hundred feet long and because of that, susceptible to failures. In the case of the cable fault or a failure of one of the panelboards ahead of the internal main breaker, the whole auxiliary AC power system becomes de-energized.
To make a simple radial system more reliable and flexible, the auxiliary bus with feeder breakers, shown in Figure 15 may be used. In this system, the auxiliary bus is connected directly to transformer breaker through a bus or a short cable run and panelboards are connected to the bus via feeder breakers and separate individual cables. A failure of any panelboard or a feeding it cable will result in a tripping of a corresponding feeder breaker, leaving the rest of the AC system intact
[pic]
—Reliable and flexible panelboard system
Further improvement of redundancy of a simple radial system may be achieved thru installation of emergency generator, which starts upon loss of the station light and power transformer’s feed to the auxiliary bus, tripping transformer breaker and closing of the generator breaker as shown in Figure 16.
[pic]
—Panelboards with emergency generator
The main advantages of a simple radial system are its low cost and simplicity of its operation and expansion. However, it has a low reliability, because loss of a primary supply, main cable or station light and power transformer will result in the interruption of auxiliary AC service for the entire substation. Another drawback of a simple radial system is the necessity to de-energize it to perform any routine maintenance of its main elements (transformer, transformer breaker, auxiliary bus etc.). That’s why this system is acceptable only for small substations, feeding low priority loads where a low reliability of auxiliary AC supply system and extended down time required to perform its adequate maintenance are acceptable.
Expanded radial systems
If a simple radial A.C. system is applied to a larger substation, its expanded version with two station power and light transformers may be used. See Figure 17.
The advantages and disadvantages of expanded radial system are the same as those described for the simple one. However, by having two transformers, a better redundancy of power supply is achieved. The panelboards can be fed through automatic or manual transfer switches, which can also provide added flexibility in the continuity of power supply to the load if one of the transformers or busses is out of service.
[pic]
—Expanded radial system
Primary selective system
Protection against loss of a primary power supply can be gained through the use of a primary selective system shown in Figure 18. Each station light and power transformer is connected to two separate primary feeders through switching equipment to provide normal and alternate sources of power supply. Upon failure of the normal source, the transformer is switched to the alternate source. Switching can be either manual or automatic.
Each panelboard can be fed through automatic or manual transfer switches, which provides the continuity of power supply to the load if one of the transformers or the busses is out of service.
[pic]
—Primary selective system
Secondary selective systems
If a pair of station power and light transformers is connected through a secondary tie circuit breaker or automatic transfer switch, it will result in a secondary selective system shown in Figure 19. If any of the primary feeders or transformers fails, power supply from the remaining source will be maintained through the corresponding transformer’s secondary breaker and a tie breaker. Tie breaker may be normally open. If this is the case, after failure of one of the sources and opening of affected transformer’s secondary breaker, a tie breaker should be closed either manually or automatically to provide a power supply for the bus section normally connected to the failed source. When a power supply from this source is restored, a manual opening of the tie breaker and closing of the returning to service transformer’s breaker are recommended.
Each panelboard can be fed through automatic or manual transfer switches, which provides the continuity of power supply to the load if one of the transformers or the busses is out of service.
[pic]
—Secondary selective system
Secondary selective system with emergency generator
If the level of redundancy provided by a secondary selective system shown in Figure 19 is not sufficient, an emergency generator with a circuit breaker may be added to it as shown in Figure 20. Normally, generator’s breaker is open, and for a loss of a single primary feeder or transformer, this scheme works exactly like the one shown in Figure 19. But upon the loss of both transformer feeds (both transformer secondary breakers are open) the emergency generator starts automatically and its breaker closes restoring power to both busses. Manual closing of transformer breaker is recommended upon restoration of any primary feed after stopping the emergency generator.
Each panelboard can be fed through automatic or manual transfer switch, which can allow the continuity of power to the load if one of the transformer or the bus is out of service.
[pic]
—Secondary selective system with emergency generator
If even more redundancy is needed, Figure 20 may be developed into a system with two tie breakers and possibly three (3) transformers and an emergency generator as shown in Figure 21. The operational logic for this scheme is consistent with the one described for schemes shown in Figure 18and Figure 19.
[pic]
—Secondary selective system with emergency generator and additional redundancy
The size of cable feeding any load or panelboard is required to be selected in accordance with NEC Article 310 or any applicable code and to be protected by upstream breaker or protective device.
AC panelboards
For distribution of electricity for heat, light or power in 50 or 60 Hz AC systems in electrical substations at or below 600 volts, AC panelboards are utilized for termination of service and feeder cable circuits and for origination of feeder and branch cable circuits.
AC panelboards have a main bus for each phase, main lug terminals or a main device such as a switch, fuses or molded case circuit breaker (MCCB) and neutral and/or ground buses if appropriate. Depending on voltage rating, AC panelboards can utilize a switch and/or overcurrent devices such as plug or cartridge fuse branch circuit devices or molded case circuit breaker (MCCB) branch circuit devices. Most AC panelboards utilized in modern industrial applications such as electrical power substations use molded case circuit breakers (MCCB) for main, feeder, and branch circuit overcurrent devices. Panelboards are designed and manufactured in accordance with NEMA PB-1 and ANSI/UL 67, and are usually supplied in suitable cabinets or enclosures which are manufactured in accordance with UL 50 and UL 50E and designed to be mounted in or on a wall or other support structure and accessible only from the front. In general, panelboards should specified and applied in accordance with the NFPA 70 including all provisions for grounding.
Usual service conditions for AC panelboards are ambient temperature of -5° C to 40° C for AC panelboards utilizing molded case circuit breakers and -30° C to 40° C for AC panelboards utilizing enclosed switches. Usual altitude is not greater than 2000 m (6600 ft).
There are two main types of AC panelboards:
A lighting and appliance branch circuit panelboard is a panelboard having more than 10 percent of its overcurrent devices rated 30 amperes or less for which neutral connections are provided. Except for those provided in the mains, a lighting and appliance panelboard is limited to forty-two overcurrent devices installed in one cabinet or enclosure.
A distribution (power or feeder) panelboard is a panelboard that does not have 10 percent of its overcurrent devices rated 30 amperes or less with neutral connections and utilized primarily to supply feeder circuits to lighting and appliance panelboards or other distribution panelboards and to loads other than lighting and appliance branch circuits.
An AC panelboard utilized for service equipment to provide main control and means of cutoff of the supply conductors near the point of entrance of supply conductors of a building, structure or other area or premises may be a lighting and appliance or distribution type panelboard and should meet all requirements for service equipment required in NFPA 70, UL67, and UL869A.
Panelboards can be single phase or three phase as required for the application.
Typical voltage ratings for AC panelboards for different AC systems are given in Table 4.
—Panelboard voltage ratings
|VOLTAGE RATINGS OF AC PANELBOARDS |
|NUMBER OF PHASES |NUMBER OF WIRES |AC VOLTAGE RATING-VOLTS |
|1 |2 |120, 240, 277 |
|1 |3 |120/240 |
|3* |3 |208Y/120, 480Y/277 |
|3 |3 |120, 240, 480, 600 |
|3 |4-wire with neutral |208Y/120, 400Y/230, 480Y/277, 600Y/347 |
|3 |4-wire delta with neutral |240/120 |
| |connected at midpoint of one | |
| |phase | |
*Derived from 3-phase, 4-wire system
Although more ratings are available, typical rms symmetrical current ratings of AC panelboard main buses, main terminal lugs, main fuse and holder, and main molded case circuit breaker (MCCB) utilized in applications in electrical substations range between 100 A and 800 A. The maximum main current rating in AC panelboards is usually less than 1600 A. The current rating of a panelboard should not be less than the feeder and branch circuit capacity required for the load.
Typical rms symmetrical current ratings of feeder and branch circuits range between 20 A and 400 A. The maximum feeder and branch circuit current rating in AC panelboards is usually 1200 A.
Unless rated for 100 percent continuous load at its rated current, the total load on any overcurrent device utilized in a panelboard should not exceed 80 percent of its current rating.
Bus bars in AC panelboards are current density rated and meet temperature rise limitations established in UL Standard 67. Standard bus bar current densities are 750 amperes per square inch for aluminum bus bars and 1000 amperes per square inch for copper bus bars. Some panelboard manufacturers offer reduced current densities of 600 amperes per square inch for aluminum bus bars and 800 amperes per square inch for copper bus bars.
Copper bus bars are preferred by some Substation Engineers.
Panelboards should be protected by overcurrent device having a rating not greater that of the panelboard
The symmetrical short-circuit current at the panelboard location should be determined in accordance with methods provided in IEEE Std. 141. Most panelboards are selected to have a fully integrated short-circuit interrupting rating where the panelboard and all overcurrent devices enclosed in the panelboard have a short-circuit current rating greater than the available short-circuit current, but series ratings may be utilized. Selectivity between overcurrent devices should be considered, if possible.
Because panelboards utilized in electrical substations may utilize oversize conductors with heavier than normal insulation and jackets, cabinets and enclosures for panelboards utilized in electric substations should be selected with adequate wire bending and gutter spaces.
Circuit Protection
Panel protection
Feeder protection
Selection of Circuit breakers
Appropriate circuit breaker selection is important for the protection and fault clearing coordination of the AC auxiliary power system. There are three important ratings to consider when properly selecting circuit breakers for AC auxiliary power system protection. These are the AC voltage rating, maximum AC current interrupting rating and the AC trip rating.
The AC voltage rating of the circuit breaker should be equal to the operating voltage of the AC auxiliary power system. Typical AC circuit breaker voltage ratings are 120, 120/240, 208Y/120, 240, 277, 347, 480Y/277, 480, 600Y/347, and 600 volts.
The maximum AC current interrupting rating is the maximum AC short circuit current that an AC circuit breaker can successfully interrupt. The power circuit breakers selected for use in an AC auxiliary power system must have a maximum AC current interrupting rating equal to or higher than the actual maximum AC current that the circuit breaker will see during service to effectively operate. AC auxiliary power system circuit breakers have typical maximum AC current interrupting ratings of 7.5 kA, 10 kA, 14 kA, 18 kA, 20 kA, 22 kA, 25 kA, 35 kA, 42 kA, 50 kA, 65 kA, 85 kA, 100 kA, 125 kA, 150 kA, and 200 kA.
The AC trip rating is the maximum AC continuous current that an AC circuit breaker will allow to flow through it. When this rating is exceeded, the circuit breaker will operate. The maximum AC continuous current required to supply an AC load should be considered when selecting the AC trip rating of the circuit breaker. Typical AC continuous current trip ratings range from 10 amps to 6000 amps.
Selection of Circuit Fuses
Appropriate fuse selection is important for the protection and fault clearing coordination of the AC auxiliary power system. The important ratings to consider when properly selecting fuses for AC auxiliary power system protection are voltage rating and current rating.
The AC voltage rating of the fuse should be equal to the operating voltage of the AC auxiliary power system. Typical AC fuse voltage ratings are 125, 250, 300, 480, and 600 volts.
The AC current rating of a fuse is the maximum AC continuous current that an AC fuse will allow to flow through it. When this rating is exceeded, the fuse will blow, thus opening the circuit. The maximum AC continuous current required to supply an AC load should be considered when selecting the AC fuse rating. Typical AC continuous current fuse ratings range from 1 amp to 6000 amps.
Equipment Specifications
Documents for specifying equipment include the necessary information for manufactures or suppliers to prepare and submit a firm proposal to furnish the requested equipment. The equipment specification is usually comprised of both commercial and technical requirements.
The commercial requirements are typically a set of terms and conditions that address how, when and to whom the proposals are to be returned. Other information included may be legal considerations such as taxes or liabilities. Commercial requirements will not be discussed in further detail in this section.
The technical requirements include the description of the necessary performance requirements for the equipment. The information in the description should include, as needed, the operational criteria of the equipment related to its design, construction, testing, and shipment.
Subjects that need to be addressed when specifying aux power equipment include voltage/current levels, service conditions, code requirements/restrictions, delivery dates, delivery/transportation to site, and temporary storage of equipment.
Designers should be aware that the standard equipment that is offered by suppliers may not meet the robust requirements needed for some substations. For instance, the size and layout of the substation may warrant that larger cables be used between equipment. These larger cable sizes will require larger cable bending space and termination sizes and hence bigger enclosure sizes.
Numerous standards have been written to specify requirements of equipment to be used in AC auxiliary power systems. These standards cover transformers, surge arresters, transfer switches, panelboards, medium and low voltage fuses, medium and low voltage circuit breakers, etc.
Some of these standards are:
IEEE C57.12.00 - General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers
IEEE C62.22 - Guide for the Application of Metal-Oxide Arresters for Alternating-Current Systems
UL 1008 - Transfer Switch Equipment
NEMA PB-2 – Dead front Distribution Switchboards
UL 248 - Low-Voltage Fuses - Parts 1 through 16: General Requirements
UL 489 (NEMA AB 1) - Molded Case Circuit Breakers, Molded Case Switches and Circuit Breaker Enclosures
UL 891 - Dead-Front Switchboards
UL 991 - Safety Tests for Safety-Related Controls Employing Solid-State Devices
NEMA standard for indoor/outdoor operation
NEMA (National Electrical Manufacturers Association) creates ratings for equipment based on expected performance. NEMA does not require independent testing to ensure that the manufacturer is compliant to the standard. Compliance to the standard is up to the manufacturer.
Standard NEMA 250-2008 describes types of enclosures for electrical equipment up to 1000 volts maximum. NEMA publishes descriptions of their enclosure types for both non- hazardous and hazardous locations. They also define which enclosure types may be used for indoor/outdoor use and which enclosure types may be used for indoor use only.
The design engineer should choose the type of enclosure specific to environmental, atmospheric and site conditions. For example, a NEMA Type 1 enclosure provides a minimum degree of protection for indoor use in a non-hazardous location while a NEMA Type 3R enclosure provides a minimum degree of protection for outdoor use in a non- hazardous location. The degree of protection offered by these types of enclosures may be sufficient for a particular substation environment.
Operation and maintenance considerations
Isolation switch requirements
Equipment accessibility
Standby backup AC system
The purpose of the standby AC system would be to provide continued AC power to essential systems for a set period of time after all sources to the auxiliary power system are unavailable. The essential systems may be defined as the DC power systems that provide the power required for relaying, control, telemetry, and communications and any AC power needed for breaker operation.
Factors that may determine the need for a standby backup AC system are the criticality of the substation, the battery life for the essential systems, and the reliability of the AC sources for the auxiliary system. If there is a possibility that an event can occur where the minimum time period to provide DC power will be exceeded, a standby backup AC system may be considered.
The standby backup AC system should be a stand-alone unit that provides power without the support of the overall electric power system. A manual start for the system will be desirable considering that telemetry and communications functions may be disabled. Isolation of the sources to the aux power system is necessary before connecting the standby backup AC system to prevent inadvertent paralleling.
The standby backup AC system used in substation normally consists of a diesel generator. The diesel generator is normally used in the substation for one of the following reasons:
a) Used as back up to the primary source, when only one source is available and the substation requires two redundant AC sources.
b) Used as the third source when two sources are available and the substation requires three AC sources.
c) Under emergency condition when all the normal AC sources are not available, the stand by generator is used to restore the system.
When the generator is used as a backup to one or more of normal AC system, the station load can be transferred to the generator automatically by the use of an automatic transfer switch or by manual transfer as required.
Standby Backup AC System
The standby backup AC system used in substation normally consists of a diesel generator. The diesel generator is normally used in the substation for one of the following reasons:
a) Used as back up to the primary source, when only one source is available and the substation requires two redundant AC sources.
b) Used as the third source when two sources are available and the substation requires three AC sources.
c) Under emergency condition when all the normal AC sources are not available, the stand by generator is used to restore the system.
When the generator is used as a back up to one or more of normal AC system, the station load can be transferred to the generator automatically by the use of an automatic transfer switch or by manual transfer as required.
Standby generator for system collapse
In anticipation of a possibility power system collapse, the station power sources will also be lost. In this case a stand by generator is installed at several predetermined substation will be used to re-energize the lost power system. The purpose of this generator is to provide the AC power to a pre-determined substation loads which is defined as essential loads. The essential loads are summarized below:
a) Breaker Load - The breaker load consists of the charging motor inrush current normally added for the first breaker and the continuous motor current added for any additional breakers.
b) Battery charger - One or two battery chargers as applicable must be included as part of the Generator load.
c) RTU/Relay Load - Any RTU, Relays and control equipment load.
d) Lighting load - Limited lightning both for the control building and the yard should be included in case the emergency condition occurs during night.
e) Air Condition/ Heating Load - Limited air condition /heating load should be considered in case generator is required to run for several days during high or low temperature conditions.
f) Stand by Voltage Rating - The generator voltage is selected based on the load voltage.
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Xxx HANNA – THE ENTIRE AC SECTION BELOW THIS POINT DOESN’T EXIST ON THE DOCUMENT YOU SENT ME. SOME OF IT WAS OBVIOUSLY MOVED TO SECTIONS ABOVE, AND THOSE SECTIONS HAVE BEEN DELETED. SOME ARE HARD TO TELL IF THEY WERE MOVED, REWORDED, AND/OR FORGOTTEN OR INTENTIONALLY DELETED. Please review and confirm deletion of remainder of AC section..Per Hanna - The information given below this line has been already discussed in previous section and is not required.. We will discuss with the working group members.
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One-line diagram
The designer may consider the following list when designing one-line diagram.
a) Transformer connection requirements when three-phase transformer is used
b) Transformer KVA and voltage rating
c) Possible available sources
d) Determine preferred sources
e) Number of AC Panels required
f) Method of connecting the AC panels to the transformer
Distribution substation
A distribution substation AC station service auxiliary system may be as simple as a step down transformer with secondary voltage to an AC panelboard to distribute service loads. Depending upon the size and criticality of the distribution substation, an alternate source and manual or automatic transfer switch may be incorporated
[pic]
—Distribution substation AC station service
Transmission substation
The AC station service auxiliary system normally requires a primary and a backup station service source. Typically, the primary source is fed within the substation from a substation bus or transformer tertiary. The backup source may also come from a substation bus or transformer tertiary, or from an external source outside the substation or by a backup generator. The design should include the most reliable and efficient means for two auxiliary system sources. The service loads should be fed through an automatic transfer switch to provide redundancy and reliability to serve the substation AC loads.
Many AC auxiliary systems in transmission substation will include AC panels in the substation yard to serve outdoor yard equipment and lighting circuits. Depending upon the voltage, yard equipment may be served from AC panels within the control building. Large three phase equipment loads may require yard panels rated 480 VAC, which would require voltage step down for other substation loads. Circuits within the control building should be served from AC panels within the building.
Provide Samples -
Convert to Block Diagram –
[pic]
—Transmission substation AC station service
Station service power source
Single-phase or three-phase
AC auxiliary systems are critical in a substation. AC power is used to provide load requirements for all essential and non-essential loads within the substation. The designer should perform a load analysis on all the AC loads in the substation in order to decide whether a single-phase or three-phase source is needed. Economic analysis and determination of essential and non-essential loads should be considered before making a final decision.
Single-phase AC source
Single-phase transformers are typically used in smaller substations where the load demand does not warrant a three phase source. If the substation has a potential expansion or serves critical loads, a backup station power circuit may be considered. These two circuits shall be from independent sources. A tertiary winding of the power transformer may also be used for an AC source if available. Given the significance of the substation, a backup generator shall also be considered for providing an auxiliary source during an outage. The load analysis shall determine the size of the single-phase transformers. All critical or essential loads shall be served at any time. The single-phase source is used when all the substation loads can operate at 120 or 240 volts, and the KVA demanded by the loads is not large enough to require high ampacity conductors and breakers. It is very important for the designer to specify the rated AC voltage on the equipment specification.
Three-phase AC source
Substations with three-phase voltage equipment and high station power load requirements should consider a three-phase AC source. Large bulk substations with high MVA autotransformers are common examples of substations with a three-phase AC source. The fans on high MVA autotransformers and some oil pumps can be rated at 480 Volts. The 240/120 volt Delta and 240/120 volt Wye connections are common three-phase AC station power connections since they can also supply 120 volts when it is a four wire connection. Standard three-phase AC sources can be obtained with a three-phase transformer, a three-phase banking of single-phase transformers, or a backup generator for auxiliary source.
With this type of AC source, there are several types of different connections in order to fit the load requirements. The standard IEEE C57.105 provides a guide for application of transformer connections in three-phase distribution systems. Some utilities utilize the three-phase AC source as a standard AC power supply to the substations. After the load analysis, the designer shall determine the rating of three-phase voltage, the type of connection and weather a three- phase transformer or transformer bank is needed.
Station power available sources
Available sources are represented in figure 4-1. The source deemed the most reliable source is typically designated and used as primary or normal source. The second source is designated as a backup source and used only when the primary source has been lost. A third source, if used, will be used as a second back up and will be connected only if both the primary and second sources have been lost.
The designer must determine the power source to serve the substation AC load as described in section 4.2. In most cases, the designer may want to consider a primary and a secondary source based on the design criteria. Four sources that are commonly used as substation AC auxiliary power sources include:
a) Power transformer tertiary
b) Substation bus
c) Distribution line
d) Standby generators
Each source has advantages and disadvantages. Substation location, substation equipment, and bus configurations may dictate which source is preferred. In substations where AC auxiliary power reliability is critical, multiple sources of AC auxiliary power may be utilized with a transfer scheme to switch between a normal AC auxiliary power source and an emergency AC auxiliary power source.
can provide a good source for station power applications. When the primary and secondary windings are connected “wye”, a third or tertiary winding connected in delta must be used for stabilizing purposes. A tertiary winding presents a low impedance path to zero sequence currents and harmonics, thereby reducing the zero sequence impedance presented to the outside world, while avoiding the problem of tank heating. The tertiary winding typically has a volt-ampere rating between 20-30% of the volt-ampere rating of the primary winding, and typically has a medium voltage rating up to 40kV. If there are plans to use the transformer tertiary for a sub-transmission or distribution source and/or for station power purposes, the tertiary winding is brought out to external bushings for user connection. Otherwise, the tertiary winding is buried inside the transformer. See Figure 4 for transformer connection.
The volt-ampere rating of the tertiary winding typically exceeds the maximum volt- ampere requirement of a substation’s AC auxiliary power load and is, therefore, an extremely adequate AC auxiliary power source.
Consideration should be given to the available fault current at the tertiary bus for phase-to-phase and three-phase faults. In case of the current magnitude exceeding the interrupting rating of the protective equipment such as the fuse or the circuit breakers, several options can be employed to reduce the fault current. These options include installing current limiting fuses, resistors, reactors or increasing the transformer tertiary impedance.
Another consideration should be given to the detection of the ground fault on the tertiary bus. The tertiary buses on three phase power transformers are generally short and may not require any ground fault protection. However, when single phase power transformers are used to construct a three phase bank, bus runs that connect and form the tertiary bus become much longer and are more likely to be subject to a phase to ground fault. A single phase to ground fault on the tertiary will not generate fault current in the tertiary delta and will not trip the distribution transformer high side protection, nor will the fault trip a typical power transformer bank differential scheme. Some utilities choose to install a ground detection network on the tertiary delta to detect this single line to ground fault, signal an alarm, but not trip the power transformer bank. A common method for constructing this ground detection network is to install three small delta connected transformers with a grounding resistor across the open delta. There will be zero voltage dropped across the grounding resistor under normal operating conditions. There will be a voltage drop across the grounding resistor due to circulating current in the broken delta during a phase to ground fault and that indicates that a phase to ground fault on the delta tertiary has occurred.
[pic]
— Tertiary delta bus with grounding resistor (normal system conditions)
[pic]
—(was 4.3) Tertiary Delta Bus with Grounding Resistor (A Phase Grounded)
Conductor selection
This section covers both the primary and secondary conductors. The primary conductor can be either a bare conductor or insulated cable depending in the location of the transformer. When the transformer is located near the source, a bare conductor either AA or copper can be used. When the transformer is located away from the source, Insulated cable Copper or All Aluminum can be used. The cable is normally installed inside a conduit and buried below grade.
Insulated cable is normally used for the secondary conductor. The following must be considered when selecting either the primary or the secondary conductor. There are three main requirements for the conductor used for the auxiliary power system. IEEE 525 provides information on the selection and application of cables and conductor for AC auxiliary power systems.
Cable insulation voltage rating
The cable insulation voltage rating is selected based on the phase to phase operating voltage and the expected clearing fault clearing time. In general, for a clearing time equal to 1 minute, 100% insulation is selected, for fault clearing time greater than one minute but less than one hour, 133% insulation is selected. In either case, the protective relays must clear the fault before the insulation can be damaged as calculated in the sections below. The primary cable standard voltages are 5, 8,15,25,28 and 35kV. The secondary cable insulating is normally given in two ratings; 600V or 1000V.
Cable insulation type
The insulation type must be also selected to meet the location condition such as dry, wet or both. Table 5 shows some of the insulation types that have used in substation application. Refer NEC for more information.
—Selected cable insulation type
|THW‐2 |Thermoplastic Insulation (usually PVC), Heat Resistant (90°C rating), |
| |suitable for Wet locations |
|THWN‐2 |Same as THW except Nylon jacket over reduced insulation thickness. |
| |Also rated THHN. |
|THHN |Thermoplastic Insulation (usually PVC), High Heat Resistant (90°C |
| |rating), dry locations only, Nylon jacket. Also rated THWN. |
|XHHW‐2 |Cross-linked Polyethylene Insulation (X) High Heat Resistant (90°C |
| |rating) for Wet and dry locations. |
|RHH |Rubber Insulation (we actually use cross-linked polyethylene because |
| |it qualifies for rubber), High Heat Resistant (90°C rating) for dry locations only. |
|RHW‐2 |Rubber Insulation (again, cross-linked polyethylene is used by most manufacturers), Heat Resistant |
| |(90°C), Suitable for Wet locations. |
| |Underground Service Entrance. Most utilize cross-linked polyethylene |
|USE‐2 |insulation rated for 90°C in direct burial applications. Product is usually triple rated |
| |RHH—RHW—2-USE-2. |
Conductor size calculations
The following factors must be considered when selecting the conductor size:
a) Required ampacity
b) Temperature correction
c) Allowable connector temperature
d) Voltage drop limitations
Required ampacity
The conductor size must be selected with a proper size to carry the maximum station power load. This is important to prevent conductor overheating and insulation damage and therefore fire. As a first step the ampacity requirements of the conductor must be determined. Station power load consists of a continuous load which is expected to continue for 3 hours or more. The non-continuous load is expected continue for short time only. The following substation load can be classified as continuous load:
← Control building air condition load
← Transformer cooling load
← Lighting load
← Battery charger load
Load that is non-continuous can be identified as follows:
← Breaker motor load
← Test equipment load
← Motor operator load
Branch conductors should be sized to meet equipment load requirements. An overload factor of 1.25 should be applied. Equipment rating data will provide the load requirements. Some loads are of short duration, such as breaker spring or compressor motors. Others are continuous duration, such as heaters and transformer fans. As loads are aggregated at panels the conductors supplying the panel can be sized using a load factor based on the anticipated coincidence the of branch loads.
Once the continuous and non-continuous load is determined, the primary and secondary conductors required size can be determined as discussed below:
1. Primary conductor
According the NEC 215.15 (B1) the rating of the conductor shall be selected to equal to at least the kVA rating of the transformer. Since the station power primary current is normally low due to transformer low kVA rating and the high primary voltage, the conductor size is normally selected to exceed the NEC requirements. Therefore no overheating will occur and the voltage drop is acceptable. When an insulated cable is used, considerations must be given to the conductor strength in order to prevent breakage and damage during pulling.
2. Secondary conductor
For secondary conductors rated 600V or less, the NEC requires the conductor be rated equal to the non-continuous load plus 125% of the continuous load as defined in 4.3.4.1 (???). Using the NEC appropriate ampacity tables, a preliminary conductor size can be selected.
Temperature corrections
If the ambient temperature at the substation location is different than the ambient temperature used for calculating the NEC ampacity tables, the selected conductor ampacity should be corrected for the new ambient temperature. The following equation can be used to calculate the ampacity rating of the conductor based on the new ambient temperature:
Correction for number of conductors
When more than three current carrying conductors either single or multi conductor cables are used for station power, the conductor rating should be derated according to NEC table 310.15(B)(3)(a) is shown below as table 4-2
Table 4-2 (NEC Table 310.15(B)(3)(1) Adjustment Factors for More Than Three Current-Carrying Conductors in a Raceway or Cable
|Number of |Percent of Values in |
|Conductors1 |Table 310.15(B)(16) through Table 310.15(B)(19) as Adjusted for Ambient |
| |Temperature if Necessary |
|4-6 |.80 |
|7-9 |.70 |
|10-20 |.50 |
|21-30 |.45 |
|31-40 |.40 |
|41 and Above |.35 |
Voltage drop verifications
The voltage for both the primary and secondary conductors must be maintained at low values. For station power applications, the voltage drop is normally low for the primary conductors and is not an issue. For the secondary conductors, depending on the distance between the transformer and AC panel must be maintained. Voltage drop limits may be given either as a target percent drop (typically 3% for a branch circuit or 5% including the feeder) or as the equipment voltage limitations. In substations with long cable lengths, the voltage drop considerations may require a larger conductor size than the ampacity requirements.
Station Power Transformer
Single-Phase
Single-phase distribution transformers are manufactured with one or two primary bushings. The single-primary-bushing transformers can be used only on grounded wye systems if they are properly connected. An example, single-phase transformer connected to a three-phase 2,400-volt L-L to obtain l20-volt single-phase is shown. The connections are the same for the following voltage levels: 4,800 volt L-L, 7,200 volt L-L, 13,200 volt L-L, and 34,400 volt L???
[pic]
—no title provided source?
A single-phase transformer connected to a three-phase 2,400-volt L-L system is shown below to obtain 120/240-volt single-phase, three-wire service. Normally the wire connected to the center low-voltage bushing will be connected to ground. Grounding the wire to the center bushing limits the secondary voltage above ground to 120 volts, even though the wires connected to the outside secondary bushings have 240 volts between them.
[pic]
—no title provided source?
The single-phase distribution transformer connected to 4,160Y/2,400 volts is shown below to obtain 120/240-volt single- phase secondary service. Other standard three-phase system voltages are 12,470Y/7,620V, 13,200Y/7,620V and 13,800Y/7,970 V.
[pic]
—no title provide source?
Three-phase connection
Single-phase transformers can be connected to obtain three-phase secondary voltages. The four common connections are shown below.
Open Delta Connections
The open delta bank is often the most economical choice for serving small three phase loads, particularly when commonly available distribution transformers can be used. The cost of the additional KVA capacity in the two transformers will normally be much less than the cost of an additional transformer, fuse, and installation labor.
Open delta banks will carry 57.7% of the equivalent three phase capacity.
Example:
3- 25 KVA transformers 3 phase capacity = 75 KVA.
2- 25 KVA transformers 3 phase capacity = 57.7% of 75 KVA or 43.275 KVA
[pic]
—no title source?
Common three phase connections
Some common three phase connections are shown in Figure 30, Figure 31, and Figure 32.
[pic]
—Delta – delta connection source
[pic]
—wye - wye connection source
[pic]
—Delta – wye connection source
Missing figure? wye –delta
Personnel Safety
All engineering, construction, and maintenance shall adhere to specific codes and standards as well as the Owner’s operating policy to ensure personnel safety. ???Necessary?
Ferroresonance
Ferroresonance is a condition that creates a high voltage between the transformer primary winding and ground. The high voltage can be as much as five times of the primary voltage. In such cases the transformer, cables insulation, or other equipment can be damaged. When present, the transformer will make sounds that are not of its normal hum.
Ferroresonance occurs under the following conditions
a) Three phase
b) Ungrounded primary and transformer grounded
c) Long primary cable, producing a high capacitance
d) No load on the bank or lightly loaded
Station power transformer types and ratings
In this section the following transformer requirements will be considered:
a) Quantity of station power transformers required
b) Station power transformer ratings
c) Transformer impedance
d) Transformer connections
Quantity of station power transformers required
Station load dictate the number of transformers that must be used for station service transformer. For substations with single-phase and light to medium loads, single-phase transformer is used. For substations with three-phase high loads, a three transformer is normally selected. Other loads such as maintenance equipment may dictate the number of transformers to be used for station power.
Station Power Transformer Ratings
The capacity of a transformer is determined by the amount of current it can carry continuously at rated voltage without exceeding the design temperature. Transformer rating is given in kilovolt-amperes (kVA) since the capacity is limited by the load current which is proportional to the kVA regardless of the power factor. The standard kVA ratings are given in Table 6.
— Standard Ratings of Distribution Transformer kVA
|Overhead Type |Pad Mounted Type |
|Single |Three |Single Phase |Three |
|Phase |Phase | |Phase |
|5 |15 |25 |75 |
|10 |30 |37.5 |112.5 |
|15 |45 |50 |150 |
|25 |75 |75 |225 |
|37.5 |112.5 |100 |300 |
|50 |150 |167 |500 |
|75 |225 | |750 |
|100 |300 | |1000 |
|167 |500 | |1500 |
|250 | | |2000 |
|333 | | |2500 |
|500 | | | |
Transformer impedance
Transformer connections
Depending on number of transformer selected for station power applications two types of connections are employed:
1. Single Phase Transformer Application
Single-phase distribution transformers are manufactured with one or two primary bushings. The single-primary-bushing transformers can be used only on grounded wye systems. For this connection the H1 bushing is connected to one of the available phases while the other bushing is connected to ground as shown in Figure 33.
[pic]
—Single Phase to Ground Connection
When a delta system is available, a phase to phase voltage is applied between the two bushings H1 and H2 as shown in Figure 34.
[pic]
—Single phase transformer with phase to phase connections (source)
The primary voltage can be any of the following; 2400,4800,13,200 and 34500 Volts. The Secondary voltage can be any of the following 120/240 and 480/120 Volts.
2. Three Phase Transformer Connections
Three-phase transformer connection can be achieved by using two or three single-phase transformers and connected as required. The user can also specify three-phase transformer connected as specified by the user. When three-phase transformer is required a pad mounted three-phase transformer is normally used for the station power applications. A pad mounted three-phase transformer is applicable to below grade connection from both the primary and the secondary’s sides.
When selecting a three-phase transformer the following must be considered before selecting the transformer connection:
← The required secondary voltage
← Safety
← Ferroresonance condition
3. Secondary Voltage
The following secondary Transformer connection must be selected in order to obtain the secondary voltage that will be required for the application.
a) Three-phase secondary connections–delta
Three-phase transformers or banks with delta secondaries will have simple nameplate designations such as 240 or 480. If one winding has a mid-tap, say for lighting, then the nameplate will say 240/120 or 480/240, similar to a single-phase transformer with a center tap. Delta secondaries can be grounded at the mid-tap or any corner.
b) Three-phase secondary connections–wye
Popular voltages for wye secondaries are 208Y/120, 480Y/277, and 600Y/347.
[pic]
—no title no source no reference to it
AC panels
Present and future load accommodation
The number of branch circuits is dependent on the ultimate station build out. The station arrangement drawing should provide the number of each type of equipment (transformers, circuit breakers, etc,). The voltage and current requirements of each piece of equipment will determine the branch circuit breaker rating requirements. For future equipment installations, the requirements should be a worst case estimation. Allowance for future “unknowns” or spare branch circuit breakers should be provided.
Load classification (or segregation)
It may be desirable to separate critical loads to different AC panels. Non-critical loads can be connected to different panels from the critical loads.
Number of panels required
The number of panels will depend on several items:
c) Voltage and phase requirements - Generally, the higher the voltage of the auxiliary power system, the fewer circuit breakers that can fit in the panel. Two and three pole circuit breakers will require more space within the panel.
d) Load classification - With critical AC loads, additional panels may be required to allow for segregating the loads.
e) Equipment location in the station - If the substation is large, additional panels installed to serve specific groupings of equipment may be desirable. This will reduce the length of the branch circuit runs.
f) Number of branch circuits required - Provision for future additions and unplanned additions should be made. If extensive future development is foreseen, it may be better to plan on providing some of the future development requirements with the addition of future panels.
Panel Rating
a) Voltage
b) Main breaker
c) Branch breakers
d) Neutral bus
e) Ground Bus
Circuit protection
The protection of AC auxiliary power systems is vital to the successful operation of the substation. AC auxiliary power system circuit protection is necessary to ensure the proper protective device coordination operation of the system. This ensures proper clearing of faults in the AC auxiliary power system.
Available short circuit current
The available short circuit current in AC auxiliary power systems is largely determined by the AC auxiliary power system station service transformer. The VA rating, transformer impedance, and voltage rating are the key components in calculating the available short circuit current.
For single phase AC auxiliary systems, the maximum available short circuit current available at the transformer secondary bushings is calculated by:
[pic]
where
ISC is the Maximum available short circuit current
VA is the Volt Ampere rating of the station service transformer
V is the Voltage rating of the AC auxiliary power system
Zxfmr is the Per Unit Impedance of the station service transformer
For three phase AC auxiliary systems, the maximum available short circuit current available at the transformer secondary bushings is calculated by:
[pic]
where
ISC is the Maximum available short circuit current
VA is the Volt Ampere rating of the station service transformer
V is the Voltage rating of the AC auxiliary power system
Zxfmr is the Per Unit Impedance of the station service transformer
AC auxiliary power system cabling adds extra impedance into the system so that the maximum available short circuit current seen at the station transformer secondary bushings is not necessarily the maximum short circuit current that is seen at AC auxiliary distribution panelboards or end use equipment. The short circuit current at any point downstream from the station service transformer can be calculated by adding the impedance of the conductor to the impedance of the transformer on a per unit basis.
[pic]
[pic]
where
Zpu is the impedance per unit
Z is the actual impedance
Zbase is the impedance reference base
VAbase is the volt ampere reference base (typically the VA rating of the station service transformer)
The per unit impedance added to an auxiliary ac circuit can be calculated by
[pic]
where
Ω is the ohms to neutral per 1000 feet (Values found in NEC Table 9)
L is the total conductor length
Once the per unit impedance of the circuit length is known, the maximum available short circuit current available at the end of that length can be calculated by
[pic]
Equation variable list?
Fault calculations
← At the source
← At the transformer low side
← At the AC panel
Design of substation DC system
Design Criteria
Prior to the start of the DC System design the designer should consider several factors that are crucial to successful implementation. Typically in substation applications, the primary purpose of DC auxiliary systems is to provide a reliable power source for the power system protection. DC systems provide power to operate protective relays, monitoring equipment, and control circuits that operate power circuit breakers or other fault isolating equipment. The DC systems are designed to provide power for these protection systems during outages and when the power systems are intact. Several key factors are listed below. The following is simplified DC block diagram
[pic]
—no caption provided – can’t read it anyway
Reliability
The reliability requirements of the power system are typically defined by the system protection design. For example the design requirements for transmission equipment is likely different than the requirements for distribution equipment. These designs determine the robustness requirements for the systems. System reliability standards should be reviewed to determine if back-up equipment or automatic switching is required in the event of one piece of equipment failing.
Redundancy
The redundancy requirements of the power system can be viewed as components of the power system protection. Typical components include: AC current and voltage sources to relays, protective relaying, DC power supply, DC circuit protection, auxiliary relays (lockout relays), breaker trip coils, and control circuitry. This philosophy is illustrated in typical transmission protection systems compared to distribution protection systems. For example, transmission systems typically are designed with redundancy throughout the components listed above while distribution systems may only be designed with single components.
The redundancy design can also be illustrated by examining what would happen if the battery (or DC source) failed during a fault condition on the power system. In a typical transmission system, the over-reaching distance elements of the line relaying on the remote ends would trip the breakers at the remote ends to isolate a fault located within the reach of the distance element (the reach to the remote terminal may be an overreaching zone that is time delayed). This provides some redundancy, however it would not provide complete redundancy for the line protection as only one end would trip for a fault beyond overreach of the line length. Thus, the batteries and relaying on the remote ends provide some redundancy for the battery (or DC source). Compared to the distribution system, unless there are ties to another substation, there typically is no redundancy for failure of the battery in the substation. The example above illustrates that it is important to design the DC system for the protection requirements. If the local substation has only a few transmission lines, the tripping of remote ends to isolate the fault during loss of DC source at the local substation may or may not result in a system stability condition. It is more likely to be a stability concern for large transmission substations. Thus, design of the DC system should coordinate with system protection and system stability requirements.
In regard for the distribution system design, consideration for system back-up for failed equipment such as mobile substations or field ties to an alternate source provide a more economical or acceptable solution to system redundancy requirements.
There may be regulatory requirements requiring redundancy.
Environment
The environment that a DC system is exposed to can impact the reliability of battery performance, the capacity of the battery, and the life of the battery. Key environmental components include: temperature variations, vibration, altitude, cleanliness, and ventilation. Some applications may be susceptible to seismic considerations.
Design considerations
The DC system design should be based on capacity and performance. It is of great importance that all applicable criteria are reviewed to insure that the most reliable, cost effective equipment has been selected for the life of the installation.
Factors to consider:
a) Load on the DC system when the maximum output of the battery charger is exceeded.
b) Demand on the battery when the output of the charger is interrupted.
c) Duration of the battery standby duration (e.g. 2, 4, 8, 12 hours), when auxiliary AC power is lost.
d) Battery Life - What is the projected minimum life of the installation? Are battery life cycle costs to be factored in cost of operation?
e) Cost/Reliability - What was the cost and quality of the battery initially selected? Does operational history align with published life/costs?
f) Operating Temperatures - Will the battery be subjected to temperature extremes? When Ac is lost what is the expected minimum or maximum temperature the building the battery is in can be expected to reach and how long to reach it? Should the extreme temperature be averaged in selecting battery size?
g) Maintenance Intervals - The overall reliability of the battery depends on proper maintenance.
h) Location - Will the battery be located where required maintenance can be completed? Is the battery properly ventilated? Will any associated equipment be susceptible to damage from corrosive lead acid fumes?
i) Vibration/Shock - Will the battery be located near rotating equipment? Lead-acid batteries easily shed their active materials from the surface of the plates, affecting battery life.
j) Weight/Size - Physical size and weight can play a significant role in determining the type of battery to be selected. Is there enough room for the battery and rack in the proposed location? Can the location of the battery accept the floor loading? Can the battery cells be replaced with all adjacent equipment installed or are lifting measures required (E.g. a multi-cell jar can easily weigh over 50 kg)? Is adequate space allocated to get either a permanent or portable lifting device installed? Parallel strings could be considered to reduce weight and size.
k) Design Process - Does the design process account for verification of the DC system loads for all additions or changes?
l) Changed state loads. - does the design need to account for loads that may change state. Examples are breaker spring charging motors that run on DC on loss of AC or SCADA computer monitor that is fed from an inverter source that fails to DC on loss of its normal AC service.
m) Is emergency lighting required? If so can an alternate source be provided?
n) Does the DC system have alternatives in the substation emergency power system?
The design considerations need to accommodate both the owner’s requirements and those of any regulatory agency, Authority Having Jurisdiction (AHJ), or quasi-regulatory agency. Other considerations may include those of any insurer or transmission operator (e.g. black start plans). For example a black start or system restoration plan may require more than one attempt to close in a transmission path and re-establish a secure source of the station AC service. During these attempts beaker spring motors may have to charge on the station battery which may be overlooked in an existing load case and may need to be accounted for in a new design.
Typical equipment served by the DC system
The DC system in a substation serves many critical and non-critical functions and equipment. Some typical equipment served may include:
a) Circuit breakers
b) Circuit switchers
c) Motor operators
d) Protective relay systems
e) SCADA
f) Fire protection/detection
g) Emergency lighting
h) Security systems
i) Pumps
j) Radio or other communication systems.
While most of the equipment is required to be operational at all times, some may be defined as non-critical and may be segregated to reduce loads in the event where the battery of the DC system is required to carry substation loads without the battery charger available. Consideration should be given to limit the amount of non-critical loads connected to the battery to provide reliability to the system protection and to limit the size of the battery.
The equipment may require DC voltages at different values such as 125 VDC for circuit breaker controls and 12 VDC or 24 VDC for a radio communication system. The designer will have to determine the best method to supply the various voltages. It is not generally recommended to tap a larger voltage battery for lower voltages (i.e. 24 volt tap on a 125 VDC battery). If alternate voltages are required to be supplied from a single battery, DC-DC converters are typically utilized for smaller non-critical loads at a lower voltage or a second DC system dedicated to the communications equipment could be installed. It is not recommended to install many DC-DC converters to provide different voltages. Vendors should be consulted to determine if alternate power supplies can be used.
One-line diagram
To start the design process it is recommended the designer create a one-line diagram showing the battery (or batteries), charger (or chargers), DC panels and all connected loads. Consideration should also be given for future load growth. A review of the overall substation one-line may aid in determining future possible additions.
Number of battery systems
The designer should evaluate the criticality of the substation facilities and owner’s preference or regulatory requirements. Protective relay systems are normally designed with two independent systems. The systems are inclusive from the DC feeds to independent trip coils in the circuit breakers. The designer should review whether separate battery systems and panels are required, a single battery system with independent DC panels or one battery system and panel. Independent systems may provide better opportunities for maintenance or replacement in the event of equipment failure or the need to upgrade in the future. The ability to tie redundant DC systems may also aid in maintenance activities.
The number of battery systems may depend on the voltage level of the equipment. For example, if a communication system requires 48 VDC and the substation equipment is 125 VDC, the designer needs to consider whether the communication equipment would be supplied by its own battery as noted in 5.2 and charger or be supplied by a DC-DC converter. The decision will have to consider reliability and control building space among other issues. The number of battery systems has a direct impact on the size of the control house as battery systems typically occupy wall space that can dictate building size. Depending on local requirements, additional preventative measures may be required with multiple battery systems.
Load transfer
The designer needs to account for any DC load transfer requirements. Load transfer could be automatic or manual and serves to back up one DC system in the event of a charger failure from another system or similar event. The need to transfer and the details of a transfer scheme can be dictated by owner’s preference or design criteria, criticality of the substation, or other similar reasons. All equipment that could serve additional load upon transfer must be sized appropriately for that additional load.
There may be regulatory or quasi regulatory requirements that require the ability to transfer the DC load to ensure reliability of the protection systems for the electric transmission system. In North America, NERC and the regional transmission organizations have established requirements for DC system reliability.
DC batteries
Battery types
Battery types and their characteristics are discussed extensively in other IEEE guides. However a brief discussion of them will be held so the designer can make themselves aware of the issues. Common types of batteries used in substation applications include: Valve Regulated Lead Acid (VRLA), Vented Lead Acid (VLA), Nickel Cadmium (N-C). This may change with time due to continued development of new DC technologies. The most common battery types used in substation applications are flooded Lead-Acid batteries. Common flooded lead acid batteries are available with the following variations:
a) Electrolite
1) Lead Calcium
2) Lead Selenium
3) Lead-Antimony
b) Plate Design
1) Flat Plate
2) Tubular Plate
3) Plante’ Plate
The selection of which type of battery to use should be based on reliability and economic criteria. The designer through the use of the referenced IEEE guides, manufacturer’s specifications, and owner’s preference should familiarize themselves with the impact of each type of battery on the design of the overall DC system. Considerations for selecting different types of batteries should include, battery load requirements, environmental conditions exposed to the battery (temperature ranges, moisture), battery life, design, duty cycle, capacity and planned maintenance cycle.
In most utility substation applications, the battery is not exposed to many deep cycles so the ability to accommodate many cycles may not be as important compared to other factors such as battery life and maintenance.
Typically the battery charger will support substation loads with the battery available to supply energy for short duration activities such as breaker trips and closes where the battery charger response time or capacity cannot support the transient.
Criterion for battery rating
The referenced IEEE guides (IEEE- 485 Recommended Practice for Sizing lead-Acid Batteries for Stationary Applications) list the requirements a designer needs to consider for obtaining the battery rating. However to aid the designer some considerations will be repeated here. In addition, this guide places emphasis on substation specific application considerations.
Continuous loads
First using the one-line or equivalent document the designer should review all the continuous loads such as protective relays, SCADA systems, emergency lighting, indicating lights, communication equipment (power line carrier, radio, telecom, microwave, fiber optic), security systems, fire protection, etc. Continuous loads can be obtained for new substations by reviewing vendor literature or calculations from previous designs. For upgrades at existing facilities, the data may need to be obtained by field testing or by examining the existing charger load as vendor data may not be readily available. The field obtained continuous load measurements should be evaluated for end of load cycle voltage and operating experience. When reviewing the literature the continuous loads should be evaluated at the final battery voltage (End of Discharge or Minimum Cell Voltage) selected (i.e. 105 volts). For example, if a device has a load of 125 watts one may be tempted to have the load at 1 Amp for a 125 VDC system. However, at final battery voltage of 105 volts the load would be 1.19 Amps.
Care should be taken to tabulate all known loads. The designer should also review the design for “phantom” loads that may be added by personnel other than the substation designer. For example the control building may be designed by another person who includes a fire protection system to meet local codes and also add DC emergency lighting. Future additions should be considered in the battery design for at least half the battery design life to prevent battery from being replaced uneconomically.
Substation designers should consider limiting loads connected to substation batteries used primarily for protection purposes to provide a more reliable source to the protective system. If emergency lighting is required with no other available source, timers could be installed to reduce the time the lights are connected to the battery. This will keep the continuous loads and the battery size to a reasonable limit.
Momentary loads
Momentary Loads are those such as breaker open or close that occur at various times through the duty cycle (see IEEE-485). Many substation momentary loads such as breaker operations, lockout relays and communication system operations operate in times frames of several cycles (Electrical cycles or Hz not to be confused with duty or load cycles) and careful analysis using IEEE guides and the battery manufacturer may be required. For example an EHV system may detect a fault in ¼ cycle initiate communications for 1 cycle, operate protective devices in ½ cycle and open the circuit breaker(s) in 2 cycles. The whole operation is over in less than 5 cycles from detection. Typical sizing per IEEE 485 looks at loads of 1 minute as the shortest period. After all momentary loads and initial battery size selected, it may be advisable to work with the battery vendor to ensure the selected battery can respond to the expected loads and duration of the load.
[pic]
—no title, this figure is from IEEE 485 – need permission
If a discrete load sequence can be determined, the peak one minute load can be determined more accurately than if the loads are summed. For example, if a substation bus trips on differential via a lockout relay (LOR) that trips three breakers with logic that opens a motor operated disconnect after the breakers open, the peak current would be either the LOR current, the sum of the three breaker trip coil currents or the MOD locked rotor current. The single max current (breaker trips or locked rotor of MOD) would be used as the peak one minute load. This reduces the likely hood of an overly conservative battery size. It requires careful examination of the trip sequence to understand the peak momentary loads. Newer computer analysis programs are available to assist in the analysis. As described in IEEE 485, all load cases should be carefully analyzed to ensure the proper case is identified. A traditional load case that may have been used over an eight hour period for example may not be applicable in a situation where the substation may be required to cycle multiple loads or an extended period in order to restore the system after a blackout. When sizing momentary loads for motor operated disconnects, the locked rotor value should be used for the DC load of the motor operator to accommodate for conditions that prevent the operation of the disconnect from opening or closing under typical force This includes iced switches or switches that have not been operated for a while the blade may be stuck in the switch jaw due to corrosion or other obstruction.
Another important issue when determining the worst case momentary load is whether to consider a breaker-failure situation where a breaker fail relay can operate a group of devices around a failed breaker to isolate the fault. When utilized, breaker failure relaying is a form of the secondary power system protection that requires a second contingency to operate. If breaker failure protection is used, a second contingency to operate the breaker fail may provide the worst case tripping scenario and this contingency should be considered to properly size the battery. In many cases, the breaker-fail operation may put a larger load on the battery and both loads may occur within a minute time frame, because the breaker fail would occur in a matter of cycles. This would exceed the more normal typical worse case. If the original trip included a motor operated device, it would still be operating when breaker fail occurred and thus should be included in both conditions prior and after the breaker fail operation to determine the worst case scenario.
As mentioned above, restoration from “black-start” or system restoration scenario may need to be considered. During “black-start” or system restoration several trip and close cycles may be required to restore the transmission system after a collapse. It would not be uncommon for two or three attempts to be made to get the system to restore and become stable. As part of the “black start” or system restoration all the station breakers may be opened prior to closing in a selected transmission path.
Duty cycle
The duty cycle of a battery is defined in IEEE485 as the loads a battery is expected to supply during specified time periods. The duration of the duty cycle and the specific loads on the battery during that time period determines the size of a battery based on IEEE485 battery sizing. An important consideration for determining the length of the duty cycle is the response time required to replace a failed battery charger. For example, a realistic sequence of events that would follow a battery charger failure may include the following:
a) Charger fails and initiates an alarm to SCADA
b) Dispatcher notices alarm
c) Dispatcher attempts to contact substation personnel
d) Substation personnel drives to substation
e) Substation personnel investigates alarm
f) Substation personnel determines that charger has failed and notifies dispatcher that a technician is needed to repair the charger
g) Dispatcher attempts to contact technician
h) Technician drives to substation
i) Technician attempts to repair charger
j) Technician determines that the charger cannot be repaired and the substation supervisor is notified
k) Substation supervisor locates spare charger
l) Substation supervisor attempts to contact additional substation personnel
m) Additional substation personnel report to service center to pick up vehicle and charger
n) Additional substation personnel drives to substation
o) Charger is replaced
It is not difficult to imagine this process taking longer than the 8 hour duration typically used in substations. Under certain circumstances (particularly during major storms where multiple outages are being worked at the same time) the acknowledgement of the initial alarm is likely delayed due to other priorities thus increasing the battery duty cycle duration. The availability of personnel to respond to an alarm may also increase the duration especially during weekends or holidays. The battery may function properly supporting continuous load during an extended time to replace the charger but may not fulfill its design basis if called upon. Remote devices may be needed to clear a fault having a greater impact.
Another important impact is loss of AC to the control house (add reference to applicable AC sections). Similar to loss of the charger the battery will be called upon to support all station loads. However many control houses may not have been designed to limit temperature minimums or maximums without the heating or cooling systems available. The designer should review the building capability to ensure battery can meet its duty cycle.
Battery voltage and number of cells
The normal DC operating voltages at most utilities are: 54 volts, for 48 volt nominal systems and 130 volts, for 125 volt nominal systems. The float voltages (voltage in the nominal charged condition) for an individual cell will vary from approximately 2.17 volts per cell to 2.25 volts per cell depending on the type of battery and number of cells. In most cases, these batteries are equalize charged (continuation of the regular charge at a higher voltage to bring the battery back to a fully recharged condition) at approximately 2.33 volts per cell.
The number of cells connected in series is based on the required minimum and maximum voltages of the battery load. Typical lead calcium and lead selenium battery individual nominal cell voltage is approximately 2.25 volts per cell. These batteries require 23 or 24 cells for the 48 volt system and 58 or 60 cells for a 125 volt system.
The maximum acceptable cell voltage is approximately 2.33 volts per cell. At this point excessive battery gassing (evolution of hydrogen and oxygen) occurs and the maximum voltage limit of the connected equipment is approached. The designer should review with the owner if the required equalization voltage would exceed alarm limits or normal equipment ratings (typically 140 volts for 125 VDC systems). In that case the number of cells may need to be reduced or the equalization voltage reduced increasing the recharge time. The minimum voltage for these battery cells is typically 1.75 volts per cell, which is normally considered fully discharged. As the voltage falls to this level the ability of connected equipment to operate may become questionable. Typically, breaker trip coils will operate at half their rated voltage but other DC operated equipment may not function properly at or around 1.75 volts per cell. The designer should verify the final battery voltage should support the equipment terminal voltage sufficient for the equipment operation. Voltage drop calculations need to be included in this consideration. Make sure to check connected equipment ratings if there are any questions. For a 58 cell 125 volt system a minimum voltage of 1.81 volts per cell is used to maintain minimum terminal voltage of 105 VDC.
The voltage of the battery is calculated by using the following formula:
[pic]
The number of cells and the end voltage of a battery system can be calculated using the following formulas:
[pic]
[pic]
Battery chargers
Battery chargers are discussed in detail in other IEEE guides. The battery charger is normally used to provide the continuous loads of the station and as a means to maintain charge on the battery, recharge after an event, and to provide an equalize charge to bring the battery back into specification when specific voltages are outside manufacturer’s tolerances.
There are four types of battery chargers commonly available as described in IEEE 1375:
a) Ferroresonant & controlled ferroresonant
b) Phase Control SCR
c) Magnetic Amplifier Chargers
d) High frequency switch mode power supply (SMPS)
Battery charger type depends largely on owner’s preference or design criteria.
Battery charger sizing
Battery charger sizing is based on the amount of continuous load plus constant times the ratio of discharge divided by recharge time as seen below (Simplified):
[pic]
where
A is the charger capacity in Amperes
L is the continuous load in Amperes
C is the discharge in Ampere-hours
H is the recharge time in hours
For C, the designer should use the actual discharge in Amp-hours if known from the sizing calculation (either manual or via computer program). If the total removed Amp-hours is not known from calculation, a conservative method is to use the 8 hour Amp-hour rating of the battery. For H, the designer should consider the owner’s preference or design criteria. Typical times of 8-24 hours are used. While a shorter recharge time may restore a fully discharged battery faster this may cause other problems. A faster recharge may lead to plate damage of the battery due to overheating or the charger being oversized for day to day operations. The designer needs to review the probability of a worst case event happening during recharge and use that to help determine battery size. For large charger sizes, the designer may consider installing two chargers operating in parallel. Since under normal operating conditions, the full capacity of the charger is not needed, it can allow for routine maintenance or even a single charger failure to occur without an effect on battery performance. The constant of 1.1 allows for some variance in loads from the original design and margin for change in performance. The constant 1.1 in Equation (16) can be changed to include altitude correction, design margin, or for varying charger efficiencies. Altitude correction should be verified by reviewing the vendor manual for any needed correction.
Sizing – The following formula is used to determine the required DC output of the battery charger.
[pic]
where
I is the calculated battery charger output, DC amps
A is the amp-hours to be replaced
t is the time in which the battery should be recharged
e is the charger efficiency factor
IC is the continuous DC load current
d is the design margin factor
k is the altitude adjustment factor
1.0 at 3,300 feet
1.1 at 5,000 feet
1.7 at 10,000 feet
Battery Charger Connections
The designer should review the owner’s preference or design criteria regarding the method of connecting the battery charger to the DC system. All connection methods have benefits and drawbacks. The charger can be connected at various points in the system including:
a) Directly to the battery terminals
b) Source side of battery disconnect switch, if one exists
c) Load side of battery disconnect switch, if one exists
d) DC panel main lugs
e) DC panel branch circuit
f) DC bus terminal block
Figure 38, Figure 39, and Figure 40 demonstrate three connection options
[pic]
—no caption provide and can’t read
[pic]
— no caption provide and can’t read
[pic]
— no caption provide and can’t read
If the charger is connected directly to the battery or on the source side of the disconnect switch, it could be considered a reliable method of charging the battery, since there are minimal points of failure in between the charger and battery. However, since the charger also serves to supply power to continuous loads under normal operation, a fault on the battery or removal of the battery for replacement (by opening the battery disconnect switch or disconnecting the main battery leads/cables) may disconnect the charger from the loads.
If the charger is connected on the load side of the battery disconnect switch or at the DC panel, it will maintain connection to the continuous loads even in the event of a battery failure or replacement. However, if the charger gets disconnected from the battery due to an event at the DC panel, the battery loses its means to re-charge.
Charger Circuit Protection
Although the charger may be equipped with integral AC and DC circuit breakers or fuses, the designer may consider external protection as well. The AC feed breaker from the main AC source should be protected in accordance applicable local codes. The DC output may need to be connected with another overcurrent device to coordinate with the overall DC system. Typical charger overcurrent protection is conservatively sized at 140% of the charger current rating. This overcurrent sizing requires charger conductors to meet NEC requirements if applicable as the NEC requires cables to be sized at 135% of the overcurrent protection. This overcurrent device could be either a fuse or circuit breaker depending in owner preference, local codes, or coordination needs. Both the AC and DC external protection should be used to protect the external circuit and cabling. The current limiting characteristics of the selected charger should be reviewed in accordance with IEEE 1375.
DC Panels
The DC panels are used to distribute power to various loads in a substation and can come in many varieties. Panels can come with overcurrent protection on the main feed or main lug only (where the main DC feed connects directly to the DC bus). Branch circuits can be protected by circuit breakers, fuses, fuses with knife blade isolation, or combinations of these such as a circuit breaker in the positive leg and knife switch isolation in the negative. The designer should review applicable local codes and owner’s preference as to what type should be used.
Critical and non-critical loads
The designer should review if there is separation required by local codes, owner’s preference or design criteria. This could be based on whether there is a need to separate loads as critical or non-critical. Critical loads are those that would be required to have DC power under unusual system conditions such as loss of power to the site, black start path, loss of the charger, etc. For example, it may be determined that during a black start condition, it may be beneficial to only have close DC and available and only DC for one trip circuit/protective relay system. Panels would then be segregated with a main DC breaker being tripped by a contact from some system input such as SCADA or the charger loss of AC. While non-critical loads would play a vital role under normal conditions, during severe events they may be overlooked until the system is stable.
Circuit size
The designer should size the DC panel to accommodate the required number of circuits needed for existing load as well as planned load growth. Branch circuits should be sized in accordance with the NEC, local codes or owner’s design criteria as applicable. Branch circuits should coordinate with any downstream devices such as fuses or circuit breakers within the downstream device such as a transformer or circuit breaker. The load side should match with installed cable to prevent a mis-coordination between sizes, such as a 30 amp breaker connected to #14 AWG cable. Circuit size should also account for any voltage drop. Voltage drop includes the effects of current through all interconnecting cable to and from the remote device. The cable should be sized so the device can operate at minimum battery voltage (i.e 105 VDC on a 125 VDC battery) so that the minimum device voltage (90 VDC typical minimum pick-up) is available at the remote device. It may be prudent to build some conservatism in the design calculation to allow for variations in field conditions due to cable lengths, device tolerances, etc.
Load transfer methods
If it is determined that load transfer is required, the designer must ensure that the additional load is accounted for in calculations that size the battery, charger, cables, etc. that are part of the DC system that will accommodate the added load. The specific details and method of transfer must also be determined:
Manual transfer
Manual transfer of DC load can be accomplished by methods including:
a) Disconnect switch(es)
b) Temporary cables
In order to ensure that manual load transfer is accomplished in a safe manner, proper switching procedures, electrical isolation, physical locks and other methods can be utilized. The equipment (cable, switch, lugs, etc.) that actually transfers the load from one system to the other must be sized for the expected load to be transferred as well as future load growth. Figure 41 and Figure 42 show two possible manual transfer schemes.
[pic]
— no caption provide
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— no caption provide
Automatic transfer
Automatic transfer could be accomplished via transfer switches similar to those used on AC systems. The following figure illustrates one version of that method.
[pic]
—DC automatic transfer scheme
Design considerations
Battery monitoring
The battery and DC system has many options for monitoring. The battery charger itself may be equipped with monitoring functions such as loss of DC, low DC, battery grounds, and loss of charger AC. Some microprocessor based chargers have programmable flexibility to provide many other forms of battery monitoring such as battery temperature, impedance, and an on-line partial battery capacity test. Many microprocessor based relays have the option to monitor the DC source voltage to the relay and can provide additional alarm capability. An auxiliary relay may be used to monitor for systems where automatic monitoring may not be available. Through the use of communication links, continuous loads may be monitored from the charger directly to a SCADA RTU or other similar device. A DC shunt may be used to measure battery current directly and connect to a monitoring device. Reference IEEE 1491 Guide for Selection and Use of Battery Monitoring Equipment in Stationary Applications.
Battery installation
Battery location
1. Fire considerations
While the battery is not normally a direct fire hazard, several conditions may present hazards. If the battery main terminals become shorted between the main terminals and there is no protection (fuse or circuit breaker) as allowed by IEEE-1375 for overcurrent, the short circuited battery would become a fire hazard. Thermal runaway conditions also present fire hazards. Another common hazard is the generation of hydrogen gas produced by lead-acid batteries (not applicable to VRLA or Ni-Cd batteries) that occurs during charging, especially when an equalizing charge is applied. Removal of any potential hydrogen build-up should be considered by the designer. This build-up may be removed through normally building exhaust or leakage, direct exhaust of the battery area or by inclusion of fresh air into the building ventilation system. IEEE-484 notes several other recommendations. The designer should be aware of any restrictions imposed by the AHJ in regards to battery ventilation. IEEE 979 provides guidance for fire protection in substation applications. IEEE 1375 provides some additional guidance as well on physical protection of batteries. Local codes or the owner’s preference should be reviewed as to whether the battery should be housed in its own room or enclosure.
The battery charger also does not present any direct fire hazard. However they generate heat as part of the AC-DC conversion and care should be taken to restrict flammable material from being located above the vent openings.
Working clearance meeting the requirements of the NESC Table 125-1 (or local codes) should be used to provide safe access to the equipment for workers and in the event of an emergency.
2. Safety considerations
As discussed in 5.8.2.1.1, working space meeting the requirements of NESC Table 125-1 or local codes should be maintained. In retrofit designs in older station, the designer should check clearances that may have been inadvertently compromised over the life of the substation or in replacing equipment that was installed prior to code applicability. Consideration should also be given to a method for removing battery cells in the future. Space for a lifting device or permanent device may be needed. Typical substation battery cells weigh 20-70 kg (44-154 pounds). Lifting cells of that weight can be very difficult for maintenance from upper steps or tiers of a battery rack. An eyewash station (or equivalent device) that conforms to local codes should be installed to support workers in the event of acid contact. Provisions should be made depending on owner’s requirement for storing the specific gravity tester and an acid resistant cloak. For building safety, acid resistant paint should be used in the battery area to prevent damage to walls and floor. Consideration should be given to using a spill containment system around the battery to absorb acid in the event of a catastrophic cell failure. Refer to 5.8.2.2.
3. Reliability considerations
The designer should review owner’s preference or local codes for separation of multiple battery systems. Physical separation or barriers may be required for multiple systems to ensure that in case of a catastrophic event (e.g. fire or short circuit) on one DC system, it does not readily propagate to the other DC system(s). This can include physical separation by air gap or installation of a barrier (a wall or locating batteries in separate rooms). As the battery system is crucial in allowing most substation equipment to successfully operate, care should be given to provide as much as reasonably possible protection to the battery system.
Reliability is also dependent on battery area temperature. Battery area temperature should be monitored and kept constant, as discussed in 5.8.2.1.5 and 5.8.2.3). Owner’s operating practice for response to building high or low temperature should be reviewed to determine effect on battery performance and reliability. Low or high temperatures outside the design of the battery load profile can affect reliability.
Reliability of the DC system is also affected by placement of DC panels. Separation of batteries and chargers could be ineffective if the DC panels are side by side, as a single panel fire could take out both systems. Cable routing should also be reviewed. It is common to separate the cables of separate DC systems in order to prevent a single event from taking more than one system out of service.
4. Battery room door requirements
If the battery is placed in its own room due to owner’s preference or local codes, the battery room door should have a fire rating equal to or exceeding fire rating of the walls. The battery room door should also incorporate all necessary signage to inform workers of potential hazards of the area, such as acid-containing, explosive mixtures, etc. as required by AHJ. Interior signage should ensure that personnel can identify and find the door. Depending on room design and local codes, the battery room door may also need to incorporate a blast louver to relive pressure in the event of a hydrogen build-up and explosion. The battery room door should have a panic par on the inside and open outward into the control room or outside to allow safe egress of personnel in the event of an emergency. Requirements for securing the door such as locks should be reviewed by the designer.
5. Battery Area Temperature
As discussed in IEEE-484 and IEEE-485 battery temperature plays a key role in battery performance. Battery specifications are generally published at 25°C (77°F) and temperatures that vary from this can affect performance. During the battery sizing calculation the designer should consider the minimum and maximum temperature that the battery area could reach. For example, in a cold weather climate in winter, the battery area could easily reach 13°C (55°F) during a loss of AC to the substation, depending on building insulation levels during the needed response time. Conversely, in a warm weather climate in summer, the same loss of AC could drive the battery area to over 40°C (104°F). Normal operating practices should also be reviewed to determine baseline conditions as part of the battery calculation. If the owner keeps the battery area at 18.3°C (65°F) during winter months as an energy conservation method, battery performance will be below published data and needs to be accounted for in the design calculation. Batteries that are installed outdoors or in small enclosures (that are not temperature controlled like a building) may be subject to large variations in temperature
Acid spill containment
The designer should review applicable local codes regarding acid containment. It is typical practice to install a spill containment system that contains the acid to an area immediately adjacent to the battery and neutralizes it for safe handling and disposal. Use of acid resistant paint on the floors and walls of the battery area is also recommended to minimize any damage to the building in the event of a spill. If permanent spill containment is not installed, the designer should review local codes or owners preference to determine if on-site temporary acid adsorbent material or temporary containment is required. For example, in the United States the Uniform Fire Code, NFPA !, requires spill containment for an individual vessel with more than 208 liters of electrolyte or multiple containers exceeding 3785 liters. Most substation batteries have electrolyte volumes below those limits.
The designer should review the footprint required for a containment system to ensure that adequate worker access is maintained. The designer should review any tripping hazard that may be presented by installation of a mechanical containment system.
Battery racks
When selecting a battery rack, there are several things that should be considered including temperature differences, weight of the battery, available space and maintenance requirements. Battery racks generally come in three types – step, tier, or stepped tier as shown in Figure 44. A step rack is designed so the battery levels are “stepped" from one another (usually offset by the depth of a cell). A tiered rack has the levels of batteries on top of each other. A stepped tier is a combination of the two.
[pic]
—Rack designs
For substation applications, steps and tiers are usually limited to two levels. Step racks generally have a larger footprint than an equivalent tiered rack and cells can be easier to access. Tiered racks tend to save floor space due to their smaller footprint. Other considerations with larger batteries include height and weight. The European din size requirements of some batteries requires the increase in battery size to increase the height rather than the width or length of the battery jar. This can create height issues for larger battery sizes. Weight can also be an issue especially for taller racks.
The height variations between upper and lower levels of a battery rack are a concern. Height variations will cause differences in cell temperatures within the same battery system. Since temperature can have such a drastic effect on battery characteristics, interconnecting cells at different temperatures can lead to an early failure of the battery system. As a general rule, temperature gradients in excess of 3°C should be avoided.
Battery racks should have an acid resistant coating applied to the structural frame to preserve its integrity. It may also be advantageous to have a liner on the support rails of polyethylene or similar material to further protect the rails from damage and provide electrical isolation.
In areas of seismic concern, the battery rack should be specified as to its correct seismic zone so the correct bracing can be applied. A seismic rack has the same basic design as a non-seismic rack with additional bracing applied to hold the rack and cells in place. Cross bracing is used on the rack and an additional set of bracing is applied around the tops of the jars to prevent the jars from shifting in the seismic event.
Circuit considerations
Grounded and ungrounded systems
Substation batteries used for operation and control of interrupting devices and protection system, SCADA etc. are typically ungrounded. Communication systems such as those used by telecom companies are typically a positively grounded 24 or 48 VDC systems. The designer should be aware of the difference and not mix the two. Direct contact input to opposite systems should be avoided and use of interposing relays or devices should be used. Addition of unintentional grounds should be reviewed during the design and installation process.
Isolation of main DC cables
As discussed further in section 5.8.3.3.2, the battery is the source of fault current for the DC system. The cables between the main battery terminals and the first overcurrent protection (breaker or fuse) are unprotected (unless using a mid-point fuse). Thus designs should place the main battery overcurrent protection as close to the main terminals as possible to reduce this exposure. A short to any portion of the battery main terminals can produce extreme heat and fire hazard for a shorted battery. Any damage to the cables from the battery can subject a worker to the full short circuit capability of the battery. The designer should review the owner’s preference to separate the positive and negative cables of the battery to reduce the possibility of a direct short circuit being applied to the battery. When separating the cables they should be placed in a non-magnetic conduit to prevent induced fields from causing other potential hazards. If the cables are not run in separate conduits, the designer should try and minimize the cable length to the DC load center to prevent risk of damage. With multiple battery systems, care should be taken to avoid routing main DC cables near one another to preserve independence and reliability.
IEEE 1375, Guide for the Protection of Stationary Battery Systems, gives additional guidance on the methods of protecting the main DC feed to the load device from the battery. They include:
a) Battery fuse (in both positive and negative leads for ungrounded systems)
b) Battery circuit breaker (including both positive and negative leads for ungrounded systems)
c) Battery disconnect switch (fused or non-fused) that allows the battery to be disconnected from the load circuits (note that for this application the battery charger must be connected between the switch and the load)
d) Mid-point battery fuse which protects for external faults and limits output short circuit current to half of the entire battery rating
e) Cable only, no overcurrent provided
IEEE 1375 gives a description of the advantages and disadvantages of each method.
[pic]
—no caption provided, can’t read
Circuit protection and coordination
1. Coordination of overcurrent protection
The designer needs to review the coordination between all devices in the DC circuit in accordance with the NEC, local codes or owner’s design criteria. Overcurrent protection devices should be sized such that an upstream device does not trip for a downstream operation. For example, if a DC panel circuit feeds both a relay panel fuse and a circuit breaker trip coil, the relay panel fuse should operate due to a protective relay power supply or circuit failure and leave the circuit breaker trip coil operational.
2. Short circuit levels
Since the battery is the primary current source in case of short circuit, the battery data sheet or manufacturer should be consulted to determine available fault current. The interrupting devices in downstream circuits should be reviewed for their DC ratings. Many devices may appear to have sufficient interrupting capability but do not have the appropriate Asymmetrical Interruption Current (AIC). Without proper AIC a breaker may not interrupt the current. It may weld close or open without the ability to dissipate the energy. These conditions could result in damage to equipment, injury to personnel and/or other un-intended operations. Similar conditions apply to fuses used for interrupting faults.
The designer should consider protection of the main DC feed by use of circuit breakers of fuses. 5.8.3.2 and IEEE 1375 give more guidance on protection of the battery main feed.
3. Fuse and circuit breakers
The designer should consider local codes as well as owner's preference or design criteria when selecting circuit breakers or fuses. Fuses may have a lower initial installed cost but may require additional spare material to be stored on site to allow for replacement in the event of an operation. Fuses may also require a fuse monitor to be installed to detect and provide indication that they have operated. Circuit breakers may have a higher initial installed cost but they provide indication they have operated and usually do not require replacement after they have operated.
Equipment rating
Indoor and outdoor equipment ratings
The DC equipment should be selected to be of the proper rating for their intended location. Outdoor rated equipment may be installed within indoor substation locations, but indoor rated equipment should not be installed outdoors. It may be advantageous to have some DC panels placed closer to the loads they support such as circuit breakers in a large transmission substation. In this application outdoor rated equipment may be required for example as NEMA 3R or NEMA 4.
Equipment rating
As discussed previously, the DC equipment should be rated for interruption of fault current. If a main breaker is used, it should be able to interrupt the maximum short circuit current available from the battery for the life of the battery. The designer should review interrupting capability during a battery replacement. Continuous current rating should match or exceed the current drawn by existing loads and allow for future growth. Voltage rating should match or exceed the maximum battery voltage (i.e. 250 VDC for a 125 VDC battery). Fault interrupting current ratings at a DC level should be known. A large battery may be capable of currents over 10kA. DC interrupting capability of the main fuse or circuit breaker should be reviewed.
Maintenance Provisions
Isolation switches
The designer should review local codes and owner’s preference or design criteria regarding the need to provide isolation switches for the battery and charger. Main isolation switches can allow a temporary battery to be installed during maintenance, upgrades or replacement. Since a substation may be in-service for more than the 20 year design life of a battery, it is reasonable to assume that the battery will be changed at least once during the life of the substation. Since it is usually not feasible to shut down an entire substation during a battery change out, providing an isolation switch where a temporary battery can be connected can be advantageous during upgrades or emergencies such as battery failure. Similar logic can be applied to chargers, though in case of a charger failure or replacement, it is usually easier to connect a charger temporarily than a battery.
Equipment accessibility
As discussed previously, access per NESC table 125-1 or other local codes should be maintained. Table 125-1 provides minimum clearances, but owner’s preference and design criteria should be reviewed as well. Battery cells/jars can be weight enough that ordinary workers may not be able to lift it without mechanical assistance. Access room may need to be maintained for mechanical lifting devices to install or remove battery cells/jars. Safe working clearances between the battery and other equipment of 30 inches side to side and 36 inches in front or behind should be maintained. Overhead lifting devices may be needed from building supports to remove the cells as well.
Battery charger weights may be such that provisions may need to be made for access for lifting devices to replace it as well. The charger may weigh over 100 kg (220 lbs.). The battery chargers also may generate a significant amount of heat and care should be taken to ensure that access may be made to service the equipment without risk of thermal damage.
Back-up Supplies
The designer should review owner’s preference for any back-ups. Based upon the importance of the substation, there may be a need for back-up equipment (either charger or battery bank). As discussed previously, if provisions are made during design then back-up supplies can easily be connected. If back-up supplies are required, the design should account for the time frame required to facilitate timely or permanent connection of any back-up supplies, including the location of back-up or temporary connections. Also, the designer needs to review if automatic actions are required to place any back-up supplies in service.
Note: DC open item:
Resolution of non-answer from NESC commitee on IEEE 1375 allowing unprotected cables. Talk to Bruce Dietzman and Gary Engmann about it. It may be that the importance of the DC system may override section 161.c of NESC. Utilities that use this method may be in conflict with adoption of NESC by their local states or other municipalities.
(informative)
Bibliography
Bibliographical references are resources that provide additional or helpful material but do not need to be understood or used to implement this standard. Reference to these resources is made for informational use only.
1] Accredited Standards Committee C-2, National Electrical Safety Code® (NESC®).
2] IEEE Std C57.12.00TM, IEEE Standard for General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers.
3] IEEE Std C57.12.10TM, IEEE Standard Requirements for Liquid-Immersed Power Transformers.
4] IEEE Std C57.105TM, IEEE Guide for Application of Transformer Connections in Three-Phase Distribution Systems.
5] IEEE Std C62.22TM, IEEE Guide for the Application of Metal-Oxide Surge Arresters for Alternating-Current Systems.
6] IEEE Std 484TM, IEEE Recommended Practice for Installation Design and Installtion of Vented Lead-Acid Batteries for Stationary Applications.
7] IEEE Std 485TM, IEEE Recommended Practice for Sizing Lead-Acid Batteries for Stationary Applications.
8] IEEE Std 525TM, IEEE Guide for the Design and Installation of Cable Systems in Substations.
9] IEEE Std 979 TM, IEEE Guide for Substation Fire Protection.
10] IEEE Std 1375TM, IEEE Guide for the Protection of Stationary Battery Systems.
11] IEEE Std 1491TM, IEEE Guide for Selection and use of Battery Monitoring Equipment in Stationary Applications
12] NEMA PB2, Deadfront Distribution Switchboards.
13] NFPA 1, Uniform Fire Code® (NEC®).
14] NFPA 70, 2014 Edition, National Electrical Code® (NEC®).
15] UL 248, ???? there are 16 different one
16] UL 489, Molded-Case Circuit Breakers, Molded-Case Switches, and Circuit-Breaker Enclosures.
17] UL 891,Switchboards.
18] UL 991, Standard for Tests for Safety-Related Controls Employing Solid-State Devices.
19] UL 1008, Standard for Transfer Switch Equipment.
xxx
AC Section References
Distribution Transformer Handbook, First Edition Transformer Connections, General Electric October 1951
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