DGL_34-617

JFScholtz/Aug’07 (Rev 0) to ensure traceability

GUIDELINE

Document Classification: Controlled Disclosure

Reference: 34-617

Document Type: DGL

Revision: 0

Effective date: OCT 2007

Total pages: 55

Title: NETWORK PLANNING GUIDELINE FOR TRANSFORMERS

Revision date: OCT 2010

TESCOD APPROVED COMPILED BY APPROVED BY FUNCTIONAL RESP AUTHORISED BY Signed _ _ _ _ _ _ _ _ CG CARTER-BROWN

Signed _ _ _ _ _ _ _ _ CG CARTER-BROWN

Signed _ _ _ _ _ _ _ _ V SINGH

Signed _ _ _ _ _ _ _ _ MN BAILEY

Chief Engineer Network Planning SC for TESCOD CMDT for MD (Dx)

Content

Page Foreword..............................................................................................................................................2 Keywords .............................................................................................................................................3 Bibliography .........................................................................................................................................3 1. Scope..........................................................................................................................................4 2. Normative references..................................................................................................................4 3. Definitions and abbreviations......................................................................................................5 4. Theory .........................................................................................................................................6

4.1 Transformer fundamentals .....................................................................................................6 4.2 Impedance..............................................................................................................................7 4.3 Vector group ...........................................................................................................................9 4.4 Tap changer..........................................................................................................................10 4.5 Transformer earthing ............................................................................................................11 4.6 Types of transformers...........................................................................................................13 4.7 Loading thermal limits...........................................................................................................14 4.8 Paralleling transformers........................................................................................................17 4.9 Fault levels and through faults..............................................................................................18 4.10 Mobile transformers/substations...........................................................................................19 4.11 Transformer rating and redundancy .....................................................................................19

5. Eskom power transformer specifications ..................................................................................20 5.1 Reticulation transformers (MV/LV and SWER isolation) ......................................................20 5.2 Major power transformers (HV/HV, HV/MV and MV/MV).....................................................22 5.3 Mobile substations (HV/MV, MV/MV and MV/LV) ................................................................24 5.4 Neutral Earthing Compensators with Resistors....................................................................25

6. Eskom power transformer application standards and guidelines .............................................25 7. Data required for Power System Analysis ................................................................................27 8. Application guideline .................................................................................................................28 9. Modelling power transformers in PSA software........................................................................30 10. Worked example .......................................................................................................................38 Annex A Earth fault current flow with common MV grounding configurations ..................................41 Annex B Major power transformer emergency overload ratings .......................................................44 Annex C Parameters required for PSA..............................................................................................46 Annex D Impact assessment.............................................................................................................52

DOCUMENT CLASSIFICATION: CONTROLLED DISCLOSURE NETWORK PLANNING GUIDELINE FOR Reference: 34-617 TRANSFORMERS Revision: 0 Page: 2 of 55

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Foreword

The location and size of power transformers is an important component of Distribution Network Planning. Network Planners need to understand the basic theory and relevant Eskom Distribution standards and specifications relating to power transformers. They also require guidance on the modelling of transformers in network simulation software. Network Planners need to be able to select transformers such that minimum requirements (thermal limits, fault level ratings and vector group compatibility) are met whilst also ensuring the redundancy requirements are complied with.

This guideline provides the Eskom Distribution Network Planner with a basic understanding of the theory and practical application, such that power transformers (HV/HV, HV/MV, MV/MV and MV/LV) can be modelled in power system analysis software (specifically ReticMaster and PowerFactory) and new transformers sizes can be selected based on minimum requirements and redundancy criteria.

Revision history

Date Rev. Compiler Remarks

Oct 2007 0 CG Carter-Brown

Original issue

Authorisation

This document has been seen and accepted by: Name Designation

Rob Stephen General Manager – Distribution Capital Program Kurt Dedikend Network Services Manager – Eastern Region (NSM Planning custodian) Riaan Smit Network Planning Manager – Western Region Mongezi Nyengane Network Planning Manager – Southern Region Mike Pallett Network Planning Manager – Eastern Region Kobus Barnard Network Planning Manager – North West Region Chris du Toit Network Planning Manager – Central Region Monde Bala Network Planning Manager – Northern Region

This guideline shall apply throughout Eskom Holdings Limited, its divisions, subsidiaries and entities wherein Eskom has a controlling interest.



Development team

This guideline was developed with input from:

Rob Stephen Craig Clark Riaan Smit Mike Pallet Devan Nardhamuni Kurt Dedekind Sifiso Sikhosana Mongezi Nyengane Koos Scholtz Ed Bunge Keith Wood Karen Vosloo Keywords

Network planning, network design, transformer, load-flow. Bibliography

DGL 34-539 Network Planning guideline for MV step-voltage regulators.

Power Transformer Maintenance and Application Guide, EPRI, 2002.

DIgSILENT Technical Documentation; Two-Winding Transformer (3-Phase), 2007.

http://en.wikipedia.org/wiki/Transformer



1. Scope

This guideline covers the theory, standards, software modelling and sizing of HV/HV, HV/MV, MV/MV and MV/LV power transformers for Eskom Distribution Network Planning. Detailed power transformer design and substation layout is not the focus of this guideline. The application of this guideline should ensure that Network Planning correctly analyse existing power transformers, and appropriately size future power transformers. The scope of work required from the Network Planner (as an input to Project Engineering design work) is defined. Voltage regulator theory, modelling and application is addressed in DGL 34-539 (Network Planning guideline for MV step-voltage regulators), and is not repeated in this guideline. For a summary of the key information jump to the Application Guideline on page 28.

2. Normative references

Parties using this guideline shall apply the most recent edition of the documents listed below:

BGL 34-335 Network Planning Philosophy

DGL 34-450 Network Planning Reliability Guideline

34-542 Distribution voltage regulation and apportionment limits

DISSCAAD1 Specification for combined three-phase neutral electromagnetic couplers (NECs) with neutral earthing resistors (NERs) and auxiliary transformers

DSP 34-346 Specification for oil-immersed power transformers up to 500kVA and 33 kV

DSP 34-342 Specification for phase to phase (11, 22 & 33kV) connected transformers with centre tapped low voltage winding

DSP 34-344 Specification for MV isolation transformers for single wire earth return systems

DSP 34-345 Specification for phase to neutral (19kV SWER) connected transformers with single-phase low voltage winding

DSP 34-343 Specification for phase to neutral (19 kV SWER) connected transformers with centre-tapped low voltage winding

DISSCAAD3 Specification for large power transformers up to 132 kV in the rating range of 1,25 MVA to 160 MVA

SCSSCAAU3 Specification for 20MVA, multi-ratio, mobile substations

DISSCAAU4 Specification for medium voltage 5-10MVA single and multi-ratio mobile substations

DISSCAAM7 Medium-voltage miniature substations for systems with nominal voltages of 11kV and 22kV

DISSCAAY1 Ground-mounted oil-immersed power transformers up to 2MVA and 33 kV with MV and LV cable boxes

DISSCABG7 1000kVA miniature substations for systems with nominal voltages of 11kV and 22kV

DISSCABR0 Specification for combined three-phase neutral electro-magnetic couplers (NECs) with neutral earthing resistors (NERs) and auxiliary transformers

DISSCAAL1 100kVA to 500kVA 11 or 22kV/415V mobile reticulation transformer

SCSAGAAG0 Transformer protection philosophy

SCSASACB6 Medium voltage system earthing practice

SCSAGAAT4 Transformer loading guidelines

RES/RR/03/20960 Transformer loading lookup table



3. Definitions and abbreviations

3.1 Reticulation transformer: MV/LV and MV SWER isolating transformers. These transformers are usually pole mounted in rural areas (MV overhead), and ground mounted (mini-substations) in urban areas (MV cable). Ratings typically range from 16kVA to 1000kVA.

3.2 Major power transformer: HV/HV, HV/MV and MV/MV power transformers. These transformers are ground mounted in substations. Ratings range from 1.25MVA to 160MVA.

3.3 Single phase: Single phase network technology consists of a phase conductor and a neutral conductor. In Eskom single phase is only used in LV networks.

3.4 Dual phase: Dual phase network technology consists of two phase conductors and a neutral conductor. The two phases are 180degress phase shifted. This technology is also referred to a bi-phase. In Eskom dual phase is only used in LV networks.

3.5 Phase to phase: Two phases of a three phase delta system. Also commonly referred to as single phase MV, but this is misleading as there is no neutral conductor. In Eskom phase to phase is only used in MV networks.

3.6 Three phase: Three phase network technology. Delta systems have no neutral conductor. Star systems have a neutral conductor. In Eskom three phase Delta is used in MV networks and three phase Star is used in LV networks.

3.7 SWER: Single Wire Earth Return. Single phase conductor with no neutral conductor. The earth is used as the return path for load current. In Eskom SWER is only used in MV networks.

3.8 Neutral Electromagnetic Coupler (NEC): A ZN connected winding, used to provide an artificial neutral point in a delta-connected system, capable of passing a specified earth-fault current for a specified time.

3.9 Earthed system: A system in which the neutral point of the supply transformer, or that of the NEC, is intentionally connected to earth either directly or through a current limiting device.

3.10 Effectively earthed system: An earthed system in which the phase-to-earth voltages on the unfaulted phases under earth-fault conditions are limited to 80% of the normal phase-to-phase voltage.

3.11 Resistively earthed system: A system in which the neutral is connected to earth through a resistance.

3.12 Reactively earthed system: A system in which the neutral is connected to earth via an impedance of which the principal component is reactance of a magnitude such that the ratio X0/X1 for the system is greater than 3. A reactively earthed system is, by definition, Non-effectively earthed.

3.13 EHV: Extra High Voltage (>132kV).

3.14 HV: High Voltage (>33kV & ≤132kV).

3.15 MV: Medium Voltage (>1kV & ≤33kV).

3.16 LV: Low Voltage (≤1kV).

3.17 MTL: Master Type Library.

3.18 PSA: Power System Analysis.

3.19 SWER: Single Wire Earth Return.

3.20 OLTC: On Load Tap Changer.

3.21 OCTS: Off Circuit Tap Switch.

3.22 EDI: Electricity Distribution Industry.



4. Theory

4.1 Transformer fundamentals

This section is based on an EPRI report titled Power Transformer Maintenance and Application Guide, which should be consulted for additional information. Typical power transformers are oil filled. Figure 1 is a cutaway view of a typical three-phase oil filled major power transformer, showing the tank, internal connections, typical windings, and the installed bushings.

Figure 1: Cutaway view of a typical oil filled major power transformer [EPRI Power Transformer

Maintenance and Application Guide] The operation of the transformer is based on electromagnetic theory proposed by Lenz and further developed by Maxwell. When a current flows through a conductor, a magnetic field is produced. By placing another conductor within that magnetic field, a voltage is induced in that conductor. This principle provides the basis for transformer action. The transformer transfers power by electromagnetic induction between circuits at the same frequency, but at different voltage and current. Transformers consist of two or more windings linked by a mutual magnetic field. When one of the windings (primary) is connected to an alternating voltage source, an alternating flux is produced. The amplitude of the flux depends on the primary voltage and number of turns in the windings. The mutual flux links the other winding (secondary) and induces voltage in that winding. The value of the induced voltage depends on the number of secondary turns. The transformer is unique because, except for equipment that cools the oil, it has no continuously moving mechanical parts. The generation of electricity requires relative motion between a magnetic field and a group of conductors. In generation plants, the turbine supplies the motion that drives the rotor magnetic field through the stator winding of the generator. In the transformer, this mechanical motion is replaced with a magnetic field that oscillates back and forth (magnetic flux) when the wires are connected to an alternating current voltage. Alternating current is required in order to produce a changing magnetic field that will in turn induce a voltage.



The transformer consists of two circuits, the electrical circuit and the magnetic circuit. The electrical circuit is the current flow through the primary winding and the secondary winding to the load. The primary winding is considered to be that which has the current applied to the transformer. The secondary winding is that winding that takes current away from the transformer. The magnetic circuit in a transformer provides a path for the flow of the magnetic flux produced by the primary windings to the secondary windings.

Figure 2: Basic transformer configuration

The transformer primary and secondary coils are wound around an iron core. Once an alternating voltage E1 is applied to the primary winding, a current I1 called the exciting current, will flow in the primary winding and a voltage E2 will be induced in the secondary winding. As the current flows through the winding, it will produce an alternating magnetic field with a flux of φ magnetic lines of force through the core. Magnetic flux φ in the iron core will always flow over the path of least resistance. The voltage induced by the rate of change of flux in each turn of the transformer will be the same. Therefore, the voltage ratio between the two windings will be the same as the ratio of the number of turns (N):

)1(2

1

2

1

2

2

1

1

NN

EEor

NE

NE

==

Thus, the fundamental relationship is established as the ratio of the primary and secondary voltage is equal to the ratio of the primary and secondary winding turns. Since power is the phaser product of voltage and current and the primary power is equal to the secondary, that is P1 = P2 or E1I1 = E2I2

)2(1

2

2

12211 I

IEE

orIEIE ==

Therefore,

)3(1

2

2

1

II

NN

=

Hence, the primary to secondary voltage ratio is inversely proportional to the current ratio. 4.2 Impedance

Referring to figure 3, the electrical and magnetic circuits result in series and shunt impedances. The shunt impedance arises due to the core magnetisation. The series impedance arises due to the winding resistance and leakage flux inductance.



Figure 3: Transformer series and shunt impedances

The shunt impedance is usually practically expressed in terms of no-load loss in kW and no-load current as a percentage of rated current. The no-load loss in kW represents the core active power consumption. The no-load current represents the core apparent power consumption. Power system analysis software converts these parameters into shunt resistance and reactance, with suitable voltage dependency (constant impedance). As the core is essentially a shunt connected reactor, the core consumes significantly more reactive power than active power. The series impedance is usually expressed as a percentage of the transformers base impedance. The series impedance is largely inductive. The resistive component of the series impedance is usually specified via either an X/R ratio or the rated active load power loss in kW at rated current. Power system analysis software converts these parameters into series resistance and reactance. Current flow through the series impedance results in an internal voltage drop across the transformer. The magnitude of this voltage drop is dependent on the series impedance, and magnitude and power factor of the load current supplied by the transformer. Poor load power factors result in increased internal voltage drop as the series impedance is largely reactive. Figure 4 illustrates the effect of load magnitude and power factor on internal voltage drop for a typical 10MVA major power transformer with an impedance of 11% and X/R ratio of 25.

Transformer internal voltage drop

0%

1%

2%

3%

4%

5%

1 2 3 4 5 6 7 8 9 10 11 12 13

Loading [MVA]

Inte

rnal

vol

tage

dro

p [%

]

PF = 1PF = 0.95

PF = 0.9

PF = 0.8

Figure 4: Typical 10MVA major power transformer internal voltage drop (Z=11%, X/R=25)

The series impedance of MV/LV transformers up to 1000kVA is typically in the range of 3% to 7%. The impedance of standard HV/HV and HV/MV major power transformers between 1.25MVA and 160MVA typically varies between 6% and 12%. “High” impedance major power transformers are utilised where the fault levels associated with standard impedance transformers are too high. The impedance of “high” impedance major power transformers typically varies between 17% and 23%.



4.3 Vector group

A Vector group is used to categorise the primary and secondary winding configurations of three phase transformers. The vector group indicates the windings configurations and the difference in phase angle between windings. The phase windings of a three phase transformer can be connected together internally in different configurations, depending on what characteristics are needed from the transformer. For example, in a three phase power system, it may be necessary to connect a three-wire (Delta) system to a four-wire (Star) system, or vice versa. Because of this, transformers are manufactured with a variety of winding configurations to meet these requirements. Different combinations of winding connections will result in different phase angles between the voltages on the windings. This limits the types of transformers that can be connected between two systems, because mismatching phase angles can result in circulating current and other system disturbances. The vector group provides a simple way of indicating how the internal connections of a particular transformer are arranged. The vector group is indicated by a code typically consisting of two or three letters, followed by one or two digits. The letters indicate the winding configuration as follows: • D (Delta winding): Each phase terminal connects to two windings, so the windings form a

triangular configuration with the terminals on the points of the triangle. Delta windings do not pass zero sequence currents and triplen (3rd, 9th, 12th etc) harmonic order currents. Delta windings are hence used to isolated primary systems from zero sequence and triplen harmonic currents in the secondary system.

• Y (Star winding): Also called a Wye winding. Each phase terminal connects to one end of a winding, and the other end of each winding connects to the other two at a central point, so that the configuration resembles a capital letter Y. The central/neutral point may or may not be connected outside of the transformer. This is usually indicated via the character “n”.

• Z (Zigzag winding): Also called an interconnected star winding. Basically similar to a star winding, but the windings are arranged so that the three legs are "bent" when the phase diagram is drawn. Zigzag wound transformers have special characteristics and are not commonly used where these characteristics are not needed.

• III (Independent windings): The three windings are not interconnected inside the transformer at all, and must be connected externally.

In the IEC vector group code, each letter stands for one set of windings. The primary (input) winding is designated with a capital letter, while the other winding or windings are designated with a lowercase letter. The digits following the letter codes indicate the difference in phase angle between the windings, in units of 30 degrees. For example, a transformer with a vector group of Dy1 has a Delta-connected primary winding and a Star-connected secondary winding. The phase angle of the secondary lags the primary by 30 degrees. Utilities standardise on the vector groups used in particular applications. As such the Network Planner will usually have little or no option as to which vector group should be applied. The vector group that needs to be used in a particular application is dictated by the following: • Technology of connecting systems:

o Three phase Delta systems have no neutral and can be connected to Delta or Star windings. In the case of Star windings the transformer neutral point floats or is connected to ground (possibly via an earthing impedance). As Eskom Distribution’s three phase HV and MV systems are Delta connected, the possible vector groups (ignoring phase angle options) for application with HV/HV, HV/MV and MV/MV three phase power transformers are Yy, Dd, Yd and Dy. Refer to table 6 for the standard Eskom Distribution major power transformers vector groups.

o Three phase Star systems have a neutral and can only be connected to Star windings. As Eskom Distribution’s three phase MV and LV systems are Delta and Star connected respectively, the possible vector groups (ignoring phase angle options) for application with



MV/LV three phase power transformers are Yy and Dy. Referring to section 5.1, the standard MV/LV three phase transformer vector group in Eskom Distribution is Dyn11.

• Isolation between primary and secondary systems: Delta windings isolate the primary system from zero sequence and triplen harmonic order currents circulating in the secondary system. Delta windings are more expensive to manufacture as compared to Star windings. Delta windings are hence used where the benefits of the associated isolation warrant the increased cost.

• Phase shift: Phase shift is important when paralleling sources. The phase-shifts of the sources should be the same. Transformers operated in parallel must have the same vector group.

4.4 Tap changer

Power transformers are usually fitted with a tap changer. One of the windings has multiple tapping leads, each one providing a different turns ratio between the primary and secondary windings. The tap changer is used to select one of these tapping leads. Each tap changer position selects a different tapping lead and hence different turns ratio. The voltage on the secondary of the transformer can be varied by changing the tap position. The tap changer can hence be used to compensate for the voltage drops in the primary system and across the transformer itself. In interconnected systems tap changer settings will also influence reactive power flow. There are two main types of tap changer: • Off Circuit Tap Switch (OCTS): An OCTS is a manual tap selector switch (see figure 5). The

transformer must be de-energised in order to change the tap position. The tap position can not be changed automatically or via remote control. The tap switch is a simple mechanical switch with no motor or diverter, and the tap position can usually be locked in place via a padlock. In some cases the tapings are connected to individual bushings on the exterior of the transformer, and the appropriate tap ratio is selected via the connection of jumpers to the appropriate bushings. OCTS tap changers are usually installed on MV/LV reticulation transformers, where the additional cost and maintenance of an OLTC tap changer can not be justified. In Eskom Distribution OCTS tap changers usually have a 2.5% or 3% step size and 5 tap positions providing a buck and boost range of ±5% or ±6%. An OCTS is also commonly referred to as a De-Energised Tap Switch (DETS).

• On Load Tap Changer (OLTC): An OLTC tap changer is a motorised tap changer fitted with a diverter such that the tap position can be changed with the transformer energised and supplying load. An OLTC tap changer is usually fitted with automatic voltage regulation relay whereby the secondary voltage is sampled and the tap position adjusted to keep the secondary voltage within specified limits. Alternatively the tap position can be changed via a remote control signal from a control centre. OLTC tap changers improve the voltage regulation and power flow control of the network, but are more costly as compared to OCTS tap changers. OLTC tap changers also require maintenance (maintenance intervals are dependant on the insulation medium used in the diverter (oil or vacuum) and frequency of tap changer operation). OLTC tap changers are usually only installed on major power transformers ≥5MVA. In Eskom Distribution OLTC tap changers usually have a 1.25% step size and 17 tap positions providing a 5% buck and 15% boost range. Refer to figure 14 for a picture of a HV/MV major power transformer fitted with an OLTC.

Figure 5: OCTS tap selector switch



OCTS or OLTC tap changers can be fitted to either the primary or secondary windings of power transformers. The location varies, but in general the tap changer tapings are located on the higher voltage winding where the load current is lower. 4.5 Transformer earthing

4.5.1 Earthing practices

This section is based on SCSASACB6 (Medium voltage system earthing practice) which should be consulted for additional information. Power Systems were initially commonly operated unearthed under the assumption that a lower rate of supply interruptions due to earth faults would occur. However it has long since been recognised that such systems are inherently earthed through the system capacitance to earth. “Unearthed” systems were susceptible to high transient overvoltages during earth faults and switching operations which in turn resulted in a high insulation failure rate on such systems. This led to the practice of intentionally earthing system neutrals with the following principal objectives in mind: • To stabilise the phase-to-earth voltages under earth fault conditions. • To limit transient over voltages. • To reduce arcing damage at the fault point. • To make possible the operation of protection equipment by allowing sufficient earth fault current

to flow to the point of intentional earthing. The following system earthing methods are currently adopted (see SCSASACB6 for additional information): • Effectively earthed: The term effectively earthed is used to define a system, or a point within a

system, at which the steady state phase-to-earth voltages will be limited to 1.4 per unit (approximately 80% of normal phase-to phase voltage) during an earth fault. By ensuring that system phase-to-earth voltages do not exceed 1.4 per unit, 80% surge arresters can be applied and correspondingly reduced insulation levels specified. Solidly earthed transformer star points will usually (but not always) result in an effectively earthed system.

• Non-effectively earthed: Non-effectively earthed describes a system, or a point within a system, at which the steady-state phase-to-earth voltages may rise above 1.4 per unit during an earth fault. In such systems it is necessary to apply surge arresters with a correspondingly higher voltage rating. It follows that the protective level will then be raised, requiring a higher Basic Insulation Level for system plant in order to maintain an adequate protective margin. The normal practice is to apply 100% arresters (i.e. rated to withstand overvoltages up to 1.73 UM for the duration of a fault) on non-effectively earthed systems. By installing an earthing impedance of sufficient magnitude the earth fault current is reduced and the system is non-effectively earthed.

• Reactively earthed: In many cases, the source transformer secondary winding is delta-connected and an NEC is necessary to provide a neutral point for earthing. Almost invariably, NEC’s have high values of X0 relative to X1 of the source, resulting in a ratio of X0/X1 in excess of 3 for the system, which is thus reactively earthed if an NER is not provided as well. As compared to resistively earthed systems, reactively earthed systems are more prone to transient over voltages following network switching and earth faults.

• Resistively earthed: Resistively earthed systems are usually non-effectively earthed as the resistance is inserted to reduce earth fault current magnitude. Resistance earthing can be effected by inserting a resistor in the earth connection to the MV neutral of each source transformer. Alternatively, when the source transformer MV winding does not have an earthed neutral, the resistor can be inserted in the neutral of a NEC. Resistively earthed systems have lower transient over voltages as compared to reactively earthed systems with similar maximum earth fault current levels.



Figure 6: NECR used to earth a Delta network

High Voltage and Extremely High Voltage systems are required to be effectively earthed to achieve acceptable limits of system-generated transient over voltages during earth faults. A primary consideration is the avoidance of the high additional insulation costs which would be necessary under conditions of higher phase-to-earth over voltages. The neutral terminals of star-connected transformer EHV and HV windings must be solidly connected to earth in order to provide an effectively earthed system, and also because, in most cases, such windings have fully graded insulation (there are exceptions to this requirement in respect of most 66 and 88 kV windings, which usually have partially graded insulation). On medium-voltage systems, the emphasis is placed more on reducing earth-fault-current magnitude for the safety of plant and personnel (rather than on the cost of insulation). This is achieved by the implementation of neutral earthing resistors (NER’s) on star-connected systems and of NEC/NER combinations on delta connected systems. The MV system is thereby non-effectively and resistively earthed. Appendix A illustrates the flow of earth fault currents for star, NEC and NEC/R earthing configurations. The application of resistance earthing rather than reactance earthing (NEC only on delta connected systems) avoids the generation of excessive over voltages as well as preventing high fault-current magnitudes.

Table 1: Effectively vs Resistively (non-effectively) earthed MV networks 1 2

Effectively earthed Resistively (non-effectively) earthed MV source star points solidly earthed, or earthed via

NEC MV source star point earthed via Resistor, or

earthed via NECR Rated voltage not to exceed 0.8Um Rated voltage of 1.0Um

Single phase fault level between 2kA and 10kA Single phase fault level between 300A and 900A High degree of earth fault damage Lesser degree

High earth fault step & touch potential Reduced High probability of inductive interference Lower Lower initial cost & higher life cycle cost Higher initial cost & lower life cycle cost

4.5.2 Transformer zero sequence impedances

The zero sequence impedance of a transformer installation is dependent on: • The transformer zero sequence impedance Z0. • Transformer star point earthing and NEC, NECR earthing. • Earthing impedances. In modern PSST software each of the above elements is modelled explicitly. By specifying the transformer zero sequence impedance and it’s earthing (with any associated impedances) the total zero sequence model of the entire transformer installation is simulated in the PSST.



In cases where test sheet data is not available, the assumptions below are commonly applied for transformer zero sequence impedance (these are zero sequence values for the transformers. Any grounding impedance must also be modelled in the PSST, and is entered separately): • Star/Delta and Delta Star: Z0 = 0.9Z1. • Star/Zig-zag: Z0 = 0.091Z1. • Star/Star with both star points earthed: Z0 = 0.85Z1. • Star/Star with only one star point earthed: Z0 = 10Z1. This is the “tank delta” effect whereby the

transformer tank provides a delta winding effect. It is important to note that with Star/Star transformers the transformer zero sequence impedance is dependent on the star point earthing. In all other cases the transformer zero sequence impedance is not dependent on transformer earthing. 4.6 Types of transformers

The main types of power transformer can be summarised as follows: • Auto-transformers: This type of winding is often used when the turns ratio is ≤3. An auto-

transformer is essentially a Star-Star transformer with a common star point. In an auto-transformer a portion of the same winding effectively acts as part of both the primary and secondary winding. Because it requires both fewer windings and a smaller core, an autotransformer for power applications is typically lighter and less costly than a two-winding transformer, up to a voltage ratio of about 3:1 - beyond that range a two-winding transformer is usually more economical. In three phase power transmission applications, autotransformers have the limitations of not suppressing harmonic currents and as acting as another source of ground fault currents. A large three-phase autotransformer may have a tertiary delta winding to absorb some harmonic currents (see three-winding transformers).

• Two-winding transformers: A two-winding transformer consists of two separate, but magnetically coupled, windings. Each winding can have a different vector group. In Eskom Distribution HV/MV and MV/LV power transformers are two winding transformers (YNd1, Dyn11 or YNyn0).

• Three-winding transformers: A three-winding transformer usually consists of a primary to secondary auto-transformer winding, and a delta tertiary winding. Eskom’s EHV/HV transformers are three-winding auto-transformers (YnA0d1).

• Voltage regulators: Voltage regulators have the same primary and secondary voltage ratings, are used to regulate the load side voltage and are usually auto-transformers without a tertiary winding. See DGL 34-539 Network Planning guideline for MV step-voltage regulators for additional information on voltage regulators.

• Phase shifting transformers: A phase shifting transformer has an OLTC tap changer that mixes phases in specific quantities such that the primary and secondary voltages are vector shifted. The magnitude of the vector shift is dependent on the tap position. Phasing shifting transformers are utilised to control power flow in interconnected systems. A phasing shifting transformer can also transformer between voltage levels and provide both voltage and phase angle control. Referring to figure 7, phasing shifting is achieved via the mixing of voltages from different phases. Note that Eskom do not yet have an phasing shifting transformers, but a pilot installation is underway.

Figure 7: Phasing shifting transformer principle of operation



4.7 Loading thermal limits

4.7.1 Effect of over loading

Power transformers operating at full load or near full load transform a large amount of electric power that generates large amounts of heat. Power transformers require some type of cooling to mitigate the consequences of excessive heat. A fluid such as oil is used as a cooling medium to remove excess heat from the transformer core and windings. The transformer cores and windings are designed to permit the flow of the oil around and through all coils. This provides a method to remove heat generated internally. The oil is then typically circulated through air-cooled radiators. To increase radiator cooling capacity, fans may be used to increase air flow across the radiator. There are two main sources of heating in power transformers: • Current flow through the windings results in I2R load losses. Increased current results in

increased load losses, proportional to the load current squared. • Hysteresis and eddy current no-load losses due to core magnitisation. Increased applied voltage

results in increased no-load losses, proportional to the applied voltage squared. The heating increases the temperature of the windings and insulating oil. The maximum temperature occurs within the windings and is referred to as the hot spot temperature. The oil temperature within the tank is a maximum at the top of the tank, and is referred to as the top oil temperature. Thermal equilibrium occurs when the rate of energy dissipation within the transformer is equal to the rate of energy dissipation to the external environment. The maximum hotspot and top oil temperatures are hence dependent on the ambient temperature and effectiveness of the heat transfer to the local environment. The following risks are associated with transformer overload: • Pressure build up as the top oil temperature increases beyond the design level, which leads to oil

leakage and eventually failure if the transformer does not have a pressure release valve. • Damage to the “accessories” such as the tap changer and bushings, which are not designed for

operation beyond certain current levels (typically 150% of rated current). • Paper degradation (paper is used to insulate each turn within the windings), due to continued

operation at hot spot temperatures in excess of 98°C. Transformer paper life and hence transformer life is halved for every 6 degrees the transformer hot spot temperature exceeds 98°C. As the insulation paper ages its mechanical strength reduces. Failure occurs when the paper can no longer provide adequate insulation. This may occur following a through fault which mechanically stresses the windings, causing them to collapse resulting in inter-turn faults.

4.7.2 Cooling methods

As the maximum loading limit of a transformer is dependent in part on the top oil and hot spot temperatures, the maximum loading limit is also dependent on the type and effectiveness of cooling. Improved cooling increases the maximum loading level. Power transformers have a four letter “code” describing the type of insulation liquid and cooling. First letter: Internal cooling medium in contact with the windings: O Mineral oil or synthetic insulating liquid with fire point ≤ 300°C; K Insulating liquid with fire point > 300oC; L Insulating liquid with no measurable fire point. Second letter: Circulation mechanism for internal cooling medium: N Natural thermosiphon flow through cooling equipment and in windings; F Forced circulation through cooling equipment, thermosiphon flow in windings;



D Forced circulation through cooling equipment, directed from the cooling equipment into at least the main windings Third letter: External cooling medium: A Air; W Water. Fourth letter: Circulation mechanism for external cooling medium: N Natural convection; F Forced circulation (fans, pumps). Example: ONAN refers to a transformer where the internal and external cooling mediums are oil and air respectively. In both cases the circulation of the cooling medium is by natural convection. If fans are fitted to the external cooling fins this transformer would be ONAF. 4.7.3 Ambient temperature and load profiles

A standard transformer is designed to withstand continuously rated load at rated ambient temperature for a period of 35 years. In reality transformers are often subjected to cyclic loads and temperatures. Major power transformers up to 132kV in the rating range of 2.5 to 80MVA are governed by the specification SCSSCAAD3. This specification requires that all major power transformers have overload capabilities in accordance with IEC60354. IEC60354 recognises that thermal loading on transformers is cyclic, whether due to cyclic variations in the load or hourly variations in the ambient temperature. The result is a temperature profile, which operates below the transformer rated temperature during off peak conditions and close to or above rated temperatures during peak conditions. IEC60354 provides guidelines for capitalising on periods of low load to allow the transformer to be “overloaded” during periods of high demand, without affecting the overall lifespan of the transformer insulation. Consider the following simple example of a 10MVA transformer subjected to a residential load on a typical winter’s day (figure 8).

Typical w inter load and ambient temperature for Johannesburg

0

0.2

0.4

0.6

0.8

1

1.2

00:0

0

02:0

0

04:0

0

06:0

0

08:0

0

10:0

0

12:0

0

14:0

0

16:0

0

18:0

0

20:0

0

22:0

0

Time of day

PU

0

5

10

15

20

25

Deg

.C Load

Temperature

Figure 8: Load profile and ambient temperature

The hot spot temperature, top oil temperature and cumulative loss of life for the above loading are shown in figures 9 and 10 respectively.



Figure 9: Top oil and winding temperatures

Figure 10: Cumulative loss of life

Considering that the maximum allowable loss of life per day is 0.0079% (this results in a 35 year lifespan), one can see that this transformer is under loaded. Increasing the loading until either the hot spot, top oil or loss of life limit is reached one obtains a maximum loading of 146%. This means that the transformer could be loaded to a maximum of 146% of the nameplate rating, and the insulation would still last for 35 years. The maximum loading is dependent on the load profile, ambient temperatures and target lifespan. Peaky loads result in increased loading limits as the transformer oil and winding temperature time constants are such that the oil and winding temperatures lag the loading, and the steady state oil and winding temperatures are not reached (the load drops off before the steady state oil and winding temperatures are reached). The overload limits can be calculated with software such as PTLoad. 4.7.4 Increased ratings

The maximum loading limit of a power transformer can be increased through one or a combination of the following: • Allowances for ambient temperature and load profile: As discussed in the previous section, actual

ambient temperatures and load profiles for a specific installation may result in increased loading levels for the design lifespan. These allowances typically result in a 10% to 30% increase in maximum loading.

• Reduced expected lifespan: Reducing the expected lifespan (to below the design value) increases maximum loading levels. This may be acceptable during contingencies when this



increased rate of aging during the contingency may not be significant if the duration of the contingency is relatively small. As a result utilities generally allow additional overloading during contingencies.

• Improved cooling: The installation of fans and/or oil pumps improves cooling resulting in increased ratings for the same rate of aging.

It should be noted that transformer losses, and hence loading limits, are also dependent on tap changer position, applied voltage magnitude and voltage and current harmonic distortion levels. Transformer loading is usually assessed as a percentage of rated nameplate current. This implies that if the primary voltage is less than the nominal primary voltage, the primary current will be greater than rated primary current in order to supply rated apparent power. Planners need to be aware of this as a transformer may start to exceed rated primary current even if the apparent power is less than rated apparent power. As load current causes the majority of the losses, overload reporting and assessment should be based on current and not apparent power. 4.7.5 Thermal stickers (reticulation transformers)

Reticulation transformers are not specifically protected against overloading resulting in these units failing before the overload is detected. The application of disposable thermal “stickers” can be used to detect overloading of transformers up to 2.5 MVA. Disposable thermal stickers consist of temperature sensitive cells calibrated to change colour at distinct temperatures. The temperature sensitive cells are protected in plastic and fixed on a magnetic strip. An attachment device is provided to allow installation onto a transformer with the aid of an operating stick. The bare side of the magnetic strip can attach to a transformers main tank. The sticker is installed near the top of the tank (see figure 11) and changes colour if the top oil temperature exceeds the temperature change colour of the sticker (selected based on the recommended maximum top oil temperature, which is related to the hotspot temperature for a specific load profile). Via a visual inspection of transformers operating staff can identify overloaded units.

Figure 11: Thermal loading “stickers” 4.8 Paralleling transformers

When paralleling transformers the following needs to be considered: • Voltages and vector group: The transfer vector group and winding voltages (turns ratio) need to

be the same. As discussed later in this section, small differences in turns ratio can be tolerated with modern OLTC tap change control schemes.



• Impedance: Transformer internal voltage drop magnitude is dependent on the transformer series impedance. Differences in per-unit impedance (expressed on the transformer rated power) between paralleled transformers results in a voltage differential between transformers when supplying load current, which in turn “drives” a circulating current between the paralleled transformers. This circulating current increases the loading (and hence also load losses) of the paralleled transformers, and can result in overloading. The magnitude of the circulating current is dependent on the magnitude of the load current supplied by the paralleled transformers.

• Tap ratios: Differences in tap ratio in the various tap positions results in a voltage differential between paralleled transformers. As with differences in impedance, this voltage differential results in a circulating current which increases losses and can result in overloading. The magnitude of the circulating current is not load dependent (unlike circulating current due to impedance imbalance).

• Power rating: Transformers of different power ratings can be paralleled. Load sharing between transformers is dependent on transformer impedance and tap ratio matching. In cases where per-unit impedances and tap ratios are not the same, the per-unit loadings will differ e.g. if a 10MVA and 20MVA transformer are paralleled and have different impedances and/or tap ratios, load will not be proportionally shared based on their power ratings and one transformer may overload well before the other e.g. if the total load supplied is 30MVA, the 10MVA and 20MVA transformers could, for the purposes of this example, supply 12MVA and 18MVA respectively.

Before the advent of modern circulating current OLTC tap change controllers, major power transformers operated in parallel utilised a “Master-Follower” tap change control scheme. Essentially all paralleled transformer OLTC tap changers were synchronised so that all transformers were in the same tap position. Any differences in transformer impedance and tapping ratios resulted in a voltage differential between transformers, and hence a circulating current would flow. As such only transformers with closely matched impedances and tapping ratios could be operated in parallel. Modern tap change control schemes incorporate circulating current control whereby the tap position of each transformer is adjusted such that control objectives (e.g. a certain secondary voltage) are achieved whilst also minimising circulating current flow. As a result transformers with different impedances and tapping ratios (within reason) can be paralleled (note that load sharing may not be optimal and the effective capacity of the installation may be significantly less than the sum of the ratings of individual transformers). These modern control schemes also allow transformers in different substations to be paralleled via their primary and secondary networks i.e. the paralleled transformers can be geographically separated. 4.9 Fault levels and through faults

Distribution power transformers are generally utilised to step-down voltage. Although the impedance of the transformer reduces the MVA fault level, the fault level current (usually expressed in kA) increases proportional to the turns ratio. The fault level current on the secondary of a transformer is dependent on the primary fault level, transformer turns ratio, rating and impedance. Switchgear is rated for a maximum fault current breaking capacity. Lines and cables have a maximum fault current rating, which is the current they can conduct before the associated increase in temperature results in permanent damage. Fault levels require careful consideration when sizing transformer installations: • The fault level ratings of equipment connected to the transformers should not be exceeded. • Transformers conduct “through fault” current for faults in the network connected to the

transformer. Through faults place mechanical stress on the transformer winding. An excessive number of through faults of sufficient magnitude will result in premature transformer failure. Networks should be planned to minimise the number of high current through faults (faults typically within a few kms from the substation) experienced by transformers.

See section 4.11 for information on how the numbers and ratings of transformers affects fault levels and through fault exposure.



4.10 Mobile transformers/substations

Figure 12: Mobile HV/MV transformer

A mobile substation (figure 12) consists of a transformer and associated protection and switchgear mounted on a trailer. A mobile substation will typically be used for the following applications: • As an emergency spare in the event of a transformer faulting. • For routine maintenance of single-transformer substations. • Urgent customer supply (i.e. ahead of Eskom’s construction schedule if applicable). • During refurbishment/upgrading of a substation, when the entire substation or a part of it must be

taken out of service for a period of time. • During the upgrading of MV voltages e.g. changing from 11kV to 22kV. 4.11 Transformer rating and redundancy

Utilities standardise on a set of standard power transformer ratings. Network Planners need to specify the number and rating of power transformers to provide adequate capacity and redundancy.

Fewer transformers of larger rating offer the following advantages and disadvantages as compared to more transformers of smaller rating:

Advantages

• Take up less space (few transformer bays are required). • Reduced maintenance costs. • Capital cost per MVA of larger transformers is less than smaller transformers. • Reduced number of transformer bays results in further cost savings due to less primary plant.

Disadvantages

• While fewer larger transformers will fail less frequently (less transformers to fault), the impact of a failure may be more significant (system versus component reliability).

• In order to parallel the larger units to provide required reliability levels, high impedance units or fault limiting reactors may be required to restrict fault levels to acceptable levels.

• Due to the increased currents MV switchgear costs may increase. • Depending on the busbar configuration larger transformers may experience increased frequency

of through faults (larger network supplied as compared with smaller transformer).



5. Eskom power transformer specifications

5.1 Reticulation transformers (MV/LV and SWER isolation)

Figure 13: Pole-mounted MV/LV reticulation transformer The important reticulation transformer characteristics of interest to Network Planners are as follows (DISSCAAM7, DISSCAAY1, DISSCABG7, 34-342, 34-343, 34-344, 34-345 & 34-346):

• Referring to table 2, rated LV voltage is 240V single phase and 415V three phase. Rated MV

voltages are 11kV, 22kV and 33kV. The rated SWER voltage is 19kV. • MV/LV pole and platform mounted transformer power ratings range from 16kVA to 500kVA. The

largest single phase rating is 16kVA. The largest dual phase rating is 64kVA. Installations requiring capacity greater than the standard sizes are catered for by installing standard transformers in parallel. Transformers ≤100kVA can be pole mounted, and >100kVA platform mounted.

• Ground mounted three phase transformer sizes range from 100 to 1000kVA. • Mini-substation transformer sizes range from 200 to 1000kVA. • Three phase and dual phase transformers have a tapping range of -6%, -3%, 0%, +3%, +6%,

achieved by means of an off-circuit tapping switch. The relationship between tap position and primary and secondary voltages is summarised in table 3.

• Single-phase transformers have a tapping range of 0%, +3%, +6%, achieved by means of external LV tappings. The relationship between external tapping and primary and secondary voltages is summarised in table 4.

• SWER isolation transformers have a tapping range of -5%, -2.5%, 0%, +2.5%, +5%, achieved by means of an off-circuit tapping switch. The relationship between tap position and primary and secondary voltages is summarised in table 5.

• Insulation and cooling is ONAN. • Three phase MV/LV transformer vector group is Dyn11.



Table 2: Standard technologies, mounting methods, voltages, power ratings and tapping ranges

1 2 2 3 4 5

Technology Mounting Rated primary voltage

Rated no-load secondary voltage Rated power Tapping range

Phase to phase / Single phase Pole 11kV, 22kV, 33kV 240V 16kVA 0%, +3%, +6%

Phase to phase / Dual phase Pole 11kV, 22kV, 33kV 480/240V (±240V) 32 & 64kVA -6%, -3%, 0%, +3%, +6%

Three phase / Three phase

Pole and platform 11kV, 22kV, 33kV 415/240V 25, 50, 100, 200,

315 & 500kVA -6%, -3%, 0%, +3%, +6%

Three phase / Three phase Ground 11kV, 22kV 415/240V 100, 200, 315,

500 & 1000kVA -6%, -3%, 0%, +3%, +6%

Three phase / Three phase Minisub 11kV, 22kV 415/240V 200, 315, 500 &

1000kVA -6%, -3%, 0%, +3%, +6%

Phase to phase / SWER

Pole and platform 11kV, 22kV, 33kV 19kV 50, 100, 200 &

400kVA -5%, -2.5%, 0%, +2.5%, +3%

SWER / Single phase Pole 19kV 240V 16kVA 0%, +3%, +6%

SWER / Dual phase Pole 19kV 480/240V (±240V) 32 & 64kVA -6%, -3%, 0%, +3%, +6%

Table 3: Three phase and dual phase transformer off-circuit tapping switch voltage ratios

1 2 3 Tap position number Primary voltage % No-load secondary voltage %

1 106% 100% 2 103% 100% 3 100% 100% 4 97% 100% 5 94% 100%

Table 4: Single phase external tapping voltage ratios

1 2 3 External tapping Primary voltage % No-load secondary voltage %

A1-A2 100% 100% A1-A3 97% 100% A1-A4 94% 100%

Table 5: SWER isolation transformer off-circuit tapping switch voltage ratios 1 2 3

Tap position number Primary voltage % No-load secondary voltage % 1 105% 100% 2 102.5% 100% 3 100% 100% 4 97.5% 100% 5 95% 100%

It is important to note that even though the standard LV service voltage is 400/230V, MV/LV transformers are rated 415/240V. Historically rated LV voltages have varied with LV service voltage standards. As a result MV/LV transformers with rated voltages of 380/220V, 400/230V and 420/242V can be found in existing networks. Refer to 34-542 (Distribution voltage regulation and apportionment limits) for additional detail. Also note that other non-standard sizes have been installed (e.g. 800, 1000, 1250kVA). Note that in order to standardise the MV/LV transformer specification within the South African EDI, it is proposed that Eskom change to the 420/240V (2.5% step size) specification for all new transformers. Should this occur this guideline and its associated references will need to be updated accordingly.



5.2 Major power transformers (HV/HV, HV/MV and MV/MV)

Figure 14: HV/MV major power OLTC transformer

The following specifications from DISSCAAD3 (Specification for large power transformers up to 132 kV in the rating range of 1.25 MVA to 160 MVA) are applicable to this guideline: • Table 6 summarises the standard transformer voltage ratings, power ratings, impedances and

vector groups. o To cater for increased load densities, reduce stock holding and improve inter-changeability

between transformers a sub-set of the standard power ratings are preferred ratings (ratings in bold). Network Planners may not deviate from the standard power ratings, and should (where possible) utilise preferred power ratings.

o Non-preferred standard ratings may need to be used in cases where space or access prevents the use of the smallest preferred size.

o Sisonke will focus on preferred sizes. Non-preferred standard sizes can still be ordered but lead times may be longer.

o Strategic stock will still need to cater for non-preferred standard sizes. o Existing non-preferred standard sizes that are replaced with larger preferred sizes can be

recycled into networks where they provide sufficient capacity. o OLTC tap changers should be installed for all ratings ≥5MVA. o All new transformers are specified for coastal conditions i.e. zink metal sprayed with

31mm/kV bushings. • The general operating conditions for transformer thermal rating are:

o Out-of-doors. o At an altitude above sea level up to 1800m. o At ambient air temperatures.

Maximum 40ºC. Daily average 35ºC. Yearly average 25ºC. Minimum -10ºC.

o Average humidity: 30% to 90%. o Sinusoidal supply voltage wave shape at 50Hz. o Symmetrical three-phase supply voltages (negative and zero phase sequence voltages less

than 2%).

OLTC tap changer



o Life expectancy at rated conditions shall be at least 35 years. • The power rating is a continuous power rating (100% load factor) and applies to the entire tapping

range i.e. each tap must be able to supply rated power. Overloading capabilities shall be in accordance with IEC 60076-7 Table 4. The default winding temperature alarm and trip settings are: Alarm 110°C Trip 120°C.

• Both OLTC and OCTS tap changers are supported: o On-load regulated transformers have on-load taps from +5% to -15% of the HV voltage in 16

equal steps of 1.25% each. o When an off-circuit tap switch is specified, the range is +5% to -5 % of the HV voltage in 4

steps of 2.5% each. o In order to support stock keeping and inter-changeability OLTC tap changers are usually

specified for all major power transformers ≥5MVA. • Cooling methods are as follows:

o Transformers with a maximum rating of 20 MVA: ONAN cooling. o Auto-transformers with a maximum rating of 40 MVA: ONAN or ONAN/ONAF cooling. o Other transformers: ONAN/ONAF cooling.

• The standard vector groups are as follows: o HV/HV three winding auto-transformer: YnA0d1. o HV/MV two winding: YNd1. o MV/MV two winding: YNyn0.

Note that these specifications are applicable to new major power transformers. The specifications of existing transformers could vary significantly. Non-standard vector groups (such as Yy10 in Cape Town) should be phased out as opportunities arise. It is understood that this may only be practical to achieve in the longer term. Also note that Eskom used to order sub-transmission transformers with a vector group Dy11, but changed to YNd1 as HV Delta windings are considerably more expensive than Star windings (Delta windings can’t have partially graded insulation and the tap changer must be rated for the full system voltage). Table 6: Standard major power transformer voltages, ratings, impedances and vector groups

(Ratings marked in bold are preferred ratings) 1 2 3 4 5 6 7 8 9 10 11 12 13 14

Nominal voltage [kV] Standard power rating [MVA] Prim Sec Tert

Imp type 160 80 40 20 10 5 2.5 1.25

Nominal imp [%]

Vector Group

132 88 22 STD 160/20 80/10 40/10 20/5 9 YnA0d1 132 66 22 STD 160/20 80/10 40/10 20/5 10 YnA0d1 132 44 22 STD 80/10 40/10 20/5 11 YnA0d1 88 44 22 STD 80/10 40/10 20/5 9 YnA0d1

132 11 HIGH X 22 YNd1 132 6.6 HIGH X 22 YNd1 88 11 HIGH X 22 YNd1 88 6.6 HIGH X 22 YNd1 66 6.6 HIGH X 22 YNd1 44 6.6 HIGH X 22 YNd1

132 33 STD X X X X 10-11 YNd1 132 22 STD X X X 10-11 YNd1 132 11 STD X X X 10-11 YNd1 132 6.6 STD X X 10-11 YNd1 88 44 STD X X 11 YNd1 88 33 STD X X X X 10-11 YNd1 88 22 STD X X X X 10-11 YNd1 88 11 STD X X X X 10-11 YNd1 88 6.6 STD X X X 10-11 YNd1 66 22 STD X X X X 10-11 YNd1 66 11 STD X X X X 10-11 YNd1 66 6.6 STD X X X 10-11 YNd1 44 22 STD X X X 10-11 YNd1 44 11 STD X X X X 10-11 YNd1 44 6.6 STD X X X 10 YNd1 33 22 STD X X X X 6-8 YNyn0 33 11 STD X X X X X 6-8 YNyn0 33 6.6 STD X X X X 6-8 YNyn0 22 11 STD X X X X X 6-8 YNyn0 22 6.6 STD X X X X 6-8 YNyn0



5.3 Mobile substations (HV/MV, MV/MV and MV/LV)

The specification for HV/MV mobile substations (SCSSCAAU3 Specification for 20MVA, multi-ratio, mobile substations) is summarised as follows: • 20MVA HV/MV multi-ratio, outdoor, mobile substation. The substation consists of a main

transformer, NEC/NER/auxiliary transformer, HV and MV circuit-breakers, HV isolator, surge arresters, instrumentation transformers, protection, metering, DC and telecommunication equipment (all mounted on a trailer(s)).

• Three types are catered for: o Type A: 132 or 66kV to 22 or 11kV, 20MVA, YNd1, OLTC o Type B: 132 or 88kV to 22 or 11kV, 20MVA, YNd1, OLTC o Type C: 132 or 88kV to 33 or 22kV, 20MVA, YNd1, OLTC

• In order to reduce the size and weight of the transformer it has OFAF cooling. • The HV breaker is connected to the HV busbar (could be directly off an HV line) via overhead

jumpers. • The MV breaker is connected to the MV busbar (could be directly onto a MV line or cable) via

single core cables. The specification for MV/MV mobile substations (ISSCAAU4 Specification for medium voltage 5-10MVA single and multi-ratio mobile substations) is summarised as follows: • ≤10MVA MV/MV multi-ratio, outdoor, mobile substation. The substation consists of a main

transformer, auxiliary transformer, primary and secondary circuit breakers, surge arresters, instrumentation transformers, protection, metering, D.C and telecommunication equipment (all mounted on a trailer).

• Three types are catered for: o Type A: 33 or 22kV to 11kV, 5 MVA, YNyn0, OCTS or OLTC o Type B: 22kV to 11kV, 5MVA, YNyn0, OCTS or OLTC o Type C: 33 or 22kV to 22 or 11kV, 10MVA, YNyn0, OCTS or OLTC

• Note that either OLTC or OCTS can be specified. • In order to reduce the size and weight of the transformer it has OFAF cooling. • A NER is provided to limit the single phase fault level to 300Amps (it has a variable impedance to

cater for the different voltage levels). The NER is connected to either the primary or secondary winding star point (depending on whether the substation is being used in a step-up or step-down application). Note that the load side star point winding must be earthed via the NER in order to provide a zero sequence return path for earth fault current.

• The MV breakers are connected to the MV busbars (could be directly onto a MV line or cable) via three core cables.

All new single transformer HV/MV and MV/MV substations must make provision for the connection of mobile substations. The specification for MV/LV mobile transformers (DISSCAAL1 100kVA to 500kVA 11 or 22kV/415V mobile reticulation transformer) is summarised as follows: • It consists of a transformer with MV and LV cable boxes, a metering kiosk and a telescopic pole

structure for connection to the MV network. • The primary MV voltage is 11kV or 22kV, selectable via a dual ratio switch. • The secondary LV voltage is 415/240V. Tapping step size and range are as for the standard

MV/LV transformer i.e. OCTS -6%, -3%, 0%, +3%, +6%. • Standard ratings are 100, 200, 315 or 500kVA. • MV and LV connections are made via cable.



5.4 Neutral Earthing Compensators with Resistors

Although an NECR is not a traditional power transformer in the sense that it is not used to supply customers, it is a critical part of the power transformer earthing configuration, and a summary of the key specifications is hence included in this guideline. The following key specifications from DISSCAAD1 (Specification for combined three-phase neutral electromagnetic couplers (NECs) with neutral earthing resistors (NERs) and auxiliary transformers) are important to note: • The NEC, neutral earthing resistor and auxiliary LV supply power transformer are all housed in

the same tank. The NECR has an auxiliary transformer (100kVA three phase), which is used for the substation LV supply.

• Nominal voltages include 6.6, 11, 22, 33 and 44kV. • Impedances have been chosen to limit the single phase fault current to 300Amps (at nominal

voltage for up to 10 seconds). The continuous current rating is 10amps. • For 11 and 22kV cable networks an 800amp current limiting NECR is also catered for. • For the earthing of 33kV networks supplying directly connected SWER, a 1000Amp (10 second

rating) NECR is provided for in DISSCABR0. This NECR has a continual current rating of 35Amps.

The NECR is directly connected to the secondary MV winding of the power transformer (directly off the MV winding terminals before the MV breaker) so that it is always in circuit if the power transformer MV breaker is closed. This ensures that there is always a zero sequence path for single phase to earth fault current such that earth faults can be detected. This is critical for both public and operator safety.

6. Eskom power transformer application standards and guidelines

6.1 Protection

Referring to figure 15, transformer failure can result in the insulating oil catching fire, resulting in considerable damage to the transformer and surrounding equipment. The appropriate level of transformer protection depends on the risk and consequence of transformer failure relative to the cost of the protection. Certain forms of protection enable early identification of certain faults such that preventative action can be taken before the fault develops to the extent that extensive damage is caused.

Figure 15: Transformer failure resulting in fire The major power transformer protection philosophy is documented in SCSAGAAG0 (Transformer protection philosophy). The protection requirements are summarised as follows: • Surge arrestors installed on all windings. • Buchholz and pressure relief.



• Winding and top oil temperatures. Default top oil alarm and trip temperature settings are 95°C and 105°C respectively. Default winding alarm and trip temperature settings are 110°C and 120°C respectively.

• HV and LV over current, earth fault and restricted earth fault protection. Over current is usually set to trip at 130% of transformer nameplate rating.

• HV breaker fail. • Sustained fault timer. • For ratings >10MVA there is a further requirement for biased differential protection. With reticulation transformers the cost of protection (apart from surge arresters) can not be justified, and the reticulation transformer protection philosophy is to run to failure. MV fuses are usually installed in the local isolation links. These fuses only operate once a fault has developed to the extent that the melting characteristic of the fuse is exceeded due to fault current. The fuses do not prevent the fault from causing critical damage, but rather isolate the transformer from the network so that the number of transformer faults resulting in MV feeder protection operation (and lock-out) is reduced. Reticulation transformer LV fuse and breaker ratings may offer very limited transformer overload protection, especially where a transformer supplies several LV feeders. Furthermore no transformer LV metering or load measurement device is usually installed. Spot load measurements may be useful in identifying overloaded transformers, but the time of peak loading and stochastic nature of the load make such measurements difficult. A thermal loading sticker can be used to detect reticulation transformer overloads. The thermal sticker is attached to the transformer tank, and changes colour when the tank temperature (which is close to the oil temperature) reaches a certain limit. An operator is required to periodically inspect the stickers. 6.2 Earthing

Sub-transmission systems are effectively earthed by solidly earthing transformer HV winding star points and auto-transformer star points. If a HV/MV Star/Delta transformer HV winding has partially graded insulation then the HV star point can be earthed via a surge arrestor to reduce the HV earth fault level and simplify earth fault protection coordination. Transformers with fully graded HV windings must have their HV windings solidly earthed. As per SCSASACB6 (Medium voltage system earthing practice), MV networks should be resistively earthed: • Transformers with MV vector group Star should be earthed via an NER (installed in the star point)

or NEC/R. A NEC/R may be installed if an auxiliary supply is required. • Transformers with MV vector group Delta should be earthed via an NEC/R. • The NER or NEC/R impedance (and hence maximum earth fault current) is dependent on the

type of MV network: o Rural: Maximum earth fault current 300/360amps. o Urban: Maximum earth fault current 800/970amps.

Note that Star/Star transformers (e.g. 33/11kV and 22/11kV) can be earthed on their secondary winding Star points (preferably via an NER). The HV winding star point is unearthed so that secondary earth faults do not result in earth fault current flow in the primary system. The tank-delta effect provides a zero sequence path for secondary earth fault current. This form of earthing is usually only performed for satellite type substations (especially 22/11kV substations). For 33/11kV transformers, and 22/11kV transformers >5MVA, earthing should preferably be performed via a NEC/R. Reticulation MV/LV transformer LV neutral points are solidly earthed. Primary MV delta and phase to phase windings are unearthed. SWER transformers have their 19kV SWER winding solidly earthed. 6.3 Loading

The procedure to be followed by Network Planners for the operation of major power transformers above nameplate rating is specified in SCSAGAAT4 (transformer loading guidelines). This procedure is applicable for the planned operation of major power transformers above nameplate rating for normal



network configuration i.e. the Network Planner is planning to operate the major power transformer at above it’s nameplate rating for the normal (non-contingency) network configuration. Network Planners must not plan to load major power transformers above nameplate rating for normal network configuration. The application of SCSAGAAT4 is hence only supported in extreme cases where project lead times can not be met. Emergency overload ratings (with allowance for ambient temperature and load profile) are provided in annex B (table B.1). These overload ratings should be utilised as emergency ratings for application with contingency studies.

7. Data required for Power System Analysis

Transformers are manufactured according to international and utility specifications. Transformers manufactured to the same specifications have similar impedances, losses etc. As such standard type data can be utilised for power transformer modelling. By specifying a set of key parameters that adequately describe the transformer, a type library linkage can be made such that standard values for other (non-key) parameters can be obtained. Where actual values (for a particular transformer) differ from the standard values, actual values can be specified. The specification of actual values is usually only required for certain attributes for major power transformers, and specifically positive and zero sequence impedances. Eskom Distribution has established a Master Type Library (MTL). The MTL contains standard transformer parameters for the vast majority of transformers utilised in Eskom Distribution. The MTL provides a standardised set of transformer parameters for all subscribing systems such as ReticMaster and PowerFactory. The data libraries in ReticMaster and PowerFactory should be referenced to view typical values. The following should be noted: • The MTL values are typical values. Actual values may vary slightly from standard values.

Standard values are acceptable for most power system studies. Standard values must be applied for future equipment where actual value information is not yet available.

• The MTL only contains standard values for equipment. There are additional installation parameters (e.g. earthing configurations, voltage control settings etc) that vary between installations of the same type of equipment. These parameters are not specified by the MTL and need to be defined by the Network Planner.

• The MTL only contains transformer and tap changer parameters as are required for normal load-flow and fault level studies. Additional parameters may be required for specialist studies such as Ferro resonance analysis.

• Reactive impedances are specified at the system frequency of 50Hz. For harmonic studies, packages such as PowerFactory adjust these impedances at different harmonic frequencies.

• Some older simulation packages, such as PSSE, required impedances to be entered in per unit on a system MVA base. The values stored in the MTL are physical impedances (ohms) and per unit impedances on the transformer rated power. Conversion to other units (or system power base) can be performed to meet the requirements of individual software packages.

• As the same specification tap changer can be utilised with different power transformers, the MTL has separate type data for tap changers and transformers.

Annex C contains details of the transformer and tap changer attribute data required for PSA, including which parameters can have standard values applied. This data model has been applied within SmallWorld. SmallWorld integration with ReticMaster and PowerFactory (in the near future) automatically converts this data into the specific formats required by ReticMaster and PowerFactory.



8. Application guideline

8.1 Reticulation transformers (MV/LV and SWER isolation)

As a general philosophy Eskom Distribution does not provide redundant MV/LV transformation. Furthermore all LV networks are operated as radial systems with no interconnection between LV networks. The equipment supplied by the reticulation transformer must be adequately rated for the LV fault level. This is enforced via appropriate LV design, which is the responsibility of Project Engineering. When planning new reticulation transformers (or upgrades to existing reticulation transformers) the Network Planner needs to ensure that the appropriate technology (SWER, single phase, dual phase or three phase) is applied and that thermal loading limits are not exceeded. Network Planners should not plan to exceed reticulation transformer nameplate ratings, except for reticulation transformers supply electrification consumers. For electrification additional overloading is allowed, typically up to 130% of the nameplate rating. These additional overloading limits are specified in Electrification Technical Bulletins (such as TB02-31), and should be referenced. Table 7 contains the scope to be provided by the Network Planner for a new MV/LV or SWER isolation transformer (or replacement of an old transformer with a new one).

Table 7: Reticulation transformer data to be specified by the Network Planner 1 2

Transformer parameter Description Rated Power Standard power rating e.g. 16, 32, 50, 100kVA etc Nominal Primary Voltage Primary MV system nominal voltage e.g. 11kV, 22kV or 19kV Secondary Technology SWER isolation (source), Single Phase, Dual Phase or Three Phase

Note: • The transformer will be included in a project, which will contain information on e.g. NDP

references, required completion dates, costs etc. The table only focuses on the reticulation transformer itself.

• The vector group and secondary voltage do not need to be specified as they are dictated by the transformer Technology and transformer specifications.

• Primary windings are unearthed, and secondary windings are solidly earthed. 8.2 Major power transformers (HV/HV, HV/MV and MV/MV)

When selecting a major power transformer for a specific application the following minimum requirements must be met by the Network Planner: • Loading limits: Taking into consideration expected project lead times and optimistic load

forecast scenarios the maximum loading should not exceed normal or nameplate ratings. PT Load software can be used to assess the capacity of a transformer, taking into account load profiles, fans, ambient temperature etc. The use of PT Load to allow transformer loading in excess of the nameplate rating should only be used as an emergency measure and should not be adopted as a planning philosophy. In sizing new transformers any overload capability is not used to cater for future forecasted load e.g. if 12MVA needs to be supplied the Network Planning must not utilise a 10MVA transformer with a 20% overload capability. Where ambient temperatures are abnormally high or the primary voltage is less than 95% the planner must take into consideration any de-rating requirements. The Eskom Distribution transformer loading guide SCSASAAT4 should be used to evaluate transformer loading levels where operation at loads in excess of nameplate ratings is proposed (typically only for emergencies). Network Planners should utilise the emergency overload limits in table B.1 for the assessment of transformer loading during contingencies (see example below table B.1). Additional constraints on transformer loading may be specified in BGL 34-335 Network Planning Philosophy and DGL 34-450 Network Planning Reliability Guideline.



• Fault level limits: The 1 second fault level ratings of equipment (supplied by transformers) should not be exceeded. Increased transformer capacity will increase fault levels. High impedance transformers and/or fault limiting reactors should only be used if there is no technically acceptable alternative that has less load losses and meets the fault level requirements.

• Vector Group compatibility: Transformer vector groups must be selected such there are no phase shift incompatibility problems between interconnected networks. Standard vector groups are specified in table 6.

• Redundancy: The transformer redundancy requirements specified in DGL 34-450 Network Planning Reliability Guideline, must be complied with.

For existing transformers the violation of the above minimum requirements is a trigger for network reinforcement or refurbishment. The future loads and network configuration must be assessed to ensure compliance with these minimum requirements for the expected load forecast and network changes. The following should be considered by the Network Planner, and included in the substation scope (as is influenced by the power transformers): • Bus sections: Running transformer bus sections open reduces fault level and also reduces the

number and severity of through faults supplied by power transformers. If the associated momentary interruption can be tolerated (in the event of a power transformer failure), consideration should be given to operating bus sections open, with automated switching of bus sections in the event of a transformer failure. This may negate the requirement for high impedance transformers or fault limiting reactors.

• Earthing and earthing transformers: Single phase fault level calculations for future transformer installations must be based on appropriate star point and NECR earthing. NECR earthing should be installed for all transformation with a MV capacity >5MVA. Star point earthing should be performed to ensure acceptable single phase fault protection coordination, considering partially graded transformer windings. See section 6.2 for additional detail. When in doubt Electricity Delivery Network Services (Protection) should be consulted.

• OLTC tap changers: Automatic OLTC control should be included as a default requirement. Manual or remote control tapping should only be proposed after careful consideration of voltage regulation implications. Remote control refers to remote tap change control via an operator at a control centre (no automatic control).

• Standard and preferred power ratings: Standard transformer sizes (table 6) shall be used. Furthermore Network Planners shall, where possible, utilise preferred sizes.

Note that the assessment of technical losses is not required. Over sizing transformers to reduce load losses results in increased no-load losses, and usually results in a net increase in technical losses. Note that environmental considerations are taken into consideration as part of transformer and substation design. Table 8 contains the scope to be provided by the Network Planner for a new major power transformer (or replacement of an old transformer with a new one).

Table 8: Major power transformer data to be specified by the Network Planner 1 2

Transformer parameter Description Rated Power Standard power rating e.g. 5, 10, 20, 40, 80 MVA Nominal Primary Voltage Standard nominal system voltage e.g. 11, 22, 33, 44, 66, 88 or 132kV Nominal Secondary voltage Standard nominal system voltage e.g. 11, 22, 33, 44, 66, 88 or 132kV Vector Group Vector group and phase shift Impedance Specification Standard or High impedance transformer. Default Standard Automatic Tap Changing Enabled

Options are Yes, No or Via Remote Control. Default Yes

Note:



• The transformer will be included in a project, which will contain information on NDP references, required completion dates, costs etc. The project will also include specific requirements for breakers, NECR earthing transformers etc. The table only focuses on the power transformer itself.

• Unless there are extenuating circumstances, standard transformers (as per DISSCAAD3) shall be used.

• Even if the specific installation does not require an OLTC tap changer, the transformer will be ordered with the standard OLTC tap changer.

• In the case of three winding transformers, the tertiary winding voltage and rating will need to be specified (the standard tertiary voltage rating is 22kV).

• High impedance transformers are only to be utilised if there is no technically acceptable alternative that has lower load losses.

8.3 Costing

The latest approved costing tool should be utilised for costing new transformer installations.

9. Modelling power transformers in PSA software

This section describes ReticMaster and PowerFactory functionality and contains software screenshots. It is possible that functionality and interfaces may change in future software versions. The latest software version and user guide should be consulted.

9.1 ReticMaster

9.1.1 Data type library

The data library contains a dictionary of power transformer parameters. This library type data is used when modelling transformers. ReticMaster only supports the modelling of two winding transformers. Three winding transformers must be modelled in PowerFactory. ReticMaster does not support a dedicated NECR model. Detailed modelling of NECR earthing must be modelled in PowerFactory.

Figure 16: Transformer data library editor

The ReticMaster data library is illustrated in figure 16. The fields are described in table 9.



Table 9: Transformer data type library fields 1 2 3

Field Units Notes Specifications: Z % Positive sequence impedance in % on transformer rated power base Specifications: X/R Ratio Positive sequence X/R ratio Specifications: Z0 % Zero sequence impedance in % on transformer rated power base Specifications: X0/R0 Zero sequence X/R ratio Specifications: Overload Per unit Overload rating as per unit of rated power. The overload rating is utilised

for all rate B reporting Specifications: Core loss Watts Rated no-load core loss active power Specifications: Boost % Rated no-load boost voltage relative to the nominal system voltage. This

field is used to model e.g. 380V, 415V and 420V transformers as may be installed in nominal 400V networks. In the above example the rated secondary voltage is 400V *(1-5/100)=380V

Specifications: Vector Group None Enumerated list of main vector groups. “Unbalanced” vector groups result in unbalanced load transformation. “Balanced” vector groups transform unbalanced secondary loads to the transformer primary as balanced loads

Specifications: Phase shift Degrees The phase shift is calculated from the vector group for “Unbalanced” vector groups. The phase shift can be user specified for “Balanced” vector groups

Specifications: Regulator equivalent

None Can only be specified if primary and secondary voltages are the same. If selected, impedance variation with tap changer position varies as would be expected for a voltage regulator i.e. neutral tap will have zero impedance.

Tap: Min Per unit Minimum tap ratio. This is the tap ratio (in per unit relative to nominal tap) for maximum boosting. Under no-load conditions the secondary voltage in this tap = rated secondary voltage * (1+ Boost/100) / Tap Min. Note that this is a ratio and not a tap position number

Tap: Max Per unit Maximum tap ratio. This is the tap ratio (in per unit relative to nominal tap) for maximum bucking. Under no-load conditions the secondary voltage in this tap = rated secondary voltage * (1+ Boost/100) / Tap Max. Note that this is a ratio and not a tap position number

Tap: Step Per unit Tap step size. This is the per unit change in secondary voltage between tap positions

Tap: Position Per unit Default tap ratio to be applied prior to any tap changing. For OCTS transformers this is the tap ratio of the fixed tap setting. Note that this is a ratio and not a tap position number

Tap: VMin Per unit Default tap changer controller minimum voltage set-point. If automatic tap changing is enabled, the secondary voltage will be adjusted (within tapping range capability) such that the secondary voltage is >= VMin (in per unit)

Tap: VMax Per unit Default tap changer controller maximum voltage set-point. If automatic tap changing is enabled, the secondary voltage will be adjusted (within tapping range capability) such that the secondary voltage is <= VMax (in per unit)

Earthing: Primary flag None Enable flag if primary winding is earthed (solid or via impedance) Earthing: Secondary flag None Enable flag if secondary winding is earthed (solid or via impedance) Earthing: R0 (*3) Ohms For each winding the earthing zero sequence resistance is specified in

ohms. Star point connected resistances must be multiplied by three for conversion to zero sequence

Earthing: X0 Ohms For each winding the earthing zero sequence reactance is specified in ohms. Star point connected reactances must be multiplied by three for conversion to zero sequence

9.1.2 Element data

The ReticMaster transformer element data editor is illustrated in figures 17 and 18. The fields are described in tables 10 and 11.



Figure 17: Transformer element editor (Specifications)

Table 10: ReticMaster transformer element fields (Specifications)

1 2 3 Field Units Notes Open None Flag to switch transformer in or out of service Transformer type None Drop down list of all transformers in data type library. Used to selected

main transformer characteristics (power rating, rated voltages and vector group) and provide default values for other characteristics such as impedances, earthing and tapping

Primary phasing None Phase connection of the transformer primary winding (only needs to be specified for single phase technologies)

Domestic load category None Used in the selection of Herman Beta load parameters for probabilistic domestic voltage drop calculation. Applies default Herman Beta parameters to all domestic connections supplied by the transformer in question. Only required for LV domestic voltage drop calculation

Specifications Various As per descriptions in data type library. Note that impedances, overload rating and core loss can be changed from library defaults

Earthing Various As per descriptions in data type library. Note that earthing flags and impedances can be changed from library defaults

Figure 18: Transformer element editor (Tap Settings)



Table 11: ReticMaster transformer element fields (Tap Settings) 1 2 3

Field Units Notes Tap: Min, Max, Step & Position Per unit As per descriptions in data type library. Note that tapping characteristics

can be changed from library defaults Tap: Lock Tap Position Flag to lock tap position. Set flag for OCTS, and unset flag for OLTC Voltage Regulation: Minimum Voltage (pu)

Per unit Same as VMin in data type library. Only used if Lock Tap Position is unset. Note that voltage control settings can be changed from library defaults

Voltage Regulation: Maximum Voltage (pu)

Per unit Same as VMax in data type library. Only used if Lock Tap Position is unset. Note that voltage control settings can be changed from library defaults

Line Drop Compensation: Use LDC

None Flag to enable LDC. The LDC primary system impedance in ohms (based on the conductor length, type and temperature) is calculated and displayed

Line Drop Compensation: Length

Meters Length of conductor utilised for LDC impedance modelling. Only used if Use LDC flag is set

Line Drop Compensation: Conductor type

None Conductor type utilised for LDC impedance modelling. Only used if Use LDC flag is set

Line Drop Compensation: Temperature

°C Conductor temperature (as influences conductor resistance) utilised for LDC impedance modelling. Only used if Use LDC flag is set

9.2 PowerFactory

PowerFactory supports both two winding and three winding transformer models. For simplification only the two winding transformer model is described in this guideline. 9.2.1 Two winding transformer data type library

Figure 19: Two winding transformer type data (Basic Data)



Table 12: Two winding transformer type fields (Basic Data) 1 2 3

Fields Units Notes Name None Name of the transformer Technology None Describes the number of phases present (three phase, single phase or

SWER). Technology modeling guidelines are provided in DGL 34-618 Rated Power MVA Nominal (nameplate) power rating Nominal Frequency Hz Default to 50 Rated voltage: HV side kV Rated (nameplate) phase to phase voltage of the primary winding. The rated

voltage can vary slightly from the nominal system voltage Rated voltage: LV side kV Rated (nameplate) phase to phase voltage of the secondary winding. The

rated voltage can vary slightly from the nominal system voltage. The LV winding is the secondary winding and is not necessarily in the LV voltage range (<1kV)

Positive Sequence Impedance: Short Circuit Voltage uk

% Positive sequence impedance in percent on the transformer rated power base (for neutral tap position)

Positive Sequence Impedance: Ratio X/R

Ratio Positive sequence impedance ratio between reactance and resistance (for neutral tap position). The X/R ratio can also be specified as a load loss in kW or the resistive component of the impedance (in percent) can be specified

Zero Sequ Impedance: Absolute uk0

% Zero sequence impedance in percent on the transformer rated power base (for neutral tap position)

Zero Sequ Impedance: Resistive part ukr0

% Zero sequence impedance resistive percentage (for neutral tap position). The resistive percentage can be calculated from the zero sequence X/R ratio as follows; ukr0 = sqrt(Z^2/((X/R)^2+1))

Vector Group: HV Side None Primary winding vector group Vector Group: LV Side None Secondary winding vector group Vector Group: Phase Shift *30deg Phase shift from primary to secondary windings. This integer is multiplied by

30 to obtain the phase shift in degrees

Figure 20: Two winding transformer type data (Load Flow)



Table 13: Two winding transformer type fields (Load Flow) 1 2 3

Fields Units Notes Tap Changer: at Side None Physical location of the tap changer Tap Changer: Additional Voltage per Tap

% Change in voltage per tap step. If the tap changer is located on the HV winding and the buck tap position number is greater than the boost tap position number (as is the Eskom standard) then the tap step must be negative

Tap Changer: Phase of du deg Tap changer phase shift between primary and secondary windings. Default 0 Tap Changer: Neutral Position None Tap position number for neutral tap (no bucking or boosting of the rated

voltages) Tap Changer: Minimum Position

None Tap position for maximum bucking of the secondary voltage

Tap Changer: Maximum Position

None Tap position for maximum boosting of the secondary voltage

Tap dependant impedance Various Positive and zero sequence impedances (real and reactive) can be specified at maximum tap positions. PowerFactory interpolates the impedances for interim tap positions. Note that in the element the user can specify impedances and phase shifts independently for each tap position

Magnetizing Impedance: No Load Current

% No load core magnetizing current for neutral tap position and rated voltage, as a percentage of the rated power. This is the apparent core loss power expressed as a percentage of transformer rating

Magnetizing Impedance: No Load Losses

% No load core magnetizing losses for neutral tap position and rated voltage, in kW. This is the active core loss power

9.2.2 Two winding transformer element data

Figure 21: Two winding transformer element data (Basic Data)



Table 14: Two winding transformer element fields (Basic Data) 1 2 3

Fields Units Notes Name None Name of transformer element Type None The relevant two-winding transformer type must be specified HV-Side None Primary busbar and phasing connection LV-Side None Secondary busbar and phasing connection Out of Service None Only select if transformer is to be excluded from study External Star Point None Set flag if transformer has external star point. This flag must be set if a

neutral is to be connected to the transformer star point Number of parallel transformers

None If a bank of identical transformers are modelled as a single element then the number of transformers in the bank must be specified. Default 1

Rating Factor Per unit Additional capacity via consideration of load profile and ambient temperature. Default 1

Auto transformer None If the vector group is Star/Star then the user can specify if the transformer is an auto-transformer (with a common star point for both windings)

Grounding Impedance: Star Point

None For each winding with a Neutral (YN or ZN vector group) the earthing configuration is specified

Grounding Impedance: Re Ohm Winding grounding resistance. This is the physical resistance (not multiplied by 3)

Grounding Impedance: Xe Ohm Winding grounding reactance. This is the physical reactance (not multiplied by 3)

Figure 22: Two winding transformer element data (Load Flow)



Table 15: Two winding transformer element fields (Load Flow) 1 2 3

Fields Units Notes According to measurement report

None If this flag is set tap specific impedances, loading limits and phase shifts can be specified (via the measurement report). Default unset

Tap position None With OCTS transformers this is the fixed tap position. For OLTC transformers this is the tap position for initial load-flow calculation. Default to nominal

Automatic Tap Changing None If OCTS transformer unset. If OLTC transformer set. Note that the tap changer control settings specified below are only relevant if Automatic Tap Changing is set

Tap Changer None Options are either discrete or continuous. Discrete – Uses integer tap positions. Tap steps are enforced. Continuous – Does not enforce tap steps. Infinite number of tap steps. Default Discrete

Controlled Node None Directly controlled node. Default LV Control Mode None Default V (Voltage). Note that the control parameters vary for different control

modes (voltage, reactive power etc). As voltage control is the most commonly used method of tap changer control, only voltage control setting attributes are included below

Phase None The phase voltage utilised as the reference voltage by the tap change controller

Remote Control None Busbar at which voltage is sampled. If unset then the busbar specified via the Controlled Node is controlled

Voltage setpoint Per unit Tap changer set-point. Default to typical Regional value e.g. 1.03 Lower Voltage Bound Per unit Tap changer lower voltage limit. Is set-point – 0.5*bandwidth. Default to

typical Regional value e.g. 1.02 Upper Voltage Bound Per unit Tap changer upper voltage limit. Is set-point + 0.5*bandwidth. Default to

typical Regional value e.g. 1.04 Controller Time Constant seconds Time between tapping for the coordination of series tap changers. Default 0.5 Line Drop Compensation None Used to specify LDC settings. Default None. See DGL 34-539 for additional

detail on LDC modelling

9.2.3 NECR element data

Figure 23: NECR element data (Basic Data)



Table 16: NECR element fields (Basic Data) 1 2 3

Fields Units Notes Name None Name of NECR element Out of Service None Only select if NECR is to be excluded from study Rated Voltage kV Rated phase to phase voltage Rated Current kA Rated short duration earth fault current e.g. 300A Zero Sequence Resistance Ohm NEC zero sequence resistance (see note below) Zero Sequence Reactance Ohm NEC zero sequence reactance Star point None Specifies if the NEC star point is grounded or is compensated. Default

grounded Grounding Resistance Ohm NEC Resistor resistance (if not modelled in Zero Sequence Resistance, see

note below) Grounding Reactance Ohm NEC Resistor reactance (if not modelled in Zero Sequence Reactance, see

note below) Note that NECRs do not require type associations. Also note that the NECR resistor does not need to be modelled separately, and can be included in the NEC zero sequence resistance. This method of modelling (combining NEC and resistor zero sequence resistances) is preferred where specifications only provide the combined NECR zero sequence impedances, and don’t differentiate between the NEC and earthing Resistor. Note that if the Resistor is included in the Zero Sequence Resistance its physical resistance must be converted to zero sequence i.e. multiplied by 3. 9.2.4 General notes

The following should be noted: • PowerFactory does not explicitly support emergency thermal ratings. However scales and triggers

can be utilised to specify multiple ratings.

10. Worked example

The following worked example illustrates some of the key issues discussed in this guideline. The associated PowerFactory file (Power transformer modelling.dz) is published as an attachment to this guideline. 20MVA and 10MVA 132/11kV transformers are operated in parallel to supply load with a maximum demand of 15MVA (figure 24): • The incoming 132kV HV supply voltage drops to 97% during peak loading. • Both transformers have a vector group YNd1 and are solidly earthed on their 132kV primary

winding star points. • The 11kV terminals of the transformers are earthed via 300amp NECRs. • Both 132/11kV transformers are fitted with 17 position -5% to +15% 1.25% step OLTC tap

changers located on their primary windings. • The 20MVA transformer has a positive sequence impedance of 10% (X/R = 25). • The 10MVA transformer has a positive sequence impedance of 8% (X/R = 25). • Both OLTC tap changers are set to regulate the 11kV busbar with a set-point of 103%. • The load power factor is 0.9. As this example involves paralleled sub-transmission transformers, modelling has only been performed in PowerFactory.



Figure 24: Example 20MVA and 10MVA 132/11kV transformers operated in parallel



Table 17: Case files

1 2 Case file Description C1 Base network The network has been modelled in PowerFactory. Note the type and element settings and values.

Dummy 11kV busbars have been used for the connection of the NECRs so that the NECRs are switched in and out of service with the MV transformer breakers.

C2 In step Perform a load flow calculation. Both transformers auto-tap to tap position 11 in order to regulate the 11kV busbar voltage at 103%. Due to the mismatch in impedance the 20MVA and 10MVA transformers supply 9.43MVA and 5.89MVA respectively. The 20MVA and 10MVA transformers are loaded to 48.6% and 60.75% respectively of their nameplate current ratings. The total load loss is 0.03MW.

C3 Out of step Perform a load flow calculation. The 11kV busbar is still regulated at 103%, but with a 4 tap step differential between the 20MVA (tap 9) and 10MVA (tap 13) transformers (the transformer taps have been locked in these positions). The tap differential results in circulating reactive power between the two transformers. The transformer loading has changed as follows: 20MVA from 48.6% to 41.10% 10MVA from 60.75% to 96.79% The total load loss has increased from 0.03MW to 0.04MW. It is important to note that this tap differential is causing the 10MVA transformer to operate close to its rated power. Load losses have increased even though there has been no change in the maximum demand of the load supplied by the 11kV busbar.

C4 Maximum 3p fault level

Perform a fault level calculation. Both transformers are in service. The three phase fault level at the 11kV busbar is 18.29kA (zero fault impedance). All equipment connected to this busbar should have a one second fault level rating > 18.29kA.

C5 Minimum 3p fault level

Perform a fault level calculation. The 20MVA transformer is out of service (HV and MV breakers are open). The three phase fault level at the 11kV busbar is 7.2kA (zero fault impedance). Protection coordination should still be acceptable with this reduced fault level.

C6 Maximum 1p fault level

Perform a fault level calculation. Both transformers are in service. The single phase to ground fault level at the 11kV busbar is 0.74kA (zero fault impedance). Each NECR supplies an earth fault current of 0.37kA. There is no zero sequence current flow in the 132kV HV network due to the 11kV Delta windings.

C7 Minimum 1p fault level

Perform a fault level calculation. The 20MVA transformer is out of service (HV and MV breakers are open). The single phase to ground fault level at the 11kV busbar is 0.368kA (zero fault impedance). Protection coordination should still be acceptable with this reduced fault level.

C8 10MVA trfr contingency

Perform a load flow calculation. The 10MVA transformer is out of service (HV and MV breakers opened). The 20MVA transformer tap position increases to tap 12. The 11kV busbar is still regulated at 103%. The loading on the 20MVA transformer is 15.53MVA (80.06% of nameplate current rating). There is no overloading problem.


Perform a load flow calculation. The 20MVA transformer is out of service (HV and MV breakers opened). The 10MVA transformer tap position increases to tap 14. The 11kV busbar is still regulated at 103%. The loading on the 10MVA transformer is 15.86MVA (163.55% of nameplate current rating). There is an overloading problem. The substation is located in Johannesburg and supplies suburban load. Referring to table B.1, the emergency overload limit is 130%.The emergency overload capability is being exceeded.


Perform a load flow calculation. The 20MVA transformer is out of service (HV and MV breakers opened). The 15MVA load has been scaled to 80%. This simulates 20% load shedding or 20% load transfer to other MV sources. The 10MVA transformer loading has been reduced to 130% of its nameplate current rating. Note that this is a loading of 12.55MVA (not 13MVA) due to the less than nominal 132kV voltage of 97%.



Annex A

Earth fault current flow with common MV grounding configurations

For simplicity the transformation ratio in the following figures is 1:1.

Figure A.1: NECR earthing of a star-delta transformer (Note that primary star point earthing does not affect earth fault current flow)

Figure A.2: Star point resistive earthing of a delta-star transformer

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Figure A.3: NECR earthing of a delta-star transformer

Figure A.4: Star point resistive earthing of a star-star transformer with earthed primary star point

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Figure A.5: Star point resistive earthing of a star-star transformer with unearthed primary star point. If a delta winding is not present the “tank delta” effect provides a delta winding effect

Figure A.6: NECR earthing of a star-star transformer (Note that primary star point earthing does not affect earth fault current flow)

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Earth fault



Annex B Major power transformer emergency overload ratings

Major power transformer emergency overload ratings have been calculated (RES/RR/03/20960 Transformer loading lookup table) for different geographical locations (variation in ambient temperature) and load types (variation in load profile) assuming standard Eskom Distribution power transformer protection settings. The following criteria constrain the maximum loading level: • Maximum top oil temperature of 105°C. • Maximum winding hot spot temperature of 120°C. • Maximum load current of 130% of rated (nameplate) current (over current will start to pick up

above this limit). The maximum emergency overload rating is the loading level at which any one of the above criteria is reached. It must be noted that these overload ratings are conservative. The IEC60354 emergency overload limits are based on maximum top oil, winding and load current limits of 115°C, 140°C and 150% respectively. Changing protection settings to align with these IEC60354 limits allows additional overload. This additional overload capacity is only to be utilised by network control in emergency conditions, and is not to be utilised by Network Planning for contingency overload ratings. Network Planning contingency overload ratings must be based on the standard Eskom Distribution power transformer protection settings thereby ensuring that these overload limits can be applied without protection setting changes. This philosophy also provides some additional overload rating capacity to provide some margin for unexpected events such as greater than forecasted loads and abnormally high ambient temperatures.

Figure B.1: SABW weather station sites



Table B.1: Major power transformer emergency overload rating (% of nameplate rating) for standard Eskom Distribution protection settings

Load type

Location

Suburban

Township

Electrification

Com

mercial

Agricultural

Basic m

etals

Chem

ical

Non-m

etallic

Textile

Food & beverage

Paper

Other m

anufac

Gold

Platinum

Other m

ining

Traction

Alexander bay 1.30 1.30 1.30 1.13 1.25 1.11 1.08 1.10 1.13 1.13 1.12 1.11 1.16 1.16 1.12 1.16 Beaufort West 1.30 1.30 1.30 1.13 1.25 1.09 1.09 1.11 1.15 1.14 1.13 1.13 1.16 1.16 1.12 1.21

Bethlehem 1.30 1.30 1.30 1.18 1.30 1.13 1.14 1.16 1.20 1.19 1.18 1.18 1.20 1.20 1.17 1.26 Bloemfontein 1.30 1.30 1.30 1.15 1.27 1.10 1.11 1.12 1.16 1.15 1.14 1.14 1.18 1.18 1.12 1.23

Calvinia 1.30 1.30 1.30 1.11 1.23 1.10 1.07 1.08 1.12 1.11 1.10 1.10 1.17 1.17 1.11 1.22 Cape Town 1.30 1.30 1.30 1.12 1.25 1.11 1.08 1.09 1.13 1.12 1.11 1.11 1.16 1.16 1.14 1.20

De Aar 1.30 1.30 1.30 1.13 1.27 1.09 1.09 1.11 1.14 1.13 1.12 1.13 1.17 1.17 1.11 1.23 Durban 1.30 1.30 1.30 1.17 1.26 1.08 1.09 1.14 1.16 1.16 1.15 1.16 1.15 1.15 1.13 1.21

East London 1.30 1.30 1.30 1.14 1.28 1.10 1.11 1.14 1.14 1.14 1.13 1.16 1.17 1.17 1.15 1.17 Ellisras 1.30 1.30 1.30 1.13 1.24 1.07 1.08 1.10 1.14 1.13 1.12 1.12 1.14 1.14 1.11 1.18 Ermelo 1.30 1.30 1.30 1.19 1.30 1.13 1.14 1.17 1.19 1.19 1.18 1.18 1.20 1.20 1.17 1.23 George 1.30 1.30 1.30 1.15 1.26 1.11 1.11 1.12 1.14 1.14 1.14 1.13 1.17 1.17 1.12 1.19

Hoedspruit 1.30 1.30 1.30 1.12 1.24 1.07 1.08 1.09 1.13 1.12 1.11 1.11 1.14 1.14 1.10 1.17 Johannesburg 1.30 1.30 1.30 1.18 1.30 1.13 1.14 1.15 1.19 1.18 1.17 1.17 1.20 1.20 1.16 1.24

Kimberly 1.30 1.30 1.30 1.13 1.25 1.08 1.09 1.10 1.14 1.13 1.12 1.12 1.15 1.15 1.10 1.21 Kroonstad 1.30 1.30 1.30 1.16 1.28 1.10 1.11 1.13 1.17 1.16 1.15 1.15 1.18 1.18 1.14 1.23 Ladysmith 1.30 1.30 1.30 1.15 1.28 1.11 1.11 1.13 1.16 1.15 1.15 1.14 1.18 1.18 1.13 1.21

Langebaanweg 1.30 1.30 1.30 1.13 1.23 1.10 1.09 1.10 1.14 1.13 1.12 1.11 1.15 1.15 1.11 1.20 Lichtenburg 1.30 1.30 1.30 1.16 1.28 1.11 1.12 1.13 1.17 1.16 1.15 1.16 1.18 1.18 1.15 1.22

Mafikeng 1.30 1.30 1.30 1.14 1.26 1.09 1.10 1.11 1.15 1.14 1.13 1.13 1.16 1.16 1.13 1.13 Margate 1.30 1.30 1.30 1.17 1.28 1.09 1.10 1.16 1.16 1.16 1.16 1.17 1.16 1.16 1.14 1.21 Nelspruit 1.30 1.30 1.30 1.15 1.27 1.10 1.10 1.12 1.16 1.15 1.14 1.14 1.17 1.17 1.14 1.19

Newcastle 1.30 1.30 1.30 1.16 1.28 1.11 1.11 1.14 1.16 1.17 1.16 1.15 1.18 1.18 1.15 1.20 Phalaborwa 1.30 1.30 1.30 1.12 1.25 1.07 1.08 1.10 1.13 1.12 1.11 1.11 1.14 1.14 1.11 1.17

Pietermaritzburg 1.30 1.29 1.30 1.12 1.24 1.09 1.08 1.09 1.13 1.12 1.11 1.11 1.15 1.15 1.09 1.17 Polokwane 1.30 1.30 1.30 1.15 1.28 1.10 1.11 1.13 1.16 1.15 1.14 1.14 1.17 1.17 1.14 1.20

Plettenberg Bay 1.30 1.30 1.30 1.15 1.28 1.11 1.12 1.14 1.14 1.15 1.14 1.16 1.18 1.18 1.14 1.19 Port Elizabeth 1.30 1.30 1.30 1.15 1.26 1.10 1.10 1.12 1.15 1.15 1.14 1.13 1.18 1.18 1.15 1.19 Potchefstroom 1.30 1.30 1.30 1.13 1.25 1.09 1.09 1.10 1.14 1.13 1.12 1.12 1.16 1.16 1.13 1.19

Pretoria 1.30 1.30 1.30 1.14 1.26 1.09 1.10 1.12 1.15 1.14 1.13 1.13 1.16 1.16 1.13 1.20 Queenstown 1.30 1.30 1.30 1.14 1.26 1.11 1.09 1.11 1.15 1.14 1.13 1.13 1.17 1.17 1.11 1.22 Richardsbay 1.30 1.30 1.30 1.13 1.23 1.06 1.08 1.11 1.13 1.12 1.11 1.11 1.13 1.13 1.10 1.18 Springbok 1.30 1.30 1.30 1.14 1.25 1.10 1.10 1.11 1.15 1.14 1.13 1.13 1.16 1.16 1.12 1.22

Umtata 1.30 1.30 1.30 1.14 1.24 1.10 1.09 1.10 1.14 1.13 1.12 1.12 1.15 1.15 1.10 1.21 Upington 1.30 1.30 1.30 1.10 1.22 1.06 1.06 1.08 1.12 1.12 1.10 1.10 1.12 1.12 1.09 1.19 Vryheid 1.30 1.30 1.30 1.15 1.28 1.10 1.11 1.13 1.16 1.15 1.14 1.14 1.18 1.18 1.14 1.19 Welkom 1.30 1.30 1.30 1.15 1.27 1.09 1.10 1.12 1.16 1.15 1.14 1.14 1.16 1.16 1.12 1.22 Witbank 1.30 1.30 1.30 1.15 1.28 1.11 1.12 1.13 1.18 1.16 1.15 1.15 1.18 1.18 1.15 1.22 Referring to table B.1, a 20MVA transformer supplying predominately commercial load in Johannesburg has an emergency rating (for planning contingency studies) of 1.18*20 = 23.6MVA. The same transformer supplying predominately agricultural load has an emergency rating of 1.3*20 = 26MVA.



Annex C Parameters required for PSA

The following colour coding has been applied to the tables in this annex. • Blue: Key parameters (determine the link to the standard values). • Orange: Parameters for which standard values can be applied. • Green: Parameters for which standard values can NOT be applied, but which are required for

PSA.

Table C.1: OLTC tap changer 1 2 3

Parameter Units Description Tapping range and step size None Tapping range and step size standard configurations Rated voltage kV Tap-changer nameplate voltage Neutral tap position voltage kV Tap-changer nominal voltage in neutral tap Automatic tap-changing enabled None Automatic tap changing enabled Voltage control voltage setpoint % % Nominal voltage setpoint for OLTC voltage control Voltage control voltage bandwidth

% % Nominal voltage bandwidth (+-) for OLTC voltage control. Total bandwidth will be double this value

Tap change control mode None On-load tap changing control objective Voltage control busbar None Controlled busbar for automatic voltage control Voltage control phase None Controlled phase(s) for automatic voltage control LDC enabled None Line drop compensation enabled on OLTC tap changer? LDC CT ratio Ratio Line drop compensation Current Transformer ratio LDC VT ratio Ratio Line drop compensation Voltage Transformer ratio LDC R Ohms or

Volts Line drop compensation resistance in either primary system ohms or controller base voltage

LDC X Ohms or Volts

Line drop compensation reactance in either primary system ohms or controller base voltage

LDC V Max % Line drop compensation Maximum secondary voltage as a % of the nominal voltage

LDC V Min % Line drop compensation Minimum secondary voltage as a % of the nominal voltage

Bi-directional None Ability to auto-regulate the voltage for power flow in both directions. Tap position None OLTC tap position Tap changer location None Tap-changer winding location Minimum tap number None Minimum tap number. Is tap position, not tap ratio Nominal tap number None Nominal tap number. Is tap position, not tap ratio Maximum tap number None Maximum tap number. Is tap position, not tap ratio Tap step size % Tap step size in %. If minimum tap number is boost tap then tap

step must be negative Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.2: OCTS tap changer

1 2 3 Parameter Units Description Tapping range and step size None Tapping range and step size standard configurations Rated voltage kV Tap-changer nameplate voltage Neutral tap position voltage kV Tap-changer nominal voltage in neutral tap Tap position None OCTS tap position Tap changer location None Tap-changer winding location Minimum tap number Number Minimum tap number. Is tap position, not tap ratio Nominal tap number Number Nominal tap number. Is tap position, not tap ratio Maximum tap number Number Maximum tap number. Is tap position, not tap ratio Tap step size % Tap step size in %. If minimum tap number is boost tap then tap

step must be negative Reliability parameter linkage None Equipment reliability library containing typical performance data



Table C.3: Reticulation transformer 1 2 3

Parameter Units Description Power rating kVA Rated power for all phases (rated line current at rated voltage) Technology None Primary and Secondary Technology (number of phases present) Rated primary voltage kV Primary nameplate voltage Rated secondary voltage kV Secondary nameplate voltage Tap changer present None Describes if a tap changer is present Tap changer type None On-Load Tap Changer versus De-Energised Tap Changer. None if

no tap changer is present. Tapping range and step size None Tapping range and step size standard configurations Primary phasing None Primary phasing (actual physical phases connected to primary) Number of transformers in parallel

None Number of transformers in parallel

Primary earthed None Primary winding earthed Primary earthing resistance Ohm Primary winding earthing resistance (physical ohms not * 3) Primary earthing reactance Ohm Primary winding earthing reactance (physical ohms not * 3) Secondary earthed None Secondary winding earthed Secondary earthing resistance Ohm Secondary winding earthing resistance (physical ohms not * 3) Secondary earthing reactance Ohm Secondary winding earthing reactance (physical ohms not * 3) Vector group None Vector group Phase shift Degrees Primary to secondary phase shift in degrees (divide by 30 to get 1-

12 equivalent) Positive sequence impedance % Nameplate impedance in % for nominal tap Positive sequence X/R ratio Ratio Positive sequence X/R ratio Zero sequence impedance % Zero sequence impedance in % for nominal tap Zero sequence X/R ratio Ratio Zero sequence X/R ratio No-load current % No-load core magnitising current as a % of the rated line current No-load loss kW No-load core loss at rated voltage Type of cooling None Type of cooling Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.4: Major power transformer

1 2 3 Parameter Units Description Power rating kVA Rated power for all phases (rated line current at rated voltage) Vector group None Vector group Technology None Primary and secondary technology (number of phases present) Rated primary voltage kV Primary nameplate voltage Rated secondary voltage kV Secondary nameplate voltage Tap changer present None Describes if a tap changer is present Tap changer type None On-Load Tap Changer versus De-Energised Tap Changer. Use

None if no tap changer is present Tapping range and step size None Tapping range and step size standard configurations Type of cooling None Type of cooling Impedance specification None Impedance specification for possible fault level attenuation Primary phasing None Primary phasing (actual physical phases connected to primary) Additional cooling None Additional cooling for increased power rating Additional cooling rating kVA Revised power rating with additional cooling Number of transformers in parallel


Primary earthed None Primary winding earthed Primary earthing resistance Ohm Primary winding earthing resistance (physical ohms not * 3) Primary earthing reactance Ohm Primary winding earthing reactance (physical ohms not * 3) Secondary earthed None Secondary winding earthed Secondary earthing resistance Ohm Primary winding earthing resistance (physical ohms not * 3) Secondary earthing reactance Ohm Primary winding earthing reactance (physical ohms not * 3) Positive sequence impedance % Name plate impedance in % for nominal tap Phase shift Degrees Primary to secondary phase shift in degrees (divide by 30 to get 1-

12 equivalent) Positive sequence X/R ratio Ratio Positive sequence X/R ratio Zero sequence impedance % Zero sequence impedance in % for nominal tap Zero sequence X/R ratio Ratio Zero sequence X/R ratio No-load current % No-load core magnitising current as a % of the rated line current No-load loss kW No-load core loss at rated voltage Reliability parameter linkage None Equipment reliability library containing typical performance data



Table C.5: Major power auto transformer 1 2 3

Parameter Units Description Power rating kVA Rated power for all phases (rated line current at rated voltage) Vector group None Vector group Technology None Primary and secondary technology (number of phases present) Rated primary voltage kV Primary nameplate voltage Rated secondary voltage kV Secondary nameplate voltage Tap changer present None Describes if a tap changer is present Tap changer type None On-Load Tap Changer versus De-Energised Tap Changer. Use

None if no tap changer is present Tapping range and step size None Tapping range and step size standard configurations Type of cooling None Type of cooling Impedance specification None Impedance specification for possible fault level attenuation Primary Phasing None Primary Phasing (actual physical phases connected to primary) Additional cooling None Additional cooling for increased power rating Additional cooling rating kVA Revised power rating with additional cooling Number of transformers in parallel


Star point earthed None Common star point of both primary and secondary windings earthed Star point earthing resistance None Star point winding earthing resistance (physical ohms not * 3) Star point earthing reactance None Star point winding earthing reactance (physical ohms not * 3) Positive sequence impedance % Name plate impedance in % for nominal tap Phase shift Degrees Primary to secondary phase shift in degrees (divide by 30 to get 1-

12 equivalent) Positive sequence X/R ratio Ratio Positive sequence X/R ratio Zero sequence impedance % Zero sequence impedance in % for nominal tap Zero sequence X/R ratio Ratio Zero sequence X/R ratio No-load current % No-load core magnitising current as a % of the rated line current No-load loss kW No-load core loss at rated voltage Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.6: Three winding transformer

1 2 3 Parameter Units Description Power rating primary kVA Rated primary winding power for all phases (rated line current at

rated voltage) Power rating secondary kVA Rated secondary winding power for all phases (rated line current at

rated voltage) Power rating tertiary kVA Rated tertiary winding power for all phases (rated line current at

rated voltage) Vector group None Vector group Rated primary voltage kV Primary nameplate voltage Rated secondary voltage kV Secondary nameplate voltage Rated tertiary voltage kV Tertiary nameplate voltage Impedance specification None Impedance specification for possible fault level attenuation Tap changer present None Describes if a tap changer is present Tap changer type None On-Load Tap Changer versus De-Energised Tap Changer. Use

None if no tap changer is present Tapping range and step size None Tapping range and step size standard configurations Additional cooling None Additional cooling for increased power rating Additional cooling rating primary kVA Primary power rating with additional cooling Additional cooling rating secondary

kVA Secondary power rating with additional cooling

Additional cooling rating tertiary kVA Tartiary power rating with additional cooling Number of transformers in parallel


Primary earthed None Primary winding earthed Primary earthing resistance Ohm Primary winding earthing resistance (physical ohms not * 3). Not

applicable to auto-transformers. Primary earthing reactance Ohm Primary winding earthing reactance (physical ohms not * 3). Not

applicable to auto-transformers. Secondary earthed None Secondary winding earthed Secondary earthing resistance Ohm Primary winding earthing resistance (physical ohms not * 3). Not

applicable to auto-transformers. Secondary earthing reactance Ohm Primary winding earthing reactance (physical ohms not * 3). Not

applicable to auto-transformers.



Tertiary earthed None Tertiary winding earthed Tertiary earthing resistance Ohm Tertiary winding earthing resistance (physical ohms not * 3) Tertiary earthing reactance Ohm Tertiary winding earthing reactance (physical ohms not * 3) Primary phasing Phasing (actual physical phases present) Technology None Primary, secondary and tertiary technology (number of phases

present) Phase shift primary to secondary Degrees Primary to secondary phase shift in degrees (divide by 30 to get 1-

12 equivalent) Phase shift primary to tertiary Degrees Primary to tertiary phase shift in degrees (divide by 30 to get 1-12

equivalent) Positive sequence impedance primary to secondary

% Name plate impedance between Primary and Secondary in % for nominal tap

Positive sequence X/R ratio primary to secondary

Ratio Positive sequence X/R ratio Primary to Secondary

Positive sequence impedance secondary to tertiary

% Name plate impedance between Secondary and Tertiary in % for nominal tap

Positive sequence X/R ratio secondary to tertiary

Ratio Positive sequence X/R ratio Secondary to Tertiary

Positive sequence impedance primary to tertiary

% Name plate impedance between Primary and Tertiary in % for nominal tap

Positive sequence X/R ratio primary to tertiary

Ratio Positive sequence X/R ratio Primary to Tertiary

Zero sequence impedance primary to secondary

% Zero sequence impedance Primary to Secondary in % for nominal tap

Zero sequence X/R ratio primary to secondary

Ratio Zero sequence ratio Primary to Secondary in % for nominal tap

Zero sequence impedance secondary to tertiary

% Zero sequence impedance Secondary to Tertiary in % for nominal tap

Zero sequence X/R ratio secondary to tertiary

Ratio Zero sequence ratio Secondary to Tertiary in % for nominal tap

Zero sequence impedance primary to tertiary

% Zero sequence impedance Primary to Tertiary in % for nominal tap

Zero sequence X/R ratio primary to tertiary

Ratio Zero sequence ratio Primary to Tertiary in % for nominal tap

No-load current % No-load core magnitising current as a % of the rated line current No-load loss kW No-load core loss at rated voltage Type of cooling None Type of cooling Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.7: Three winding auto transformer

1 2 3 Parameter Units Description Power rating primary kVA Rated primary winding power for all phases (rated line current at

rated voltage) Power rating secondary kVA Rated secondary winding power for all phases (rated line current at

rated voltage) Power rating tertiary kVA Rated tertiary winding power for all phases (rated line current at

rated voltage) Vector group Vector group Rated primary voltage kV Primary nameplate voltage Rated secondary voltage kV Secondary nameplate voltage Rated tertiary voltage kV Tertiary nameplate voltage Impedance specification None Impedance specification for possible fault level attenuation Tap changer present None Describes if a tap changer is present Tap changer type None On-Load Tap Changer versus De-Energised Tap Changer. Use

None if no tap changer is present Tapping range and step size None Tapping range and step size standard configurations Additional cooling None Additional cooling for increased power rating Additional cooling rating primary kVA Primary power rating with additional cooling Additional cooling rating secondary

kVA Secondary power rating with additional cooling

Additional cooling rating tertiary kVA Tartiary power rating with additional cooling Number of transformers in parallel


Auto-transformer star point earthed

None Auto transformer star point earthed. Only set if auto-transformer

Star point earthing resistance Ohm Auto-transformer star point winding earthing reistance (physical ohms not * 3)



Star point earthing reactance Ohm Auto-transformer star point winding earthing reactance (physical ohms not * 3)

Tertiary earthed None Tertiary winding earthed Tertiary earthing resistance Ohm Tertiary winding earthing reistance (physical ohms not * 3) Tertiary earthing reactance Ohm Tertiary winding earthing reactance (physical ohms not * 3) Primary phasing None Phasing (actual physical phases present) Technology None Primary, secondary and tertiary technology (number of phases

present) Phase shift primary to secondary Degrees Primary to secondary phase shift in degrees (divide by 30 to get 1-

12 equivalent) Phase shift primary to tertiary Degrees Primary to tertiary phase shift in degrees (divide by 30 to get 1-12

equivalent) Positive sequence impedance primary to secondary

% Name plate impedance between Primary and Secondary in % for nominal tap

Positive sequence X/R ratio primary to secondary

Ratio Positive sequence X/R ratio Primary to Secondary

Positive sequence impedance secondary to tertiary

% Name plate impedance between Secondary and Tertiary in % for nominal tap

Positive sequence X/R ratio secondary to tertiary

Ratio Positive sequence X/R ratio Secondary to Tertiary

Positive sequence impedance primary to tertiary

% Name plate impedance between Primary and Tertiary in % for nominal tap

Positive sequence X/R ratio primary to tertiary

Ratio Positive sequence X/R ratio Primary to Tertiary

Zero sequence impedance primary to secondary

% Zero sequence impedance Primary to Secondary in % for nominal tap

Zero sequence X/R ratio primary to secondary

Ratio Zero sequence ratio Primary to Secondary in % for nominal tap

Zero sequence impedance secondary to tertiary

% Zero sequence impedance Secondary to Tertiary in % for nominal tap

Zero sequence X/R ratio secondary to tertiary

Ratio Zero sequence ratio Secondary to Tertiary in % for nominal tap

Zero sequence impedance primary to tertiary

% Zero sequence impedance Primary to Tertiary in % for nominal tap

Zero sequence X/R ratio primary to tertiary

Ratio Zero sequence ratio Primary to Tertiary in % for nominal tap

No-load current % No-load core magnitising current as a % of the rated line current No-load loss kW No-load core loss at rated voltage Type of cooling None Type of cooling Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.8: NEC

1 2 3 Parameter Units Description Continuous normal current rating Amps Continuous earth fault current rating 10s current rating Amps 10 second earth fault current rating Rated primary voltage kV Primary nameplate voltage NEC Primary phasing None Phasing (actual physical phases present) NEC R0 Ohm NEC zero sequence resistance NEC X0 Ohm NEC zero sequence reactance NEC Technology None NEC: Primary Technology (number of phases present) NEC Vector group None NEC Vector group Reliability parameter linkage None Equipment reliability library containing typical performance data

Table C.9: NECR

1 2 3 Parameter Units Description Continuous normal current rating Amps Continuous earth fault current rating 10s current rating Amps 10 second earth fault current rating Rated primary voltage kV Primary nameplate voltage NEC Primary phasing None Phasing (actual physical phases present) NEC R0 Ohm NEC zero sequence resistance NEC X0 Ohm NEC zero sequence reactance Resistor R Ohm Resistor resistance (physical resistance not * 3) Resistor X Ohm Resistor reactance (physical reactance not * 3) Combined NECR R0 Ohm Combined NEC and Resistor zero sequence resistance Combined NECR X0 Ohm Combined NEC and Resistor zero sequence reactance



NEC Technology Ohm NEC: Primary Technology (number of phases present) NEC Vector group Ohm NEC Vector group Reliability parameter linkage Ohm Equipment reliability library containing typical performance data



Annex D

Impact assessment

1 Guidelines

o All comments must be completed. o Motivate why items are N/A (not applicable) o Indicate actions to be taken, persons or organisations responsible for actions and deadline for

action. o Change control committees to discuss the impact assessment, and if necessary give feedback

to the compiler of any omissions or errors.

2 Critical points

2.1 Importance of this document. E.g. is implementation required due to safety deficiencies, statutory requirements, technology changes, document revisions, improved service quality, improved service performance, optimised costs.

Comment: Implementation is required to improve Dx Network Planning by providing network planners with the information/training to analyse and plan transformers.

2.2 If the document to be released impacts on statutory or legal compliance - this need to be very clearly stated and so highlighted.

Comment: N/A no impact on statutory or legal compliance.

2.3 Impact on stock holding and depletion of existing stock prior to switch over.

Comment: A sub-set of the standard major power transformer ratings have been flagged as preferred ratings. Planners are to utilise preferred ratings where possible. This will consolidate the number of ratings, and positively impact future stock keeping and procurement.

2.4 When will new stock be available?

Comment: N/A no impact on stock as there is no change to the standard ratings.

2.5 Has the interchangeability of the product or item been verified - i.e. when it fails is a straight swop possible with a competitor's product?

Comment: N/A no impact on products.

2.6 Identify and provide details of other critical (items required for the successful implementation of this document) points to be considered in the implementation of this document.

Comment: The Master Type Library containing default transformer attribute values for power system studies needs to be maintained and updated. This is being managed by the PSST NUG, chaired by the author of this document.

2.7 Provide details of any comments made by the Regions regarding the implementation of this document.

Comment: (N/A during commenting phase)



3 Implementation timeframe

3.1 Time period for implementation of requirements.

Comment: Can be applied immediately via self study. Full application by all network planners will be dependent on training rollout (being managed as a separate project under the Planning Study Committee).

3.2 Deadline for changeover to new item and personnel to be informed of DX wide change-over.

Comment: N/A is not a new product or change to an existing product.

4 Buyers Guide and Power Office

4.1 Does the Buyers Guide or Buyers List need updating?


4.2 What Buyer’s Guides or items have been created?


4.3 List all assembly drawing changes that have been revised in conjunction with this document.


4.4 If the implementation of this document requires assessment by CAP, provide details under 5

4.5 Which Power Office packages have been created, modified or removed?


5 CAP / LAP Pre-Qualification Process related impacts

5.1 Is an ad-hoc re-evaluation of all currently accepted suppliers required as a result of implementation of this document?

Comment: No, is not a new product or change to an existing product.

5.2 If NO, provide motivation for issuing this specification before Acceptance Cycle Expiry date.


5.3 Are ALL suppliers (currently accepted per LAP), aware of the nature of changes contained in this document?


5.4 Is implementation of the provisions of this document required during the current supplier qualification period?




5.5 If Yes to 5.4, what date has been set for all currently accepted suppliers to comply fully?


5.6 If Yes to 5.4, have all currently accepted suppliers been sent a prior formal notification informing them of Eskom’s expectations, including the implementation date deadline?


5.7 Can the changes made, potentially impact upon the purchase price of the material/equipment?


5.8 Material group(s) affected by specification: (Refer to Pre-Qualification invitation schedule for list of material groups)


6 Training or communication

6.1 State the level of training or communication required to implement this document. (E.g. none, communiqués, awareness training, practical / on job, module, etc.)

Comment: The guideline is suitable for self study, but training will be included as part of the Dx network planning training framework that is being driven by the TESCOD Planning Study Committee.

6.2 State designations of personnel that will require training.

Comment: All Dx Network Planners.

6.3 Is the training material available? Identify person responsible for the development of training material.

Comment: No. Training material will need to be developed via a new Research project that has been initiated within R&S for the development of Dx Network Planning training material.

6.4 If applicable, provide details of training that will take place. (E.G. sponsor, costs, trainer, schedule of training, course material availability, training in erection / use of new equipment, maintenance training, etc).

Comment: To be decided.

6.5 Was Training & Development Section consulted w.r.t training requirements?

Comment: Yes, this is being done as part of the broader Dx Network Planning training framework.

7 Special tools, equipment, software

7.1 What special tools, equipment, software, etc will need to be purchased by the Region to effectively implement?

Comment: None. The guideline utilises existing tools and simply enhances there application and the interpretation of results.

7.2 Are there stock numbers available for the new equipment?




7.3 What will be the costs of these special tools, equipment, software?

Comment: None. The guideline utilises existing tools and simply enhances there application and the interpretation of results.

8 Finances

8.1 What total costs would the Regions be required to incur in implementing this document? Identify all cost activities associated with implementation, e.g. labour, training, tooling, stock, obsolescence

Comment: The direct costs will be training costs. Application will enhance network planning decision making. Minimum criteria for transformer redundancy as specified elsewhere, and as such this guideline is not expected to impact the Distribution capital budget.

Impact assessment completed by:

Name: Dr Clinton Carter-Brown

Designation: Chief Engineer IARC, TESCOD Network Planning Study Committee chairperson

Documents

DGL_34-617