Standard for the Interconnection of Embedded Generation

Standard
Title: STANDARD FOR THE INTERCONNECTION
OF EMBEDDED GENERATION
Group Technology
Unique Identifier:
240-61268576
Alternative
Reference Number:
34-1765
Part:
15 - Protection
18 - Telecontrol
Area of
Applicability:
Eskom
Documentation
Type:
Standard
Revision:
1
Total Pages:
91
Next Review Date:
October 2018
Controlled Disclosure
Disclosure Classification:
Compiled by
Approved by
Approved by
………………………………..
…………………………………..
…………………………………..
Andrew Craib
Graeme Topham
Marlini Sukhnandan
Chief Engineer
Protection SC Chairperson
Telecontrol SC Chairperson
Date: 18 October 2013
Date: 21 October 2013
Date: 23 October 2013
Functional Responsibility
Authorised by
…………………………………..
…………………………………..
Richard McCurrach
Richard McCurrach
Snr Manager PTM&C CoE
Snr Manager PTM&C CoE
Date:
Date:
ESKOM COPYRIGHT PROTECTED
STANDARD
FOR
THE
EMBEDDED GENERATION
INTERCONNECTION
OF Unique Identifier:
240-61268576
Revision:
1
Page:
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Content
Page
1
2
3
4
INTRODUCTION ................................................................................................................................... 6
SUPPORTING CLAUSES ..................................................................................................................... 7
2.1
SCOPE ........................................................................................................................................... 7
2.1.1 Purpose .......................................................................................................................................7
2.1.2 Applicability .................................................................................................................................7
2.2
NORMATIVE/INFORMATIVE REFERENCES .............................................................................. 8
2.2.1 Normative ....................................................................................................................................8
2.2.2 Informative ................................................................................................................................10
2.3
DEFINITIONS .............................................................................................................................. 11
2.3.1 Disclosure Classification ...........................................................................................................13
2.4
ABBREVIATIONS ........................................................................................................................ 14
2.5
ROLES, RESPONSIBILITIES, MONITORING AND DOCUMENTATION ................................... 16
2.5.1 Roles and Responsibilities ........................................................................................................16
2.5.2 Process for Monitoring ..............................................................................................................16
2.5.3 Related/Supporting Documents ................................................................................................16
REQUIREMENTS ............................................................................................................................... 17
3.1
GENERAL REQUIREMENTS ...................................................................................................... 17
3.1.1 Open Access to Networks for Safe Operation ..........................................................................17
3.1.2 Redundancy ..............................................................................................................................17
3.1.3 Ownership and Plant Clauses ..................................................................................................18
3.1.4 Autonomy ..................................................................................................................................19
3.1.5 Interfaces ..................................................................................................................................19
3.1.6 Audits ........................................................................................................................................20
3.2
LEGAL AND REGULATORY REQUIREMENTS ......................................................................... 21
3.3
OPERATIONAL SAFETY ............................................................................................................ 22
3.3.1 Operational and Safety Aspects ...............................................................................................22
3.3.2 Means of Isolation .....................................................................................................................22
3.4
GENERATOR CAPABILITIES AND OPERATION ...................................................................... 23
3.4.1 Excitation Control and Governor Requirements .......................................................................24
3.4.2 Synchronisation ........................................................................................................................24
3.4.3 Islanded Operation ....................................................................................................................25
3.4.4 Voltage Ride Through Capabilities ...........................................................................................25
3.5
REQUIREMENTS FOR THE UTILITY NETWORK INTERFACE ................................................ 26
3.5.1 Fault Infeed ...............................................................................................................................26
3.5.2 Quality of Supply .......................................................................................................................26
3.5.3 Electromagnetic Compatibility...................................................................................................27
3.5.4 Neutral Earthing ........................................................................................................................28
3.5.5 Prevention of Out of Synchronism Closure ...............................................................................29
3.5.6 Requirements for Directional and/or Unit/DTT Protection ........................................................29
3.5.7 Auto-reclose Dead-time Settings on Networks with Embedded Generation ............................32
3.5.8 Tapchanger Requirements at the PUC for Connected EG .......................................................32
3.6
REQUIREMENTS AT THE PUC AND PGC ................................................................................ 34
3.6.1 Primary equipment ....................................................................................................................34
3.6.2 Protection ..................................................................................................................................35
3.6.3 DC Systems and Auxiliary Supplies .........................................................................................41
3.7
Metering ....................................................................................................................................... 42
SUPERVISORY CONTROL AND DATA ACQUISITION .................................................................... 43
4.1
GATEWAY EQUIPMENT ............................................................................................................. 43
4.2
PROTOCOLS FOR INFORMATION EXCHANGE ...................................................................... 43
4.2.1 SCADA Protocol between the EG and the Approved Gateway................................................44
4.2.2 SCADA Protocol between the Approved Gateway and Eskom Control Centre .......................44
4.2.3 SCADA Protocols within the EG system ...................................................................................44
4.3
TELECOMMUNICATION INTERFACE REQUIREMENTS ......................................................... 44
4.3.1 Option1: X.21 communication interface ....................................................................................45
4.3.2 Option2: UHF radio communication interface. ..........................................................................47
4.3.3 Option3: Satellite communication interface. .............................................................................49
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4.4
MINIMUM DATA EXCHANGE REQUIREMENTS ....................................................................... 51
4.4.1 Generator Availability and Forecast Production values ............................................................52
4.4.2 The concept of a Bay ................................................................................................................53
4.4.3 Double-bit Indications ...............................................................................................................54
4.4.4 Digital Input Signals From the EG ............................................................................................55
4.4.5 Analogue Input Signals .............................................................................................................55
4.4.6 Weather and Environmental Data .............................................................................................56
4.4.7 Command Function Requirements ...........................................................................................56
4.4.8 Data Communications Specifications .......................................................................................66
4.4.9 IEC 60870-5-101 Address Ranges ...........................................................................................66
4.4.10 Provision of the Signal Data and Substation Layout Information to Eskom .............................66
5
TESTS ................................................................................................................................................. 68
5.1
PRE-COMMISSIONING AND COMMISSIONING TESTS .......................................................... 68
5.2
MAINTENANCE TESTS .............................................................................................................. 69
6
AUTHORISATION ............................................................................................................................... 70
7
REVISIONS ......................................................................................................................................... 70
8
DEVELOPMENT TEAM ...................................................................................................................... 73
9
ACKNOWLEDGEMENTS ................................................................................................................... 74
Annex A – Impact Assessment ...................................................................................................................... 75
Annex B – Summary of generator connection types ..................................................................................... 79
Annex C – Summary of plant types ............................................................................................................... 80
Annex D – Protective Relay Type Test requirements ................................................................................... 81
Annex E – Residual over-voltage protection grading example ..................................................................... 83
Annex F – Eskom Approved Gateway ordering information ......................................................................... 84
Annex G – Detailed Signal list required between the EG and the Approved Gateway ................................. 85
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TABLES
TABLE 1-1: SOUTH AFRICAN CODES TECHNICAL AREAS OF RELEVANCE ................................................................6
TABLE 3-1: GENERATOR CAPABILITIES AND OPERATION .....................................................................................23
TABLE 3-2: TYPICAL SYNCHRONISING PARAMETER LIMITS (IEEE 1547 P.12) .......................................................25
TABLE 3-3: MAXIMUM V CHANGE AT DIFFERENT V LEVELS AS A FUNCTION OF THE FREQ. OF THESE V CHANGES.....27
TABLE 3-4: PUC MINIMUM PROTECTION REQUIREMENTS PER VOLTAGE LEVEL .....................................................35
TABLE 3-5: PGC PROTECTION REQUIREMENTS ..................................................................................................36
TABLE 3-6: MAXIMUM OPERATING TIMES FOR VOLTAGE PROTECTION ...................................................................37
TABLE 3-7: TYPICAL SETTINGS FOR LOSS-OF-GRID PROTECTION..........................................................................39
TABLE 4-1: EMBEDDED GENERATION CATEGORIES .............................................................................................51
TABLE 4-2 - XML DEFINITION FOR 6 HOUR FORECAST DATA.................................................................................52
TABLE 4-3: DOUBLE-BIT INDICATIONS .................................................................................................................54
TABLE 4-4: BAY-WIDE BINARY INDICATIONS ........................................................................................................55
TABLE 4-5: SWITCH STATE INDICATIONS .............................................................................................................55
TABLE 4-9: BAY ANALOGUES FROM THE EG SITE................................................................................................55
TABLE 4-10: BAY BINARY INDICATIONS ..............................................................................................................56
TABLE 4-11: EG ENVIRONMENTAL INPUTS ..........................................................................................................56
TABLE 4-12: COMMAND FUNCTIONS ...................................................................................................................57
TABLE 4-13: BREAKER COMMAND SIGNAL..........................................................................................................57
TABLE 4-14: PRIMARY FREQUENCY RESPONSE COMMAND ...................................................................................57
TABLE 4-15: PRIMARY FREQUENCY RESPONSE INDICATIONS ...............................................................................57
TABLE 4-16: AGC COMMANDS...........................................................................................................................58
TABLE 4-17: AGC INDICATIONS .........................................................................................................................58
TABLE 4-18: AGC ANALOGUES ..........................................................................................................................58
TABLE 4-19: CURTAILMENT COMMANDS .............................................................................................................59
TABLE 4-20: CURTAILMENT INDICATIONS ............................................................................................................59
TABLE 4-21: CURTAILMENT ANALOGUE ..............................................................................................................59
TABLE 4-22: GENERATION STOP/START COMMAND ............................................................................................60
TABLE 4-23: GENERATION STOP/START INDICATION ...........................................................................................60
TABLE 4-24: DELTA PRODUCTION COMMANDS ....................................................................................................61
TABLE 4-25: DELTA PRODUCTION BINARY INDICATIONS .......................................................................................61
TABLE 4-26: DELTA PRODUCTION ANALOGUES ...................................................................................................61
TABLE 4-27: POWER GRADIENT COMMANDS .......................................................................................................62
TABLE 4-28: POWER GRADIENT INDICATIONS ......................................................................................................62
TABLE 4-29: POWER GRADIENT ANALOGUES ......................................................................................................62
TABLE 4-30: REACTIVE POWER OUTPUT RANGES ...............................................................................................63
TABLE 4-31: Q MODE COMMANDS ......................................................................................................................64
TABLE 4-32: Q MODE BINARY INDICATIONS .........................................................................................................64
TABLE 4-33: Q MODE ANALOGUES .....................................................................................................................64
TABLE 4-34: POWER FACTOR COMMANDS ..........................................................................................................64
TABLE 4-35: POWER FACTOR BINARY INDICATIONS .............................................................................................65
TABLE 4-36: POWER FACTOR ANALOGUE ...........................................................................................................65
TABLE 4-37: VOLTAGE MODE COMMANDS ...........................................................................................................65
TABLE 4-38: VOLTAGE MODE BINARY INDICATIONS..............................................................................................65
TABLE 4-39: VOLTAGE MODE ANALOGUE ............................................................................................................65
TABLE 4-40: ESKOM ASDU INFORMATION OBJECT ADDRESS RANGE..................................................................66
TABLE 5-1: PRE-COMMISSIONING TESTS AT THE PUC AND PGC .........................................................................68
TABLE 5-2: COMMISSIONING TESTS ...................................................................................................................69
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FIGURES
FIGURE 3-1: LAYOUT OF HV NETWORK INDICATING THE TERMINOLOGY USED .....................................................31
FIGURE 4-1: X.21 COMMUNICATION INTERFACE (TRANSMISSION) ........................................................................46
FIGURE 4-2: X.21 COMMUNICATION INTERFACE (DISTRIBUTION) ..........................................................................47
FIGURE 4-3: UHF RADIO COMMUNICATION INTERFACE ........................................................................................48
FIGURE 4-4: SATELLITE COMMUNICATION INTERFACE. .........................................................................................50
FIGURE 4-5: SIMPLISTIC VIEW OF AN ESKOM—EG ELECTRICAL INTERFACE .........................................................54
FIGURE 4-6: MODE CHANGE HMI INTERFACE EXAMPLE ......................................................................................63
FIGURE B-1: GENERIC LAYOUT WITH SHARED EARTH MAT .................................................................................79
FIGURE B-2: RADIAL CONNECTION ....................................................................................................................79
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1 INTRODUCTION
This standard serves to fulfil Eskom‘s obligation under Section 8.2 (4) of the South African Distribution
Code: Network Code (SADCNC) which is applicable to all users of the distribution system and states the
following:
“The Distributor shall develop the protection requirement guide for connecting Embedded
Generators to the Distribution System to ensure safe and reliable operation of the Distribution
System”.
This standard sets out the minimum technical and regulatory requirements for the connection of Embedded
Generators (EG) to Eskom‘s EHV, HV and MV electrical networks. This standard therefore is inclusive of
Eskom Distribution‘s protection requirement guide.
Users must adhere to the Grid Connection Code for Renewable Power Plants (RPPs) in South Africa
(GCCRPPSA), the South African Grid Code (SAGC) and the South African Distribution Code (SADC)
requirements where relevant. The table inserted below briefly explains where the listed codes above are
technically relevant.
For information on pricing and contractual requirements with regard to the connection and operation of
Embedded Generators, the user is referred to Eskom Policy 34-193 Purchasing of energy from embedded
distribution generators or to Eskom Policy 240-68105435 Purchasing of Energy from Embedded Generation
Policy.
In this document, references to ‗Eskom‘ shall mean Eskom Holdings SOC Limited. In many instances, the
terms ‘Network Service Provider‘ or ‘Distributor‘ have been used in place of ‗Eskom‘ in anticipation of the
standard‘s broader application in the electricity distribution industry in South Africa (NRS 097). In this
context, ‗Network Service Provider‘ includes Eskom Transmission, Eskom Distribution and any Municipal
entity that might adopt this standard.
Table 1-1: South African Codes Technical Areas of Relevance
Code/
Standard
Relevance
Requirements/Capabilities Include
Omits
Refer To
GCCRPPSA
All RPPs
(the
GCCRPPSA
code takes
precedence)
System
Operating
Conditions
&
Response,
FRT,
Reactive,
QOS,
Protection,
Anti-islanding,
Power
Constraints, Control Functions, SCADA,
Forecasting,
Data
Communications,
Testing
&
Compliance,
Modelling
(including the Process)
Protection
Details, Antiislanding Details
Metering
This Standard
All EGs,
All Thermal,
All Hydro
Protection, Excitation, Reactive, Multiple SCADA Details
Unit
Tripping,
System
Operating
Conditions & Response, Governors
Metering
(>50MVA), FRT, Equipment Design
Standards, Earthing, QOS, System
Protection,
Planning,
Performance,
Forecasting, Integration
This Standard
All EGs
(except EHV
connected)
Connection Process, Responsibilities, SCADA Details
Protection, QOS, Earthing, Equipment
Requirements, Planning, Investment
Metering Details
Criteria, Metering, Connection Point,
Telemetry, Power Station Supplies
This Standard
SAGCNC
Section 3.1
SADCNC
Metering: Use
of System
Agreement
SAGC
Metering
Code
SADCMC
Metering: Use
of System
Agreement &
34-1024
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2 SUPPORTING CLAUSES
2.1 SCOPE
2.1.1 Purpose
This standard sets out the minimum technical and regulatory requirements for the connection of Embedded
Generators to Eskom‘s Medium Voltage (MV), High Voltage (HV) and Extra High Voltage (EHV) electrical
networks. As such and according to the categories as stipulated in the Grid Connection Code for
Renewable Power Plants in South Africa (GCCRPPSA), this standard is also applicable to Category B and
C Renewable Power Plants (RPP) but not Category A RPPs since this category only applies to Low Voltage
1
(LV) connected RPPs .
2.1.2 Applicability
This standard applies to systems where the generating plant may be paralleled with the Eskom MV, HV or
EHV network either permanently, periodically or temporarily. This standard does not apply to generating
plant that does not operate in parallel with the Eskom Grid (e.g., own use customer generators or stand-by
generators). Additionally this standard does not apply to Eskom owned generating plant that is not
categorised as renewable power plant. Eskom‘s requirements for stand-by generators are detailed in
ESKAGAAG2 (operation with alternative connection to the Eskom system), and the use of portable
generators is addressed in NRS 098. All requirements of ESKAGAAG2 pertaining to generators that are
operated in parallel with the Eskom network are superseded by the requirements of this standard.
The intention is that this interconnection standard, or one of broadly similar requirements, shall also apply to
Embedded Generators connecting to Municipal electricity networks which, in turn, are supplied by Eskom.
In this way, technical requirements for the point of connection between the Supply Authority and the
Embedded Generator need not be replicated between Eskom and the Supply Authority.
The standard provides for generic interconnection requirements and shall be applicable to all types of
generators, prime movers etcetera.
The standard applies to all Embedded Generation new builds.
1
For LV connected Embedded Generators please refer to the NRS097-2 series.
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2.2 NORMATIVE/INFORMATIVE REFERENCES
2.2.1 Normative
Parties using this standard shall apply the most recent edition of the documents listed below:
South African Legislation:
Electricity Regulation Act 4 of 2006, as amended.
Occupational Health and Safety Act No 85 of 1993.
South African Distribution Code (all parts).
South African Grid Code (all parts).
Grid Connection Code for Renewable Power Plants Connected to the Electricity Transmission System or
the Distribution System in South Africa (also called the ‗Grid Connection Code for RPPs in South
Africa‘).
International and National Standards:
IEC 60870-5-101: Telecontrol equipment and systems – Transmission protocols – Companion standard for
basic Telecontrol tasks.
IEEE 1815-2012: IEEE Standard for Electric Power Systems Communications—Distributed Network
Protocol (DNP3).
IEC 62116: Test Procedure of Islanding Prevention Measures for Utility-Interconnected Photovoltaic
Inverters.
IEC 62271-100: High-Voltage Alternating-Current Circuit-Breakers.
IEEE 1547: IEEE Standard for Interconnecting Distributed Resources with Electric Power Systems.
IEEE 1547.1, IEEE Standard Conformance Test Procedures for Equipment Interconnecting Distributed
Resources with Electric Power Systems.
NRS 029, Current transformers for rated A.C. voltages from 3,6kV up to and including 420kV.
NRS 030, Electricity distribution – Inductive voltage transformers for rated A.C. voltages from 3,6kV up to
and including 145kV for indoor and outdoor applications.
NRS 031, Alternating current disconnectors and earthing switches (above 1000V).
NRS 037-1, Telecontrol Protocol for stand-alone remote terminal units.
NRS 048-2, Electricity Supply – Quality of Supply Part 2: Voltage characteristics, compatibility levels, limits
and assessment methods.
NRS 048-4, Electricity Supply – Quality of Supply Part 4: Application guidelines for utilities.
NRS 054, Rationalized User Specification – Power Transformers.
NRS 098, Guidelines for the installation and safe use of portable generators on utilities‘ networks.
SANS 211 (CISPR11), Industrial, scientific and medical equipment - Radio-frequency disturbance
characteristics - Limits and methods of measurement.
SANS 222 (CISPR 22), Information technology equipment - Radio disturbance characteristics - Limits and
methods of measurement.
SANS 474 (NRS 057), Code of practice for electricity metering.
SANS 1019, Standard voltages, currents and insulation levels for electricity supply.
SANS 10200, Neutral earthing in medium voltage industrial power systems.
SANS/IEC 50065-1, Signalling on low-voltage electrical installations in the frequency range 3 kHz to 148,5
kHz Part 1: General requirements, frequency bands and electromagnetic disturbances.
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International and National Standards (Protective Relays):
IEC 60068-2-1, Environmental testing — Part 1 Cold.
IEC 60068-2-2, Environmental testing — Part 2 Dry Heat.
IEC 60068-2-30, Environmental testing — Part 30 Damp heat, cyclic (12h + 12h cycle).
IEC 60255-6, Electrical relays Part 6: Measuring relays and protection equipment.
IEC 60255-21, Electrical relays Part 21 Vibration, shock, bump and seismic tests on measuring relays and
protection equipment (All sections).
IEC 60255-22, Electrical relays Part 22 Electrical disturbance tests for measuring relays and protection
equipment (All sections).
IEC 60255-30, Electrical relays Part 3: Single input energizing quantity measuring relays with dependent
and independent time.
SANS IEC 60529, Degrees of protection provided by enclosures (IP Code).
SANS IEC 61000-4, Electromagnetic compatibility (EMC): Test and measurement techniques (All sections).
2
Eskom Standards :
DGL 34-1944, Network Planning Guideline for Embedded Generation (Steady State Studies).
DST_34-1985, MV and LV Reticulation Earthing.
DST_34-906, Medium Voltage Earthing Practice.
DSP_34-392, Specification for digital transducer based measurement system for electrical quantities.
DST_34-462, Standard design for Distribution protection schemes.
DST_34-540, Distribution Standard for the application of Sensitive Earth Fault protection.
DST_34-542, Distribution voltage regulation and apportionment limits.
DPL 34-680, Policy on access to meters, metering circuits and metering data.
DST_34-1024, Standard minimum requirements for the metering of electrical energy and demand.
ESKAGAAG2, Minimum requirements for the connection of non-Eskom generating plant to the Eskom
electrical networks (32-272).
ESKASAAW2, Generator excitation system standard for power stations (under review – Nico Jacobs).
GGS 36-1054, Eskom generator protection philosophy for gas turbine power stations with generator circuitbreaker (240-56356543).
TST_32-1101: IEC 60870-5-101 Master Station implementation standard.
240-59089329 DNP3 Implementation Standard.
TST_240-46264031: Fibre optic Design Standard – part 2 substations.
TST_240-42623618: Labelling of Fibre Optic Cables.
240-65692753, Standard for Apportionment of Quality of Supply Parameters for All Customers.
Eskom Test and Maintenance Procedures:
DPC_34-759, Maintenance of L/M/H range nickel cadmium batteries.
DPC_34-1033, Voltage transformer test procedure.
DPC_34-1034, Isolator test procedure.
2
Note: in cases where documents are still to be re-published using the revised document numbering system, the future
document classification and number is indicated in brackets following the existing reference code.
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DPC_34-1035, Current transformer test procedure.
DPC_34-1036, Procedure for testing of Circuit-Breakers.
DPC_34-1039, Procedure for the maintenance of D.C. supply equipment.
DPC_34-1043, Maintenance of vantage nickel cadmium cells.
DPC_34-1395, Over current and Earth fault relay test procedure.
Eskom Documentation:
DCUOSA, Distribution Connection and Use-of-System Agreement with Generators.
CUOSA, Connection and Use-of-System Agreement with Generators (Transmission).
2.2.2 Informative
BDEW Technical Guideline, Generating Plants Connected to the Medium-Voltage Network, June 2008.
Fieldstone report for NERSA. Development of Regulatory guidelines and qualifying principles for cogeneration projects. November 2006.
DST_32-326, Terminology relating to the direction of power flow.
DST_32-327, Functional measurement requirements for network management.
Electrical Safety Authority, Distributor Safety bulletin, DSB-07/11.
ESB Networks, Conditions Governing Connection to the Distribution System, Doc Ref: DTIS-250701-BDW,
March 2006.N. Jenkins, R. Allan, P. Crossley, D Kirschen, G Strbac. Embedded Generation.
IEC/SANS 61400, Wind Turbines.
IEEE 1547.2: 2008, Application Guide for IEEE Standard 1547.
IEEE Power and Energy series 31. 2000.
ISO 9001 Quality Management Systems.
Kinetrics Inc. Report no: K-418086-RA-001-R00, Technical review of Hydro One‘s anti-islanding criteria for
microfit PV generators, November 2011.
Network Protection & Automation Guide, Alstom, July 2002.
NRS 097-2, Small Scale Embedded Generation.
Protection Relays Application Guide, Third edition 1990. GEC Alsthom Protection & Control Ltd.
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2.3 DEFINITIONS
Automatic generation control (AGC): The automatic centralised closed-loop control of units by means of
the computerised EMS of the System Operator. Unit output is controlled by changing the setpoint on the
governor. [SAGC]
Co-generator: A source of electrical power that complies with types I, II or III below:
Type I: Projects utilizing process energy which would otherwise be underutilised or wasted (e.g.
waste heat recovery).
Type II: Primary fuel based generation projects which produce, as part of their core design, other
usable energy in addition to electricity (e.g. Combined Heat and Power projects).
Type III: Renewable fuel based projects where the renewable fuel source is both the primary
source of energy, and is a co-product of an industrial process (e.g. use of bagasse and/or forestry
waste from the sugar and paper industries).
Distributor:
[SAGC]
A legal entity that owns or operates/distributes electricity through a distribution system.
Distribution System: An electricity network consisting of assets operated at a nominal voltage of 132 kV
or less. [SAGC]
DNP3 protocol: DNP3 is the preferred protocol used for the Telecontrol of the South African distribution
systems as per NRS 037-1.
Embedded Generator’s authorised person: The person appointed by the Embedded Generator in terms
of the appropriate act to sanction the return to service of plant after major maintenance or repair.
Embedded Generator’s responsible person: The person appointed by the Embedded Generator in
terms of the appropriate act to receive communications and take necessary action in accordance with
instructions from the system controller.
Embedded Generator: A legal entity that operates or desires to operate any generating plant that is or
will be connected to the Grid at MV or HV levels and renewable power plant connected at EHV levels. This
definition includes all types of connected generation, including co-generators and renewables.
Alternatively, the item of generating plant that is or will be connected to the Grid at MV or HV levels and
renewable power plant connected at EHV levels.3
Extra High Voltage: The set of nominal voltage levels greater than 220 000 V and up to and including
400 000 V. [SANS 1019].
High Voltage: The set of nominal voltage levels greater than 44 000 V and up to and including 220 000 V.
[SANS 1019].
Island: The opening of a circuit breaker or circuit breakers resulting in the severance of the synchronous
connection between the Network Service Provider‘s network and the Embedded Generator, or between the
Network Service Provider‘s network and another section of the Network Service Provider‘s network
containing a Synchronised generator.
Loss-of-grid protection: Relay protection designed to detect the loss of connection to the utility network
and trip the Embedded Generator to prevent it from energising an island.
Low Voltage: Nominal voltage levels up to and including 1 000 V. [SANS 1019].
Medium Voltage: The set of nominal voltage levels greater than 1 000 V and up to and including
44 000 V. [SANS 1019]
Network Service Provider (NSP): A legal entity that is licensed to provide network services through the
4
ownership and maintenance of an electricity network . [SAGC]
3
A request for review has been lodged with the Grid Connection Code document Secretariat concerning this revised
definition for Embedded Generation.
4
For the purpose of this standard, the term ‘NSP’ refers to a Distributor and/or a Transmission Network Service
Provider whichever is relevant within the context used.
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Point of Common Coupling (PCC): The electrical node, typically a busbar, on the Network Service
Provider‘s network, electrically nearest to the Embedded Generator facility, at which more than one
customer is or may be connected or metered. The PCC is used in the context of Quality of Supply emission
requirements.
5
Point(s) of Connection (POC) : The electrical node(s) on the Network Service Provider‘s network where
the Embedded Generator‘s electrical equipment is physically connected to the Network Service Provider‘s
electrical equipment.
Point of Utility Coupling (PUC): The PUC may be located near the Point of Connection or may be some
other point(s) within the Embedded Generator‘s facility between the PGC and Point of Connection.
Point of Generator Connection (PGC): The circuit-breaker and associated ancillary equipment
(instrument transformers, protection, isolators) that connects a generator to any electrical network. Where
more than one such circuit-breaker exists, the PGC shall be the circuit-breaker electrically closest to the
generator.
Point of Secure Supply (PSS): That point on the Network Service Provider‘s network at which a single
upstream contingency will not result in the islanding of an Embedded Generator with a portion of the supply
network.
Point(s) of Supply (POS): The point(s) on the Network Service Provider‘s network from where electricity
is supplied to the Embedded Generator by the Network Service Provider, or from where the Embedded
Generator supplies electricity to the Network Service Provider.
Renewable Power Plant (RPP): A unit or a system of generating units producing electricity based on a
primary renewable energy source e.g. wind, sun, water, biomass, etc. A RPP can use different kinds of
primary energy sources. If a RPP consists of a homogenous type of generating units it can be named as
follows [RSA Grid Code Requirements for Renewable Power Plants]:
PV Power Plant (PVPP): A single photovoltaic panel or a group of several photovoltaic panels
with associated equipment operating as a power plant.
Concentrated Solar Power Plant (CSPP): A group of aggregates to concentrate the solar
radiation and convert the concentrated power to drive a turbine or a group of several turbines with
associated equipment operating as a power plant.
Small Hydro Power Plant (SHPP): A single hydraulic driven turbine or a group of several
hydraulic driven turbines with associated equipment operating as a power plant.
Landfill Gas Power Plant (LGPP): A single turbine or a group of several turbines driven by
landfill gas with associated equipment operating as a power plant.
Biomass Power Plant (BMPP): A single turbine or a group of several turbines driven by
biomass as fuel with associated equipment operating as a power plant.
Biogas Power Plant (BGPP): A single turbine or a group of several turbines driven by biogas as
fuel with associated equipment operating as a power plant.
Wind Power Plant (WPP): A single turbine or a group of several turbines driven by wind as fuel
with associated equipment operating as a power plant. This is also referred to as a wind energy
facility (WEF).
5
A request for review has been lodged with the Grid Connection Code for Renewable Power Plants in South Africa
document Secretariat concerning the following statement within the code, ‘A RPP has only one POC’ and the effect
it would have on parallel feeds. In the intervening time, this standard ignores the statement.
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Renewable Power Plant (RPP) Categories: Renewable power plants are grouped into the following three
categories [RSA Grid Code Requirements for Renewable Power Plants]:
Category A: 0 – 1 MVA (only LV connected RPPs). Typically called ‗small-‘ or ‗micro turbines‘.
This category shall further be divided into 3 sub-categories:
(i)
(ii)
(iii)
Category A1:
0 kVA ≤ x ≤ 13.8 kVA
Category A2: 13.8 kVA < x < 100 kVA
Category A3: 100 kVA ≤ x < 1 MVA
Note: RPPs with a rated power greater than 4.6 kVA must be balanced three-phase.
Category B: 1 MVA ≤ x < 20 MVA and RPPs less than 1MVA connected to the MV network.
Category C: 20 MVA ≤ x.
Stand-by generator: A legal entity that operates or desires to operate a generating plant so as to provide
a stand-by supply in the event of a loss of the grid electricity supply. The stand-by generator‘s plant will
only be connected to the Network Service Provider‘s network for maintenance load testing, and only if the
requirements of this standard have been fulfilled.
Synch-check: (Synchro-check) relay/function that electrically determines if the difference in voltage
magnitude, frequency and phase angle falls within allowable limits. Synch check allows the closing
conditions of a circuit breaker to be checked by inhibiting the closing circuit until approach of the correct
synchronising conditions [Protection Relay Application Guide: 1987].
Synchronising: The process of manually (synchroscope etc.) or automatically (synchronising unit)
controlling generation equipment to attain the conditions where the voltage magnitudes, frequency and
phase angle differences, of two independent electrical systems, fall within allowable limits so as to initiate
an interconnection between the two electrical systems.
System Operator:
The legal entity licensed to be responsible for short-term reliability of the
Interconnected Power System, which is in charge of controlling and operating the Transmission System
and dispatching generation (or balancing the supply and demand) in real time. [SAGC]
Thermal Generating Unit: A generating unit that uses heat (for instance the burning of fossil fuels) to
generate electricity (either through steam or internal combustion processes). This shall include coal,
concentrated solar power, nuclear and gas turbine units [SA Grid Code: The Scheduling and Dispatch
Rules].
Transmission System (TS): The TS consists of all lines and substation equipment where the nominal
voltage is above 132kV. All other equipment operating at lower voltages are either part of the Distribution
System or classified as transmission transformation equipment. [SAGC]
Transmission Network Service Provider (TNSP): A legal entity that is licensed to own and maintain a
network on the Transmission System . [SAGC]
2.3.1 Disclosure Classification
Controlled disclosure: controlled disclosure to external parties (either enforced by law, or discretionary).
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2.4 ABBREVIATIONS
Abbreviation
A.C. or ac
Alternating Current
AGC
Automatic Generator Control
ARC
Auto-reclose
ASDU
Application Service Data Unit
CB
Circuit Breaker
CT
Current Transformer
CUOSA
Connection and Use-of-System Agreement with Generators (Transmission)
D.C. or dc
Direct Current
DCUOSA
Distribution Connection and Use-of-System Agreement with Generators
DMS
Distribution Management System
DTT
Direct Transfer Trip
EG
6
Embedded Generator (includes Co-Generator)
EMC
Electromagnetic Compatibility
EMS
Energy Management System
FRT
Fault Ride Through
FTP
File Transfer Protocol
GCCRPPSA
HV
ICASA
The Grid Connection Code for Renewable Power Plants in South Africa
High Voltage
Independent Communications Authority of South Africa
IED
Intelligent Electronic Device (e.g., Protection Relay)
IPP
Independent Power Producer
I/O
Input/output Protection or Telecontrol Signals
JB
Junction Box
LV
Low Voltage
MCOV
MUT
MV
NEC/R
6
Description
Maximum Continuous Operating Voltage
Multiple Unit Tripping
Medium Voltage
Neutral Earthing Compensator with Resistor
NOD
Network Optimisation Department
NPD
Network Planning Department
NSP
Network Service Provider
PCC
Point of Common Coupling
The term is also used for Dispersed Generator or Distributed Generation (DG).
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Abbreviation
Description
PF
Power Factor
PGC
pu
POS
Point of Supply
POP
Point of Presence
PSS
Point of Secure Supply
PUC
Point of Utility Connection
PVPP
Photovoltaic Power Plant
RTU
Remote Terminal Unit
RVC
Rapid Voltage Changes
The South African Distribution Code: Metering Code
SADCNC
The South African Distribution Code: Network Code
The South African Grid Code: Metering Code
SAGCNC
The South African Grid Code: Network Code
SCOT
SEF
SO
SOD
TNSP
TOV
The South African Grid Code: System Operation Code
Supervisory Control and Data Acquisition (aka. Telecontrol)
Steering Committee for Operational Technology
Sensitive Earth Fault
System Operator
System Operator Department
Transmission Network Service Provider
Temporary Over-voltage
TS
Transmission System
VRT
Voltage Ride Through
VT
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The South African Grid Code
SAGCMC
SCADA
Page:
The South African Distribution Code
SADCMC
SAGCSOC
1
Rate of Change of Frequency (protection)
Renewable Power Plant
SAGC
Revision:
Quality of Supply
RPP
SADC
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POC
QOS
7
INTERCONNECTION
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Voltage Transformer
Often called LVRT (low voltage ride through) or Withstand Capability.
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2.5 ROLES, RESPONSIBILITIES, MONITORING AND DOCUMENTATION
2.5.1 Roles and Responsibilities
The SCOT IPP Operations Care-Group are responsible for the implementation of this standard within
Eskom (inserting it within the Eskom processes) whilst the various Control Plant sections in the Project
Engineering Departments are responsible for the application of the standard. The standard DGL 34-1944
states that it is mandatory for Distribution Planners to familiarise themselves with this standard. Substation
Design national team members should also familiarise themselves with this standard as it impacts on the
various primary plant designs.
The SCOT Protection and Automation Study Committee together with the Telecontrol/SCADA Study
Committee, Measurements Study Committee and DC Study Committee are responsible for the accuracy of
this standard.
The EGs must adhere to the minimum requirements of this standard as partial fulfilment in order to connect
to the Network Service Provider‘s network.
2.5.2 Process for Monitoring
Any revision of the Grid Codes referenced within this standard shall initiate a review of the relevancy and
accuracy of this standard. The SCOT IPP Operations Care-Group shall be responsible for the initiation of
the review.
2.5.3 Related/Supporting Documents
The following documents or parts of documents are superseded by this standard:
a) Revision 0 of the Eskom standard 34-1765.
b) Requirements of ESKAGAAG2 pertaining to generators that are operated in parallel with the
Eskom network are superseded by the requirements of this document .
The most recent revision of this standard shall be inserted in the Appendices of the Agreements, DCUOSA
and CUOSA.
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3 REQUIREMENTS
3.1 GENERAL REQUIREMENTS
By way of introduction to the detailed technical requirements of subsequent sections, this section serves to
outline the broad principles on which the standard is based.
3.1.1 Open Access to Networks for Safe Operation
An Embedded Generator (EG) may connect to the Network Service Provider‘s network at any time provided
safety can be assured.
EGs are required to operate within regulated power quality limits. Eskom and the Municipalities are held
liable for deviations from regulated power quality limits that their customers may experience. Therefore no
EG shall continue to energise any portion of the network that has been unintentionally islanded on a section
of the Network Service Provider‘s network. Disconnection shall occur at the PUC upon detection of an
unintentional island. The primary concern is for human safety, plant protection and power quality, in that
order.
The National Transmission System Operator or Regional Network Optimisation Departments reserve the
sole right to permit the operation of intentional islands within the Eskom network. EGs permitted to operate
intentional islands shall adhere to the procedures and operating requirements as stipulated by the
applicable System Operator.
The EG shall be responsible for protecting its own assets. Notwithstanding this, unnecessary tripping of
EGs presents quality of supply and network stability problems and should be avoided where possible. The
design philosophy, equipment used and settings applied to anti-islanding protection equipment will impact
on the number of unnecessary trips obtained over the life of the EG (nuisance tripping).
Safe operation of the power system, its stability and security of supply are paramount and require that the
Network Service Provider be responsible for specifying predetermined minimum Protection, Measurements
and SCADA requirements to the EG.
As per the South African Distribution Code requirement, a circuit breaker and visible isolation shall be
installed at the connection point to provide the means of electrically isolating the distribution system from
the generating facility. The requirement stated above shall also apply to the transmission system.
It is the responsibility of the EG to establish synchronism between the EG‘s network and the Network
Service Provider‘s Grid supply prior to paralleling the two networks. Detailed technical and regulatory
requirements for synchronising onto the power network are stipulated in Section 3.4.2.
The neutral earthing philosophy to be applied shall be in accordance with Section 3.5.3.
Where it is necessary for Eskom to provide any electrical lines, or other electrical plant, or for any other
works to be carried out to enable the connection of embedded generation to its networks, Eskom may
require payments in respect of any expenditure incurred in carrying out this work.
The EG will be accountable for the cost to establish a communications infrastructure to the nearest Eskom
Telecoms Point of Presence and if differential and/or intertripping circuits are required, to the associated
Eskom substation.
3.1.2 Redundancy
The failure of any single component or system will not result in unsafe operation. Thus:
a) No generator shall be connected to a Network Service Provider‘s network via a single circuitbreaker.
b) Primary system protection provided at the PUC shall be duplicated elsewhere within the EG‘s
facility. The protection requirements are dealt with in Section 3.6.2.1.
c) Loss-of-grid protection as detailed in Section 3.6.2 shall be provided at the PUC by the EG or if the
NSP owns the PUC circuit breaker(s), then loss-of-grid protection must be applied on the first circuit
breaker(s) owned by the EG that can become an islanding point. Note that this protection shall be
either the main or back-up loss-of-grid protection dependant on the governing criteria (refer to
Section 3.6.2. for detailed requirements). Loss-of-grid protection and system integrity checks shall
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be provided elsewhere in the Network Service Provider‘s network (e.g., DTT, live-line close
blocking etc.).
d) The DC supplies at the Point of Utility Connection (PUC) and Point of Generator Connection (PGC)
shall be independent of one another and shall be subject to continual monitoring, both locally and
remotely by the owner of the equipment.
e) EHV connected RPP‘s shall include dual redundancy on protection, control, D.C. supplies (double
banks) and teleprotection circuits.
3.1.3 Ownership and Plant Clauses
The POC represents the point of demarcation between the Network Service Provider and the EG, examples
of which are given in Annexure B. This standard does not stipulate the specific ownership of plant used at
the PUC. The only exceptions are the Eskom metering equipment and communications infrastructure.
These will be Eskom owned, operated and maintained. Specifics regarding the ownership of other plant,
including the instrument transformers, must be agreed between the participants. It is preferred that Eskom
owns the instrumentation transformers that supply the Eskom metering circuits.
The following ownership regimes are possible:
Regime 1
The EG owns, operates and maintains the PUC circuit-breaker(s) and there is no Distributor
circuit breaker(s) between the PUC circuit breaker(s) and the Distributor busbars. Specifically, the
EG shall own the circuit-breaker(s) and associated instrument transformers and protection and
the isolator(s) to be installed between the PUC circuit-breaker(s) and the Distributor‘s network.
The Distributor‘s network would consist of a busbar isolator and instrument transformers for
metering. The specific point of demarcation between the Distributor and the EG shall be the
Distributor-side terminals of the isolator(s) (POC). The clamps or cable terminations made at this
point shall be the responsibility of the Distributor.
There were a number of installations accepted in Bid Round 1 where the Distributor did not own
or control a circuit breaker (i.e., the EG connected directly to the Distributor busbars as above via
their own PUC circuit breaker). Subsequently, a decision was made by the Eskom Substation
Working Group in September 2012 that Eskom shall always have control and ownership of at
least one circuit breaker per feeder (i.e., at a minimum this circuit breaker would be the circuit
breaker closest to the Eskom busbars). Thus this standard does not currently support an EG
owned PUC circuit breaker directly connected to the Eskom busbars.
OR
Regime 2
The EG owns, operates and maintains the PUC circuit-breaker(s). Specifically, the EG shall own
the circuit-breaker(s) and associated instrument transformers and protection and the isolator(s) to
be installed between the PUC circuit-breaker(s) and the Network Service Provider‘s network. The
specific point of demarcation between the Network Service Provider and the EG shall be the
Network Service Provider-side terminals of the isolator(s) (POC). The clamps or cable
terminations made at this point shall be the responsibility of the Network Service Provider.
The Network Service Provider will control and own at least one circuit breaker per feeder (i.e. at a
minimum this circuit breaker would be the circuit breaker closest to the Network Service Provider
busbars). In circumstances where the Network Service Provider owns the powerline which
terminates at the POC, the Network Service Provider shall have its own isolator for safety unless
a double-lock mechanism is fitted on the POC isolator.
In certain network layouts, the Network Service Provider may require external protection trip
inputs into the EG owned PUC protection and control circuits.
OR
Regime 3
The Network Service Provider owns, operates and maintains the PUC equipment. Specifically,
the Network Service Provider shall own the circuit-breaker(s) and associated instrument
transformers and protection and the isolator to be installed between the PUC circuit-breaker(s)
and the EG‘s facility. The specific point of demarcation between the Network Service Provider
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and the EG shall be the EG-side terminals of the isolator(s) (POC). The clamps or cable
terminations made at this point shall be the responsibility of the EG. The EG shall have its own
isolator for safety.
The Network Service Provider will never own the PUC on a shared feeder (i.e., a feeder that has
both customers and EG connected).
The EG will require external protection trip inputs into the Network Service Provider owned PUC
protection and control circuits to meet the stipulated EG related PUC protection requirements as
discussed in section 3.6.2.
Regime 1 ownership is not supported within this standard.
Regime 2 ownership is the preferred case.
It is preferred that the Network Service Provider owns the feeder power lines.
It is preferred that the EG builds the infrastructure and hands over the Network Service Provider‘s assets
upon completion.
Each party shall be responsible for the commissioning, operation and maintenance of plant installed on
their side of the POC.
The Eskom-owned metering and QOS instrumentation, Remote Terminal Units (RTU) and communications
infrastructure will be commissioned, operated and maintained by Eskom irrespective of its specific location.
All equipment at the PGC(s) shall be owned, operated and maintained by the EG.
For EHV, HV and MV connections, the PUC and PGC breakers shall be separate.
For EG‘s connected at 220 kV or greater, only dedicated feeders shall be allowed.
It is preferred that EG‘s connected at all voltage levels, but especially at HV levels, are connected using
dedicated feeders. Loop in/out substations must not cause any degradation of the system integrity (i.e., the
protection of the network with regard to security, reliability and stability shall not be compromised when the
EG is connected).
Zero sequence currents on the Network Service Provider‘s network and EG plant shall be decoupled from
one another.
3.1.4 Autonomy
Each party is to design, protect and maintain their own assets to industry best practice. The POC
represents the point of connection and is also the demarcation between the Network Service Provider and
the EG. The PUC represents a point of common interest. The standard provides minimum technical
requirements for the equipment and functionality to be provided at the PUC. The PGC provides back-up to
the protection functions of the PUC, and is also subject to minimum technical requirements imposed by the
Network Service Provider and the Grid Codes.
All of the required PUC functionality shall be provided at the PUC or in exceptional circumstances at an
alternate location agreed to by both parties. All of the required functionality shall be provided at the same
location. Any changes to the PUC or PGC will be agreed between the parties prior to implementation.
3.1.5 Interfaces
Where the Network Service Provider and EG substations are adjacent to each other, the following clauses
are relevant:
a) The earth mats shall be bonded together.
b) A Customer Interface Junction Box (JB) shall be provided and furnished with all the required I/O
and/or interface relays and connections for the Protection circuits, CT circuits, VT circuits and
shared buszone wiring (if applicable). If the JB is situated in a yard, it should preferably be
mounted on its own support structure and shall be connected to the earth mat as per the relevant
NSP standard for earthing. For easy access to the shared JB, both by Network Service Provider
and EG personnel, it is recommended that if the JB is situated in a yard then the JB should be
placed at the fence line in a separate enclosure, with a gate to the EG yard and a gate to the NSP
yard. This enclosure may also serve as a controlled access point between the two yards during
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commissioning and maintenance. The gates shall have a mechanism that provides the option for
8
two locks .
Refer to SCADA Chapter 4 for preferred Telecontrol and remote indication interface options.
c) Where Fibre Optical cables are used they should not be connected through this Interface JB as it
would constitute another point of potential failure.
d) Where copper Solkor is used it should be wired through the Interface JB (with suitable insulation
applied) as it would also be a point of test during fault-finding.
In the case where the Network Service Provider substation is not adjacent or the earth mats are not bonded
together, all connections between the two yards shall be fibre optical for the I/O.
3.1.6 Audits
Owing to the strong interdependence between the EG and the Network Service Provider, and so as to
avoid a requirement for duplication of equipment as far as possible, either party is entitled to perform
technical audits of the other‘s equipment relevant to the interconnection. This specifically includes the PUC
and PGC equipment and the metering equipment. Audits shall be performed with a minimum notice of 24
hours.
8
The double lock mechanism would be used during commissioning/maintenance when one party worked on circuits
within the JB and required limiting the access due to safety concerns.
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3.2 LEGAL AND REGULATORY REQUIREMENTS
The Electricity Regulation Act 4 of 2006 details the legislative requirements with regard to the generation,
transmission, distribution and trading of electricity. In this regard, the Operator of a Grid-connected
generator is required to hold a licence from the Regulator (Section 8). Operators of non-grid connected
generators are not required to hold a license provided that the plant is designated only for own-use and is
not used commercially (Schedule II).
Section 47 (1) of the Act makes provision for the Regulator to, following consultation with licensees and
other participants, set guidelines and publish codes of conduct and practice. The South African Grid Code,
Grid Code Requirements for Renewable Power Plants and Distribution Code are examples of such codes
of practice.
The South African Distribution Code includes a section of specific requirements for the connection of EG‘s.
The Distribution Network Code (Section 8.4.1.1 (1)) requires that all EG‘s of nominal capacity greater than
10 MVA shall in addition to the other requirements of the Distribution Code, also comply with the protection
requirements of Section 3.1 of the South African Grid Code: Network Code.
Under Section 8.2 (4) of the South African Distribution Code: Network Code, each South African Distributor
is required to develop a protection requirement guide for the connection of EG‘s. This standard serves to
fulfil Eskom‘s obligation in this regard.
Each EG installation must be designed to comply with the Grid Code, Distribution Code, Grid Code
Requirements for Renewable Power Plants and the Eskom NSP requirements detailed in this standard.
The South African Grid Code Requirements for Renewable Power Plants takes precedence whenever there
is a conflict between it and the other Codes.
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3.3 OPERATIONAL SAFETY
3.3.1 Operational and Safety Aspects
The EG must obtain from the relevant Network Service Provider a written agreement to operate generating
equipment in parallel with the Network Service Provider‘s network once NERSA has licenced the entity. A
plant diagram and schedule giving details of ownership, operation, maintenance and control of substation
and generation plant shall be prepared, as agreed between the parties. The schedule shall include:
a)
Names and contact details of responsible persons from both parties.
b)
A description of any operating limitations with regard to the plant and/or the interconnection.
The EG shall ensure that all operating personnel are competent in that they have adequate knowledge and
sound judgment to take the correct action when dealing with an emergency. Failure to take correct action
may jeopardize the EG‘s and/or the Network Service Provider‘s systems.
EGs shall ensure that;
a)
Except in the case of agreed unmanned facilities, a responsible person is available at all times to
receive communications from Eskom‘s Control Centre so that emergencies requiring urgent action
by the EG can be dealt with adequately. Where required by Eskom, it will also be a duty of the
EG‘s staff to advise Eskom‘s Control Centre immediately of any abnormalities that occur on the
Embedded Generating plant which have caused, or might cause, disturbance to the Network
Service Provider‘s network;
b)
In the case of unmanned facilities, the Network Service Provider will have remote control facilities
9
to trip and isolate the facility at the EG Feeder circuit breaker or if not available, at the PUC. The
Network Service Provider shall not control the PGC circuit breaker directly.
c)
Where it is necessary for their employees to operate Eskom equipment (where provided), they
have been designated in writing by Eskom as an ‗authorised person‘ for this purpose. All
operations on the Eskom equipment must be carried out to the specific instructions of the Eskom
Control Centre. In an emergency, a switch can be opened by anybody, without prior agreement in
order to avoid danger. The operation must be reported to the Eskom Control Centre immediately
afterwards.
3.3.2 Means of Isolation
Every installation or network which includes an Embedded Generating plant must include a means of
isolation, suitably labelled, capable of disconnecting the whole of the Embedded Generating plant in-feed
from the Network Service Provider‘s network.
The means of visible-break isolation must be lockable, in the open position only, by a padlock. Rackable
indoor metal clad switchgear is deemed acceptable for this function, provided that it is lockable.
The EG must grant the Network Service Provider rights of access to the means of isolation without undue
delay. The Network Service Provider shall have the right to reasonably isolate the EG‘s network connection
at any time as network conditions dictate. The means of isolation will normally be installed at the EG feeder
circuit breaker, alternatively at the PUC or at both points with the Network Service Provider‘s written
agreement.
9
Note that in the case of RPPs, under the heading ‘Control Signals’ the GCCRPPSA states that it shall be possible for
the Distributor to send a trip signal to the circuit breaker at the HV side of the POC.
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3.4 GENERATOR CAPABILITIES AND OPERATION
The various codes, standards and sources that govern the requirements and settings for excitation control,
governors, normal and abnormal voltage and frequency ranges, reactive capabilities and Voltage Ride
Through (VRT)/Fault Ride Through (FRT) response of RPPs/EGs are summarised in the following table:
Table 3-1: Generator Capabilities and Operation
Plant
Requirement
Governing Source
Overriding Criteria
RPPs: ≥
0 MVA on
MV/HV/EHV
.
Excitation control,
V & f ranges,
frequency
response, VRT,
reactive power
capabilities, power
constraint
functions.
Detailed
capabilities, ranges
and settings in
GCCRPPSA.
• Un for normal conditions initially determined
by NPD, dynamically by SOD/NOD in
consultation with RPP.
• SOD/NOD decides frequency control droop &
power-frequency response frequency defaults.
• Category B/C: Control Mode & Operating
point initially determined by NPD, dynamically
by SOD/NOD.
• Category B/C: Power constraint initiated by
SOD/NOD dynamically.
RPPs: All
Thermal &
Hydro on
MV/HV/EHV
.
Excitation control,
V & f ranges,
frequency
response, reactive
power capabilities,
power constraint
functions, power
system stabilisers,
MUT risks, VRT.
Detailed
capabilities, ranges
and settings in
GCCRPPSA and
capabilities,
synchronous power
system stabilisers
in SAGCNC/
SAGCSOC.
• As above.
• GCCRPPSA takes precedence.
• RPP to categorise MUT risk only if rated MW
> 920 MW, no MUT1 trip, MUT2 trip 1/10year
period – SOD to determine risk.
• VRT: GCCRPPSA takes precedence over
SAGCNC.
RPPs: All
Thermal &
Hydro >
50 MVA on
MV/HV/EHV
Governor
capabilities.
Turbo-alternators
and hydroalternators detailed
in SAGCNC &
SAGCSOC.
• GCCRPPSA takes precedence.
• SOD requirement for Governor capabilities
may override the > 50 MVA minimum level
clause (i.e., stipulate a lower level).
EGs: ≥
0 MVA on
MV/HV
excluding
RPPs.
Excitation control,
reactive
capabilities, power
system stabilisers,
MUT risks, VRT
capabilities.
Detailed capabilities
in SAGCNC and
limits in SAGCSOC,
detailed ranges and
settings for VRT
criteria in SAGCNC,
synchronous power
system stabilisers
in SAGC.
• Excitation settings initially determined by NPD
in consultation with EG, dynamically by
SOD/NOD in consultation with EG. Normal
operating range detailed in SAGCSOC, defined
voltage initially determined by NPD and
supplied in Connection & Use-of-System
Agreement, dynamically by SOD/NOD in
consultation with EG.
• Connection & Use-of-System Agreement
gives PF range at rated Power (MW)
determined by NPD in consultation with
SOD/NOD (default synchronous: 0.85lag < PF
< 0.95 lead). Reactive Power to be variable
between these limits.
• EG to categorise MUT risk only if rated MW >
920 MW, no MUT1 trip, MUT2 trip 1/10 year
period – SOD to determine risk.
• VRT: Required for all EG. Requirement may
be overridden or decreased by SOD decision.
EGs: >
50 MVA on
MV/HV
excluding
RPPs
Governor
capabilities.
Turbo-alternators
and hydroalternators detailed
in SAGCNC &
SAGCSOC.
• SOD requirement for Governor capabilities
may override the > 50MVA minimum level
clause (i.e., stipulate a lower level).
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3.4.1 Excitation Control and Governor Requirements
The EG shall consult the Network Service Provider‘s standards and shall familiarise themselves with the
local operating conditions. The EG‘s normal operation shall not cause conditions on the network which are
outside the accepted power quality standard limits. The generator‘s excitation control mode must best suit
the local environmental conditions.
10
The South African Grid Code Requirements for Renewable Power Plants states that all thermo and hydro
units shall comply with the design requirements specified in the South African Grid Code (specifically
section 3.1 of the Network code). Section 3.1 of the South African Grid Code Network Code details,
amongst other items, the excitation system requirements, the reactive capabilities, the governor controls
(governor controls mandatory for units > 50 MVA), mandatory power system stabilisers, the external supply
disturbance withstand capability and testing and compliance monitoring. The South African Grid Code
Network Code, Section 3.1 also has relevance concerning Embedded Generation which is not deemed to
be renewable.
All EG units that are not designated as RPP‘s and are of nominal capacity larger than 50 MVA shall
conform to the continuous and short-duration frequency operating limits outlined in the Section 3.1.6
(Governing) of the South African Grid Code: Network Code. The same section of the code also stipulates
the frequency vs. guaranteed operating time capability, as well as the requirements for governor control
using a droop characteristic, required by turbo-alternators.
With regard to voltage, frequency, reactive power, VRT control and response, RPPs shall comply with
sections 5 – 7 of the South African Grid Code Requirements for Renewable Power Plants.
3.4.2 Synchronisation
All Embedded Generating plant other than mains excited asynchronous machines must be synchronised
with the Eskom supply prior to making the parallel connection. For mains excited asynchronous machines
the responsibility rests with the EG to prove that the EG cannot self-excite prior to being connected,
alternatively a dead EG bar voltage check interlock on the PUC breaker must be installed.
Where the mode of operation of generating equipment is such that frequent synchronising of a machine or
machines will occur, the EG will ensure compliance with the rapid voltage change requirements stipulated
within NRS 048-4 (refer to Section 3.5.2.).
Automatic synchronising equipment shall be the preferred method of synchronising. However, manual
synchronisation of the EG units is permissible on condition that synchronising check relays (three phase
comparators) are used by the EG in conjunction with the manual synchronising, and that the EG‘s
responsible person is authorised in writing to do so. Synchronising shall occur using all three phases on
both sides of the circuit breaker and shall only occur either at the PUC circuit breaker if owned by the EG or
within the EG plant (i.e. it is not a requirement to apply synchronising facilities on the Network Service
11
Provider network past the POC) . If synchronising occurs within the EG plant and not at the PUC, then
synch check or a dead EG bar voltage check interlock on the PUC breaker must be installed.
The SADCNC states that it is the responsibility of the EG to provide synchronising facilities and to
synchronise within agreed limits. Section 5.1.1 of the South African Grid Code Requirements for
Renewable Power Plants states governing times for connection and voltage and frequency ranges at the
Network Service Provider‘s POC for connection or synchronising (EG plant other than RPPs shall also
adhere to these requirements). The voltage between the unit and the system prior to synchronising shall
not differ by more than the values specified in Table 3-2 below:
10
Please note that the SA Grid Code: The Scheduling and Dispatch Rules define ‘thermal’ as including coal,
concentrated solar power, nuclear and gas turbine units. The author believes that in the context used here (i.e., by
GCCRPPSA), it was meant for thermally driven rotating units.
11
The statement does not preclude the Network Service Provider or EG from applying ‘synch-check’ or dead-line
checks elsewhere.
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Table 3-2: Typical synchronising parameter limits (IEEE 1547 p.12)
Aggregate rating of EG
(kVA)
Maximum
Frequency
Difference
f (Hz)
Maximum
Voltage
Difference
V (%)
Maximum
Phase Angle
Difference
(Degrees)
S < 500
0.3
10
20
500 ≤ S < 1500
0.2
5
15
S ≥ 1500
0.1
3
10
3.4.3 Islanded Operation
Intentional islanding of a generator with part of the Eskom network is not permitted unless specifically
agreed to with Eskom. Refer to the Eskom policy for neutral earthing of electrical networks (DPL 34-2149)
for the permitted earthing arrangements under islanded conditions.
For unintentional islanding, where a generator is synchronised with the Eskom network at the time that an
upstream Eskom circuit breaker opens, severing the connection between the generator supply and the grid
supply, the Eskom Connection and Use-of-System Agreement and the South African Grid Code for
Renewable Power Plants for Category B and C, requires detection by the EG and shutting down of
12
generation within 2 seconds . If at any stage it is found that the EG is in breach of the above condition or
could be in breach of the above condition and the EG is not linked to the PSS via a dedicated feeder, it
shall be mandatory to retrofit direct transfer trips that operate the PUC circuit breaker from all of Eskom‘s
13
circuit breakers up to the PSS at the cost to the EG.
3.4.4 Voltage Ride Through Capabilities
The voltage ride through capabilities that the EG shall comply with are specified in Section 5.2.1 of the
South African Grid Code Requirements for Renewable Power Plants and in Section 3.1.9 of the South
African Grid Code Network Code for EG that is not deemed renewable (non-renewable EG).
Maximum disconnection times for various under- and over voltage levels for non-renewable EG are
stipulated in Section 3.6.2.4 of this standard.
12
Internationally values ranging from a Class 3 DTT to 2 s are found.
13
Operate time of ≤ 100 ms which includes the communication end to end time and the circuit breaker switching time.
Internationally, times obtained range from Class 3 to 100 ms.
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3.5 REQUIREMENTS FOR THE UTILITY NETWORK INTERFACE
3.5.1 Fault Infeed
When it is proposed to install Embedded Generating plant, consideration must be given to the contribution
that the plant will make to the fault levels on the Network Service Provider‘s network. The design and safe
operation of the EG‘s and the Network Service Provider‘s installations depend upon accurate assessment
of the fault contributions made by all plant operating in parallel at the instant of the fault. The EG shall
discuss this with the relevant Network Service Provider at the earliest possible stage. The EG shall provide
all relevant information for the Network Service Provider to be able to model the generator and its
contribution to fault current over time. The fault current in-feed over time must be confirmed in writing to
NPD by the EG using the format presented in the Standard IEEE 1547, Table 6: Generator short-circuit
current and reactance versus time.
Should the EG result in the increase of fault levels to such an extent that the Network Service Provider‘s or
Customer‘s plant at the PCC is placed at risk, the EG shall apply fault current limiting measures to ensure
that the fault levels are maintained at acceptable levels. The fault limiting solution applied shall be
presented to the Network Service Provider for acceptance prior to implementation.
3.5.2 Quality of Supply
Power quality and voltage regulation impact shall be monitored at the POC and shall include an
assessment by the Network Service Provider of the impact on power quality from the EG concerning the
following disturbances at the POC:
a) voltage fluctuations:
(i)
rapid voltage changes (RVC)
(ii)
flicker
b) high-frequency currents and voltages:
(i)
harmonics
(ii)
inter-harmonics
(iii)
disturbances greater than 2 kHz.
c) unbalanced currents and voltages:
(i)
deviation in magnitude between three phases
(ii)
deviation in angle separation from 120° between three phases.
Note that the EG will generally follow the supply network frequency; any attempt by the EG to change the
supply frequency may result in severe distortion of the voltage at the POC, PCC and other points in the
network.
Voltage and current quality distortion levels emitted by the EG at the POC shall not exceed the apportioned
limits as determined by the Network Service Provider. The calculation of these emission levels shall be
undertaken according to the standard 240-65692753 in line with NRS 048-4. The EG shall ensure that the
EG is designed, configured and implemented in such a way that the specified emission limit values are not
exceeded.
Voltage changes shall be limited according to minimum values provided in Table 3-3 below. These limits
apply at the full range of fault levels and network impedance angles at the POC of the EG, regardless of
contingencies that may exist on the network.
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Table 3-3: Maximum V change at different V levels as a function of the freq. of these V changes.
Number of changes per hour
Percentage Change in the Voltage
(r)
nominal voltage at PCC
r <1
4
3
1 < r <=10
3
2,5
10 < r <=100
2
1,5
100 < r < 1000
1,25
1
44 kV
nominal voltage at PCC > 44 kV
The EG can assume that the network harmonic impedance at the POC will be less than 3 times the base
harmonic impedance for the range of reference fault levels at the POC. That is the network harmonic
impedance shall not exceed a harmonic impedance of:
Z ( h)
2
3* VS * h
where h is the harmonic number, V is the nominal phase-to-phase voltage in kV, and S is the fault
level in MVA. The angle of the network harmonic impedance may range from fully inductive to fully
capacitive.
In order to assist with the maximum resonance of 3 times, no EG may connect equipment (e.g., shunt
capacitor banks) that will cause a resonance of more than three times at the POC at any frequency.
There shall be main and check QOS instruments if the main and check metering instruments are not used.
3.5.3 Electromagnetic Compatibility14
Electromagnetic Compatibility (EMC) entails the coordination of all electromagnetic disturbances emitted by
a device or an installation as well as the susceptibility of devices to electromagnetic disturbances.
Electromagnetic disturbances may be radiated or conducted.
In the event of susceptibility to both radiated and conducted electromagnetic interference, the EG shall be
fail-safe (i.e., any deviation from intended performance must comply with all relevant specifications), both in
terms of safety (i.e., disconnection) and impact on the network.
Radiated interference shall be tested according to relevant clauses of SANS 211 (CISPR11) or SANS 222
(CISPR 22) and test certificates provided. Whilst these tests will typically be for units of the EG, reasonable
assurance of compliance at the EG boundaries will be required.
Conducted interference shall be tested according to SANS/IEC 50065-1 in the frequency range 3 kHz to
15
148.5 kHz and with SANS 211 (CISPR11) above 148.5 kHz, using limits for Class B group 1 equipment.
Exceedance of emission limits of SANS 211 and SANS/IEC 50065-1 may be temporarily allowed, provided
that no interference exists to existing PLC, smart grid or other communication protocols implemented by the
Network Service Provider. Should interference occur in future, the temporary exemption will be retracted
and the EG will have to reduce intentional and unintentional emissions to levels acceptable to the Network
Service Provider.
14
The IEC is presently dealing with a specification for EMC requirements with regard to EG. Once the IEC
specification is issued, this standard shall be updated.
15
The start frequency given in SANS 211 is 150 kHz; however, to avoid the existing gap, limits applying at 150 kHz
will be extrapolated down to 148.5 kHz.
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3.5.4 Neutral Earthing
The neutral earthing philosophy to be applied on EG networks that are galvanically connected to the Eskom
supply network shall comply with the Eskom Standard DPL_34-2149 for neutral earthing of electrical
networks. Adequate earthing of networks at other voltage levels within the EG plant is the responsibility of
the EG and is not stipulated herein.
The Network Service Provider‘s networks may use effective, resistive or reactive earthing methods
depending on the voltage level and local requirements. The magnitude of the possible earth fault current
will depend on which of these methods is used. The EG‘s earthing arrangement must therefore be
designed as follows:
a)
In consultation with the Network Service Provider such that the EG‘s system is compatible with
the Network Service Provider‘s network.
b)
Such that the EG‘s plant safety is not compromised due to the above requirement.
The actual earthing arrangements will also be dependent on the number of machines in use and the EG‘s
system configuration and method of operation. Earthing within the EG plant could be achieved by the use
of a busbar earthing transformer (e.g., NEC/R), the use of the star point of the generator, or by earthing the
star point of the generator transformer.
Care should be taken with multiple generator installations to avoid excessive circulating third harmonic
currents. It may therefore be necessary to restrict the earthing to the star point of a single machine and
provide automatic transfer facilities of the generator star point earth to another machine in the event of the
selected machine being tripped. The use of suitable generator transformers with delta windings may
provide a means of avoiding excessive circulating harmonic currents.
The winding configuration of the EG transformer(s) (e.g., delta-star, star-delta etc.) closest to the POC shall
be such that zero sequence currents on the Network Service Provider‘s network and EG systems are
decoupled from one another. Due to the above decoupled mandatory clause, the use of autotransformers
is not permitted at the PUC.
Under conditions of separation between the Network Service Provider‘s network and the EG system, care
must be taken to not run any part of any of the systems unearthed. In such circumstances, it will be
necessary to provide automatic switched facilities of the EG‘s Network Service Provider-side neutral earth
(star point) as stated within DPL_34-2149. If at any stage it is found that the EG is in breach of the
16
condition (re., energising an unearthed system or having the ability to energise an unearthed system ), it
shall be mandatory to retrofit direct transfer trips that operate the PUC circuit breaker from all of Eskom‘s
17
circuit breakers up to the PSS at the cost to the EG .
3.5.4.1 MV networks
Eskom‘s MV networks are generally resistively earthed at the source substation. Standard DPL_34-2149
states that in new installations, the NEC or NECR for each point of MV neutral earthing shall be specified so
as to limit earth fault currents contribution per neutral earthing point to the typical ranges: less than 360A
(Rural networks) and less than 960 A (urban networks). SABS 0200-1985 recommends 300 A per earthing
device.
The preferred neutral earthing philosophy for MV-connected generators is that the MV neutral point directly
connecting onto the Network Service Provider‘s network (at the POC) be left un-earthed. This will serve to
avoid issues of earth fault relay de-sensitisation, as well as avoiding ‗circulating‘ zero sequence or triplen
rd
th
th
(i.e., 3 , 6 , 9 etc.) harmonic currents between the distant earth connections. Alternatively, as stated in
the Eskom Standard DPL_34-2149, when a separate earth mat is provided (i.e., a separate earth mat to the
network‘s neutral earth connection), the EG may provide a permanent point of neutral earthing as long as
16
GCCRPPSA states the maximum time to be 2 s for Category B and C. EGs that do not fall under the aegis of
GCCRPPSA have a maximum operate time of 2 s according to the DCUOSA agreement. Internationally values
ranging from a Class 3 DTT to 2 s are found.
17
Operate time of ≤ 100ms which includes the communication end to end time and the circuit breaker switching time.
Internationally, times obtained range from Class 3 to 100 ms.
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the total earth fault current contribution from this neutral point is less than or equal to 10% of the total earth
18
fault current contribution from the Eskom source, but no more than 72 Amperes .
No MV connected generators will be allowed to connect directly to the Eskom system. This means that an
isolating transformer(s) is required at the POC. An auto-transformer is not acceptable as it does not
provide isolation.
With the EG not earthing the Eskom MV network, and in the case of the source tripping as a result of a line
earth fault, the healthy line voltages may momentarily be raised to full phase-to-phase values. In addition,
there is a possibility of resonant over-voltages or capacitive driven over-voltages. Possible damage to
surge arresters may be avoided by specifying arrester Maximum Continuous Operating Voltage (MCOV)
values at the full phase-to-phase voltage and grading the over-voltage protection functions with regard to
the surge arrester Temporary Over-voltage (TOV) curves.
In the case of an agreed intentional island, the conditions of which are stipulated in Section 3.4.3, the MV
star-point shall be earthed. The EG shall ensure that the star-point is resistively earthed the instant prior to
intentional islanded operation, as per Eskom standard DPL 34-2149. As stated within the Standard
DPL_34-2149, the earth shall be disconnected an instant after the reconnection to the Grid for resumption
of parallel operation.
3.5.4.2 HV and EHV networks
HV and EHV networks are required to be effectively earthed at source substations. The high voltage side
of the transformer winding shall therefore cater for solid earthing of the neutral using a star-connected
winding at the side of the transformer connecting to the Network Service Provider‘s network. The generator
side of the transformer winding shall use a delta-connected winding. The HV or EHV neutral point will have
the least effect on the Network Service Provider‘s protective relays if it is not included in a feeder protective
19
primary system zone.
3.5.5 Prevention of Out of Synchronism Closure
The Network Service Provider shall provide synchronism check (synch check) and/or live-line close
20
blocking functionality on all circuit-breakers and/or pole-mounted switchgear between the PUC and the
PSS. This shall serve as additional security against possible out-of-phase closure onto an islanded EG.
Synchronising (auto or manual) shall remain the sole responsibility of the EG and this shall be done at the
PUC or PGC, and/or elsewhere within the EG‘s plant. It is important to note that unintentional islanding
events can occur in the event of equipment failure or under power system circumstances that fall within the
non-detection zones of inverter protection (i.e., it can never be guaranteed as stated in the Kinetrics Inc.
21
report K-418086-RA-001-R10) .
3.5.6 Requirements for Directional and/or Unit/DTT Protection
Where the EG is adjacent to the Network Service Provider substation, shares the same earth-mat and it is
deemed prudent by the Network Service Provider to employ an extended buszone sectionalised by bussections, that part of the protection functionality requirements listed below pertaining to the dedicated EG
feeder(s) may be ignored (i.e., the protection functionality requirements for the feeder from the PCC to the
POC).
The protection functionality requirements for the network/connected feeders have been split into the three
relevant voltage levels and are listed below:
18
This Standard requires the total earth fault current from the Eskom source to be the ‘total minimum earth fault
current contribution from the Eskom source’. Eskom’s Regional Operating Unit Manager/Grid Business
Management is required to give written approval for this connection.
19
That is, within a feeder unit protection zone or impedance reach zone 1 or zone 2 without communication assisted
tripping.
20
Currently the auto reclosers on Eskom’s contract have the ability for live-line close blocking. It may possibly
require masking of the function.
21
An anti-islanding failure of an inverter is reported in the Electrical Safety Authority bulletin DSB-07/11.
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3.5.6.1 MV networks
22
For MV networks with a dedicated EG feeder or dedicated EG feeders, feeder bays with unit protection
are required on the EG feeder(s) if the incoming feeder(s) from the Network Service Provider source to the
PCC has unit protection. Serious consideration should be given to the type of unit protection functionality
applied as the ‗differential‘ type is generally more immune than the ‗distance‘ type to EG related
installations. The back-up protective relays shall be directional.
For MV networks, with an added EG source, feeder bays or reclosers are required to protect fault in-feeds
at the local and remote point.
In some cases, the fault current in-feed from the EG to network faults will be a small fraction of the gridsupplied fault current. The fault current in-feed from the generator may also decay rapidly with time. As a
result, it is unlikely in these circumstances that the traditional non-directional IDMT overcurrent, earth fault
and SEF protection applied to radial MV networks will be rendered unsuitable by the presence of an EG.
The fault current in-feed over time must, however, be confirmed in writing by the EG using the format
presented in the Standard IEEE 1547, Table 6: Generator short-circuit current and reactance versus time,
and checked by NPD in collaboration with the Network Service Provider Co-ordination and Settings
Department during the early design phase of each project (NPD are to obtain the confirmation and
tabulated results). Where no confirmation is obtained and/or studies indicate otherwise, directional
protective relays shall be used.
It is important to note that for substantial fault in-feed over time from the EG, the protective devices applied
to the radial MV Network Service Provider network will have reduced sensitivity. In these cases, differential
type protection may be required.
To maintain safety and to minimise equipment damage of the network and nuisance tripping of the EGs
connected to non-dedicated feeders in MV networks and where the maximum rated aggregated EG output
(aggregated only if more than one EG of a different energy source is connected on the feeder) is greater
than one third of the connected minimum aggregated Customer load (i.e., it is not beyond doubt that the EG
will disconnect within the stipulated 2 second period – this information is to be obtained by NPD) or where
there is a proven safety concern, it is recommended to employ a DTT from the relevant Network Service
23
Provider circuit breakers for anti-islanding purposes .
For MV networks, implementation of a DTT from the relevant Network Service Provider circuit-breakers
shall be mandatory with regards to EG Inverters connected to the Network Service Provider at any point
other than the PSS except where EGs are certified to pass the non-islanding tests as stipulated in
IEEE 1547.1 or if preferred, stipulated in IEC 62116 (IEC 62116 is relevant to photovoltaic inverters only).
Note that the above test requirement is also stipulated in the pre-commissioning tests in Table 5-1.
Certificated proof of the non-islanding test pass is to be obtained from the EG in the early stages of the
design by the relevant Eskom Grid Access Unit as design and installation of DTTs in most MV networks will
impact on the cost and complexity of the project.
As certificated proof of the non-islanding capability is required in the early design stages as stipulated
above, in this instance, the requirement for this test to be conducted on-site as stipulated in Section 5.1 is
waived. However, this does not in any way cancel the requirement for the unintentional islanding test of
Section 5.1 for the test to be conducted on-site at the time of commissioning.
22
The term ‘dedicated feeder’ used in this context, means that no customer/s or alternative NSP feed shares the same
feeder or the supply from that feeder.
23
Maximum rated generation versus minimum aggregated loading criteria found internationally ranges from 1/3 to
1/2. The maximum rated generation may be taken as an aggregated value when more than one EG is connected on
the same feeder.
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3.5.6.2 HV networks
The terminology used in this sub-section is explained in the generic layout diagram of Figure 3-1 inserted
below:
NSP
SOURCE
X
X
TRFR
BUSBAR
RING
NETWORK
RADIAL
NETWORK
(PCC)
X
X
OUTGOING FDR (RADIAL)
INCOMER FDR (RADIAL)
X
REMOTE FDR
BREAKER
EG FDR
X
INCOMER FDR (RING)
INCOMER FDR (RING)
X
PROPOSED NEW FDR
CUSTOMER
OR NSP
SUBSTATION
BUSBAR (PSS)
X
X
NSP OWNED
POC
POS
PUC
X
POM
PUC BKR
NSP
SOURCE
EG OWNED
TRFR
PGC
EG
SOURCE
X
X
EG BUSBAR
PGC
EG
SOURCE
Figure 3-1: Layout of HV Network Indicating the Terminology used
For HV networks with a dedicated EG feeder or dedicated EG feeders, full feeder bays with unit protection
are required on the EG feeder(s).
For HV networks, full feeder bays with unit protection are required on the Network Service Provider incomer
(ring) feeders at a ring-supplied in-out substation (PSS). The back-up protective relays shall be directional.
For HV radial networks, full feeder bays with unit protection are required on the Network Service Provider
24
incomer (radial) feeder (from the PCC up to the PSS) for the following conditions :
a) Where DTT to the PUC breaker or dedicated EG feeder from the PCC is required from any remote
Network Service Provider breaker up to the PSS. This DTT clause shall be mandatory where
Customers are connected to the PCC busbar or are connected downline (in essence the Network
25
Service Provider incomer in this case is a non-dedicated feeder).
The mandatory DTT clause may be ignored if the maximum rated aggregated EG output
(aggregated only if more than one EG of a different energy source is connected on the feeder) is
greater than one third of the connected minimum aggregated Customer load (the information is to
be obtained by NPD) and, in the case of EG Inverters, where EGs are certified to pass the nonislanding tests as stipulated in IEEE 1547.1 or if preferred, stipulated in IEC 62116 (IEC 62116 is
relevant to photovoltaic inverters only).
24
An in-out substation with no feeder bay on the incomer radial source is, with reference to the application of
protective relays and the problems encountered, still regarded as a tapped station.
25
Internationally, this has been instituted by a number of utilities and is strongly recommended even in those cases
where it is not mandatory.
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b) Where limited nuisance tripping of the EG is important as the main anti-islanding protection will
26
employ a DTT .
c) Where the Network Service Provider‘s incomer remote feeder (remote feeder breaker) zone E/F
under-reach due to the EG transformer being in service is ≥ 10%.
d) Where the installed maximum capacity of EG generation, the source impedances and network
layout causes a Network Service Provider incomer remote feeder (remote feeder breaker) zone
phase underreach ≥ 10%.
e) Where the risk of cross-country trips is increased.
f)
Where a tapped connection causes sequential tripping of the protective devices.
g) Where an out-feed at the tapped terminal desensitisers a multi-terminal differential protective
scheme by ≥ 10% or causes a feeder zone overreach ≥ 10%.
h) Where single-pole tripping and ARC are employed.
i)
Where the QOS of the PSS is important as unit protection will decrease the dip duration to
< 150 ms for all faults between the two line ends.
j)
Where there is increased risk of an ARC block due to the generation being temporary islanded.
k) Where it is considered important to retain the same ARC dead-time as was previously applied on
the feeder (e.g. QOS impact - retain instantaneous ARC or the standard 3 second dead-time).
l)
Where the Network Service Provider incomer originates from an Eskom Transmission substation.
The ‗unit protection‘ clause stated above for radial networks on the Network Service Provider incomer may
be ignored if item a, (the feeder is a dedicated EG feeder), h, i and l are not applicable and the EG indicates
in writing that their plant will adequately feed into a fault over time on the Network Service Provider incomer
(so it is not considered a weak in-feed point).
For HV radial networks, the Customer/Network Service Provider outgoing (radial) feeders at the PCC
busbar, other than the EG feeder, shall include either full feeder bays with unit protection or zone II
accelerated trip functionality (dependant on the Network Service Provider‘s network layout).
3.5.6.3 EHV networks
For EHV networks, full feeder bays with main1 and main2 unit protection per bay are required. The main1
and main2 unit protection shall include both distance and differential functionality except where the EG is
adjacent to the EHV substation, shares the same earth-mat and it is deemed prudent by the Transmission
Network Service Provider to employ an extended buszone together with bus-sections. Note that only
dedicated feeders are allowed for EHV networks.
3.5.7 Auto-reclose Dead-time Settings on Networks with Embedded Generation
Auto-reclose dead-time settings on all circuit-breakers between the PUC and the PSS shall be increased
from the standard 3 seconds to at least 5 seconds so as to provide additional margin for the detection and
isolation of possible power islands except in cases where QOS and/or power system criteria override this
clause. In this case, Section 3.5.5 shall prevent any out-of-synch closures.
It must be noted that the fault current supplied by inverter based EGs is not unbalanced and therefore
single-pole ARC may not be possible in certain network layouts (where it would be difficult to detect the
correct faulted phase).
3.5.8 Tapchanger Requirements at the PUC for Connected EG
When EG is connected to the MV busbar of a HV/MV Distributor substation where the MV busbar voltage is
controlled by means of an automatic tapchanger, the possibility exists that the EG may cause the
tapchanger to lose control of the busbar voltage. It is recommended that the automatic tapchanger control
26
It is well documented internationally that it is difficult to obtain both security and reliability using localised antiislanding protection.
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scheme utilised at these stations be remotely controllable to allow the NSP‘s Control Centre to remotely
switch the tapchanger operation to manually tapped to prevent unwanted lockouts. Additionally, according
to the Eskom Standards DGL_34-1944 and DST_34-542, NPD or a department within Network Services
are to conduct load flow simulations with regard to the application of EG. Recommendations from the
above simulations may include reverse power flow tapchanger block or in some cases the application of bidirectional tapchanger schemes.
For HV and EHV networks it is recommended that the automatic tapchanger control schemes utilised at the
interface stations be remotely controllable to allow the NSP‘s Control Centre to remotely control the
tapchanger operation.
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3.6 REQUIREMENTS AT THE PUC AND PGC
This section details the requirements for the primary plant and control plant equipment to be installed at the
PUC and PGC.
3.6.1 Primary equipment
3.6.1.1 Current Transformers
Current transformers shall be specified in accordance with NRS 029. Protection CTs shall be in compliance
with the protection relay manufacturer‘s requirements with regard to accuracy class. Metering circuits shall
27
use Class 0.2 CTs as a minimum, with Class 0.2s CTs being preferred . Refer to Section 3.7 for further
requirements with respect to metering CT cores for Eskom use. Measurement circuits shall use Class 0.2
CTs or protection class CTs. Protection class CTs will typically only be used for Telecontrol measurements
where the measurement data is derived from a protection relay instead of a stand-alone transducer.
3.6.1.2 Voltage Transformers
Voltage transformers shall be specified in accordance with NRS 030. Metering and measurement circuits
shall use VTs of accuracy class 0.2. Protection VTs shall be of accuracy Class 3P. The VTs shall not be
overburdened so as to ensure accuracy within class definitions.
3.6.1.3 Isolator/Disconnector
The isolator fulfilling the requirements of Section 3.3.2 shall be specified in accordance with NRS 031.
The isolator shall include at least one normally-open and one normally-closed auxiliary status contact for
use by Eskom for remote indication purposes. The contacts shall operate in the fully-opened and fullyclosed positions of the primary contacts respectively. These contacts may not be provided by a separate
relay or device not forming an integral part of the isolator.
The isolator shall be lockable using a standard Eskom padlock:
a)
Case: 35–38 mm high, 28–40 mm wide, 18–20 mm thick; and
b)
Shackle: 6 mm diameter, 30–34 mm length (in the locked position), 20 mm width (minimum).
(Dimensions from Eskom Specification DSP_34-1488 Specification for Master Locks and Master Keys for Electrical and
Related Equipment)
3.6.1.4 Circuit-Breakers
The circuit-breakers shall comply with the requirements of IEC 62271-100 and shall be suitably rated to
interrupt the maximum prospective fault current at the PUC or PGC as appropriate.
To allow for network growth, the fault interruption capability of circuit-breakers shall be chosen to be at least
30% higher than the maximum fault levels calculated in the initial integration study for the EG plant.
The maximum circuit-breaker trip operating times shall be as follows:
a)
EHV network: < 40ms
b)
HV network: < 60 ms
c)
MV network: < 100 ms
The circuit-breakers shall have a ‗maximum over-voltage‘ factor for switching conditions of IEC 62271-100
of 2.5 pu or higher.
The circuit-breakers shall include at least one normally-open and one normally-closed auxiliary status
contact for use by Eskom for remote indication purposes. These contacts may not be provided by a
separate relay or device not forming an integral part of the circuit-breaker.
27
Class 0.2s CTs are more accurate over a wider range when compared with Class 0.2 CTs. Large load/supply
variances are expected for EG’s.
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3.6.2 Protection
3.6.2.1 Protection overview
This section details the protection functionality that shall be installed at the PUC, irrespective of whether the
same functionality is installed elsewhere within the EG‘s plant. Protection requirements are also stipulated
for the PGC, providing back-up to the PUC protection. The protection systems shall provide adequate
protection of the parts of the Network Service Provider‘s network that could be supplied by the EG, either in
parallel operation or under conditions of the EG supplying an intentionally islanded portion of the Network
Service Provider‘s network.
Further, the protection systems shall:
a)
Inhibit connection of the generating equipment to the Network Service Provider‘s network unless
all phases of the Network Service Provider‘s network are energised and operating within the
agreed limits;
b)
Disconnect the generator from the system when a system abnormality occurs that results in an
unacceptable deviation of the voltage or frequency at the point of connection; and
c)
Prevent un-intentional islanding of the EG with a portion of the Network Service Provider‘s
network.
28
Table 3-4 includes a summary of specific protection functions that shall be provided at the PUC .
Table 3-4: PUC minimum protection requirements per voltage level
Protection Type
Section
EHV/HV
MV
Overcurrent, Earth Fault
3.6.2.3
Yes
Yes
Sensitive Earth Fault (SEF)
3.6.2.3
No
Note 1
Phase Under/Over Voltage *
3.6.2.4
Yes
Yes
Residual over-voltage *
3.6.2.5
No
Note 1
Under/Over Frequency *
3.6.2.6
Yes
Yes
Loss-of-Grid *
3.6.2.7
Yes
Yes
Check Synchronising / interlocking (Block dead line charge)
3.6.2.8
Yes
Yes
Reverse Power *
3.6.2.9
Note 2
Note 2
DC Failure Monitoring
3.6.2.10
Yes
Yes
Double Trip Coils with Trip Circuit Supervision and Breaker Failure
3.6.2.12
Yes
Yes
Note 1: Depends on neutral earthing philosophy adopted. Neutral voltage displacement protection will be applied on
networks where the EG or generator transformer does not provide an earth connection to the Eskom network. Earth Fault
and Sensitive Earth Fault protection will be required in the event that an earth connection is provided
Note 2: Reverse power protection shall be applied in the event that the EG does not plan to, or is not permitted to export
power to the Grid, but which will be synchronised with the Grid.
*
28
These functions are to be applied by the EG. As such, if the Network Service Provider owns the PUC circuit breaker(s)
then they must be applied on the first circuit breaker(s) owned by the EG that can become an islanding point. The
Network Service Provider may also provide these functions but only as a back-up to the EG applied functions.
The requirements of this section indicate the Network Service Provider’s minimum requirements at the PUC and
PGC so as to safeguard the network in the event of faults within the EG’s facility, or faults within the network with
a fault current contribution from the EG. In keeping with the requirements of the SADCNC, the SAGCNC and the
GCCRPPSA, the EG may require additional protection (e.g., biased differential, restricted earth-fault, pole slipping
protection, negative phase sequence overcurrent etc.) to safeguard his/her assets against damage due to abnormal
events or faults on the power system.
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Notwithstanding the requirements of Table 3-4 for the PUC, Table 3-5 below lists the minimum protection
functionality to be installed at the PGC:
Table 3-5: PGC Protection requirements
Protection Type
Section
Phase Under/Over Voltage
3.6.2.4
Under/Over Frequency
3.6.2.6
Synchronising
3.4.2
Reverse Power
3.6.2.9
DC Failure Monitoring
3.6.2.10
Negative Phase Sequence overcurrent
3.6.2.11
Double Trip Coils with Trip Circuit Supervision and Breaker Failure
3.6.2.12
The South African Grid Code Requirements for Renewable Power Plants states that all thermo and hydro
units shall comply with the design requirements specified in the South African Grid Code (specifically
section 3.1 of the Network Code). The Distribution Code: Network Code requires all EGs of nominal
capacity greater than 10 MVA, in addition to the South African Distribution Code, to comply with the
protection requirements of Section 3.1 of the South African Grid Code: Network Code. The latter requires
generators to be provided with back-up impedance (for EGs ≥ 20 MVA) and circuit-breaker fail protection, in
addition to the requirements of Table 3-4 and Table 3-5 above. Reverse power is required on rotating plant
that is capable of motoring. EGs of capacity larger than 20 MVA require loss-of-field and pole slipping
protection where applicable.
3.6.2.2 General protection requirements
a) All protection relays used at the PUC, PGC and other intermediate points if installed, shall comply
with the type test requirements of Annex C.
b) Protection relay accuracy requirements of the following sections shall be defined as per IEC 602553 and -6.
c) The PUC and PGC protection shall be totally independent of each other.
d) Protection clearance times and coordination shall comply with the requirements specified as a
result of the EG integration fault studies. EG fault levels over time shall be supplied to the Network
Service Provider prior to acceptance of the EG protective design.
e) If automatic resetting of the protective equipment is used (e.g., for an unmanned EG facility), the
time delays must be applied in consultation with the regional auto-reclose philosophy. The
automatic reset must be inhibited for faults within the EG installation.
f)
To prevent nuisance tripping and to assist with grading, it is mandatory that the EG shall have
overlapping unit protection whenever the Network Service Provider applies unit protection at the
PCC.
g) Buszone protection shall be applied at the PCC or an equivalent unit protection dependant on the
relevant Distributor standard. It is mandatory to apply buszone protection on the generating busbar
when this is connected directly to a Eskom Transmission substation.
h) Circuit breaker fail protection shall always be implemented at the PUC, PGC and other intermediate
points, together with trip circuit supervision of both trip circuits (breaker fail retrip and/or crosstrip to
energise the second trip coil, timed breaker failure to energise back-up circuit breakers and/or
zone).
i)
It is mandatory for EHV connected EGs to have main 1 and main 2 protection functionality.
j)
Each protection relay system shall include a sequence of event recording function that logs any
settings change; settings group change, protection pick-up or trip operation, or change in circuitbreaker and/or input and output status.
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k) The relay system installed at the PUC, PGC and other interconnected points if installed, shall
incorporate an oscillographic waveform recording function capable of storing at least five
recordings, with a settable recording window to record any protection start until trip output (this may
also be achieved with a settable pre-fault duration followed by the fault duration). A sampling rate
of sixteen samples per cycle or higher is required. The recording shall have retrigger capability to
capture an event subsequent to the initial trigger with a complete recording of the second event.
The waveform recording shall contain the three phase voltage, three phase current and neutral
current signals from the PUC as well as all significant digital signals (i.e., protection tripping
elements, circuit-breaker status, input and output contact status etc.). A recording shall be
triggered upon any protection operation.
l)
The event and waveform recordings shall be stored in non-volatile memory and shall be time
stamped with a resolution of 1 millisecond real time. It shall be possible for the recordings to be
made available in COMTRADE format.
m) Protection settings for all functions identified in Table 3-4 and Table 3-5 to be applied at the PUC,
PGC and other intermediate points if installed, will be to the Network Service Provider‘s written
approval. No changes to the settings shall be made without written consent from the Network
Service Provider. The EG shall keep written record of all protection settings, and provide a signed
electronic copy of the same to the Network Service Provider.
3.6.2.3 Overcurrent, Earth Fault and Sensitive Earth Fault protection
Overcurrent and earth fault protection shall provide Inverse Definite Minimum Time (IDMT) time-current
characteristics. IDMT curves shall be in accordance with the requirements of IEC 60255-3: Type A, B and
C curves (i.e., IEC Normal Inverse, Very Inverse and Extremely Inverse). Directional protection is
recommended.
Overcurrent protection will be provided in all cases. Voltage-controlled overcurrent protection shall be
considered in applications where the fault current contribution of EG decays with time.
Appropriate earth-fault protection will be applied in all cases. Current-based detection is not appropriate in
MV networks where the generator or generator transformer does not include a point of neutral earthing.
Sensitive earth-fault (SEF) protection will be applied on MV networks where the generator or generator
transformer provides a point of neutral earthing to the Distributor network. SEF protection will be set in
compliance with Eskom Standard DST_34-540.
Sensitive earth-fault protection will use a definite time characteristic.
The overcurrent, earth-fault and SEF protection shall be set to co-ordinate with the Network Service
Provider‘s network protection as dictated by the integration fault studies.
3.6.2.4 Under- and Over-Voltage protection
Under- and over-voltage protection shall be provided. The voltage protection functions shall detect the
effective (i.e., root mean square) or the fundamental component of each phase-to-phase voltage. The
under-voltage condition shall be supervised using fuse failure check and fuse MCB trip (i.e., blocked for any
failed circuit to prevent a maloperation).
RPPs shall comply with the voltage requirements as set out in Section 5.2.1 of the Grid Code for
Renewables. Non-renewable EG shall comply with the maximum operating times for the voltage protection
as indicated in Table 3-6 below as stipulated in IEEE 1547.
Table 3-6: Maximum operating times for voltage protection
Voltage range
Maximum Operate Time
(% of nominal)
(s)
V < 50%
0.2 s
50% ≤ V < 90%
2s
110% < V < 120%
1s
V ≥ 120%
0.2 s
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In cases where the EG facility may import or export power from the network, the voltage protection may be
supervised so as only to operate in the event of real and/or reactive power export by the facility to the
network. Care should be taken to still meet the GCCRPPSA requirements for reactive power support.
3.6.2.5 Residual over-voltage / neutral voltage displacement protection
Residual over-voltage (also known as neutral voltage displacement) protection shall be applied on MV
networks where the generator or generator transformer MV neutral is unearthed. The voltage signal must
be derived from a VT configuration that is capable of transforming zero-sequence voltage: three single
phase VTs or three phase 5-limb VTs, with primary neutral earth connection. The residual voltage may be
derived from a broken-delta configuration of the VTs, or may be calculated by the relay based on the
measured phase-to-neutral voltages.
The pick-up and time delay of the residual over-voltage protection shall be chosen so as to grade with the
current-based earth-fault protection that is applied to the Network Service Provider‘s network. It is preferred
that the residual over-voltage protection uses an inverse voltage-time characteristic rather than a definite
time characteristic. The residual over-voltage protection will be less sensitive and slower than the Network
Service Provider network protection. Refer to Annex E for a worked grading example.
3.6.2.6 Under and Over Frequency protection
Under- and over frequency protection shall be provided. The under- and over frequency protection relay
shall be accurate to within 10 millihertz of the setting. Where an averaging ‗window‘ is used for the
frequency measurement, this shall be limited to a maximum length of 6 cycles.
The frequency protection shall be set so as to allow generator operation within the frequency ranges
referenced in Section 3.4.1. Operation above the over frequency ranges shall cause the EG to sever the
connection with the Network Service Provider‘s network within 4.1s. Operation below the under frequency
ranges for greater than 200ms for RPPs and turbo-alternators and greater than 1.0s for hydro-alternators,
allows EGs to sever the connection with the Network Service Provider‘s network.
In cases where the EG facility may import or export power from the Network Service Provider network, the
frequency protection may be supervised so as only to operate in the event of real power export by the
facility to the Grid.
3.6.2.7 Loss-of-Grid protection
Operation of an EG in an unintentional islanded mode with part of the Network Service Provider network
constitutes a serious safety hazard to both equipment and personnel, and shall be avoided.
The philosophy to be applied is that the detection of an islanding condition shall take precedence over the
continuity of the EGs Grid connection (via the PUC). The EG must be disconnected from the Network
Service Provider network upon reasonable suspicion of islanded operation. EGs of capacity greater than
50 MVA must also include more definitive islanding detection methods (e.g., communication-assisted
intertripping schemes); so as to further avoid nuisance tripping for non-islanding events. If communicationassisted intertripping is used, it is mandatory that dedicated loss-of-grid protection be installed as back-up
protection.
Dedicated loss-of-grid protection will be applied at the PUC in all applications. An EG may be exempted
from this requirement in the event that it is prohibited from exporting real power to the Network Service
Provider network by a suitable reverse power relay (see Section 3.6.2.9). An exemption could be given for
applications where it is physically impossible to island and the EG has obtained independent certificated
proof of this. Care should be taken by the SOD/NOD when considering an exemption on this basis and it
must be noted that obtaining a certificate for the required tests as given in Section 3.5.6. does not preclude
the necessity for loss-of-grid protection (i.e., even the best designed and tested protection systems may
experience component failure as stated in the Kinectrics Inc. Report).
Loss-of-grid protection may take the form of Rate-of-Change of Frequency (ROCOF) with typical settings as
suggested in Table 3-7 below. Voltage Vector Shift protection has been discontinued due to nuisance
tripping in the German Association of Energy and Water Industries which includes the associations BGW,
VDEW, VRE, and VDN [BDEW] and discussed in the IEEE 1547 Working Group. As such Voltage Vector
Shift should be used with caution.
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Table 3-7: Typical settings for loss-of-grid protection
ROCOF
f
0.2–1.0 Hz/s (0.4 Hz/s typical)
t
40 ms – 2000 ms
Time delay
Voltage Vector Shift
V
200 ms – 500 ms
6° – 12° (6° typical. 12° on weak networks).
Where ROCOF is not deemed suitable, a communication-based direct transfer trip scheme (DTT) must be
applied such as to disconnect the EG in the event of an island developing. The onus rests on the EG to
prove that the Loss-of-grid protection is suitable and the Network Service Provider takes no liability for the
frequency of nuisance tripping.
It must be noted that use of a communication-assisted intertripping scheme, regardless of MW size, allows
for minimum nuisance tripping that could be caused by passive loss-of-grid protection schemes such as
ROCOF and voltage vector shift.
3.6.2.8 Check Synchronising / Block dead line charge
The circuit-breaker at the PUC shall be blocked from closing onto a de-energised Network Service Provider
network (block dead line charge). Charging of the EG network shall be permitted subject to synchronism
check having been performed.
Synchronising shall be done at the PGC, in accordance with the requirements of Section 3.4.2. Where
synchronising occurs at the PUC, for situations where the EG would island onto his/her own internal
network, the PUC shall also adhere to the requirements in Section 3.4.2.
3.6.2.9 Reverse Power protection
There are two principal applications of reverse power protection:
a) Prevention of generator motoring:
This shall be applied as standard at the PGC on all rotating generators.
The recommended setting for a reverse power relay is 10–20% of the maximum allowable motoring
power. The operating time is typically 10–30 s. The time delay is required to prevent a
maloperation during power swings or when synchronising the generator to the network [Jenkins
p.177].
b) Prevention of power export to the Grid:
A reverse power protection relay may be installed at the PUC of an EG whose entire output will be
consumed by the plant in which it is embedded. The reverse power protection relay will prevent
unintended export of power to the Network Service Provider‘s network, and may obviate the need
for dedicated loss-of-grid protection (see Section 3.6.2.7). When serving as loss-of-grid protection,
the reverse power protection relay shall be graded with time overcurrent protection in order to
ensure ride-through during fault conditions.
The clearance times shall comply with the
requirements determined by the EG integration fault studies.
3.6.2.10
DC Failure Monitoring
DC failure within the EG facility is deemed a serious safety risk. The DC supplies provided for the PUC and
PGC circuit-breakers and associated protection systems shall be subject to continuous monitoring. Two
separate DC alarms shall be provided per DC system:
a) Non-urgent DC alarm:
An alarm activated when the battery voltage is lower than normal, or for any fault appearing on the
AC supply to the battery charger.
b) Urgent DC alarm:
An alarm activated when the battery voltage is such that the available capacity is less than 20% of
the rated Ampere-hour capacity, and when the DC voltage is less than 90% of the nominal DC
voltage.
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The EG shall initiate disconnection from the Network Service Provider network immediately upon receipt of
an Urgent DC alarm.
3.6.2.11
Negative Phase Sequence Overcurrent
Negative phase sequence overcurrent protection shall be applied as a generator protection function, and
shall serve to protect the generator against damage due to unbalanced loading, broken conductors or other
asymmetrical operating conditions.
Negative sequence current components can be extremely harmful to the EG. System faults, by their
nature, are a large contributor to negative sequence currents. The EG should be aware that negative
phase sequence overcurrent protection must be effectively applied.
3.6.2.12
Circuit Breaker Fail/Double Trip Coils/ Trip Circuit Supervision
Circuit breaker fail protection shall be applied firstly as a breaker fail re-trip/cross-trip of the second trip coil
and then secondly as a breaker fail trip to a back-up circuit breaker or zone (bus strip). Both trip circuits
within each circuit breaker shall have trip circuit supervision functionality.
Note that where a circuit breaker is installed at a node where there is the possibility of a source on both
sides of the node (e.g., NSP source and EG source), both source in-feeds must be tripped for a breaker fail
trip operation.
There shall be a ‘breaker fail‘ bus strip time and a retrip time. The timers shall only start when there is a
protection initiation and an overcurrent condition (selectable). The ‘breaker fail‘ bus strip and retrip timers
shall start simultaneously when the initiating conditions become true and reset instantaneously when either
the protection initiation and or the overcurrent condition terminates.
A ‘breaker fail‘ bus strip output shall be produced once its set time has expired. A retrip shall be issued
before expiry of the set ‘breaker fail‘ bus strip time. If the retrip function is not offered then this function
shall be replaced by a selectable time delayed trip contact from the main protective relay operating the
back-up trip coils for single-pole protection operations. For three-pole protection operations (in a singlepole scheme) an instantaneous ‗retrip‘ shall be issued to the back-up trip coils. A three-pole scheme shall
issue a retrip (settable time) via the retrip timer. Supervisory indications of both the retrip and bus strip
outputs shall be provided.
The ‘breaker fail‘ retrip output contact (normally open) shall be located in the back-up D.C. circuit and shall
issue trip commands to the back-up trip coil when the TNS switch is selected to the ‗NORMAL‘ position
only.
Three bus strip output contacts (normally open) should be provided as a minimum. One bus strip output
contact should be located in the main D.C. circuit and shall initiate a direct transfer trip send command
(where relevant) when the TNS switch is selected to the ―NORMAL‖ position only. The second bus strip
contact shall issue trip commands to the buszone panel or back-up circuit breaker when the TNS switch is
selected to the ‘NORMAL‘ position only. The third bus strip contact shall be located in the back-up D.C.
circuit and shall issue trip commands to the back-up trip coil when the TNS switch is selected to the
‘NORMAL‘ position only (this output may be shared with the ‗retrip‘ output).
All initiating contacts shall be located in the main D.C. circuit and as a minimum the following conditions
where relevant should be arranged to initiate the ‘breaker fail‘ function:
a) external trip input to the scheme.
b) buszone trip input to the scheme (where applicable).
c) main protection trips and intertrip receive (where applicable).
d)
-up protection trips.
e) direct transfer trip receive (where applicable).
f) pole disagreement trip (single-pole tripping schemes only).
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3.6.3 DC Systems and Auxiliary Supplies
The circuit-breakers and associated protection systems at the PUC and PGC shall operate from
independent DC supplies.
The DC supplies to the PUC and PGC shall be subject to continual monitoring as per Section 3.6.2.10. The
EG shall cease to energise the Network Service Provider‘s network upon critical failure of either the DC
system at the PUC or at the PGC or both.
The DC systems at the PUC and PGC shall be maintained in accordance with the applicable Eskom
standard or an alternative written policy acceptable to Eskom. Eskom reserves the right to perform audits
on the DC systems.
In the scenario of a switching substation where there is no Eskom auxiliary supply point available, the
Distribution standard Provision of Auxiliary Supplies at Switching Substations (DST_34-2095) discusses the
following options:
a) Single phase power VTs
b) Power from a nearby reticulation line
c) Power from the customer‘s auxiliary transformers
If thyristor controlled rectifiers or larger battery charger A.C. currents are required to meet the Distributor
design for its DC system and the Power VT`s cannot meet the current AC requirements then the following
options are to be made available to the Distributor:
a) At initiation stage the EG is required to apply to Eskom for a minimum of 50 kVA three phase rural
AC supply. This supply will be used during the construction phase. Eskom will then use this as the
alternative mains AC supply, to the Eskom control room.
b) The cabling from the NEC/R/T/Aux on the EG side is to be fitted with LV surge arrestors, fitted into
the NEC/R/T/Aux (DEHNBlock Maxi fitted to the 3 phases).
c) The EG shall supply Eskom‘s control room from their NEC/R/T/Aux transformer(s) with a minimum
of 63 Amps three phase AC supply. This supply will be fed via the EG standby generator (if
available), with a chop-over on the EG side.
For each new substation, the regional or national DC Specialist should consider and compare all the
available options against the substation load requirements, and decide on the best possible solution for
each application.
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3.7 METERING
The metering arrangement adopted per EG application will depend on the specific conditions of the power
purchase agreement. The following metering philosophy shall, however, apply to all EG interconnections:
a) Tariff metering, which shall be maintained and owned by the Network Service Provider, shall be
installed through a main and check meter arrangement normally at the PUC which will be used to
bill the EG for their auxiliary load. The Network Service Provider‘s metering shall comply to
NRS057 as well as the relevant Eskom standards where applicable.
b) It is recommended that this same tariff metering infrastructure be used by the Network Service
Provider for billing purposes on behalf of the EG. The EG may, as a safeguard, install a back-up
meter on the Network Service Provider check circuit for verification purposes and audit the
installations as per Section 3.1.5.
c) Where the EG does not want to use the Network Service Provider‘s infrastructure, the EG will be
responsible for the installation, maintenance and operation of its own metering system including the
optional verification billing. The EG shall comply with the NRS057 requirements as a minimum.
d) Tariff meters for the sale of electrical energy to the Network Service Provider will be located such
that they measure the net energy exported by the EG, excluding the power consumed by its
auxiliaries. In certain circumstances, the Network Service Provider may allow the power consumed
by the auxiliaries to be a fixed unmetered amount but this decision rests with the Network Service
Provider.
e) All Eskom-owned meters shall include facilities for automated remote downloading by Eskom. The
meters shall be energised via their auxiliary input, preferably by a 110V DC supply, alternatively by
a 240V AC supply. Class 0.5 meters, which do not have the auxiliary input facility, may be
energised through the normal 110V VT supply. The selected (chop-over) VT supply should be
used where more than one VT exists.
f) In limited cases where the Network Service Provider metering system is installed within a customeror EG-owned substation or industrial plant, the Network Service Provider metering equipment shall
be limited to the metering panel and the associated equipment. The EG shall provide suitable
instrument transformers, which will be owned by the EG. In this case, sharing of instrument
transformer circuits shall be in accordance to DPL_34-680.
g) All access to data shall be in accordance with DPL_34-680.
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4 SUPERVISORY CONTROL AND DATA ACQUISITION
This section details the requirements, standards and procedures to ensure that adequate and reliable
SCADA facilities exist between the NSP and the EG to enable trouble-free operation of the Grid.
The SCADA system utilised for this purpose must be designed; operated and maintained in such a manner
that does not compromise the stability of the NSP‘s network.
For the Transmission and/or Distribution NSP to monitor the EG plant, the NSP‘s Control Centre must
connect to the SCADA system installed at the EG station. The NSP is also required to control the EG plant
under certain circumstances as per the connection agreement.
Sections 13.1.1 to 13.1.5 of the GCCRPPSA point to the need for ―…SO or NSP designated communication
gateway equipment located at the RPP site:‖
Section 13.6.1 of the GCCRPPSA states that ―The RPP shall have external communication gateway
equipment that can communicate with a minimum of three simultaneous SCADA Masters, independently
from what is done inside the RPP.‖
Section 3.6.3 of the GCCRPPSA states that ―The necessary communications links, communications
protocol and the requirement for analogue or digital signals shall be specified by the SO…‖
4.1 GATEWAY EQUIPMENT
As required by the GCCRPPSA, the SO designates that the communication gateway equipment located at
the EG site shall be an RTU or Gateway currently approved on Eskom‘s Gateway/RTU Contract.
This Eskom Approved Gateway shall be the gateway through which the EG interfaces to the relevant
Eskom Control Centre. The EG shall not interface to Eskom Control Centres directly or via the SCADA
system in the Eskom substation.
The Approved Gateway shall be located in the EG control room. The Approved Gateway shall be owned
and operated by the EG.
The Approved Gateway will essentially serve as a protocol and communications interface device that will
greatly simplify the interfacing of many different EGs to Eskom‘s Control Centres via Eskom‘s various
communications channel types. With this approach; there will be no need for the EG to conduct protocol
implementation conformance testing to ensure interoperability with the Eskom Control Centres. Protocol
implementation and interoperability with the Eskom Control Centres will already have been tested and
approved by Eskom.
In order to ensure the above mentioned interoperability between the Approved Gateway and the Eskom
Control Centres, the protocol firmware used on the Approved Gateway shall be the latest Eskom approved
version. Eskom will inform the EG if and when a new approved firmware version is available. The EG must
implement the latest firmware version within 90 days of being notified by Eskom.
The Codes stipulate that this Gateway shall have at least three communication ports available exclusively
for Eskom master station communications. This is to cater for cases where the EG is connected to the
Eskom Transmission Network and hence is required to communicate with the Main and Standby
Transmission Control Centres and the delegated Distribution Control Centre. For Distribution connected
EGs it should be noted that two of these communication ports may not be required.
The EG must determine from Eskom the details of the currently approved Gateway/RTUs and source it
directly from the Eskom approved Vendor. Ordering information for the Eskom Approved Gateway/RTUs
as at the publish date of this standard is provided in Annex F.
4.2 PROTOCOLS FOR INFORMATION EXCHANGE
Only the IEC 60870-5-101 and DNP3 protocols shall be used for SCADA information exchange between
the EG and the Eskom Control Centres.
The EG SCADA system shall be capable of reliably exchanging system status and data with the Eskom
Control Centres.
The EG shall cater for the communication infrastructure to connect the required number of Approved
Gateway ports to the Eskom telecommunications infrastructure in the Eskom substation.
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4.2.1 SCADA Protocol between the EG and the Approved Gateway
The IEC 60870-5-101 protocol shall be implemented between the EG system and the Approved Gateway
when the EG connects to the Eskom Transmission System.
The DNP3 protocol shall be implemented between the EG system and the Approved Gateway when the EG
connects to the Eskom Distribution System.
It shall be the responsibility of the EG to ensure correct implementation of the applicable protocol on their
device for communication with the Approved Gateway. It shall also be the responsibility of the EG to
ensure the interoperability between the EG systems and the Approved Gateway.
Eskom shall however reserve the right to witness and endorse the correctness of the interface prior to
commissioning. The EG shall demonstrate to Eskom that each Application Service Data Unit (ASDU) that
was implemented is behaving as expected.
The EG shall supply Eskom with the Acceptance Test Procedure to be followed for conducting the
conformance test. Eskom shall be given the opportunity to influence the Test Procedure prior to its
finalisation.
Eskom shall supply the EG with the applicable Protocol Implementation Document upon request.
4.2.2 SCADA Protocol between the Approved Gateway and Eskom Control Centre
The IEC 60870-5-101 protocol shall be implemented between the Approved Gateway and the Eskom
Control Centre when the EG connects directly to the Eskom Transmission System.
The DNP3 protocol shall be implemented between the Approved Gateway and the Eskom Control Centre
when the EG connects to the Eskom Distribution System.
4.2.3 SCADA Protocols within the EG system
The EG may use any protocol of their choice for communication between the EG field devices and the EG
RTU.
The protocol used should however be capable of time stamping of all digital inputs at the IED level.
The EG shall be responsible for correct implementation of the communication protocol between the EG
RTU and the field IEDs.
If the IEDs in the EG substation support the applicable Eskom Approved protocols (IEC 60870-5-101 or
DNP3), the EG may interface the IEDs directly to the Approved Gateway. The serial port capacity
limitations of the Approved Gateway must be ascertained from the Supplier and must not be exceeded.
Where a Distribution connected EG is using the approved Eskom RTU as their SCADA Gateway/RTU it can
double-up as the Eskom Approved Gateway provided that the applicable Eskom firmware is used.
Where a Transmission connected EG is using the approved Eskom RTU or approved Eskom Gateway
(currently GE D400) as their SCADA Gateway/RTU it can double-up as the Eskom Approved Gateway
provided that the applicable Eskom firmware is used.
4.3 TELECOMMUNICATION INTERFACE REQUIREMENTS
Large capacity EGs have the potential of pushing the system voltage to the trip level, which is an
undesirable situation. It is therefore imperative for larger EGs to have a very reliable communication link
between the EG and the Eskom Control Centres. The type of communication interface shall therefore be
dictated by the generating capacity of the EG and the voltage level that the EG connects to the Grid.
The available telecommunication interface to the Eskom Control Centres may vary from substation to
substation.
There are three acceptable communication interface options as follows;
a) Option 1: X.21 channel (very high availability full-duplex channel suitable for polled comms).
b) Option 2: UHF radio channel (high availability half-duplex channel not suitable for polled comms).
c) Option 3: Satellite channel (high availability option for where Eskom has no comms infrastructure)
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The EG should obtain verification at the inquiry stage from Eskom as to which interface option will be used
in order to adequately cater for this.
Eskom shall be responsible for the running cost and maintenance of the communication equipment
between the Eskom substation and the Eskom Control Centre, once commissioned.
In all cases, The EG shall supply and install at least a 24-core 9/125 µm single-mode fibre optic cable
between the EG substation and the Eskom substation.
4.3.1 Option1: X.21 communication interface
Due to the impact that a category C generator can have on the Grid, it shall use the X.21 interface for
communication with the Eskom Control Centres wherever feasible. If the Eskom connecting substation
does not have X.21 communications, it should be upgraded to have this facility wherever feasible.
Regardless of its size, all EGs connecting at EHV levels shall use the X.21 option.
For the Self-Builds, where the EGs are building a new substation for Eskom, the new Eskom substation
shall be equipped with the X.21 communication facility. The EG shall make timely provision for the
communication equipment to be installed at the new substation.
The fibre optic cable will facilitate the communication interface between the Eskom Approved Gateway at
the EG substation and the X.21 communication equipment installed at the Eskom substation.
A fibre optic to RS422/RS485(4-wire) media converter shall be used to interface with the X.21
communication equipment. This requirement is to enable the connection of the Approved Gateway and
Eskom substation RTU to the same X.21 interface on the Eskom telecommunications equipment. The
standard media converter used for this purpose shall be sourced from the Substation Control System
Eskom National Contract (ENC).
The Approved Gateway at the EG substation shall also have a fibre to RS232 communication interface for
each master station communication channel to facilitate interfacing with the fibre to RS422/RS485 media
converter at the Eskom substation.
4.3.1.1 Responsibilities and Ownership
a) The EG shall supply, install and commission at least a 24-core 9/125 µm single-mode fibre optic
cable between the fibre patch panels in the EG and Eskom substations. OPGW is recommended.
b) When installed on a power line, the fibre shall be owned and maintained by the owner of the line
otherwise the fibre shall be owned and maintained by the EG. The extent of this responsibility is to
the fibre patch panels in the substations at each end.
c) The EG shall supply and install the fibre patch panel at the EG substation.
d) Eskom shall provide and install the fibre patch panel at the Eskom site
e) It shall be Eskom‘s responsibility to terminate from the fibre patch panel to the communications
equipment located at the Eskom substation.
f) Eskom shall also supply all ancillary equipment and cabling requirements for the connection from
the fibre patch panel located at the Eskom substation to the Eskom communications equipment.
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Eskom Transmission
Main & Standby Control
Centres
Eskom Distribution
Control Centre
IEC 60870-5-101
Eskom Control Room
EG Control Room
Eskom Comms
Equipment
FO / RS422
Converter x 3
Eskom
SCADA
Gateway
IED
FO Patch
Panel
IED
FO Patch
Panel
IED
Eskom
Approved
Gateway
IED
Eskom Transmission Substation
IED
EG Gateway
RTU
IED
EG Substation
Figure 4-1: X.21 communication interface (Transmission)
Figure 4-1 above illustrates the communication links, interfaces and protocols for the case of a
Transmission connected EG.
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Eskom Distribution
Control Centre
DNP3
Eskom Control Room
EG Control Room
Eskom Comms
Equipment
FO/RS422
Converter x 2
Eskom
SCADA
Gateway
IED
FO Patch
Panel
IED
FO Patch
Panel
IED
Eskom
Approved
Gateway
IED
Eskom Distribution Substation
IED
EG Gateway
RTU
IED
EG Substation
Figure 4-2: X.21 communication interface (Distribution)
Figure 4-2 above illustrates the communication links, interfaces and protocols for the case of a Distribution
connected EG interfacing via an Eskom X.21 link.
4.3.2 Option2: UHF radio communication interface.
For category B generators, the UHF area radio option may be used. This however does not preclude the
EG from employing X.21 communication where feasible as this is the more reliable form of communication
interface. It should be noted that the Eskom UHF Radio channel is shared by up to 40 substations which
results in non-deterministic latency.
The availability of this option depends on the availability of a UHF radio repeater within range.
The Approved Gateway will ensure that the EG SCADA system is adequately capable of successful
communication over this interface.
This option is not allowed for Transmission connected generators.
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4.3.2.1 Responsibilities and ownership
a) The EG shall supply, install and commission at least a 24-core 9/125 µm single-mode fibre optic
cable between the fibre patch panels in the EG and Eskom substations, OPGW is recommended.
b) When installed on a power line, the fibre shall be owned and maintained by the owner of the line
otherwise the fibre shall be owned and maintained by the EG. The extent of this responsibility is to
the fibre patch panels in the substations at each end.
c) The EG shall supply and install a fibre patch panel at the EG substation.
d) Eskom shall supply and install the fibre patch panel at the Eskom site.
e) It shall be Eskom‘s responsibility to terminate from the fibre patch panel to the communications
equipment located at the Eskom substation.
f) Eskom shall also supply all ancillary equipment and cabling requirements for this connection from
the fibre patch panel located at the Eskom substation to the Eskom communications equipment.
g) Eskom shall be responsible for the UHF radio equipment hardware and installation thereof. Eskom
shall be responsible for application of the radio operating frequency license from the Independent
Communications Authority of South Africa (ICASA).
Eskom Distribution
Control Centre
DNP3
Eskom Control Room
EG Control Room
FO/RS232
Converter
Panel
Eskom
SCADA
Gateway
IED
FO Patch
Panel
IED
FO Patch
Panel
IED
IED
Eskom Distribution Substation
Eskom
Approved
Gateway
IED
EG Gateway
RTU
IED
EG Substation
Figure 4-3: UHF radio communication interface
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4.3.3 Option3: Satellite communication interface.
This communication interface may only be considered if options 1 and 2 are not possible or allowed. This
will probably only be needed in deep rural areas where the installation of terrestrial communication is
impractical or too costly.
4.3.3.1 Responsibilities and ownership
a) The EG shall supply, install and commission at least a 24-core 9/125 µm single-mode fibre optic
cable between the fibre patch panels in the EG and Eskom substations, OPGW is recommended.
b) When installed on a power line, the fibre shall be owned and maintained by the owner of the line
otherwise the fibre shall be owned and maintained by the EG. The extent of this responsibility is to
the fibre patch panels in the substations at each end.
c) The EG shall supply and install a fibre patch panel at the EG substation.
d) Eskom shall supply and install the fibre patch panel at the Eskom site.
e) It shall be Eskom‘s responsibility to terminate from the fibre patch panel to the communications
equipment located at the Eskom substation.
f) Eskom shall also supply all ancillary equipment and cabling requirements for the connection from
the fibre patch panel located at the Eskom substation to the Eskom communications equipment.
g) Eskom shall be responsible for the satellite equipment connectivity and licensing arrangements.
The satellite receiver equipment shall be located at the Eskom substation.
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Eskom Distribution
Control Centre
DNP3
Eskom Control Room
EG Control Room
FO/RS232
Converter
Eskom
SCADA
Gateway
IED
FO Patch
Panel
IED
FO Patch
Panel
IED
Panel
IED
Eskom Distribution Substation
Eskom
Approved
Gateway
IED
EG Gateway
RTU
IED
EG Substation
Figure 4-4: Satellite communication interface.
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4.4 MINIMUM DATA EXCHANGE REQUIREMENTS
The data exchange requirements of the System Operators related to the Eskom owned Substation and
Lines is covered in Eskom‘s internal design standards and will not be dealt with specifically in this standard.
The data exchange between the EG SCADA systems and Eskom Control Centres shall conform to the
Codes and this standard as laid out in section 0 above.
In the GCCRPPSA the data exchange requirements for the EG are grouped according to the EG category.
Currently the category definitions in the GCCRPPSA indicate that only LV connected Embedded
Generators fall into category A. As illustrated in the table below, MV connected EGs with rated power less
than 1 MVA fall into category B.
Table 4-1: Embedded Generation categories
RATED POWER
less than 1 MVA
1 MVA but less than 20 MVA
20 MVA and higher
LV Connected
Category A
Category B
Category C
MV, HV or EHV connected
Category B
Category B
Category C
Therefore the requirements for the exchange of signals between the NSP and category A Embedded
Generators are outside the scope of this standard and will be covered by NRS 097-2.
Requirements for the exchange of signals between the NSP and EGs of category B and C are described in
subsequent sections. A detailed signal list is provided in Annex G.
The signals indicated below are the minimum requirement that the EG must provide; additional site-specific
signals may also be accommodated in agreement with the relevant SO.
Section 13.2 of the GCCRPPSA stipulates periodic update requirements for Analogue and Digital signals
but due to the nature of Eskom‘s SCADA implementations these requirements are impractical. The times
stipulated in the GCCRPPSA will instead be interpreted as maximum delays between the initiation of a
29
change and the arrival of the related signal at the Approved Gateway as explained below .
All digital input changes shall be reported to the Approved Gateway within 1 second of any change and
shall be timestamped to an accuracy of +/-10 milliseconds (UTC +2:00).
Timestamps on analogue changes are not required.
All analogue input changes shall be reported to the Approved Gateway within 2 seconds of any change
greater than or equal to the applicable jitter-values as follows;
a) Frequency shall be updated when the value changes by 0.01 Hz or more.
b) Power factor values shall be updated when the value changes by 0.01 or more.
c) Active power values shall be updated when the value changes by 1% or more of rated power. If
rated power is 50 MW or more then values shall be updated when the value changes by 0.5 MW or
more.
d) Actual Ramp Rate shall be updated when the value changes by 1 MW/min or more.
e) All other analogues shall be updated when the value changes by 1% or more of the full-scale or
nominal value.
To protect the communications bandwidth especially on Area Radio channels the jitter values used by the
Approved Gateway to report analogue changes to the NSP Control Centre may be set higher than the
values listed above.
Support for both direct operate and select-before-operate Commands shall be provided between the Eskom
Approved Gateway and the EG Gateway/RTU.
29
A request for review has been lodged with the GCCRPPSA document Secretariat concerning this change
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4.4.1 Generator Availability and Forecast Production values
It should be noted that the delivery of the Availability and Forecast Production Values to the Control Centres
are no longer required via SCADA but rather required via an FTP push service from the EG to the Eskom
30
FTP site .
The content of each forecast will be structured using XML tags. An example is provided in the table below.
The format is subject to change.
Table 4-2 - XML definition for 6 hour forecast data
<?xml version="1.0" encoding="UTF-8"?>
<esk:OfferFile xmlns:esk="http://www.eskom.co.za/offers"
xmlns:xsi="http://www.w3.org/2001/XMLSchema-instance"
xsi:schemaLocation="http://www.eskom.co.za/offers offers.xsd">
<FileHeader Filename="H6_forecast.xml" Timestamp="2013/10/17 06:02:41 AM">
<Station StationId="4101">
<Unit UnitId="Unit ID">
<OfferDay Date="2013-09-12">
<OfferIncrement Increment="0">
<MW>0</MW>
<Price>0.0</Price>
</OfferIncrement>
<OfferHour Hour="22">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>30 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
</OfferHour>
<OfferHour Hour="23">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>31 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
</OfferHour>
</OfferDay>
<OfferDay Date="2013-09-13">
<OfferIncrement Increment="0">
<MW>0</MW>
<Price>0.0</Price>
</OfferIncrement>
<OfferHour Hour="0">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>31 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
30
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</OfferHour>
<OfferHour Hour="1">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>30 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
</OfferHour>
<OfferHour Hour="2">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>30 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
</OfferHour>
<OfferHour Hour="3">
<Availability>100</Availability>
<Flexible>false</Flexible>
<Run>true</Run>
<Forecast>30 </Forecast>
<MVARLowLimit>10</MVARLowLimit>
<MVARHighLimit>40</MVARHighLimit>
</OfferHour>
</OfferDay>
</Unit>
</Station>
</FileHeader>
</esk:OfferFile>
4.4.2 The concept of a Bay
Figure 4-5 is an example of a typical Eskom Transmission connected EG electrical interface diagram.
In this figure the Breakers are shown as squares and the line isolators and busbar isolators are shown as
diamonds. In this case a solid red symbol indicates that the device is closed and a hollow green symbol
indicates that the device is open or tripped.
The breaker, line isolators, earth switches and busbar isolators are all grouped together into a logical unit
called a Bay. The Bay is the group of electrical devices that provide the electrical connection to the
busbars.
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Busbar
Isolators
Diff
Protection
Isolator 1
Breaker 1
Busbar kV
MW / Mvar
Amps (3 Ph)
Hz, kV & Bus
QOS/Metering
Isolator 2
MW / Mvar
Amps (3 Ph)
Hz, kV & Bus
QOS/Metering
Eskom Bay
Breaker 2
CT
Busbar kV
RPP Bay
Figure 4-5: Simplistic view of an Eskom—EG Electrical interface
The indications shown in Table 4-4 below refer to the Bay as a unit and the alarms associated with it.
In all cases, each bay shall have a Supervisory Isolator Switch associated with it, which when switched off,
effectively prevents any and all supervisory controls from reaching the physical plant. All operating on the
Bay under these conditions shall be performed locally from the panel by the substation personnel.
It should be noted that the EG Breaker will not normally be tripped directly by the Eskom Control Centres.
In practice Eskom Control Centres will use the ‗Stop‘ command to reduce the plant output to zero.
4.4.3 Double-bit Indications
Breakers, isolators, earth switches and any other power system switch such as links etc. shall be indicated
by means of two sensors/contacts, one bit that indicates all poles fully opened and another bit that indicates
all poles fully closed.
When the IEC-101 protocol is used between the EG and the Approved Gateway, these two bits shall be
reported via the double-bit ASDU.. When the DNP3 protocol is used between the EG and the Approved
Gateway, two consecutive single bits should be used rather than the DNP3 double-bit ASDU.
Double-bit indications being sent to the Eskom Control Centres are required to adhere to the convention
described in the table below.
Table 4-3: Double-bit indications
Bit values per index
number
n+1 n
0 0
0 1
1 0
1 1
Meaning for Breaker
and Isolator states
In transit
Opened
Closed
Invalid
Meaning for Supervisory
Switch states
In transit
On (active)
Off (inactive)
Invalid
Meaning for
Start/Stop function
states
In transit
Stopped
Started
Invalid
It should be noted that all other signals stipulated in the GCCRPPSA as double-bit indications have been
31
changed by Eskom to single-bit indications .
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4.4.4 Digital Input Signals From the EG
The bay-wide digital indications for each bay as required by the Grid Code and NSP are as follows:
Table 4-4: Bay-wide binary indications
Bay binary
Indications
State
Supervisory
Switch
In transit-00
On-01
Off-10
Invalid-11
Type
Report
Explanation
Doublebit
1 second
On
change
When Off this switch prevents supervisory
controls from being transferred from the
gateway device to the bay devices.
4.4.4.1 Breaker State and Isolator State Indications
It is a System Operator requirement that all Breakers and Isolators between the HV side of the EG
transformer and the PSS are telemetered.
The breaker and isolator state indications for each POC are listed as shown in Table 4-5
Table 4-5: Switch state indications
Device State
Breaker State
Isolator State
State
Opened-01
Closed-10
In transit-00
Invalid-11
Opened-01
Closed-10
In transit-00
Invalid-11
Type
Report
Explanation
Double-bit
1 second On
change
Circuit Breaker State
Double-bit
1 second On
change
Isolator State (if needed)
4.4.5 Analogue Input Signals
The analogue indications for each bay are listed in the Grid Code and comprise the following.
Table 4-6: Bay Analogues from the EG site
Analogue indications
Type
Report
Active power sent out
Analogue
2 seconds(On
change)
Reactive power sent out
Analogue
2 seconds(On
change)
Current sent out
Analogue
Actual ramp rate
Analogue
Power Factor
Analogue
Voltage sent out
Analogue
Frequency
Analogue
2 seconds(On
change)
2 seconds(On
change)
2 seconds(On
change)
2 seconds(On
change)
2 seconds(On
change)
Explanation
Measured summated three phase active
power sent-out at the POC
Export/Produce(+)
Measured summated three phase Reactive
Power sent out at the POC
Export/Produce(+) Import/Absorb(-)
Red, White and Blue phase amps
Active Power Ramp rate of the entire
facility. (+)Up, (-)Down
Power Factor of the EG
Voltage at the POC
Frequency of the generated energy (only
required where Islanding is allowed)
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The digital indications for each bay as required by the Grid Code and comprise the following:
It should be noted that all of the following single-bit signal will use at ‗1‘ state when active and ‗0‘ value
when non active.
Table 4-7: Bay Binary Indications
Bay digital
indications
Plant Islanded
Plant Shutdown
State
Type
Yes-1
No-0
Yes-1
No-0
Report
Explanation
Singlebit
1 second
(On
change)
This indication must go high when the EG detects that it
is islanded. This indication must stay high as long as
the EG is in an islanded state. Typically this could be a
result of the frequency dropping below the sustainability
point of the plant which will ultimately result in the plant
disconnecting from the Grid
Singlebit
1 second
(On
change)
High when the EG initiates a shutdown. .Stays high as
long as the EG is shutdown. Not set when a stop or trip
command is issued from the NSP
4.4.6 Weather and Environmental Data
As per the Grid Code the environmental measurements required from the EG are listed in the table below.
Table 4-8: EG environmental inputs
Environmental data
Type
Report
Wind Speed
Analogue
1 minute
Wind Direction
Analogue
1 minute
Air temperature
Air pressure
Air density
Solar Irradiation
Humidity
Analogue
Analogue
Analogue
Analogue
Analogue
1 minute
1 minute
1 minute
1 minute
1 minute
Explanation
Within 75% of the hub height) – measured signal in
meters/second (for WPP only)
Within 75% of the hub height) – measured signal in
degrees from true north(0-359) (for WPP only)
Measured signal in degrees centigrade (-20.0 to 50.0);
Measured signal in millibar (800 to 1400).
3
Measured signal in kg/m (for WPP only)
2
Measured signal in watts/m
Measured signal in Percentage
4.4.7 Command Function Requirements
The table below differs from Table 3 in the GCCRPPSA due to changes requested by the SO. The purpose
of the various command functions is to ensure overall control and monitoring of the EG‘s generation.
The Control Centre shall be able to dispatch the command signals listed in this document to each EG.
There are typically two types of controls:
1. Normal device state change – Trip/Close or On/Off or Stop/Start etc.
2. Setpoint controls – Analogue Output commands or Digital Raise/Lower commands
The Grid Codes stipulated Raise/Lower commands for all Setpoint controls however Analogue Output
commands have many advantages and therefore the System Operator has requested that setpoint
32
commands be performed via Analogue Outputs rather than Raise/Lower Digital Outputs . Where AGC is
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fitted, this document makes provision for both options. EGs should confirm the choose of AGC setpoint
control with the SO.
Table 4-9: Command functions
Command function
Absolute production constraint
Power factor control
Q control
Voltage control *
Power gradient constraint
Frequency control *
Delta production constraint
Category B
X
X
X
X
X
-
Category C
X
X
X
X
X
X
X
* The EG must not perform any frequency or voltage control functions without having entered into a
specific agreement to this effect with the Network Service Provider.
The Control Centre shall be able to send a trip signal to the Breaker that fulfils 13.3.2 of the GCCRPPSA
using the following control:
Table 4-10: Breaker Command Signal
Command
Breaker Trip
Action
Trip (no Close)
Reason
Isolate the EG from the Grid
4.4.7.1 Frequency Response System Settings
Primary frequency control services are only provided if the EG has entered into an ancillary services
agreement with the SO.
The EG shall make the following primary frequency control signals available via the Approved Gateway:
Table 4-11: Primary frequency response command
Command
Action
Frequency Control
On/Off
Reason
Activate or deactivate Frequency Control Mode as
requested by the applicable Control Centre
Table 4-12: Primary frequency response indications
Digital indications
State
Type
Explanation
Single-bit
Report
1 second
(On change)
Frequency Control
Mode Status
On-1
Off-0
Frequency Control not
ready
Yes-1
No-0
Single-bit
1 second
(On change)
Will report high if frequency control
cannot be done
Will report a ‗1‘ state when active and
‗0‘ state when not active
4.4.7.2 Automatic Generation Control System Settings
Automatic Generation Control (AGC), also called Secondary frequency control, is only required if the EG
has entered into an ancillary services agreement with the SO. This function is currently only applicable to
category C EGs connected to the Transmission system (excluding PVPPs). The AGC functional
requirements are specified in the Transmission AGC functional description, Unique identifier: 32-1211.
The AGC governor setting can be adjusted by a setpoint command.
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Table 4-13: AGC commands
Command
Action
Reason
AGC Mode
On/Off
Activate or deactivate Automatic Generation Control
AGC setpoint
Setpoint command
Setpoint command to change the AGC setpoint when the
EG is on AGC
Table 4-14: AGC indications
Binary indications
State
Type
Report
Explanation
AGC mode status
On-1
Off-0
Singlebit
1 second
(On change)
Will report a ‗1‘ state when active and ‗0‘ state
when not active
1 second
(On change)
Will report high if the controller opts to not take
any more Raise commands. The raise block
signal is set high when the AGC setpoint value is
equal to or higher than the AGC high regulating
limit.
1 second
(On change)
Will report high if the controller opts to not take
any more Lower commands. The lower block
signal is set high when the AGC setpoint value is
equal to or lower than the AGC low regulating
limit.
Raise block
Lower block
Yes-1
No-0
Yes-1
No-0
Singlebit
Singlebit
Table 4-15: AGC analogues
Analogue indications
Type
Report
Explanation
AGC Setpoint feedback
Analogue
2 seconds(On
change and jitter)
EG echo response to a setpoint command
or a bit string command
AGC High regulating
limit
Analogue
2 seconds(On
change and jitter)
Higher limit of the active power provided for
AGC. This limit shall also be updated when
in Delta mode.
AGC Low regulating
limit
Analogue
2 seconds(On
change and jitter)
Lower limit of the active power provided for
AGC. This limit shall also be updated when
in Delta mode.
If secondary frequency control is not possible, then the ‗frequency control not ready‘ indication shall be set
high.
4.4.7.3 Active Power Constraint / Curtailment
The following discussion pertains to the following constraint areas:
Absolute Production Constraint (Curtailment)
Delta Production Constraint (P-delta)
Power Gradient Constraint (Power Gradient)
In the event of excessive voltage or frequency conditions, the only way to bring the power system back
within the defined operating limits is to reduce generator output.
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The System Operator has decided that the Absolute Production Constraint (Curtailment) and Delta
Production Constraints will be mutually exclusive.
4.4.7.4 Absolute Production constraint
Curtailment to a set Power
The Control Centre will set the desired Power output by sending a ‗setpoint‘ command.
The Control Centre will send a ‗Curtailment mode ON‘ command.
The EG installation will do nothing until the Curtailment Mode is activated.
When it is in the ‗ON‘ state the EG installation will limit the total MW output to the value that is defined by
the Curtailment setpoint.
When conditions in the power system improve, the Control Centre will reset the ‗Curtailment mode‘ state to
‗OFF‘. When the EG installation detects the reset, it will then be able to resume its planned MW output.
It is essential that when Curtailment is initiated and cancelled that the time and the Curtailment setpoint
value is captured and logged to ensure that disputes are minimised.
When the setpoint for Curtailment (Absolute Production Constraint) has to be changed, such change shall
be commenced within contractual time frames and ramp rates.
Table 4-16: Curtailment commands
Command
Action
Curtailment mode
On/Off
Curtailment setpoint
Setpoint command
Reason
Activate or deactivate production curtailment in the event
of system constraints.(also called absolute production
constraint)
Setpoint command to change the active power setpoint of
the EG
Table 4-17: Curtailment indications
Digital indications
State
Type
Curtailment mode
status
On-1
Off-0
Single-bit
Report
1 second (On
change)
Curtailment in
progress
Yes-1
No-0
Single-bit
1 second (On
change)
Curtailment Not
Ready
Yes-1
No-0
Single-bit
1 second (On
change)
Explanation
Will report a ‗1‘ state when active and ‗0‘
state when not active
Will be high while the facility is moving from
the current value to the curtailed value.
Once the facility reaches the curtailment
value, this bit will be reset.
Will be high in the event of conditions at the
plant preventing the plant from being
curtailed.
In the case of any not ready indication being
detected, it is up to the EG to correct the
problem as soon as possible.
Table 4-18: Curtailment analogue
Analogue indications
Type
Report
Curtailment Setpoint
feedback
Analogue
2 seconds(On
change)
Explanation
EG echo response to a new Power
setpoint issued by the Control Centre.
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Curtailment to 0 MW
Under extreme system conditions and when the curtailment option will take too long, provision has been
made to send a ‗Stop‘ command to the EG to initiate a controlled shutdown of the installation at a rate faster
than the normal operational ramp rate setting. The normal operating and startup ramp rate setting is called
the Positive or Up Ramp Rate. The ramp rate applicable to a ‗Stop‘ command is called the Negative or
Down Ramp Rate as per Chap 12 of the GCCRPPSA.
When this ‗Stop‘ command is received by the EG it should set the ‗Curtailment Setpoint feedback‘ to zero,
the ‗Curtailment Mode‘ and ‗Curtailment in Progress‘ indications to ‗ON‘ and should ramp the installation to
zero output at the negative ramp rate setting. Once generation has stopped, the ‗Curtailment in Progress‘
indication should be set ‗Off‘.
It is not expected that this command action would open the EG Breaker but only reduce the output to zero.
This will maintain supply to auxiliaries as required.
When the ‗START‘ command is issued, the EG should set the ‗Curtailment Mode‘ to ‗Off‘ and ramp up
generation to the scheduled generation output but no faster than the positive ramp rate setting.
Table 4-19: Generation Stop/Start command
Command
Action
Generation Start/Stop
Start/Stop
Reason
By sending a START command, the Control Centre should be
able to start generation of the EG and by sending a STOP
command, the Control Centre should be able to bring the EG to
a non-generating mode, but do not open the Breaker.
Table 4-20: Generation Stop/Start indication
Digital indications
State
Type
Generation State
Started-10
Stopped-01
Doublebit
Report
1 second
(On
change)
Explanation
Will report a ‗10‘ state on receipt of a
START command and ‗01‘ state for
STOP command
4.4.7.5 Delta Production Constraint
This function is only applicable to Category C (exception of PVPP).
To activate this function the Control Centre will send the ‗ON‘ command to the ‗P-Delta Mode‘ address.
Before activating P-delta mode the Control Centre shall set the P-delta setpoint (percentage) as a ‗setpoint‘
command. The EG shall decrease the output by P-delta providing reserves for frequency control. The
Control Centre shall reset the ‗Delta Production Mode‘ to ‗OFF‘ if the reserve functionality is not required
any further.
The ‗P-delta Constraint mode not ready‘ shall be set high whenever the Delta Production Constraint facility
is not available.
When the P-delta Constraint is changed, such change shall be commenced within contracted time frames.
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Table 4-21: Delta production commands
Command
Action
Reason
P-delta constraint mode
On/Off
P-delta Setpoint
Setpoint command
Activate or deactivate delta production constraint.
The EG shall decrease its output by the set
percentage of available active power to provide
reserve for frequency control
Setpoint command to change the P-delta setpoint
(expressed in percentage).
Table 4-22: Delta production binary indications
Digital indications
Start
Type
Report
Explanation
P-delta constraint
mode
On-1
Off-0
Single-bit
1 second
(On change)
P-delta mode Not
Ready
Yes-1
No-0
Single-bit
1 second
(On change)
Will report a ‗1‘ state when active and ‗0‘
state when not active
Will be high in the event of conditions at the
plant preventing the plant from going into
Delta Production Mode.
Table 4-23: Delta production analogues
Analogue indications
Type
P-delta setpoint feedback
Analogue
Report
2 seconds(On
change and
jitter)
Explanation
EG echo response to a new P-delta
setpoint(percentage) issued by the
applicable Control Centre
4.4.7.6 Power Gradient Constraint
A Power Gradient Constraint is used to limit the maximum ramp rates by which the active power can be
changed in the event of changes in primary renewable energy supply of the EG.
A Power Gradient Constraint is typically used for reasons of system operation to prevent rapid changes in
active power from impacting the stability of the Grid.
For example when a conventional generator is shutting down with ramp rates less than a wind farm, the
ramp rates of the wind farm (which has increased to compensate for the loss of generation) can be set by
the Control Centre in order to keep the power balance.
The Control Centre will send ‗setpoint commands‘ to change ramp rate setpoints of the EG to new values
within the limits specified by the EG.
The EG will echo the updated values within 2 seconds of the change and will proceed to respond to the
updated ramp rates within 30 seconds.
To implement the Power Gradient Constraint, the Control Centre will send an ‗ON‘ command to the ‗Power
gradient constraint mode‘ address.
The ‗Power gradient mode not ready‘ mode shall be set to high by the EG whenever ramp rate
modifications cannot be done.
Apart from the echo values being updated, no additional activation is implemented.
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Table 4-24: Power gradient commands
Command
Action
Reason
Power gradient constraint mode
On/Off
Up Ramp Rate Setpoint
Setpoint command
Down Ramp Rate Setpoint
Setpoint command
Activate or deactivate power gradient constraint
in the event of system constraints.
Setpoint command to change the up ramp rate
of the EG
Setpoint command to change the down ramp
rate of the EG
Table 4-25: Power gradient indications
Binary indications
State
Type
Report
Explanation
Power gradient
constraint mode
On-1
Off-0
Single-bit
1 second
(On change)
Will report a ‗1‘ state when active and
‗0‘ state when not active
Power gradient mode
not ready
Yes-1
No-0
Single-bit
1 second
(On change)
Will report a ‗1‘ state when ‗not ready‘
and ‗0‘ state when ‗ready‘
Table 4-26: Power gradient analogues
Analogue indications
Type
Report
Explanation
Up Ramp Rate setpoint
feedback
Analogue
2 seconds
(On change)
Up ramp rate high limit
Analogue
2 seconds
(On change)
Up ramp rate low limit
Analogue
2 seconds
(On change)
Down Ramp Rate
setpoint feedback
Analogue
2 seconds
(On change)
Down Ramp rate high
limit
Analogue
2 seconds
(On change)
Down ramp rate low limit
Analogue
2 seconds
(On change)
EG echo response to a new ‗up‘ ramp rate
setpoint issued by the applicable Control Centre
When the plant is in power gradient constraint
mode, the EG shall give the NSP an indication of
what the high limit is for up ramp rate.
When the plant is in power gradient constraint
mode, the EG shall give the NSP an indication of
what the low limit is for up ramp rate.
EG echo response to a new ‗down‘ ramp rate
setpoint issued by the applicable Control Centre
When the plant is in power gradient constraint
mode, the EG shall give the NSP an indication of
what the high limit is for down ramp rate.
When the plant is in power gradient constraint
mode, the EG shall give the NSP an indication of
what the low limit is for down ramp rate.
4.4.7.7 Reactive Power and Voltage Control Functions
The EG shall be equipped with reactive power control functions capable of controlling the reactive power
supplied by the EG at the POC as well as a voltage control function capable of controlling the voltage at the
POC via commands using setpoints and gradients.
The required reactive power ranges for Category B and C are shown in the table below.
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Table 4-27: Reactive Power Output ranges
Category
Power Factor
B
0.975 lagging and 0.975 leading available from 20% of rated power measured at the POC.
C
0.95 lagging and 0.95 leading available from 20% of rated power measured at the POC
The reactive power and voltage control functions are mutually exclusive, which means that only one of the
three functions mentioned below can be active at a time. At least one of these functions must be active.
a) Reactive Power Control (Q control)
b) Power Factor control (PF Control)
c) Voltage control (V Control)
The control function and applied parameter settings for reactive power and voltage control functions shall
be determined by the NSP in collaboration with the SO, and implemented by the EG.
The agreed voltage control functions shall be documented in the operating agreement.
 Q Mode
 Voltage
 Power Factor
 60 Mvar SP
 400 kV SP
NR
- 40 : 40 Mvar
 0.95 SP
NR
NR
 Curtailment
RPP Plant
Hz : 50.01 Pf : 0.95
Ramp Rate : 10 / 15
Islanded: No
 10 MW SP
Power Gradient Constraint :  Off
 10 Up SP
(Ramp Rate MW/Min)
NR
Delta Production Constraint :  Off
  3% Down SP
NR
NR
 Stop
33 kV
( 5 to 15 Range )
 15 Down SP ( 5 to 15 Range )
 97
 30
135
5
AGC :  Off
R Block: No
L Block : Yes
60 MW (AGC Set Point)
60 MW to 80 MW Regulating limits
133 kV
Primary Hz Control :  Off
NR
Weather
5.5 m/s 35
Muldr 1
 80
 10
22 C
Bacch 1
 17
 20
1.204 kg/m3
875 mB 7.5 w/m2
Figure 4-6: Mode Change HMI interface example
Figure 4-6 shows an example screen of the mode change functions and the stop(start) command button.
4.4.7.8 Reactive Power Control Mode
The Control Centre will firstly change the analogue setpoint of the Q-Control value to the desired output.
On receipt of the Q-mode activation request, the EG shall update its Q-mode echo analogue value in
response to the new value within two seconds.
The Control Centre will then send a supervisory command to the EG to move the plant to Q control mode
which will set the associated digital indication to ‗active‘.
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At the same time the EG control system shall deactivate both the Power Factor Control mode and the
Voltage Control mode.
The EG shall respond to the new setpoint within 30 seconds after receipt of an order to change to the new
setpoint.
Table 4-28: Q mode commands
Command
Action
Q control mode
On (no OFF)
Q control setpoint
Setpoint command
Reason
Activate Reactive Power Control Mode as
requested by the Control Centre
Command to change the kvar or Mvar setpoint
of the EG
Table 4-29: Q mode binary indications
Digital indications
State
Type
Q control mode status
On-1
Off-0
Singlebit
Q control mode Not
Ready
Yes-1
No-0
Singlebit
Report
1 second
(On
change)
1 second
(On
change)
Explanation
Will report a ‗1‘ state when active and
‗0‘ state when not active
Will be high in the event of conditions at
the plant preventing the plant from
going into Q mode.
Table 4-30: Q mode analogues
Analogue indications
Type
Report
Q Lower Limit
Analogue
2 seconds
(On change and
jitter)
Q Upper Limit
Analogue
2 seconds
(On change and
jitter)
Q Setpoint feedback
Analogue
2 seconds
(On change and
jitter)
Explanation
This value is an indication of the low Reactive
Power operating limit. This value can change
depending upon environmental or plant
conditions.
This value is an indication of the high
Reactive Power operating limit. This value
can change depending upon environmental
or plant conditions.
This value is an indication of the Reactive
Power setpoint issued by the Control Centre
4.4.7.9 Power Factor Control Mode
This function is covered in section 8.2 of the GCCRPPSA.
It is preferred that a single bit is used to indicate the state of this mode to the Control Centre. If the EG can
only provide a double bit indication, this can be changed in the Approved Gateway.
Table 4-31: Power factor commands
Command
Action
PF control mode
On (no OFF)
PF control setpoint
Setpoint command
Reason
Activate Power Factor Mode as requested by the
applicable Control Centre
Setpoint command to change the power factor of the
EG. Producing vars (-), Absorbing vars (+)
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Table 4-32: Power factor binary indications
Digital indications
State
Type
Explanation
Singlebit
Report
1 second (On
change)
PF control mode
On-1
Off-0
PF control mode Not
Ready
Yes-1
No-0
Singlebit
1 second (On
change)
Will be high in the event of conditions at
the plant preventing the plant from going
into this mode.
Will report a ‗1‘ state when active and ‗0‘
state when not active
Table 4-33: Power factor analogue
Analogue indications
Type
Report
PF setpoint feedback
Analogue
2 seconds
(On change)
4.4.7.10
Explanation
Echo response to a new Power Factor setpoint
issued by the applicable Control Centre.
Producing vars (-), Absorbing vars (+)
Voltage Control mode
The Control Centre will firstly change the analogue setpoint of the Voltage Control value to the desired
output. On receipt of the Voltage Control setpoint command, the EG shall update its Voltage control mode
echo analogue setpoint value to the new value within two seconds.
The Control Centre will then send a supervisory command to the EG to move the plant to Voltage Control
mode.
At the same time the EG control system shall set both the Q-Control mode and the PF Control mode as
deactivated and update these states.
On receipt of the Voltage Control-mode activation request, the EG shall respond to the new setpoint within
30 seconds after receipt of an order to change to the new mode.
Table 4-34: Voltage mode commands
Command
Action
Voltage control mode
On (no Off)
Voltage control setpoint
Setpoint command
Reason
Activate Voltage control Mode as requested by
the applicable Control Centre
Setpoint command to change the voltage
Table 4-35: Voltage mode binary indications
Digital indications
State
Type
Voltage control Mode
On-1
Off-0
Single-bit
Voltage mode Not Ready
Yes-1
No-0
Single-bit
Report
1 second
(On
change)
1 second
(On
change)
Explanation
Will report a ‗1‘ state when active and
‗0‘ state when not active
Will be high in the event of conditions
at the plant preventing the plant from
going into the Voltage mode.
Table 4-36: Voltage mode analogue
Analogue indications
Type
Report
Voltage setpoint feedback
Analogue
2 seconds(On
change and jitter)
Explanation
EG echo response to a new voltage
setpoint issued by the Control Centre
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4.4.8 Data Communications Specifications
Active Power Curtailment or Voltage Regulation facilities at the EG may be tested at minimum once a
month. It is essential that facilities exist to allow the testing of the functionality without tripping the EG.
Test procedures will involve a setpoint being sent then activated (which monitors the response) and then
returning to normal.
Where signals or indications required to be provided by the EG become unavailable or do not comply with
applicable standards due to failure of the EG equipment or any other reason under the control of the EG,
the EG shall restore or correct the signals and/or indications within 24 hours.
.
4.4.9 IEC 60870-5-101 Address Ranges
When an EG is connected to the National Control Centre the SCADA signals need to conform to the
Standard 32-1101, TEMSE IEC 60870-5-101 Implementation Standard.
A summary of address numerical ranges found in Appendix C of the above mentioned standard is shown in
the table below.
Table 4-37: Eskom ASDU Information Object Address Range
IEC 60870-5-101 ASDU
Information Object Address
Range
Single point information
1 to 10 000
Double point information
10 001 to 15 000
Step position information
15 001 to 20 000
Measured value
20 001 to 25 000
Integrated totals
25 001 to 30 000
Single command
30 001 to 35 000
Double command
35 001 to 40 000
Bit string of 32 bit command (lamp drive outputs)
40 001 to 43 000 (not used)
Bit string of 32 bit command (AGC outputs)
43 001 to 45 000 (not used)
Setpoint command (meter drive outputs)
(not used)
Setpoint command (setpoint outputs)
45 001 to 65 355
Notes:
1. If no meter drives are present then setpoint commands start at address 45 001.
4.4.10 Provision of the Signal Data and Substation Layout Information to Eskom
When the EG is ready to commence with commissioning of their plant, the following data should be
provided to Eskom commissioning personnel at least 8 weeks prior to the planned commissioning date.
An Excel spread sheet containing the following signal sets – each in its own work sheet.
o
Digital inputs - including cross links to the associated commands
o
Analogue inputs – including scaling information e.g. Low Engineering Value, Low
Transmitted Value, High Engineering Value, High transmitted value,
associated Setpoint command if any etc.
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o
o
Digital commands – including cross links to the associated digital inputs.
Setpoint commands – including scaling information e.g. Low Engineering Value, Low
Transmitted Value, High Engineering Value, High transmitted value,
associated analogue input etc.
o
Revision History
o
Each row on the spread sheet should list the point address, description in full, a 32
character SCADA database Tag name for database identification, and space to record
the commissioning tests.
Station Electric diagram showing all bays; CT ratios, VT Ratios etc.
An example spreadsheet is available from the System Operator on request.
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5 TESTS
Full tests on the equipment needed to meet the requirements of this document must be carried out to the
satisfaction of the Network Service Provider. These tests are the responsibility of the equipment owner.
Tests carried out on equipment installed at the PUC and PGC, as well as loss-of-grid and synchronising
tests must be witnessed by a technical representative of Eskom.
The test on primary equipment must be carried out on site with the equipment installed in its final position.
Results from tests performed before delivery and installation are not acceptable.
The EG must keep a written record of all Protection and Control drawings, protection settings and of test
results. A copy of this record should be available for inspection at the PUC or as required by the Network
Service Provider.
Measurement and injection test equipment used in testing shall have a traceable calibration record, and
shall be of suitable accuracy for the tests to be undertaken.
5.1 PRE-COMMISSIONING AND COMMISSIONING TESTS
Tests to be conducted at the PUC and PGC are divided into two categories:
a) Pre-commissioning tests include all tests to be performed prior to the EG synchronising with the
Network Service Provider‘s network for the first time.
b) Commissioning tests: those tests that can only be completed during the first synchronisation of the
EG with the Network Service Provider‘s network, or thereafter. Commissioning tests shall be
conducted upon written agreement of the Network Service Provider after acceptance of the precommissioning test results.
Pre-commissioning and commissioning tests for equipment installed at the PUC and PGC shall be as per
the requirements of Table 5-1 and Table 5-2 below. Table 5-1 and Table 5-2 also indicate the applicable
synchronising tests to be conducted at every point at which auto-synchronising functionality is provided.
The applicable pre-commissioning and commissioning tests shall be repeated in the event of any firmware
or software change on the control plant equipment, or any hardware component has been replaced,
repaired or modified.
Table 5-1: Pre-commissioning Tests at the PUC and PGC
Equipment
Applicable Eskom
Test Procedure
Test requirements
Primary Plant Equipment
Current Transformers
DPC_34-1035
Insulation Resistance test.
Ratio test.
Magnetising test.
Secondary resistance and burden test.
Polarity test.
Primary injection test.
Visual inspection and application checks.
Voltage Transformers
DPC_34-1033
Insulation Resistance test.
Ratio test.
Lead and burden resistance test.
Polarity test.
Visual inspection and application checks.
Isolators
DPC_34-1034
Insulation Resistance test.
Contact Resistance test.
Contact Timing test.
Visual inspection and application checks.
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Test requirements
DPC_34-1036
Insulation Resistance test.
Contact Resistance test.
Timing Test.
SF6 Gas/Oil tests.
Miscellaneous and General Checks.
DPC_34-1395
Insulation resistance test of CT, VT and DC circuits.
Pick-up/Drop Off tests.
Timing Characteristic Test.
Directional limit tests (where applicable).
Visual Inspection.
Control Plant Equipment
Over Current, Earth Fault & SEF
Protection
Voltage Protection
-
As per IEEE 1547.1 Section 5.2.
Frequency Protection
-
As per IEEE 1547.1 Section 5.3. See Note 1.
Loss-of-grid protection
(Unintentional Islanding)
-
As per IEEE 1547.1 Section 5.7 using appropriate
frequency ramps.
Inverter Anti-islanding
-
As per IEEE 1547.1 Section 5.7 or if preferred, stipulated
in IEC 62116 (relevant to photovoltaic inverters only)
Synchronisation
-
As per IEEE 1547.1 Section 5.4.1.
Reverse Power
-
As per IEEE 1547.1 Section 5.8.
DC Failure
-
Non-urgent and urgent DC failure alarms to be issued as
per the requirements of Section 3.6.2.10.
Note 1. For Frequency relays employing an averaging technique, timing tests may be more appropriately done using ramp
frequency changes in the range from ±50 mHz/s to ±1 Hz/s rather than a step frequency change as per IEEE 1547.1.
Table 5-2: Commissioning Tests
Equipment
Applicable Eskom
Test Procedure
Test requirements
Control Plant Equipment
Unintentional islanding
-
As per IEEE 1547.1 Section 7.4
Synchronisation (all points of
synchronisation)
-
As per IEEE 1547.1 Sections 5.4.2, 5.4.3 or 5.4.4 as
appropriate.
Interlocking circuits
-
All interlock circuits to be tested as per Design.
DTT
-
All transfer trip circuits to be tested dynamically.
Differential functionality
-
All differential functionality to be tested dynamically with
GPS timed injection methodology.
Distance unit functionality
-
All distance functionality to be tested dynamically with
GPS timed injection methodology
5.2 MAINTENANCE TESTS
Maintenance of the primary and control plant and metering equipment shall be conducted according to the
recommendations of NRS-089.
The control plant equipment at the point of connection shall be subject to routine inspection on a three year
cycle, witnessed by a technical representative of Eskom. Major maintenance including secondary injection
of all protection relays and testing of primary equipment (e.g., CTs, VTs, circuit-breakers etc.) shall be
conducted at intervals of 6 years. Major maintenance shall include repeating the unintentional islanding
test conducted during commissioning.
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6 AUTHORISATION
This document has been seen and accepted by:
Name
Designation
Adam Bartylak
Corporate Specialist
Prince Kara
Chief Engineer
Reginald Brooks
SCOT Metering & Measurements SC Chair
Riaan Smit
Convenor RIPP Care Group
Teresa Smit
Corporate Specialist
Thomas Jacobs
SCOT DC SC Chair
Prudence Madiba
Snr Manager, Electrical and C&I Engineering (Gx)
This standard shall apply throughout Eskom Holdings its divisions, subsidiaries and entities wherein Eskom
has a controlling interest.
7 REVISIONS
This revision cancels and replaces revision number 0 of document number DST_34-1765.
Date
Rev.
Compiled By Clause
Oct 2013
1
A Craib
Oct 2013
0.3
K Brown
various
Oct 2013
0.2
A Craib
All Clauses
Aug 2013
0.1
J Ranyane
4
Aug 2013
0.1
July 2013
1
Remarks
Document published
Removed category A signals
Separated Primary and Secondary Frequency Control
functions into 2 sections.
All Mode statuses changed to single bit indications.
Added RPP Code references to the signal list.
All double-bit indications which are not real switches
changed to single bits.
Setpoint commands changed from Raise/Lower digital
commands to Analogue Output setpoint commands.
Removed the signals pertaining to the NSP substation
and feeder.
Removed 32-bit AGC Control
Document revised extensively.
Added the contents of the draft document, Standard for
interfacing EG SCADA systems and Eskom Control
Centres.
Doc number changed to 240_61268576
L Kleyn
Bibliography Updated document references
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Remarks
0
Corrected Electricity Supply Act number from Act 6 of
2006 to Act 4 of 2006; added ‗as amended‘
Added reference to the Renewable Grid Code
SCSASAAL9 superseded by DST_34-1985
SCSASACB6 superseded by DST_34-906
SCSPVAAS9 superseded by DPC_34-1039
DISPVAEB6 superseded by DPC_34-1033
DISPVAEC6 superseded by DPC_34-1035
DISPVAED1 superseded by DPC_34-1395
DISPVAEF9 superseded by DPC_34-1043
DISPVAEG1 superseded by DPC_34-759
DISPVAEQ6 superseded by DPC_34-1036
Added reference to DST_34-1024
0
Updated definition for ‗Island‘ to be the same as in the
Distribution Connection and Use of System Agreement
Updated definition for ‗Point of Common Coupling (PCC)‘
to be the same as in the Distribution Connection and Use
of System Agreement
Added ‗Point of Connection (POC)‘ definition
Updated definition for ‗Point of Utility Connection (PUC)‘
to be the same as in the Distribution Connection and Use
of System Agreement
Updated Secure Supply Point (SSP) to Point of Secure
Supply (PSS) as per the Distribution Connection and Use
of System Agreement
Added ‗Renewable Power Plant (RPP) definition as well
as a list of and definitions for the different types of
renewable power plants according to the renewable
energy sources – as defined in the Grid Code for
Renewable Power Plants.
Added RPP Categories
0
Removed Secure Supply Point (SSP)
0
Corrected Electricity Supply Act number from Act 6 of
2006 to Act 4 of 2006; added ‗as amended‘
Added reference to Grid Code Requirements for
Renewable Power Plants
3.4.1
Added reference to Grid Code Requirements for
Renewable Power Plants
Removed power factor requirements – specified in Grid
Code already
Moved neutral earthing requirements to 3.5.3
3.4.2
Corrected table auto-numbering and references
Added reference to NRS 048-4
3.4.3
Added reference to DPL 34-2149 and SA Grid Code
requirements for RPPs
3.4.4
Changed ‗fault ride through‘ to ‗voltage ride through‘ to
align with the SAGC for RPPs; referenced ride through
requirement in SAGC for RPPs
3.5.3
Re-wrote section to comply with DPL 34-2149
Clarified MV earthing requirements
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Compiled By Clause
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SJ van Zyl
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Remarks
3.5.5
Changed SSP to PSS
4.5.5
Added reference to IDMT overcurrent protection
3.5.7
Changed SSP to PSS
4.5.7
Added section
3.6.1.3
DISSCAAM8 superseded by DSP_34-1488
3.6.2.1
Corrected table auto-numbering and references
Added recommendation for EG to use unit-protection at
POC
3.6.2.2 (m)
March
2008
OF Unique Identifier:
Corrected table references
Added requirement for fault level submission
Added unit protection recommendation
Added CB fail requirement
3.6.2.4
Corrected table auto-numbering and references
Added reference to SAGC for RPPs
3.6.2.7
Corrected table auto-numbering and references
Re-worked section
0
Added reference to DST_34-2095 for auxiliary supply at
switching stations
3.7
Rewrote Metering section to refer to and comply with
relevant Eskom Metering standards and policies.
5
Added requirement for Eskom representative to be a
technical representative
Added requirement to keep signed copy of protection &
control drawings
5.1
Corrected table, table auto-numbering
references
DISPVAEB6 superseded by DPC_34-1033
DISPVAEC6 superseded by DPC_34-1035
DISPVAED1 superseded by DPC_34-1395
DISPVAEQ6 superseded by DPC_34-1036
and
table
5.2
Added requirement for Eskom representative to be a
technical representative
Document published
Incorporated changes agreed upon by work-group and
KEC
Rewrote Section 4.5.3 (Metering).
Document issued for TESCOD comments
Revised Section 4.5.4.2 (SCADA Controls) to indicate
possible requirement of Eskom remote control of
interconnection circuit-breaker.
Rewrote Section 4.6.2 (Quality of Supply).
Extensive revision to incorporate work-group feedback.
Original issue for work-group comments
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8 DEVELOPMENT TEAM
The original revision 0 document was based upon Eskom Guideline ESKAGAAG2 ―Minimum requirements
for the connection of non-Eskom generating plant to the Eskom electrical networks‖ that was compiled in
1995 by a working group led by Graeme Topham. ESKAGAAG2 in turn was based upon Engineering
Recommendation G.59 ―Recommendations for the connection of private generating plant to the Electricity
Boards‘ Distribution Systems‖ issued by the Electricity Council, and prepared for use in relation to the
United Kingdom‘s system.
The present document constitutes an update of the original revision, with contributions made by the
following individuals:
Andrew Craib
Lize-Mari Kleyn
PTM&C, Power Delivery, Engineering
ex-Eskom, EDNS Technology, Eastern Cape Operating Unit
D.C. Requirements:
Richard Vlantis
Design Base & Operating Unit Support, Power Delivery, Engineering
EMC Requirements:
Hendri Geldenhuys
Technology, Power Delivery, Engineering
Metering Requirements:
Mohammed Omar
Reginald Brooks
PTM&C, Power Delivery, Engineering
Maintenance and Operations, WCOU, Distribution
Primary Plant and IPP Workgroup Interface:
Riaan Smit
Planning, Power Delivery, Engineering
QOS Requirements:
Gerhard Botha
PD&U, Research Testing & Development, Sustainability
SCADA Requirements:
Ian Naicker
James Ranyane
Kenneth Brown
Control & Automation, PTM&C, Power Delivery, Engineering
Control & Automation, PTM&C, Power Delivery, Engineering
Control & Automation, PTM&C, Power Delivery, Engineering
TX Requirements:
Kevin Pillay
Matthys Bower
PTM&C, Power Delivery, Engineering
PTM&C, Power Delivery, Engineering
TX SO Requirements:
Adam Bartylak
David Mvura
Geoffrey Ive
Maya Kurup
Richard Candy
Teresa Smit
System Operator, Transmission
System Operator, Transmission
System Operator, Transmission
System Operator, Transmission
System Operator, Transmission
System Operator, Transmission
General:
Andre De La Guerre
Bernard Magoro
Brandon Peterson
Carmintha Moodley
Dayahalan Chetty
Ian Worthington
Kurt Dedekind
Leon Drotsche
Michael Rawson
Nelson Luthuli
Patrick Griffith
Stuart van Zyl
Tejin Gosai
Willem van Heerden
Design Base and Operating Unit Support, Power Delivery, Engineering
Grid Code Management, System Operator, Transmission
Business Integration & Performance Management, Transmission
Regulation Department, Regulation and Legal, Enterprise Development
Network Optimisation KZNOU, Distribution
Southern Grid, Grid Business Management, Transmission
Planning COE, Power Delivery, Engineering
AC Asset Creation, WCOU, Distribution
Network Operations and Support, FSOU, Distribution
North West Grid, Grid Business Management, Transmission
PTM&C, Power Delivery, Engineering
PTM&C, Power Delivery, Engineering
PTM&C, Power Delivery, Engineering
Asset Creation, ECOU, Distribution
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9 ACKNOWLEDGEMENTS
The compiler would like to acknowledge the work completed on the DST_34-1765 revision 0 document by
Stuart van Zyl and on the subsequent revision by Lize-Mari Kleyn. The compiler would also like to thank
both Stuart van Zyl and Lize-Mari Kleyn for their subsequent support to this document.
James Ranyane and Kenneth Brown added the in-depth SCADA requirements to the present document.
Kenneth Brown proofread the entire document, debated, raised and solved numerous issues and re-worked
the SCADA requirements. The compiler would therefore like to thank the co-author Kenneth Brown for his
considerable input to this document.
Riaan Smit supplied in-depth feedback, sometimes at short notice and was of great help throughout the
process.
Teresa Smit provided a co-ordination role which included links to the various committees and debate on
certain issues.
Adam Bartylak, who at short notice checked the System Operations requirements within the document.
Richard Vlantis provided the updated D.C. and Auxiliary Supplies requirements.
Gerhard Botha provided the updated QOS requirements.
Mohammed Omar provided detailed comments concerning the metering section.
Graeme Topham who compiled the original document, made it available.
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Annex A – Impact Assessment
(Normative)
Impact assessment form to be completed for all documents.
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.
The document serves to establish the technical standard for the interconnection of Embedded Generation
to Eskom‘s EHV, HV and MV networks. The standard sets out some key safety aspects relating to the
interconnection of Embedded Generation and is central to the National Co-generation project.
2.2 If the document to be released impacts on statutory or legal compliance - this need to be very
clearly stated and so highlighted.
The standard serves to fulfil the requirements of the South African Distribution Code: Network Code in so
far as a Protection, Measurement and Telecontrol interconnection standard for Embedded Generation is
required.
2.3 Impact on stock holding and depletion of existing stock prior to switch over.
Not applicable
2.4 When will new stock be available?
Not applicable
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?
Not applicable
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.
A generic Power Purchase Agreement (PPA) and Connection Agreement for EG‘s has been developed
separately to this document. A planning guideline for the integration of Embedded Generation has been
developed and describes in detail the types of impact assessment studies required.
2.7 Provide details of any comments made by the Regions regarding the implementation of this
document - None.
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Annex A
(continued)
3 Implementation timeframe
3.1
Time period for implementation of requirements.
Dependant on IPP Caregroup decision.
3.2
Deadline for changeover to new item and personnel to be informed of DX wide change-over.
Dependant on IPP Caregroup decision.
4 Buyers Guide and Power Office
4.1 Does the Buyers Guide or Buyers List need updating?
No.
4.2 What Buyer’s Guides or items have been created?
Not applicable.
4.3 List all assembly drawing changes that have been revised in conjunction with this document.
Not applicable.
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?
Not applicable.
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?
Depends on IPP Caregroup decision.
5.2 If NO, provide motivation for issuing this specification before Acceptance Cycle Expiry date.
Changing technology.
5.3 Are ALL suppliers (currently accepted per LAP), aware of the nature of changes contained in
this document?
No.
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Annex A
(continued)
Is implementation of the provisions of this document required during the current supplier
qualification period?
To be decided by IPP Caregroup.
5.4 If Yes to 5.4, what date has been set for all currently accepted suppliers to comply fully?
Possibly not applicable.
5.5 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?
Not applicable.
5.6 Can the changes made, potentially impact upon the purchase price of the material/equipment?
Possibly not applicable.
5.7 Material group(s) affected by specification: (Refer to Pre-Qualification invitation schedule for
list of material groups)
Not applicable.
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.)
The document is to be issued by the IPP Workgroup to all relevant parties.
6.2 State designations of personnel that will require training.
Not applicable.
6.3 Is the training material available? Identify person responsible for the development of training
material.
No training material is available at this stage.
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.).
To be announced.
6.5 Was Training & Development Section consulted w.r.t training requirements?
No.
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Annex A
(continued)
7 Special tools, equipment, software
7.1 What special tools, equipment, software, etc. will need to be purchased by the Region to
effectively implement?
None.
7.2 Are there stock numbers available for the new equipment?
Not applicable.
7.3 What will be the costs of these special tools, equipment, software?
Not applicable.
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
Project costing will be evaluated on a per-project basis via the normal Investment Committees, guided by
the pricing policies for Embedded Generation presently under development.
Impact assessment completed by:
Name: Stuart van Zyl
Designation: Chief Engineer, Protection Discipline Specialist
Updated by: Andrew Craib
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Annex B – Summary of generator connection types
(Informative)
This section provides typical examples of generator connection types to which this standard shall apply,
indicating the likely locations of the PUC, PGC and PCC in each case. The application of the standard shall
not be limited to only these plant connection types.
Generator connection to NSP busbar: The EG in this case is connected directly to a NSP busbar, via a
generator transformer. In the case where the EG is within the same substation as the NSP (e.g., one earthmat with two separately owned yards), and noting that the standard states that Eskom will own the circuit
breaker closest to the Eskom busbar and that there shall be a minimum of two owned EG circuit breakers in
series, the following figure is relevant:
Distributor Busbar
Distributor Busbar
PCC
CB
POC
CB
To other
customers
PUC CB
EG
Gen Transformer
PGC
PGC
CB
CB
Figure B-1: Generic Layout with Shared Earth Mat
The unit protection of the generator transformer and the busbar protection shall overlap such that there is
no unprotected zone between the two circuit breakers. The EG and NSP shall make a suitable CT core
available to the other party to facilitate this zone overlapping.
Radial line tee-in generator connection: The EG is connected via a tee-in on a radial distribution line, via
a transformer.
CB
Distributor Busbar
EG connected via
Gen Transformer
PCC
PCC
PUC
CB
PGC
CB
radial feeder
Customer loads
EG
Figure B-2: Radial Connection
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Annex C – Summary of plant types
(Informative)
This section provides a summary of the typical plant types to which this standard shall apply.
application of the standard shall not be limited to only these plant types.
The
Synchronous generator: A type of rotating electrical generator which operates at a speed that is directly
related to system frequency. The machine is designed to be capable of operation in isolation from other
generating plants. The output voltage, frequency and power factor are determined by control equipment
associated with the generator. Under certain conditions, the synchronous generator may be paralleled with
a network containing other generation. On disconnection of the paralleled connection, the synchronous
generator will continue to generate at a voltage and frequency determined by its control equipment.
Mains-excited asynchronous generator: A type of rotating electrical generator which operates at a
speed not directly related to system frequency. The machine is designed to be operated in parallel with a
network containing other generation. The machine is excited by reactive power drawn only from the
network to which it is connected.
The output voltage and frequency are determined by those of the system to which it is connected. On
disconnection of the parallel connection, the mains-excited asynchronous generator will cease generation.
Power factor corrected asynchronous generator: A derivative of the mains-excited asynchronous
generator where the machine is excited partly by the network to which it is connected and partly by a device
of fixed capacitance connected locally to the machine. On disconnection of the parallel connection, the
power factor corrected asynchronous generator may continue to generate electrical power at a voltage and
frequency determined by the machine and system characteristics.
Self-excited asynchronous generator: A derivative of the mains-excited asynchronous generator where
the machine is excited purely by a device of variable capacitance connected locally to the machine. The
machine is capable of operation in isolation from a network containing other generation and in this respect
is similar to the synchronous generator. Under certain conditions, the self-excited asynchronous generator
may be operated in parallel with other generation, and on failure of that connection, the machine will
continue to generate at a voltage and frequency determined by its control equipment.
Self-commutated static inverter: An electronic device to convert direct current (D.C.) to alternating
current (A.C.) in which the output value of A.C. frequency and voltage is determined by control equipment
associated with the device. It is similar to the rotating synchronous generator in that, under certain
conditions, it may be connected in parallel with a network containing other generators. On failure of that
connection, the device will continue to provide power at a voltage and frequency determined by its control
equipment.
Line-commutated static inverter: A derivative of the self-commutated static inverter where the output
A.C. frequency and voltage are determined by the network containing other generation to which it must be
connected. On disconnection of the parallel connection, the line-commutated static inverter will normally
cease operation.
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Annex D – Protective Relay Type Test requirements
(Normative)
Protective relays installed at the Point of Connection shall comply with the following international type test
requirements.
Table D-1: International standard type test requirements for protective relays
Item
Test
Standard
Test Level
Compliance Criteria
-
VNom –20% to VNom +10%.
Auxiliary power supply
1
Operating range
2
Interruption
IEC 60255-11
-
For supply interruptions lasting less
than 10 ms, the device shall function as
if no interruption had occurred.
3
A.C. ripple
IEC60255-11
-
Device shall function correctly with 12%
100 Hz A.C. signal superimposed on
the D.C. supply.
SANS 61000-48
Class 4
30 A/m continuous, 300 A/m short
duration, 50Hz
Power frequency magnetic field
4
Steady State
Insulation resistance
5
Dielectric withstand
IEC 60255-5
-
2 kV rms 50 Hz for 1 minute between
all terminals to case earth.
Transverse tests between contacts
shall also be performed to the above
specification.
6
Insulation resistance
IEC 60255-5
-
Insulation resistance greater than
20 M when measured at 500 Vdc
Environmental tests
°
7
Cold
IEC 60068-2-1
-10 C or less
8
Dry Heat
IEC 60068-2-2
+55 C or more
°
°
Operates within tolerance at -10 C
(LCD screen operative)
°
Operates within tolerance at +55 C
°
°
9
Cyclic Temperature
and Humidity
IEC 60068-2-30
Test Db
25 C and 95% relative humidity/ 55 C
and 95% relative humidity, 12 + 12 hour
cycle
10
Enclosure protection
SANS 60529
IP53
Protected against ingress of dust
particles, spraying water
Mechanical tests
11
Vibration
IEC 60255-21-1
Class 2
(response and
endurance)
Response: 1 g, 10-150 Hz, 1 sweep
energised. Contacts should not close
for longer than 2 ms.
Endurance: 2 g 10–150 Hz, 20 sweeps,
unenergised contacts should not close
for longer than 2 ms.
12
Shock
IEC 60255-21-2
Class 1
(response and
withstand)
Response: 5 g, 11 ms, 3 pulses in each
direction, energised
Withstand: 15 g, 11 ms, 3 pulses in
each direction, unenergised
13
Bump
IEC 60255-21-2
Class 1
10 g, 16 ms, 1000 pulses unenergised.
14
Seismic
IEC 60255-21-3
Class 1
Test method A (single axis sine sweep
test) 1 – 35 Hz, 1 sweep.
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Annex D
(continued)
Table D-1. International standard type test requirements for protective relays (continued)
Item
Test
Standard
Test Level
Compliance Criteria
IEC 60255-5
-
5 kV 1.2/50 s waveform, 0.5J
Impulse tests
15
Electrical impulse
(1.2/50 s)
Electromagnetic compatibility
16
1MHz Disturbance
Burst
IEC60255-22-1 or
SANS 61000-4-12
Class 3
2.5 kV common mode, 1 kV
differential mode, 2 s total test
duration, 6 – 10 bursts
17
Fast Transient
IEC 60255-22-4 or
Class A (IV)
4 kV, 2.5 kHz
2 kV, 5 kHz on Comms ports
SANS 61000-4-4
Class 4
4 kV, 5 kHz (power port)
2 kV, 5 kHz (I/O signal, data and
control ports)
18
Electrostatic
Discharge
IEC 60255-22-2 or
SANS 61000-4-2
Class 3
6 kV Contact Discharge, 8 kV Air
Discharge
19
Surge immunity
IEC 60255-22-5 or
SANS 61000-4-5
Class 3
2 kV
20
Radiated Radio
Frequency EM field
immunity
IEC 60255-22-3 or
SANS 61000-4-3
Class 3
10 V/m, 80 MHz – 1 GHz
21
Conducted Radio
Frequency EM field
immunity
IEC 60255-22-6 or
SANS 61000-4-6
Class 3
10 Vrms, 150 kHz – 80 MHz
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Annex E – Residual over-voltage protection grading example
(Informative)
Reference: Network Protection & Automation Guide, p309.
This section provides an example of the method to be used to grade the residual over-voltage protection at
an MV point of connection with the current-based earth fault protection on the Distribution system.
The voltage pick-up must be set at a value corresponding to the current pick-up of the least sensitive earth
fault relay on the network. The least sensitive current pick-up will typically occur on the source substation
feeder circuit-breakers. For a relay that operates using the residual voltage, 3V 0, the effective setting is
given by Equation D.1.
VS
IS
(3 Z N )
VT Ratio
(D.1)
Where:
VS = Voltage setting of the residual over-voltage protection
IS = Highest current setting of the Distribution network earth fault protection
ZN = Earthing impedance
The time delay of the residual over-voltage protection, either definite time or using an inverse-time
characteristic, must be chosen such that it operates after the slowest earth fault protection relay on the
feeder.
Application example:
Consider a 22 kV network that is supplied by two power transformers, each earthed via a 35.8 resistor to
limit the earth fault current to 710 A. The highest earth fault current pick-up applied on the network is 40 A.
The earth fault protection uses a normal inverse characteristic with a time multiplier of 0.2.
The voltage setting is calculated as follows:
VS
IS
(3 Z N )
VT Ratio
35.8
)
2
200
40 A (3
10.8V
The earth fault protection will operate in 470 ms for a 710 A fault. Assuming that the residual overvoltage
protection uses a time-current curve given by the equation:
Trip Time, t
K
VM
VS
1
Where:
K = Time multiplier
VM = Measured voltage during the fault
VS = Voltage setting.
For the residual over-voltage protection to operate in 870 ms at 190 V requires a setting of K = 14.5.
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Annex F – Eskom Approved Gateway ordering information
(Informative)
Intended
Application
Transmission
connected
Embedded
Generator
Isolated
Voltage
Output
Power
Supply
Product Description
Product Part
No
Budgetary
Cost *
20-60VDC
D20ME Single CPU Gateway (Non-VME)
with IEC-101 drivers for power supplies in the
range 20-60VDC
ISTE-800360
R 38,400
48VDC
D20ME Single CPU Gateway (Non-VME)
100-300VDC
with IEC-101 drivers for power supplies in the
/ 85-264VAC
range 100-300VDC or 85-264VAC
20-60VDC
D20ME Single CPU Gateway (Non-VME)
with DNP3 drivers for power supplies in the
range 20-60VDC
ISTE-800370
R 38,400
ISTE-800340
R 38,400
48VDC
Distribution
connected
Embedded
Generator
Protocol Support
Bootrom
Version
Required Rack
Space
Physical
Dimensions
IEC101 DCA (For
comms with
IEC101 Slave)
IEC101 DPA (For
comms with
IEC101 Master)
ISTE-000145-164 P-130-0 ver 2.07
3U
Width: 482.6mm
Height: 133.35mm
Depth: 215.9mm
DNP DCA (For
comms with DNP
Slave)
DNP DPA (For
comms with DNP
Master)
ISTE-000037-164 P-130-0 ver 1.33
3U
Width: 482.6mm
Height: 133.35mm
Depth: 215.9mm
D20ME Single CPU Gateway (Non-VME)
100-300VDC
with DNP3 drivers for power supplies in the
/ 85-264VAC
range 100-300VDC or 85-264VAC
ISTE-800350
R 38,400
iBox Serial Substation Controller with DNP3
drivers for power supplies in the range 2060VDC
ISTE-800380
R 13,300
DNP3 DCA
DNP3 DPA
ISTE-800390
R 1,100
NA
20-60VDC
Firmware Set
Part No
SAX0001.06
P-155-0 ver 3.10
7U
5U + 1U above
and 1U below
Width: 279.4mm
Height: 190.5mm
Depth: 43.9mm
NA
NA
To be integrated
with iBox
Width: 45mm
Height: 75mm
Depth: 91mm
NA
110-290VDC
Optional Power Supply for iBox to accept
/ 100110-290VDC/100-240VAC
240VAC
* Prices exclude VAT, are based on a rate of exchange of 1USD = R10.25 Prices are provided as an indication only and are subject to change without notice.
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Annex G – Detailed Signal list required between the EG and the Approved Gateway
(normative)
B C Point Name
State
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3 DNP3 DNP3
Number signal Index Class Data Type
IEC -101
IEC 60870-5-101 ASDU
ASDU
Type
(Address)
IEC 101
Class
Point Description
Note
DIGITAL INPUTS
X Generation status
Stopped-01
Started-10
X
X Supervisory switch
On-01
(Dx=0)
Off-10
(Dx=1)
X
X Breaker State
Open-01
Closed-10
In Transit-00
Invalid-11
X
X Isolator State
X
X
13
0,1
1
binary input event
with time (2 bits)
10001
<31> Double-point info with
time tag CP56Time2a
1
Unit operation status
2,3
1
binary input event
with time (2 bits)
10002
<31> Double-point info with
time tag CP56Time2a
1
Supervisory isolator switch
'Off' means supervisory
controls are disabled
4,5
1
binary input event
with time (2 bits)
10003
<31> Double-point info with
time tag CP56Time2a
1
State of the PUC Circuit
Breaker
DI 3
6,7
1
binary input event
with time (2 bits)
10004
<31> Double-point info with
time tag CP56Time2a
1
State of the PUC Isolator
DI 4
8
1
binary input event
with time
1
<30> Single-point info with
time tag CP56Time2a
1
Plant Shutdown
9
1
binary input event
with time
2
<30> Single-point info with
time tag CP56Time2a
1
Plant islanded
10
1
binary input event
with time
3
<30> Single-point info with
time tag CP56Time2a
1
Curtailment mode status
Table 4-23
DI 0
Table 4-4
DI 1
Table 4-5
DI 2
Open-01
Closed-10
In Transit-00
Invalid-11
Table 4-5
X Plant shut down
Yes-1
No-0
Table 4-10
X
X Plant islanded
Yes-1
No-1
X
X
Curtailment mode
status
On-1
Off-0
X
X
Curtailment in
progress
X
X
Curtailment mode
not ready
13.3.2
DO 3
DO 1
Table 4-10
DI 5
13.1.3
Table 4-20
DI 6
Yes-1
No-0
13.1.3
Table 4-20
DI 7
11
1
binary input event
with time
4
<30> Single-point info with
time tag CP56Time2a
1
Curtailment in progress
Yes-1
No-0
13.1.3
Table 4-20
DI 8
12
1
binary input event
with time
5
<30> Single-point info with
time tag CP56Time2a
1
Curtailment mode not ready
X
Power gradient
X constraint mode
status
On-1
Off-0
11.3
Table 4-28
DI 9
13
1
binary input event
with time
6
<30> Single-point info with
time tag CP56Time2a
1
Power gradient constraint
mode status
X
Power gradient
X constraint mode not
ready
Yes-1
No-0
11.3
Table 4-28
DI 10
14
1
binary input event
with time
7
<30> Single-point info with
time tag CP56Time2a
1
Power gradient constraint
mode not ready
X
X
PF control mode
status
On-1
Off-0
8.2
Table 4-35
DI 11
15
1
binary input event
with time
8
<30> Single-point info with
time tag CP56Time2a
1
Power factor control mode
status
X
X
PF control mode not
ready
Yes-1
No-0
Table 4-35
DI 12
16
1
binary input event
with time
9
<30> Single-point info with
time tag CP56Time2a
1
Power factor control mode
not ready
X
X
V control mode
status
On-1
Off-0
Table 4-38
DI 13
17
1
binary input event
with time
10
<30> Single-point info with
time tag CP56Time2a
1
Voltage control mode status
X
X
V control mode not
ready
Yes-1
No-0
Table 4-38
DI 14
18
1
binary input event
with time
11
<30> Single-point info with
time tag CP56Time2a
1
Voltage control mode not
ready
X
X
Q control mode
status
On-1
Off-0
Table 4-32
DI 15
19
1
binary input event
with time
12
<30> Single-point info with
time tag CP56Time2a
1
Reactive power control
mode status
8.3
8.1
DO 4
DO 5
DO 6
DO 7
DO 8
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A Control Centres that requires a single
bit indication for this can use the most
significant bit of the pair
EG has initiated the shutdown
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B C Point Name
State
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3 DNP3 DNP3
Number signal Index Class Data Type
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IEC -101
IEC 60870-5-101 ASDU
ASDU
Type
(Address)
IEC 101
Class
Point Description
Note
DIGITAL INPUTS
X
Q control mode not
X
ready
Yes-1
No-0
8.1
Table 4-32
DI 16
Frequency control
mode status
On-1
Off-0
13.1.4
Table 4-15
DI 17
Frequency control
X
mode not ready
Yes-1
No-0
X P-delta mode status
On-1
Off-0
P-delta mode not
ready
On-1
Off-0
X
X
Table 4-15
DI 18
11.2
Table 4-25
DI 19
11.2
Table 4-25
DI 20
DO 9
DO 9
20
1
binary input event
with time
13
<30> Single-point info with
time tag CP56Time2a
1
Reactive power control
mode not ready
21
1
binary input event
with time
14
<30> Single-point info with
time tag CP56Time2a
1
Primary frequency control
mode status
As per agreement only
22
1
binary input event
with time
15
<30> Single-point info with
time tag CP56Time2a
1
Primary Frequency control
not ready
Not needed?
23
1
binary input event
with time
16
<30> Single-point info with
time tag CP56Time2a
1
Delta production constraint
mode status
not PVPP
24
1
binary input event
with time
17
<30> Single-point info with
time tag CP56Time2a
1
Delta production constraint
mode not ready
not PVPP
25
1
binary input event
with time
18
<30> Single-point info with
time tag CP56Time2a
1
AGC mode state
Only required for Transmission
connected IPP (not PVPP)
X AGC mode Status
On-1
Off-0
Table 4-17
DI 21
X AGC Raise block
Yes-1
No-0
Table 4-17
DI 22
26
1
binary input event
with time
19
<30> Single-point info with
time tag CP56Time2a
1
AGC Raise block
Only required for Transmission
connected IPP (not PVPP)
X AGC Lower block
Yes-1
No-0
Table 4-17
DI 23
27
1
binary input event
with time
20
<30> Single-point info with
time tag CP56Time2a
1
AGC Lower block
Only required for Transmission
connected IPP (not PVPP)
DO 11
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B
C Point Name
State
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3 DNP3 DNP3
Number signal Index Class Data Type
Unique Identifier:
240_61268576
Revision:
1
Page:
87 of 91
IEC -101
IEC 60870-5-101 ASDU
ASDU
Type
(Address)
IEC 101
Class
Point Description
Note
DIGITAL COMMANDS
1
Reserved for future use
(broadcast)
<46> Double Command
1
Remote disconnection (Trip
the POC or PUC or PGC
Circuit Breaker)
35003
<46> Double Command
1
Stop/Start generation of the
EG
Binary Command
- CROB
35004
<46> Double Command
1
Curtailment mode
(Deactivate/Activate)
-
Binary Command
- CROB
35005
<46> Double Command
1
Power gradient constraint
5
-
Binary Command
- CROB
35006
<46> Double Command
1
Activate power factor control
mode
deactivate V / Q
DI 13
6
-
Binary Command
- CROB
35007
<46> Double Command
1
Activate voltage control
mode
deactivate PF / Q
DO 8
DI 15
7
-
Binary Command
- CROB
35008
<46> Double Command
1
Activate reactive power
control mode
deactivate PF / V
Table 4-14
DO 9
DI 17
8
-
Binary Command
- CROB
35009
<46> Double Command
1
Primary frequency control
deactivate/activate
command
As per agreement only, If EG sends
double bit, send only most significant bit
Table 4-24
DO 10
DI 20
9
-
Binary Command
- CROB
35010
<46> Double Command
1
Activate/Deactivate Delta
production constraint mode
Mutually exclusive with Curtailment
Table 4-16
DO 11
DI 21
10
-
Binary Command
- CROB
35011
<46> Double Command
1
AGC mode
Deactivate/Activate
command
Only required for Transmission
connected IPP (not PVPP)
X
X RESERVED
DO 1
0
35001
X
X Breaker (Trip)
Trip-01
Close-NA
13.3.2
Table 4-13
DO 2
DI 3
1
-
Binary Command
- CROB
35002
X
X
Generation
(Stop/Start)
On-10
Off-01
13
Table 4-22
DO 3
DI 0
2
-
Binary Command
- CROB
X
X
Curtailment mode
(Deactivate/Activate)
On-10
Off-01
13.1.3
Table 4-19
DO 4
DI 6
3
-
X
Power gradient
X constraint mode
(Deactivate/Activate)
On-10
Off-01
11.3
Table 4-27
DO 5
DI 9
4
X
X
PF control mode
(Activate)
On-10
Off-NA
8.2
Table 4-34
DO 6
DI 11
X
X
V control mode
(Activate)
On-10
Off-NA
8.3
Table 4-37
DO 7
X
X
Q control mode
(Activate)
On-10
Off-NA
8.1
Table 4-31
Frequency control
X mode
(Deactivate/Activate)
On-10
Off-01
13.1.4
X
P-delta mode
(Deactivate/Activate)
On-10
Off-01
11.2
X
AGC mode
(Deactivate/Activate)
On-10
Off-01
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
mutually exclusive with P-delta constraint
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B
C
Point Name
Unit
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3
Number Signal Index
DNP3 DNP3
Class Data Type
IEC
60870-5101 ASDU
(Address)
Unique Identifier:
240_61268576
Revision:
1
Page:
88 of 91
IEC 60870-5-101 ASDU
Type
IEC
608705-101
Class
Point Description
Note
ANALOGUES INPUTS
X
X
Active Power sent
out
X
X
Reactive Power
sent out
X
X
Red Phase Amps
X
X
X
20001
<9> Measured value,
normalized value
2
Measured summated three
phase active power sent-out
(at the POC)
Actual summated three phase sent-out
at the POC
20002
<9> Measured value,
normalized value
2
Total summated three
phase Reactive Power
Import/Export (+/-Mvar) at
the POC
Total summated three phase Reactive
Power Import/Export (+/-Mvar) at the
POC
Analog Input Event
16-bit without time
20003
<9> Measured value,
normalized value
2
Red phase current
2
Analog Input Event
16-bit without time
20004
<9> Measured value,
normalized value
2
White phase current
4
2
Analog Input Event
16-bit without time
20005
<9> Measured value,
normalized value
2
Blue phase current
AI 6
5
2
Analog Input Event
16-bit without time
20006
<9> Measured value,
normalized value
2
Power Factor at the POC
Table 4-9
AI 7
6
2
Analog Input Event
16-bit without time
20007
<9> Measured value,
normalized value
2
Voltage at the POC
13.1.3
Table 4-21
AI 8
AO 2
7
2
Analog Input Event
16-bit without time
20008
<9> Measured value,
normalized value
2
Curtailment setpoint
feedback
8.2
Table 4-34
AI 9
AO 5
8
2
Analog Input Event
16-bit without time
20009
<9> Measured value,
normalized value
2
Power factor setpoint
feedback
Table 4-9
AI 10
10
2
Analog Input Event
16-bit without time
20010
<9> Measured value,
normalized value
2
Frequency
Only required where intentional islands
are allowed
11
2
Analog Input Event
16-bit without time
20011
<9> Measured value,
normalized value
2
Active Power Ramp rate of
the entire facility
pos = ramp up, neg = ramp down
13
2
Analog Input Event
16-bit without time
20012
<9> Measured value,
normalized value
2
Reactive power control
setpoint feedback
Kw or MW
13.1.1
Table 4-9
AI 1
0
2
kvar or Mvar
13.1.1
Table 4-9
AI 2
1
2
A
Table 4-9
AI 3
2
2
White Phase Amps
A
Table 4-9
AI 4
3
X
Blue Phase Amps
A
Table 4-9
AI 5
X
X
Power Factor
PF
13.1.1
Table 4-9
X
X
Voltage sent out
kV
13.1.1
X
X
Curtailment
setpoint feedback
kW or MW
X
X
PF setpoint
feedback
PF
X
X
Frequency
Hz
X
X
Actual ramp rate
X
X
X
X
Analog Input Event
16-bit without time
Analog Input Event
16-bit without time
MW/min
13.1.1
Table 4-9
AI 11
Q setpoint
feedback
kvar or Mvar
8.1
Table 4-33
AI 12
X
Q lower limit
kvar or Mvar
13.1.1
Table 4-33
AI 13
14
2
Analog Input Event
16-bit without time
20013
<9> Measured value,
normalized value
2
Reactive Power Lower limit
X
Q upper limit
kvar or Mvar
13.1.1
Table 4-33
AI 14
15
2
Analog Input Event
16-bit without time
20014
<9> Measured value,
normalized value
2
Reactive Power Upper limit
AO 7
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
neg = Gen producing vars (lagging)
pos = Gen absobing vars (leading)
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B
C
Point Name
Unit
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3
Number Signal Index
DNP3 DNP3
Class Data Type
IEC
60870-5101 ASDU
(Address)
Unique Identifier:
240_61268576
Revision:
1
Page:
89 of 91
IEC 60870-5-101 ASDU
Type
IEC
608705-101
Class
Point Description
Note
ANALOGUES INPUTS
kV
8.3
Table 4-39
AI 15
AO 6
16
2
Analog Input Event
16-bit without time
20015
<9> Measured value,
normalized value
2
Voltage setpoint feedback
Up ramp rate
setpoint feedback
MW/min
11.3
Table 4-29
AI 16
AO 3
17
2
Analog Input Event
16-bit without time
20016
<9> Measured value,
normalized value
2
Up ramp rate setpoint
feedback
applies to startup and normal
operation
X
Down ramp rate
setpoint feedback
MW/min
11.3
Table 4-29
AI 17
AO 4
18
2
Analog Input Event
16-bit without time
20017
<9> Measured value,
normalized value
2
Down ramp rate setpoint
feedback
applies to shutdown
X
X
Up ramp rate high
limit
MW/min
Table 4-29
AI 18
19
2
Analog Input Event
16-bit without time
20018
<9> Measured value,
normalized value
2
Up ramp rate high limit
X
X
Up ramp rate low
limit
MW/min
Table 4-29
AI 19
20
2
Analog Input Event
16-bit without time
20019
<9> Measured value,
normalized value
2
Up ramp rate low limit
X
X
Down ramp rate
high limit
MW/min
Table 4-29
AI 20
21
2
Analog Input Event
16-bit without time
20020
<9> Measured value,
normalized value
2
Down ramp rate high limit
X
X
Down ramp rate
low limit
MW/min
Table 4-29
AI 21
22
2
Analog Input Event
16-bit without time
20021
<9> Measured value,
normalized value
2
Down ramp rate low limit
X
X
Wind speed
m/s
13.1.5
Table 4-11
AI 22
23
2
Analog Input Event
16-bit without time
20022
<9> Measured value,
normalized value
2
Wind speed
Within 75% of the hub height) measured signal in metres/second (for
WPP only)
X
X
Wind direction
Deg
13.1.5
Table 4-11
AI 23
24
2
Analog Input Event
16-bit without time
20023
<9> Measured value,
normalized value
2
Wind direction
Within 75% of the hub height –
measured signal in degrees from true
north (0-359) (for WPP only)
X
X
Air temperature
°C
13.1.5
Table 4-11
AI 24
25
2
Analog Input Event
16-bit without time
20024
<9> Measured value,
normalized value
2
Measured Air temperature
Signal in degrees centigrade (-20.0 to
50.0)
X
X
Air pressure
mbar
13.1.5
Table 4-11
AI 25
26
2
Analog Input Event
16-bit without time
20025
<9> Measured value,
normalized value
2
Air pressure
Signal in millibar (800 to 1400).
X
X
Air density
kg/m3
13.1.5
Table 4-11
AI 26
28
2
Analog Input Event
16-bit without time
20026
<9> Measured value,
normalized value
2
Air density
WPP only
X
X
Solar Irradiation
W/m2
13.1.5
Table 4-11
AI 27
27
2
Analog Input Event
16-bit without time
20027
<9> Measured value,
normalized value
2
Solar radiation (for PVPP
only)
PVPP only
X
X
Humidity
%
Table 4-11
AI 28
29
2
Analog Input Event
16-bit without time
20028
<9> Measured value,
normalized value
2
Humidity
X
P-delta setpoint
feedback
%
Table 4-26
AI 29
30
2
Analog Input Event
16-bit without time
20029
<9> Measured value,
normalized value
2
Pdelta setpoint feedback
X
X
V setpoint feedback
X
X
X
11.2
AO 8
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B
C
Point Name
Unit
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3
Number Signal Index
DNP3 DNP3
Class Data Type
IEC
60870-5101 ASDU
(Address)
Unique Identifier:
240_61268576
Revision:
1
Page:
90 of 91
IEC 60870-5-101 ASDU
Type
IEC
608705-101
Class
Point Description
Note
ANALOGUES INPUTS
31
2
Analog Input Event
16-bit without time
20030
<9> Measured value,
normalized value
2
AGC setpoint feedback
Only required for Transmission
connected EG
AI 31
32
2
Analog Input Event
16-bit without time
20031
<9> Measured value,
normalized value
2
AGC high regulating limit
Only required for Transmission
connected EG
AI 32
33
2
Analog Input Event
16-bit without time
20032
<9> Measured value,
normalized value
2
AGC low regulating limit
Only required for Transmission
connected EG
X
AGC setpoint
feedback
MW
Table 4-18
AI 30
X
AGC high
regulating limit
MW
Table 4-18
X
AGC low regulating
limit
MW
Table 4-18
AO 9
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
STANDARD FOR THE INTERCONNECTION OF EMBEDDED GENERATION
B
C
Point Name
Unit
RPP Grid
Code Ref
Cross
Reference
Signal
Assoc DNP3
Number Signal Index
DNP3 DNP3
Class Data Type
IEC
60870-5101 ASDU
(Address)
Unique Identifier:
240_61268576
Revision:
1
Page:
91 of 91
IEC 60870-5-101 ASDU
Type
IEC
60870-5101
Class
Point Description
Note
ANALOGUE CONTROLS
X
X
RESERVED
X
X
Curtailment
setpoint
X
X
X
AO 1
0
-
45001
Setpoint Command
Reserved for future use
(broadcast)
kW or MW
13.1.3
Table 4-19
AO 2
AI 8
1
-
Analog Output
16-bit
45002
Setpoint Command
Absolute Production
Constraint Setpoint (Active
Power)
Up ramp rate
setpoint
MW/min
11.3
Table 4-27
AO 3
AI 16
2
-
Analog Output
16-bit
45003
Setpoint Command
Up ramp rate setpoint
applies to startup and normal operation
X
Down ramp rate
setpoint
MW/min
11.3
Table 4-27
AO 4
AI 17
3
-
Analog Output
16-bit
45004
Setpoint Command
Down ramp rate setpoint
applies to shutdown
X
X
PF control setpoint
PF
8.2
Table 4-34
AO 5
AI 9
4
-
Analog Output
16-bit
45005
Setpoint Command
Power Factor control
setpoint
neg = Gen producing vars (lagging)
pos = Gen absobing vars (leading)
X
X
V control setpoint
kV
8.3
Table 4-37
AO 6
AI 15
5
-
Analog Output
16-bit
45006
Setpoint Command
Voltage control setpoint
X
X
Q control setpoint
kvar or Mvar
8.1
Table 4-31
AO 7
AI 12
6
-
Analog Output
16-bit
45007
Setpoint Command
Reactive Power control
setpoint
X
P-delta setpoint
%
11.2
Table 4-24
AO 8
AI 29
7
-
Analog Output
16-bit
45008
Setpoint Command
Pdelta setpoint(percentage
of available power)
X
AGC setpoint
Table 4-16
AO 9
AI 30
45009
Setpoint Command
AGC setpoint
MW
-
CONTROLLED DISCLOSURE
When downloaded from the EDMS, this document is uncontrolled and the responsibility rests with the user
to ensure it is in line with the authorised version on the system.
Only required for Transmission
connected EG
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