tes-p-107-01-r0

February 26, 2013

TESP10701R0/KSB

TRANSMISSION ENGINEERING STANDARD TES-P-107.01, Rev. 0

TESP10701R0/KSB

PAGE 2 OF 119 Date of Approval: February 26, 2013

TABLE OF CONTENTS

1. SCOPE

2. INTRODUCTION

3. SYSTEM DESIGN

3.1 General System Design 3.2 System Architecture 3.3 Ethernet Topology

4. FUNCTIONAL REQUIREMENTS

4.1 General SAS Functionality 4.2 Bay Level Functions 4.3 System/Station Level Functions

5. PERFORMANCE REQUIREMENTS

5.1 Message Performance 5.2 System Performance

6 RELIABILITY AND SYSTEM DESIGN

6.1 Reliability Aspects

6.2 General Design Requirements

7. IEC 61850 AND IEC 62439-1 COMMUNICATION PROFILE

7.1 Introduction Related to IEC 61850

7.2 Typical Architecture and Required Communication Services Related to IEC 61850

8. CONFIGURATION TOOLS/SERVICE AND SUPPORT SYSTEM

9. GENERAL REQUIREMENTS

9.1 Compliance With Standards 9.2 Vendors/SOLUTION PROVIDERS experience and Proposal for the SAS

10. PROJECT EXECUTION

10.1 Engineering

10.2 Factory Acceptance Test (FAT)

10.3 SAT (Site Acceptance Test)/Pre-commissioning and Commissioning

10.4 Design and Operating Requirements

10.5 Services, After Sales and Maintenance

11. DOCUMENTATION


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12. CYBER SECURITY REQUIREMENTS

13. KEMA CERTIFICATION

14. ADDITIONAL SUBSTATION AUTOMATION SYSTEM

15. DRAWINGS


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1.0 SCOPE

This Transmission Engineering Standard (TES) specifies Substation Automation System

(SAS) required for 110kV through 380kV system voltage for the transmission system of

National Grid, Saudi Arabia.

2.0 INTRODUCTION

2.1 The Substation Automation System (SAS) shall be installed to monitor, control and protect all the substation equipment connected to SAS. Monitoring and control shall

be from the remote control center (Power Control Center/SCADA Master Stations)

as well through local means within the substation (e.g. Bay Oriented Local Control

with Mimic, Local HMI contained in the Control IED and Station HMI).

The Substation Automation System (SAS) comprises full station and bay protection

as well as control, monitoring and communication functions and provides all

functions required for the safe and reliable operation of the substation. It shall enable

local station control via a PC by means of a human machine interface (HMI) and

control software package, which shall contain an extensive range of Supervisory

Control and Data Acquisition (SCADA) functions. It shall include Communications

Gateway, station bus, inter-bay bus, time synchronization system and intelligent

electronic devices (IEDs) for bay control & protection.

The attached diagram entitled, Substation Automation System Diagram (Conceptual), Fig 07-01, is conceptual drawings for substation SAS configuration.

The Communications Gateway shall enable and secure the information flow with

remote Power Control Center and other remote Master Stations. Besides performing

protocol conversion, the Communications Gateway will perform Network/Port

Address Translation from internal SAS IP/Port addresses to external IP/Port

addresses in integrated units/computers.

The station bus shall provide the interconnections between the station level

subsystems (Front End/Station computer, Operators Workstation, Engineers Workstation, printer etc.). The inter-bay bus shall provide independent station-to-bay

and bay-to-bay data exchange. The bay level intelligent electronic devices (IEDs) for

protection and control shall provide the direct connection to the switchgear without

the need of interposing components and perform control, protection, and monitoring

functions.

The SAS control and monitoring system (SCMS) shall implement a network

redundancy based on IEC62439-3 PRP 1 (Parallel Redundancy Protocol) as shown

in the attached Substation Automation System Diagram (Conceptual), Drawing Fig 07-01, and as further explained in this Standard. Implementation of IEC62439-3 PRP

1 (Parallel Redundancy Protocol) applies to both the station LAN and bay LAN at all

voltage levels.


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2.2 All the SAS components shall comply with latest revision of SEC standards wherever applicable.

2.3 Summary of Main Functional Parts of SAS

2.3.1 As a summary, the SAS shall contain (but may not be limited) to the

following main functional parts:

2.3.2 Bay Control Intelligent Electronic Devices (Control IEDs) for control and monitoring.

2.3.3 Bay Protection Intelligent Electronic Devices (Protection IEDs) for the internal substation's protection applications as well as for protection of

external equipment connected to the substation.

2.3.4 Unless otherwise specified, combined control/protection IEDs with the control IED function and protection IED function (for each item of

switchgear to be controlled) may be combined into one unit. Combined

control/protection IEDs are to be used at the medium voltage levels only

(34.5 kV and below).

2.3.5 Redundant Managed hardened Ethernet switches providing managed Ethernet Local Area Networks communications infrastructure.

2.3.6 Supporting Power Supply equipment such as inverters UPS, etc.

2.3.7 Peripheral equipment like printers, display units, key boards, Mouse, KVM switches, etc.

2.3.8 Station Human Machine Interface (Station HMI)/ Station with process database. The Station HMI shall contain as minimum: fully redundant two (2)

Front End/ Station Computers, fully redundant two (2) Operator's

Workstation, fully redundant one (1) Engineering Workstation, and related

applications software, operating systems and firmware to support full Station

HMI operation.

2.3.9 Separate Redundant Communications Gateway for remote supervisory control via SCADA Master Station(s) and for interconnecting external SOE

Master Stations. One side of each Communications Gateway shall face the

internal SAS Inter-bay bus using IEC 61850 and the other side of each

Communications Gateway shall face the external SCADA and SOE Master

Stations which will communicate using IEC 60870-5-101, IEC 608705-104

protocols, and support IEC 61850 communication with SCADA master

stations for future use.

2.3.9 Redundant GPS Receivers (e.g. Master Clock).


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2.3.10 Redundant standalone Firewalls to provide one of the means for cyber

security for the SAS.

2.3.11 Quantities of VF Modems to support the IEC-101 interconnections between

the SCADA Master Stations and the redundant Communications Gateways.

2.3.12 Collection of the relevant data concerning the substation and distribution of

the data where needed.

2.3.13 Data exchange between the different system components via the inter-bay

bus (for data exchange between bay level IEDs) and other communications

buses (such as station bus for interconnecting the station level subsystems:

Operators Workstations, Engineering Workstation, Front End Computers,

and Printers etc).

2.3.14 Bay-oriented local control panels with mimic diagram. One of the functions

of the Bay-Oriented local control panels with mimic diagram is to provide

emergency local operation of related Bay switchgear in the event of failure

and/or disabling of the Bay Control IED(s).

2.3.15 Local Control Cubicles (LCCs) for all High Voltage (above the medium voltage (34.5 kV and below) level) switchgear which will be installed in the

related High Voltage GIS Switchgear Rooms which will house/contain the

Control IEDs, Bay-oriented local control panels with Mimic Diagram and required Annunciator Panels.

2.3.16 For the Medium Voltage level (34.5 kV voltage and below), unless otherwise specified differently in other sections/appendices of the main PTS,

combined Control/Protection IEDs which are to be mounted/installed in the Low Voltage Compartments of the Metal Clad Medium Voltage Switchgear

as specified in latest revision of 32-TMSS-01 (for Metal Clad Switchgear)

and as specified in latest revision of 32-TMSS-03,( Metal Clad GIS

Switchgear), and with these IEDs fully integrated into this Metal Clad Switchgear by the SAS Solution provider /Sub Solution provider .

2.3.17 SAS Cubicles/Panels which will contain SAS equipment which includes, computers, Ethernet switches, firewalls/routers, VF modems, maintenance

displays, common alarm panels and related annunciators, terminal blocks,

MCBs, internal cabling/wiring, etc.

2.3.18 Protection Cubicles/Panels which will contain Protection IEDs. terminal

blocks, physical switches, MCBs, auxiliary relays, internal cabling/wiring,

etc.

2.3.19 All cabling/wiring/terminations required to provide for a fully functional

SAS installation to be provided/installed by the SAS Solution provider and

interconnected between SAS equipment as well as any SAS equipment and

external Communications/WAN/LAN equipment. The only exception to this


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cabling/wiring requirement will be the cabling/wiring between the Control

IEDs and external switchgear, the Protection IEDs and external switchgear, and thecombined Control/Protection IEDs and the external switchgear which can be run and terminated at the switchgear end by the Substation Solution

Provider . (however for the IED to switchgear cable connections at the IED

end and this cable termination shall be performed by the SAS Solution

provider).

2.3.20 Other devices, equipment and software (not mentioned above) which will

provide for a fully integrated and operational SAS at the substation.

2.4 Definition of Terms

2.4.1 HMI Human Machine Interface: Display screen, either part of an IED or as a

stand-alone device, presenting relevant data in a logical format, with which

the user interacts. An HMI will typically present windows, icons, menus,

pointers, and may include a keypad to enable user access and interaction.

2.4.2 IED Intelligent Electronic Device: Any device incorporating one or more

processors, with the capability to receive or send, data/control from, or to an

external source, for example electronic multifunction meters, digital relays,

controllers. Device capable of executing the behavior of one, or more,

specified logical nodes in a particular context and delimited by its interfaces.

Also see definitions relating to Protection IED, and Control IED.

2.4.3 Bay

A substation consists of closely connected sub parts with some common

functionality. Examples are the switchgear between an incoming or outgoing

line, and the bus bar, the bus coupler with its circuit breaker and related

isolators and earthing switches, the transformer with its related switchgear

between the two bus bars representing the two voltage levels. The bay

concept may be applied to 1 1/2 breaker and double bus substation

arrangements by grouping the primary circuit breakers and associated

equipment into a virtual bay. These bays comprise a power system subset to

be protected, for example a transformer of a line end, and the control of its

switchgear that has some common restrictions such as mutual interlocking or

well-defined operation sequences. The identification of such subparts is

important for maintenance purposes (what parts may be switched off at the

same time with minimum impact on the rest of the substation) or for

extension plans (what has to be added if a new line is to be linked in). These

subparts are called 'bay' and may be managed by devices with the generic

name 'bay controller' and have protection systems called 'bay protection'. The

bay level represents an additional control level below the overall station

level.


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2.4.4 Bay Level Functions

Functions that use mainly the data of one bay and act mainly on the primary

equipment of that bay. Bay level functions communicate via logical interface

3 within the bay level and via logical interfaces 4 and 5 to the process level,

i.e. with any kind of remote input/output or with intelligent sensors and

actuators. Control and data acquisition functions related to the bay level

functions may be performed at the bay level Control IED(s)/Local

HMI(s)/Bay-oriented Local Control Panel with Mimic Diagram, or indirectly

through the station HMI interface or the SCADA Master Station(s).

Protection functions related to the bay level functions are performed through

the bay level Protection IED(s) dedicated specifically for protective relaying

function(s).

2.4.5 Station Level Functions Functions applying to the whole substation. There are two classes of station

level functions i.e. process related station level functions and interface related

station level functions. Control and data acquisition functions which are

related to the station level functions for each substation indicated in Section

2.1 and which may include control and data acquisition from the local HMI,

Station HMI, and with the SCADA Master Station(s) providing external

(outside the substation) control and data acquisition capabilities.

2.4.6 Process:

The scheme which contains the actual conventional switchgear which

includes Breakers, Disconnect Switches, Tap Changers, Instrument

transformers and all instrumentation like Gas Density Monitors, etc.

2.4.7 Process Level Functions

All functions interfacing to the process, i.e. binary and analogue input/output

functions for example data acquisition (including sampling) and the issuing

of commands. These functions communicate via the logical interfaces 4 and 5

to the bay level.

2.4.8 Process Related Station Level functions Use data from more than one bay, or from each whole substation and act on

the primary equipment of more than one bay, or on the primary equipment of

each whole substation. Examples of such functions are: station wide

interlocking, automatic sequencers, and bus bar protection. These functions

communicate mainly via logical node 8.

2.4.9 Station HMI The set of computers/workstations and other equipment inside each

substation where control, data acquisition, monitoring, configuration of SAS

equipment and other SAS functions on a station level takes place.


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2.4.10 Front End Computers/Station Computers The set of computers where data gets directly transferred between the IEDs

(for recording/data acquisition and control functionality), and where

interfaces are provided for the Operator's and Engineering Workstations.

2.4.11 Local HMI

The set of equipment inside each substation where control, data acquisition,

alarms, configuration of SAS equipment, and other SAS functions on a bay

level takes place.

2.4.12 Operator Workstation

The computer (s),which are contained as part of the Station HMI and where

substation control/data acquisition, alarms/events/trends/disturbance records

recording/retrieval and other SAS equipment manufacturers recommended

functions are displayed and takes place. It is noted that the Operator's

Workstations and Engineering Workstation shall be dedicated separate

computers with separate dedicated displays, keyboards, and mice.

2.4.13 Engineering Workstation The computer (s) where equipment configurations supported and other SAS

equipment manufacturers functions related to SAS Engineering is allowed to take place. It is noted that the Operator's Workstation and Engineering

Workstation shall be dedicated separate computers with separate dedicated

displays, keyboards, and mice.

2.4.14 Control IED An intelligent electronic device that provides for control functions on a bay

level. Depending on the equipment manufacturer's design, data acquisition

functions may also be provided as part of the Control IED. Also, depending

on the equipment manufacturer's design, a Local HMI may be integrated as

part of the Control IED, or the Control IED may be separate from the Local

HMI. As part of the design of the Control IED, there shall be a requirement

for IEC 61850 compatibility. For the purposes of this standard, Control IEDs

shall be physically separate devices from Protection IEDs, with dedicated

Control IEDs being installed for all voltage levels above the Medium Voltage level, and where related Appendix of the main PTS specifies

dedicated Control IEDs at the Medium Voltage Level.

2.4.15 Protection IED An intelligent electronic device that provides for protective relay functions,

primarily on a bay level. Depending on the equipment manufacturer's design,

the Protection IED may provide for a single protective relay function, or

multiple protective relay functions in the same Protection IED unit. Also,

depending on the equipment manufacturer's design, additional

features/functions of the Protection IED may include status recording

functions (such as fault recording and other status recording functions), data

acquisition and other features. Also, Protection IED's shall be considered as

Protective Relays which are integrated in the SAS and with IEC 61850

connectivity/functionality. For the purposes of this standard, Protection IEDs

shall be physically separate devices from Control IEDs, with dedicated


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Protection IEDs being installed for all voltage levels above the Medium Voltage level, and where related Appendix of the main PTS to this standard

specifies dedicated Protection IEDs at the Medium Voltage Level.

2.4.16 Combined Control/Protection IED

An intelligent electronic device that provides for combined control and

protection functions on a bay level. Depending on the equipment

manufacturer's design, data acquisition functions may also be provided as

part of the Combined Control/Protection IED. Also, depending on the

equipment manufacturer's design, the combined Control/Protection IED may

provide for a single protective relay function, or multiple protective relay

functions in the same combined Control/Protection IED unit. Also,

depending on the equipment manufacturer's design, additional

features/functions of the combined Control/Protection IED may include

status recording functions (such as fault recording and other status recording

functions), and other features. Also, combined Control/Protection IED's shall

be considered as Protective Relays which are integrated in the SAS and with

IEC 61850 connectivity/functionality Also, depending on the equipment

manufacturer's design, a Local HMI may be integrated as part of the

combined Control/Protection IED, or the combined Control/Protection IED

may be separate from the Local HMI. For the purposes of this Standard,

combined Control/Protection IEDs shall be provided for all Medium Voltage (34.5 kV and below) applications, unless separate dedicated Control IEDs, and separate dedicated Protection IEDs are specified for some or all of the Medium Voltage applications in the main PTS.

2.4.17 Station Bus

The medium through which communications takes place among the station

level subsystems such as Operators Workstation, Engineering Workstation, Front End Computers, Printers etc. Station bus shall be fully compliant with

IEC 62439-3 (PRP1).

2.4.18 Inter-Bay Bus:

The medium through which communications takes place between the bay-

level IEDs and the station HMI interface and which protection, control and

data acquisition/monitoring signals for the SAS pass through. The Inter-Bay

Bus shall be fully compliant with IEC 61850 for all voltage levels of the

substation, and also will be fully compliant with IEC-62439-3 PRP1 for all

voltage levels of the substation.

2.4.19 Bay-oriented Local Control Panel with Mimic Diagram

A panel, which is installed on a bay level which provides for local indication

of switchgear status, limited alarm indication, other sets of limited readings,

and local switchgear control (on an emergency basis upon failure of a Control

IED and/or local HMI.

2.4.20 Time Synchronization System: A redundant set of GPS receivers which

provide for time synchronization data to all equipment contained as part of

the SAS within each substation.


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2.4.21 Communications Gateway

A set of redundant equipment which will provide for communications

interfacing between the SAS and equipment outside of each substation, and

which will also provide for required protocol conversions as needed for the

SAS to communicate with Master Station equipment outside each substation.

2.4.22 SCADA Master Station(s) The station(s) (outside of each substation) where remote control and remote

data acquisition functions are performed for each substation. For purposes of

the SAS, interfacing between the station SAS and the SCADA Master

Station(s) will be through the Communications Gateways.

2.4.23 SOE Master Station The station (outside of each substation) where SOE (Sequence of Events)

information which eventually gets routed to. For purposes of the SAS,

interfacing between the station SAS and the SOE Master Station will be

through Communications Gateways.

2.4.24 PTS Project Technical Specification, which is the same as the Scope of Work and

Technical Specifications (SOW/TS).

Additional Definitions Relating to IEC 61850

For additional definitions relating to IEC 61850, refer to the latest revision of IEC

TS 61850-2.

3.0 SYSTEM DESIGN

3.1 General System Design

3.1.1 The Substation Automation System (SAS) shall be suitable for operation,

monitoring, and maintenance of each complete substation including future

extensions which are identified in this entire standard document. The offered

products shall be suitable for efficient and reliable operation under the

environmental conditions specified in Section 14.

3.1.1 The systems shall be: State-of-the art based on IEC61850 for operation under electrical conditions present in high-voltage substations, follow the latest

engineering practice & ensure long term compatibility requirements,

continuity of equipment supply and the safety of the operating staff.

3.1.2 The offered SAS shall support remote control and monitoring from remote SCADA Master Stations via Communications Gateways.

3.1.3 The offered SAS shall provide for SOE (Sequence of Events) points support and overall SOE functions, with SOE monitoring information forwarded to

both the Station HMI and the external SOE Master Station (which is located

outside of the substation) through the Communications Gateways.


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3.1.4 The offered SAS shall provide for Protective Relay functions, (through bay-level Protection IEDs) for each substation.

3.1.5 The offered SAS shall provide for the substations interlocking functions, both through hard-wired interlocks in the substation as well as a system of

software/GOOSE interlocks.

3.1.6 The offered SAS shall provide for other miscellaneous functions related to substation control, data acquisition, protection and other functions as

described elsewhere in this Standard and the related Main PTS and other

Appendices to the Main PTS.

3.1.7 The system shall be designed such that personnel with little background knowledge in microprocessor-based technology are able to operate the

system easily after having received some basic training.

Installation/Maintenance/Operating Manuals/ documentation describing the

features and functions of the system shall be provided. Necessary 'HELP'

files shall be built into the HMI and database software. Also, the Operator

Interface (through the Engineering Workstation and Operator's Workstation)

shall be intuitive such that operating personnel shall be able to operate the

system easily after having received basic training on the SAS.

3.1.8 Cubicles shall incorporate the control, monitoring and protection functions specified, self-monitoring, signaling and testing facilities, measuring as well

as memory functions, event recording and disturbance recording. The basic

control functions are to be derived from a modular standardized and type-

tested software library.

3.1.9 Maintenance, modification or extension of components may not cause a shut-down of the whole SAS. Self-monitoring of single components, modules and

communication shall be incorporated to increase the availability and the

reliability of the equipment and minimize maintenance. In the cases of

modification or extension of components, if a shutdown of the SAS is

required, features, functions and configurations shall be provided to keep the

shutdown time of all or part of the SAS to an absolute minimum.

3.1.10 Preference will be given to suppliers who are in a position to provide protection and control devices and other devices freely adaptable to the

required application functionality.

3.1.11 The SAS shall be expandable as and when required at the Bay, Station and Process levels.

3.1.12 As part of the general system design of the SAS, alarm features shall be included which shall forward alarms to the SCADA Master Station(s) (as

well as the SAS Central Alarm Unit and/or substation Annunciator system

which will be included as part of the SAS) if the SAS determines that any

component of the SAS is not operating properly (with such components

including the station HMI, local HMI, IEDs, Communications Gateways,


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inter-bay bus, Ethernet switches, GPS receivers and other components of the SAS). For further details refer to Section 14.26 as well as latest revision of

TES-P-119.27 for SCADA points list and 38-TMSS-05 for Alarms list. It

should be noted that these are minimum requirements and the complete lists

to be provided by the SOLUTION PROVIDER which will be subject to

review and acceptance.

3.1.13 Generally, part or all of the SAS will be installed inside the substation building, which will be air conditioned. However in some cases, where

outdoor switchyards are used (refer main PTS) all bay-level unit hardware

(such as Bay Control IEDs and Bay Oriented Local Control Panels with

Mimic Operation) which need to be co-located with the outdoor switchgear

shall be designed and constructed to meet and fully operate without failure in

the outdoor environmental conditions in Saudi Arabia at the substation's

location. Refer to latest revision of standard 01-TMSS-01 (Outdoor

Environmental Conditions) for further details. However in the case of SAS

equipment located inside the substation building, the SAS equipment shall be

operational during both normal indoor conditions, and emergency indoor

conditions for a minimum 12 hour period where there is no heating/air

conditioning inside the substation building (for this matter, refer section 14.

of this standard for further detail on these requirements).

3.2 System Architecture

3.2.1 For safety and availability reasons the Substation Automation System shall be based on a decentralized architecture and on a concept of bay-oriented

distributed intelligence.

3.2.2 Functions shall be decentralized, object-oriented and located as close as possible to the process.

3.2.3 The main process information of the station shall be stored in distributed databases.

3.2.4 The proposed SAS layout shall be structured in three levels, i.e. a Station, a Bay and a Process level.

3.2.5 The Station level shall provide all the station level functions related to monitoring, control and protection. It shall consist of the station level

subsystems such as operators workstations, engineering workstation, front end computers, printers, etc. interconnected via the Station Bus. At bay level

the IEDs shall provide all bay level functions regarding control, monitoring

and protection, inputs for status indication and outputs for commands. The

inter-bay bus shall provide the interconnection between the bay level IEDs

and other bay level IEDs, the bay level IEDs and SAS front end computers/Communications Gateways, and between SAS front end

computers and SAS Communications Gateways. The IEDs should be directly

connected to the switchgear without any need for additional interposition or

transducers. It shall be the responsibility of the SAS

Manufacturer/SOLUTION PROVIDER to determine the proper layout for


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the SAS and the independent from each other and its functioning shall not be

affected by any fault occurring in any of the other bay control units of the

station. The only exception to this section will be for GOOSE interlocks,

where GOOSE interlocking information from one bay control unit to other

bay control units and in the event of the failure of the bay control unit

(Control IED) GOOSE interlocks may not be functional.

3.2.6 The communication buses shall be realized using fiber-optic cables and substation hardened Ethernet switches thereby guaranteeing disturbance free

communication. To maximize the physical protection of the fiber optic cables,

the fiber optic cables shall be run in GI Conduit pipes or other means

acceptable to the National Grid Saudi Arabia.. Furthermore for the redundant

schemes using Fiber Optic cables, routing of Fiber Optics cables shall be such

that "collapsed ring" schemes and routing of the redundant schemes in the

same routing media shall be avoided.

3.2.7 The communication buses (both station communications bus and inter-bay communications bus) shall be designed in dual redundant fault-tolerant rings

at all voltage levels. For the links between individual bay IEDs to Ethernet

switches a "star" scheme shall be used. It shall be such that failure of one set

of fibers shall not affect the normal operation of the SAS. However failure of

any fibers shall be alarmed in SAS. Additionally, fiber optics cable

connection shall provide sufficient fibers for the actual connection plus 20%

of overall fibers provided (along with the required fiber optics

termination/connectors) to support ease of replacement in event of failures of

individual working fibers.

3.2.8 To increase system performance and availability the cable routing/communication buses requirement shall be as follows:

a. The inter-bay busses shall be independent and redundant at each voltage level.

b. Inter-bay buses shall be independent of each other for each voltage level, as shown in the conceptual diagram, Substation Automation System Diagram (Conceptual), Drawing Fig 07-01. The detailed requirements related to the required common interconnections at the different levels

shall be designed by the Manufacturer/Solution provider .

3.2.9 The Station bus shall be fully redundant. At station level, the entire station

shall be controlled and supervised from the station HMI. It shall be possible

to control and monitor the bay from the bay level equipment in the event that

the communication link fails. The station wide interlocking shall also be

available when the station computer, IED(s), communications link, or other

component of the SAS fails. To support station wide interlocking upon failure

of the station computer, IED(s), communications link, or other component,

there shall be hard wired interconnection both within a bay and between the


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required bays for keeping the interlocking intact. For the substation's

interlocking requirements, manufacturer/SOLUTION PROVIDER shall meet

the latest revision requirements of 32-TMSS-01 for metal clad switchgear

(11kV, 13.8kV, 33kV or 34.5kV), 32-TMSS-02 for SF6 GIS (69kV through

380kV) and 32-TMSS-03 for metal clad gas insulated medium voltage

switchgear (11kV, 13.8kV, 33kV OR 34.5kV).

3.2.10 To provide highest reliability the station HMI and the Communications

Gateways shall work completely independent, i.e. the process data can be

retrieved directly from the bay level devices. Additionally the

Communications Gateway, Station HMI, communication buses (inter-bay bus

and station bus), GPS Receiver (which are part of the Time Synchronization

System) and Front End / Station Computer Unit, Firewalls and other related

hardware shall be built and configured fully redundant to ensure full

functionality and avoid single point of failure.

3.2.11 Clear control priorities shall prevent the initiation of operation of a single

switch at the same time from more than one of the available control levels, i.e.

SCADA Master Station(s), station level, bay level or apparatus level. To

ensure that clear control priorities exist, a hierarchy scheme between the

various control levels shall exist.

3.2.12 The priority shall always be on the lowest enabled control level. The station

level contains the station-oriented functions, which cannot be realized at bay

level, e.g. alarm list or event list related to the entire substation's SAS and

Communications Gateway required for the communication with remote

control centers.

3.2.13 Dedicated master clock (GPS Receivers which are part of the Time

Synchronization System) for the synchronization of the entire system shall be

provided. This master clock should be independent of all station computer

equipment and of the Communication Gateway and should synchronize all

devices via the communication buses

3.3 Ethernet Topology

The following described criterias have to be fulfilled concerning the Ethernet switches and the topology.

3.3.1 Ethernet Switches

a. The proposed Ethernet (LAN) Switches shall be modular, industrially hardened, fully manageable and specifically designed to build Ethernet

networks for mission critical, real-time control applications in utility

substation environments.

b. These hardened requirements include. (but may not be limited to) temperature, EMC and power supply (DC from the station battery) which

are suitable to be installed in the substation operating at the voltage


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levels of the substation (indicated in Section 1 of this Standard, are

included in this specification.

c. The proposed LAN switches shall be equipped with dual DC (125 VDC)

power supplies.

d. The switches shall support priority tagging and open standards for ring

management.

e. External switches are required as they have the advantage that there is no interruption or reconfiguration of the Ethernet ring if one or several bay

devices are taken out of service.

f. Ethernet switches for inter-bay buses shall have 100Base-FX technology

(fiber optic-100MBPS) for inter connection of all IEDs (control,

protection and combined protection/control IEDs) with EHV/HV and

MV inter bay buses (PRP1- Bay LAN) and have Gigabit Ethernet

1000Mbps to connect Ethernet switches inside each ring EHV/HV and

MV inter-bay buses (PRP1-Bay LANs) and each ring of station buses

(PRP1-Station LANs) provided by SOLUTION PROVIDER. There shall

be consistency throughput for all inter-bay signals being provided from

the IEDs located throughout the substation and shall be consistent with

IEC 61850 requirements.

g. Security Features:

Should provide multilevel security/user passwords to prevent

unauthorized users from altering the switch configuration.

SNMPv3 encrypted authentication and access security

Support authentication/Centralized password management

(RADIUS)

IEEE 802.1q VLANs to segregate and secure network traffic

Port based Network access control (IEEE 802.1x)

Secure Shell (SSH)/Secure Sockets Layer (SSL) encryption.

h. Management Features:

Support enhanced traffic management, monitoring, and analysis,

through Embedded Remote Monitoring (RMON) software agent

supporting at least four RMON groups (history, statistics, alarms,

and events).

Telnet, CLI, LAN Switch Vendor GUI, and Web based

management interfaces.

Support for SNMP v3 interface to deliver comprehensive in-band

management.


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3.3.2 System Architecture

The system architecture shall be based on completely distributed approach

also concerning the connection of any device to the system. Meaning any

device protection as well as control and station level devices shall be directly

connected to the Ethernet backbone.

3.3.3 Redundant Networks

a. To ensure maximum performance and availability the network shall

b. For the inter-bay bus level of the SAS which contains the Ethernet

Switch connections for the Control IEDs, the Protection IEDs, the

SAS Front End Computers, and Communications Gateways, as a

minimum, redundant LAN configuration shall be provided by the

SOLUTION PROVIDER at all voltage levels, with separate redundant

networks provided for the IEDs at each voltage level.

c. The separate redundant networks at all voltage levels shall be

provided where the redundant inter-bay bus is interconnected with the

redundant station bus.

d. Refer to Section 14 of this Standard for further redundancy

implementation requirements which is to be implemented by the

SOLUTION PROVIDER .

e. The Bid proposal shall fully describe the proposed networks scheme.

This shall be supported by detailed network block/schematic

diagrams.

4.0 FUNCTIONAL REQUIREMENTS

4.1 General SAS Functionality

4.1.1 Control Scheme Hierarchy

a. A scheme with a predetermined hierarchy shall be provided for the

operation of the high-voltage apparatus. As such, the high voltage

apparatus within the station shall be operated from different places

(from the lowest level to the highest level):

Bay-oriented Local Control Panel with Mimic Diagram (Mimic)

Control IED

Combined Control/Protection IED

Station HMI


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Power Control Center (PCC/SCADA Master Station/LDC):

b. In the scheme shown above, operation of a specific piece of high

voltage apparatus shall be allowed to be performed by only one

operation at a time. To insure this, double operation interlocking shall

be employed. Double operation interlocking shall be employed as part

of the hard-wired interlocking scheme, as well as the

Software/GOOSE interlocking scheme resident in the Control IEDs and the combined Control/Protection IEDs.

4.1.2 Control Scheme-Select-before Operate

For safety and security reasons the command execution is always to be given

in two stages, with the first stage being the selection of the object that is to

be controlled, and the second stage being the operation (execution) of the

object being selected. This select before operate scheme shall be applicable

for the Control IED level, the combined Control/Protection IED level, and

the Station HMI level Also, depending on the SAS Equipment

Manufacturers design, and National Grid Saudi Arabia requirements/standards, either a direct select before operate scheme, a direct operate scheme, or a modified two handed select-before-operate scheme may be applicable for emergency operation through the Bay

Oriented Local Control Panels with Mimic.

4.1.3 Self Supervision

The entire SAS shall be designed with continuous self-supervision features

of the entire SAS installation, with self-diagnostic features for the SAS to

specifically pinpoint trouble/mal-operation areas of the SAS. Generally, the

self-diagnostic features will be built into the Station HMI, with displays

available for these diagnostics on the Operator's Workstation and/or

Engineering Workstation.

4.1.4 User Configuration

a. The monitoring, controlling and configuration of all input and output

logical signals and binary inputs and relay outputs for all built-in

functions and signals shall be possible both locally and remotely.

b. It shall also be possible to interconnect the built-in functions using

additional logics (AND-gates, OR-gates and timers) as well as to

configure additional functions such as over-current, over-voltage,

etc.(multi-activation of these additional functions should be possible).

4.1.5 Division of Functional Requirements

a. The functional requirements shall be divided into two areas which are

shown in the two paragraphs below.


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b. The Bay level functions shall comprise of operations within one bay

only, with the bay comprising of one circuit breaker, associated

disconnectors (isolation switches), earthing (grounding switches) and

associated instrument transformers (PTs and CTs).

c. System Level functions which look at the SAS and the substation as a

whole.

4.1.6 Direct Connection between PTs/CTs to SAS IEDs for Analog inputs

Analogue inputs for voltage transformers (PTs/VTs) and current

transformers (CTs) measurements shall be connected directly to the voltage

transformers (PTs/VTs) and the current transformers (CTs) without

intermediate transducers. The values of active power (W), reactive power

(VAR), frequency (Hz), and the rms values for voltage (U) and current (I)

shall be calculated on the Control IEDs, combined Control/Protection IEDs

and Protection IEDs. All readings on all SAS equipment shall be direct on all

displays, taking into account the scaling factors for each device (CTs and

PT/VTs).

4.2 Bay Level Functions

4.2.1 In a decentralized architecture the functionality shall be as close to the process as possible.

4.2.2 In this respect, the following functions shall be allocated at bay level:

a. Bay control functions including data acquisition/data collection

functionality in Bay Control IED's .and combined Control/Protection

IEDs

b. Bay protection functions including data acquisition/data collection

functionality in Bay Protection IED's. and combined

Control/Protection IEDs

c. Data collection functionality.

4.2.3 Bay control functions

a. Overview

Basic functions

Control mode selection(Local/Off/Emergency/Remote)

Select-before-execute principle

Command supervision: o Interlocking and blocking


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o Double command

Autoreclosing (may be considered as either a control function or protection function, depending on National Grid Saudi

Arabia requirements)

Synchrocheck, voltage selection (may be considered as either a control function or protection function, depending on

National Grid Saudi Arabia requirements)

Interruption of drive latching in case runtime is exceeded

Monitoring pole discrepancy and trip function, if applicable

Transformer tap changer control raise/lower (for power transformer bays)

Operation counters for circuit breakers and pumps, if applicable

Hydraulic pump control and runtime supervision, if applicable

Pump start cascading, if applicable

Anti pumping of circuit breaker (open/close)

Operating pressure supervision through digital contacts only

Display of interlocking and blocking

Breaker position indication on a three phase basis with indication showing pole discrepancy conditions/alarms where

pole discrepancy between the phases is detected/indicated

Alarm annunciation

Measurement display

Local HMI (local guided, emergency mode)

Interface to the station level

Data storage for at least 200 events

Run Time Command cancellation

Extension possibilities with additional I/O's inside the unit, installation of additional units and/or via fiber optic

communication and process bus

Additional functions, if any, specified in Main PTS/SCADA & Protection Appendices.

Advanced functions

Disturbance recording with capabilities for all analogue and binary values

Extension possibilities with additional I/O's inside the unit or via fiber-optic inter-bay communications and process bus

b. Control Mode Selection

As soon as the operator receives the operation access at bay level the operation is normally performed via the local HMI.

During normal operation the local HMI is guided and allows

the safe operation of all switching devices via the bay control

IED or the combined control/protection IED.


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It will be ensured that Protection features for the station (through the Protection IED's or the combined

control/protection IED used for the station protection function)

shall be functioning irrespective of the Control Mode.

In the event that the bay control IED or a combined control/protection IED fails, the operator shall have access to

the essential bay switchgear via a separate bay-oriented local

control panel with mimic diagram for High Voltage

switchgear, or via the Low Voltage Compartment for Medium

Voltage switchgear. This is an emergency function.

i. OFF Mode

It is not possible to operate any object, neither locally

nor remotely.

ii EMERGENCY Mode

A. The position indication shall be directly from

the primary equipment bay switchgear being

controlled.

B. On the bay-oriented local control panel with

mimic diagram, for the two handed operate principle, the device selection push button and

either the ON or OFF push button has to be

pushed simultaneously in order to close or open

the primary equipment bay switchgear. For the

single handed operate principle, as indicated in latest revision of 32-TMSS-02 each device

will have its own OFF or ON push button to press, and the operator will not be required to

use two hands to operate a device. Control

operation from other places (e.g. from

REMOTE or LOCAL) shall not be possible in

this operating mode.

iii. LOCAL (BCU) Mode

A. On the HMI the object has first to be selected.

In case of a blocking or interlocking conditions

the selection will not be possible and an

appropriate alarm annunciation shall occur.

B. If a selection is valid the position indication will

show the possible direction and the appropriate

ON or OFF button shall be pressed in order to

close or open the corresponding object.


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C. Control operation from other places (e.g.

REMOTE) shall not be possible in this

operating mode.

iv. REMOTE-STATION LEVEL mode

Control authority in this mode is given to the next

highest level (the Station HMI level) and the

installation can be controlled only remotely via the

Station HMI. Control operation from lower levels shall

not be possible in this operating mode.

v. REMOTE-PCC LEVEL mode

Control authority in this mode is given to the highest

level (SCADA Master Station) via the Station HMI and

the installation can be controlled only remotely via the

PCC (SCADA Master Station/LDC). Control operation

from lower levels shall not be possible in this operating

mode. National Grid Saudi Arabia notes that control

from this mode shall also be available in the event of

failure of even the (redundant) Station HMI Front End

computers, in which PCC Control and Data Acquisition

information will be transmitted and received directly

from the Communications Gateways to the applicable

Control IEDs and combined Control/Protection IEDs through the IEC 61850 Inter-bay bus.

c. Command supervision

Bay/station interlocking and blocking

i. Interlocking facilities have to be installed in the

switchgear to prevent damages and accidents in case of

false operation.

ii. Within the bay itself, a system of hard-wired interlocks and software/GOOSE interlocking controlled only

through the Bay Control IEDs (in conjunction with the

Bay Oriented Local Control Panel with Mimic) shall be

used. However, upon failure of a bay Control IED(s)

and/or combined Control/Protection IED(s) or

communications link(s), the hard-wired interlocking

shall operate and prevail. The SOLUTION PROVIDER

's proposed solution shall describe the bay interlocking

scenario in event of switching off or failure of a bay

Control SAS component(s) (Control IED(s) or

combined Control/Protection IED(s)),or other SAS

components.


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iii. Station interlocking systems shall be provided via hardwired or inter-bay bus. However, upon failure of

station computer, IED(s), communications link (inter-

bay bus), or other component of the SAS, the

hardwired station interlock shall operate and prevail. It

shall be a simple layout, easy to test and simple to

handle when upgrading the station with future bays.

The SOLUTION PROVIDER's proposed solution shall

describe the station interlocking scenario in event of

switching off or failure of a bay Control SAS

component(s) (Control IED(s) or combined

Control/Protection IED(s)),or other SAS components.

iv. Software/GOOSE "interlock override" functionality

shall be available as part of the SAS. However, there

shall be methods available to disable such a

software/GOOSE bay/station "interlock override scheme and/or to allow only access to this

software/GOOSE "interlock override" scheme by

privileged users using strong passwords and other

security features.

Double operation interlocking

i. Double operation interlocking prevents the operation of

two or more switches at the same time. The double

operation interlocking is a part of the station

interlocking; it shall preferably be hard-wired, but

provisions shall also be made in the SAS design for

software (GOOSE) double operation interlocking. It

shall be included for all the switches in the station. It

should be noted that unless interlocked for some

specific purpose (other than for Double Operation

Interlocking), there is no need of preventing

simultaneous operation of switches located in different

bays.

ii. With a hard-wired solution the interlocking is independent from the control authority of the station. If

a control IED and/or a combined Control/Protection

IED fails, the double operation interlocking does not

block the operation of the station. It shall still be

controlled from all the control authorities. Refer to

above Section i (under double operation interlocking) of

this Standard for further details pertaining to the overall

requirements for Double Operation Interlocking.

iii. The proposed solution shall describe the double

operation interlocking scenario while an IED of


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another bay or another component of the SAS is

switched off or fails.

Other General Interlocking requirements

i. For software/GOOSE interlocks, schemes which use

the Station HMI (or other Front End) Computer

equipment to make ANY software/GOOSE

interlocking decisions or transfer software/GOOSE

interlocking data shall NOT be used..

Software/GOOSE interlocking scheme shall ONLY

utilize the Bay Control IED equipment, the combined

Control/Protection IED equipment, and

intercommunications (through GOOSE messages)

between Control IEDs and combined

Control/Protection IEDs to support software/GOOSE

interlocking requirements.

ii. For the backup hard wired interlocking scheme/solution, Solution provider shall consult with

National Grid Saudi Arabia during the Base Design

stage of the project to determine if there is a need to

incorporate hard-wired interlock bypass/override in the related SAS design.

iii. For interlocking signals which are required between voltage levels in each substation which will be used for

software/GOOSE interlocking, these interlocking

signals described in this paragraph shall be transmitted

and received between voltage levels in hardwired form

and inputted/outputted to the other voltage levels

through GGIOs/Digital Inputs/Digital Outputs between

the related Control IEDs. This is required to guarantee

that separate dedicated IP Subnets can be allocated for

each voltage level in each substation.

iv. For the relation between software/GOOSE and backup hard wired interlocks, a series downstream principle will be used. This series downstream principle will first check the conditions of the

software/GOOSE interlocks and if the interlocking

conditions are satisfied at the software/GOOSE level at

the control or combined control/protection IED, then

the control signal will then pass to the hard wired interlocks, and if it is determined at the hard wired interlocking level that the interlocking conditions are

satisfied, the control signal will then pass to the related

switchgear device.


TESP10701R0/KSB


v. Finally, the hard wired interlock scheme shall be configured in such a way that, once the National Grid

Saudi Arabia obtains enough satisfactory operating

experience with the software/GOOSE interlocking

scheme, then National Grid Saudi Arabia personnel can

later easily disable the hard wired interlock scheme and later only rely on software/GOOSE interlocking for

the bay/station interlocking functionality.

Synchronism and energizing check

i. The synchronism and energizing check functions shall

be bay-oriented and distributed to the bay control

and/or protection devices. These features are:

A. Adjustable voltage, phase angle and frequency difference.

B. Energizing for dead line-live bus, live line-dead bus or dead line-dead bus with no synchro-check

function.

C. Synchro-check between live line and live bus with synchro-check function.

D. Settings for manual close command and autoreclose command shall be adaptable and adjustable for the

operating times of the specific switchgear.

E. Determination of a live line/dead line or a live bus/dead bus shall be provided automatically at the

IED level for the particular bays where the IED's

are installed by looking at the configuration of

related circuit breakers, disconnects (isolators) and

earthing (grounding) switches.

F. Furthermore, use of "sampled value" messages from adjacent IED's to transmit analog information

from PTs (VTs) (either line or bus PTs (VTs)) shall

NOT be accepted for performing synchro-check

inside an IED.

G. Depending on National Grid Saudi Arabia requirements as stated in the related Appendix of

the main PTS, synchronism and energizing check

may be required to be performed by dedicated

Synchrocheck Relays/IEDs and NOT Control or combined Control/Protection IEDs


TESP10701R0/KSB


ii. Voltage selection

A. The voltages relevant for the synchro-check functions are dependent on the station topology, i.e.

on the positions of the circuit breakers and/or the

isolators.

B. The correct voltage for synchronizing and energizing is derived from the auxiliary switches of

the circuit breakers, the isolator, and earthing

switch and related PTs and shall be selected

automatically by the Bay Control IEDs and/or

Protection IEDs. The correct voltage selection shall

also be dependent on the bay/station one-line

scheme (e.g. double bus bar-single breaker, breaker

and one-half, double bus, etc.) for each substation

to be equipped with SAS.

C. Voltage selection (which is required for synchronism and energizing check as described

Section i under Synchronism and energizing check)

shall be an integral function of the IED or

Synchrocheck Relay, and NOT through external

means.

D. Depending on National Grid Saudi Arabia requirements as stated in related Appendix of the

main PTS, voltage selection may be required to be

performed by dedicated Synchrocheck

Relays/IEDs and NOT Control IEDS or combined Control/Protection IEDs

Auto-reclosing and related synchro-check functions

i. These functions can be considered as either control or

protection functions.

ii. Depending on the National Grid Saudi Arabia

requirements as indicated in related Appendix of the

main PTS, autoreclosing and synchro-check (related to

auto-reclosing) may be implemented in a general

Control IED or combined Control/Protection IED (used

for general substation switchgear control) or a

dedicated Autoreclosing functional unit (Control IED

or combined Control/Protection IED or

Autoreclosing/related Synchro-Check built into a


TESP10701R0/KSB


Protection IED) integrated into the Protection portion

of the SAS.

iv. The autorecloser should be settable for the following modes of operation:

A. First autoreclosure sequence:

Three-phase autoreclosure Single/three-phase autoreclosure Single-phase autoreclosure

B. Further auto-reclosure sequences:

No further auto-reclosure sequences Further auto-reclosure sequences (totally 2, 3 or

4 sequences), always three-phase sequences

iv. It shall be possible to perform all three-phase

autoreclosure sequences with or without synchro-

check.

v. If synchro-check is required for any autoreclosure

sequence, refer the sub heading Synchronism and energizing check above and its subsections for a description of the synchro-check, and voltage selection

functionality

Run Time Command cancellation

If the control action is not completed within a specified time,

the command shall get cancelled, and an alarm/event shall be

raised at the Station HMI level (which may be reported to the

PCC (SCADA Master Station level). For operation of

switchgear which involves drive latching the latching shall be

interrupted by the Control IED or combined Control/Protection

IED and the drive motor power (for the latched device) shall

be interrupted also by the Control IED or the combined

Control/Protection IED. National Grid Saudi Arabia requires

that the Run-Time Command Cancellation functionality and

the Command cancellation execution timer be embedded in the

Control IEDs and combined Control/Protection IEDs either through the use of dedicated IEC 61850 Logical Nodes, or

general timer/logic gates which are incorporated in the IED

which can be configured by the user/manufacturer (by

software) through the IED configuration process.

Pole discrepancy monitoring/relaying (if applicable)


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A Pole Discrepancy monitoring function, based on the

measurement of phase over-currents and current differences

between phases as well as on breaker pole status (which is

determined by reading the auxiliary contacts on each pole of

the breaker) has to be provided. Also, depending on the SAS

Equipment manufacturer's design, additional Pole Discrepancy

Relaying may be included in the SAS as an integrated

function. If the additional Pole Discrepancy Relaying is

provided as part of the SAS, the Pole Discrepancy Relaying

feature integrated into the SAS shall support Stage I and Stage

II Pole Discrepancy Relaying functions, as well as being able

to initiate Pole Discrepancy Trip signals to remote substations

via Protection Signaling equipment (PSE), and

Communications equipment (PSE and Communications

provided by other parts of the project, as applicable). Refer to

related Appendix of the main PTS to determine additional

information on whether Pole Discrepancy monitoring/relaying

will be through separate Pole Discrepancy Relays, or

integrated into the functionality of SAS (Note: If main PTS

specifies separate dedicated external Pole Discrepancy Relays,

there will still be a requirement to monitor Stage I and Stage II

Pole Discrepancy from the external Pole Discrepancy Relay(s)

through SAS as part of the alarm function of SAS.).

Transformer tap changer control

i. Voltage regulation for single transformers or parallel

transformers with on-load tap-changer shall either be

included in the numerical control unit for the power

transformer or located in a separate tap changer control

device which is associated with the power transformer.

ii In the event that a separate tap-changer control device

is selected, this shall be an integral part of the SAS like

any bay oriented Control IED or Protection IED.

iii. OLTC scheme shall be .accomplished by the Control

IED's and/or dedicated Tap Changer IEDs (which have IEC 61850 interfaces) which will be performing

the regulation and tap changing function.

iv. National Grid Saudi Arabia notes that a built-in

numerical control unit is preferred instead of a separate

tap changer unit. Also, the Transformer tap changer

control scheme shall meet latest revision of TES-P-

119.26 for control schemes for each Substation's

Equipment.


TESP10701R0/KSB


d. Interface between Control IEDs and Maintenance Laptop Computer

and also between combined Control/Protection IEDs and Maintenance

Laptop Computer:

All IEDs used for the Control functions shall be provided with a serial,

Ethernet RJ45 and/or optical front connector for connection to a

Maintenance Laptop Computer.

e. Interface between the Control IEDs, the combined Control/Protection

IEDs and the inter-bay Bus pertaining to IEC 61850 and IEC 62439-3

PRP1:

For IEDs used for dedicated control, and/or combined

control/protection, each Control IED and combined Control/Protection

IED shall have full interfacing to the inter-bay communications bus

only through IEC 61850 and IEC 62439-3 PRP 1. Use of Protocol

Converters to convert from legacy protocols (e.g. DNP 3.0,

MODBUS, IEC-103, etc.) to IEC 61850/IEC 62439-3 PRP 1 will

NOT be accepted by the National Grid Saudi Arabia. REDBOX is not

acceptable for IEDs. For other equipment it is subjected to National

Grid Saudi Arabia review and acceptance. Refer enclosed drawing Fig

07.01 which shows where REDBOX is acceptable.

4.2.4 Bay protection functions

a. General

For all voltage levels except for the Medium Voltage level, the protection functions shall be independent of the control

functions (i.e. the Protection IED will NOT be performing

Control IED functions). For the Medium Voltage level, unless

specified in the main PTS, both control functions and

protection functions for a bay can be provided in one IED

(which will be known as a combined Control/Protection IED).

Refer to the related Appendix of the main PTS involving Relay

and Protection for further details on the functionalities

involved, as well as other details.

Furthermore, at the High Voltage level, for trip applications/trip commands, where there is a dedicated

Protection IED, the Protection IED shall perform the tripping

functions ONLY, and this tripping function shall NOT be

passed on to a Control IED (either through hard-wired means

and/or through use of GOOSE messages).

The protection functions are an integral part of the Substation Automation System.

All protection functions realized in the IEDs should be based on numerical technology.


TESP10701R0/KSB


All IEDs shall be serial integrated for data sharing and meet the real-time communication requirements for automatic

functions. The data presentation and the configuration of the

various IEDs shall be compatible with the overall system

communication and data exchange requirements.

All IEDs used for the protection functions (Protection IEDs and the combined Control and Protection IEDs) shall also be

provided with a serial, Ethernet RJ 45 and/or optical front

connector for connection to a Maintenance Laptop Computer.

For IEDs used for dedicated protection and/or combined control/protection, each Protection IED and combined

Control/Protection IED shall have full interfacing to the inter-

bay communications bus only through IEC 61850 and IEC

62439-3 PRP 1. Use of Protocol Converters to convert from

legacy protocols (e.g. DNP 3.0, MODBUS, IEC-103, etc.) to

IEC 61850/IEC 62439-3 PRP 1 will NOT be accepted by the

National Grid Saudi Arabia. REDBOX is not acceptable for

IEDs. For other equipment it is subjected to National Grid

Saudi Arabia review and acceptance. Refer enclosed drawing

Fig 07-01 which shows where REDBOX is acceptable.

This Standard only describes general Protection Requirements, with more specific protection requirements outlined in related

portions of the main PTS/standards. Refer to the related

Appendix of the main PTS/standards for Protection (Protective

Relaying) functions for the IEDs.

b. Self-supervision

Continuous self-supervision function with self-diagnostic possibilities

shall be included.

c. Event and disturbance recording function

Each Protection IED and combined Control/Protection IED shall contain an event recorder capable of storing at least 256

time-tagged events. A Protection IED and combined

Control/Protection IED shall also provide the user, either

locally or remotely, with complete information on the last ten

disturbances.

A disturbance recorder with a minimum of 5 seconds recording time for at least 10 disturbances shall provide the user with

time-tagged disturbance records.

At least the analogue inputs as well as 16 binary signals must be recorded.


TESP10701R0/KSB


The pre-fault and fault currents and voltages shall be recorded for each disturbance and be made available for further

evaluation purposes.

d. Local HMI

The local human machine interface (HMI) shall be front-mounted and based on a user-friendly, menu-structured

program, and performed with the use of a permanently

installed human machine interface unit, type-tested together

with the protection terminal.

In addition service values of current and voltages as well as active and reactive power (if voltage measurements included)

shall be available. Also the characteristic analogue values

related to the activated functions (e.g. impedance in case of

distance protection) should be available.

4.2.5 Line protection

a. General

The Protection IED and combined Control/Protection IED devices which incorporate numerical line protection shall be

selected for the protection of lines according to specific

network configurations and conditions. The scheme must

ensure reliable isolation for all kind of faults that might occur

on the specific line as per protection requirements stipulated in

Protective Relaying Appendix to the main PTS/Protective

Relay Standard.

Depending on the voltage level and complexity, the following line protection functions may be required:

b. Distance function

Distance function requirements shall be compatible to the relay

requirements indicated in Protective Relaying Appendix to the main

PTS/Protective Relay Standard.

c. Differential function

Differential function requirements shall be compatible to the relay



d. Earth fault function


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Earth fault function requirements shall be compatible to the relay



e. Fault location

Fault location function requirements shall be compatible to the relay


PTS.

f. Transformer protection

General

i. The transformer protection shall be suitable for the

protection of two- or three-winding transformers,

auto-transformers, reactors, and generator-transformer

block units, as per protection requirements stipulated

in Protective Relaying Appendix to the main PTS or

standard.

ii. The numerical transformer terminal shall be designed

to operate correctly over a wide frequency range and to

accommodate for system frequency variations and

block generator start-ups.

Current differential function

Refer to the Protective Relaying Appendix to the main PTS or

Protective Relay Standard for further details.

Other functions

Refer to the Protective Relaying Appendix to the main PTS or

Protective Relay Standard for further details.

Breaker failure protection

i. The breaker failure protection shall comprise two time

stages. The first stage shall be bay-oriented and shall

re-trip the local circuit breaker.

ii. The second stage shall be station-oriented, requiring

information from other bays, and shall trip the circuit

breakers in adjacent bays.

iii. Refer to the Protective Relaying Appendix to the main PTS or Protective Relay Standard for further details.


TESP10701R0/KSB


4.3 System/Station level functions

4.3.1 Control

a. The different high-voltage switchgear and medium voltage switchgear

within the station shall be operated from different places:

from the remote control centers (SCADA Master Station(s))

from the station level

For High Voltage switchgear from the Control IED(s) in the LCC(s) (in the bays)

For High Voltage switchgear from the Bay-Oriented Local Control Panel(s) with Mimic Diagram

For Medium Voltage switchgear from the Control IED(s)/combined Control/Protection IED(s)

For Medium Voltage switchgear from the Low Voltage Compartment(s)

b. Operation shall only possible by one operator at a time.

c. The operation shall depend on the conditions of other functions, such

as interlocking, synchrocheck, etc. (see description in chapter Bay control functions).

4.3.2 Status supervision

a. The position of each switchgear, e.g. circuit breaker, isolator, earthing

switch, transformer tap changer etc., shall be supervised permanently.

Every detected change of position shall be immediately visible in the

single-line diagram on the station HMI screen, recorded in the event

list, and a hard copy printout shall be produced. Alarms shall be

initiated in the case of spontaneous position changes.

b. The switchgear positions shall be indicated by two auxiliary switches,

normally closed (NC) and normally open (NO), which shall give

relevant signals. An alarm shall be initiated if these position

indications are inconsistent or if the time required for operating

mechanism to change position exceeds a predefined limit.

c. The SAS shall also monitor the status of substation auxiliaries (which

will include, but not be limited to auxiliary relays such as trip current

supervision, DC supervision, etc.).. The status and control of

auxiliaries shall be done through separate one or more Control IEDs

and all alarm and analogue values shall be monitored and recorded

through the respective Control IEDs. It is noted also by the National

Grid Saudi Arabia that monitoring of the status of auxiliaries shall

NOT be performed from dedicated Protection IEDs or combined Control/Protection IEDs.


TESP10701R0/KSB


4.3.3 Measurements

a. The measured values shall be displayed locally on the Local HMI

contained as part of an IED, Station HMI and in the control center

(SCADA Master Station(s)). At the Station HMI level, facilities shall

exist to discard abnormal values (through the Station HMI Filtering

functions) and when an abnormal value is reached, generate an

alarm/event indicating that an abnormal value (s) has been detected.

b. All analogue values shall be updated (both in Local HMIs (contained

as part of the IEDs), and Station HMI equipment every 2 seconds, or

faster.

c. Threshold limit values shall be selectable for alarm indications.

4.3.4 Event and alarm handling

a. Events and alarms shall be generated either by the switchgear, by the

control IEDs, by the protection IEDs, by the combined

control/protection IEDs, or by the station level unit.

b. They shall be recorded in an event list in the station HMI. Alarms

shall be recorded in a separate alarm list and appear on the screen. All,

or a freely selectable group of events and alarms shall also be printed

out on an event printer.

c. The alarms and events shall be time-tagged with a time resolution of 1

ms National Grid Saudi Arabia notes that the time tagging of the

alarms and events shall be performed at the IED itself only, and NOT

through SAS Computer equipment..

d. During the Base Design Stage, the Solution provider shall submit the

Events and Alarms List (Signals List) for National Grid Saudi Arabia

approval, and once approved the Solution provider will use this

approved list as a basis for development of his SCD files for SAS.

e. As a minimum, the Signals and Events List shall contain all applicable

points as identified in TES-P-119.27 the SOE Points List and the

approved Annunciator Alarms List for the Substation. Also, in

development of the Events and Alarms List, separate dedicated lists

shall be generated for SOE, SCADA, and the Station HMI contained

as part of the Substation Automation System for review and approval.

f. Finally as part of the events and alarms handling requirement, when

there are cases where IEC 61850 DOES NOT provide for

alarms/events as part of the logical node (LN) signals definitions

(under IEC 61850) and where these alarms/events signals are required


TESP10701R0/KSB


under latest revision of Engineering Standard TES-P-119.27 (for

SCADA) the SOE Points List, and the National Grid Saudi Arabia

approved Annunciator Alarms List for the Substation, the SOLUTION

PROVIDER shall provide suitable auxiliary binary input contacts

(and/or binary outputs) as part of each IED design to extend non IEC

61850 alarms/events by hard-wired means to other components of the

SAS (which will appear as one of the GGIOs included as part of the

SAS Data Acquisition function which will be reported to the Station

HMI, the SCADA Master Stations and other equipment).

g. In/Out facility for the protection is isolating trip out put only during

maintenance of relays. However during this condition all alarms to

remote Master stations shall be isolated in order to avoid receiving any

nuisance alarms during maintenance. Facility for isolating alarms shall

be provided as part of relays or at the Gateways.

4.3.5 Time Synchronization System

a. A dedicated clock synchronization unit shall set the time within the

SAS. Time synchronization of all SAS equipment shall be

independent of the station level equipment e.g. station computer or

Communications Gateway. Time Synchronization shall be from

redundant GPS receivers located on the property of each substation.

The time shall then be distributed to the control IEDs, combined

Control/Protection IEDs and protection IEDs and other SAS

equipment via the communication buses. An accuracy of 1ms (from

the actual time) within the substation (and for ALL SAS components

within the substation which require time signals) is required.

b. Hardware/Firmware for the GPS receivers supplied by the

SOLUTION PROVIDER shall provide for a antenna, decoder, other

hardware, interfaces with the SAS and Firmware as per the latest IRIG

B122 or other National Grid Saudi Arabia approved standard time

code format (e.g. SNTP and others).

c. Software for the GPS receivers shall include a software package to

implement GPS-based time as per at least IRIG B122 standard time

code format (Day of Year and Time update rate of once per second,

AM 1 KHz carrier, resolution of + 1 mS, expressed in hh, mm, ss,

ddd) or other National Grid Saudi Arabia approved standard time code

format and able to synchronize time and date into the SAS, with all

components of the SAS receiving consistent time and date

information.

d. Upon failure of any GPS receiver in the time synchronization system,

the GPS receiver shall transmit an alarm to both the Station HMI

equipment in the SAS, and the remote SCADA Master Station(s).


TESP10701R0/KSB


e. In the event of failures of both GPS clock receivers which are beyond

the control of the GPS clock receivers (e.g. shutdown of the GPS

satellite network, atmospheric conditions blocking reception of GPS

signals at the GPS receivers, etc.) there shall be a means of time

synchronization by the use of either internal SAS clocking sources

(e.g. internal clocks inside the IED(s), etc). or tertiary clocking

sources from the respective SCADA Master Station(s). In this respect,

during the Base Design Stage, the SOLUTION PROVIDER shall state

the holdover clocking accuracy of the internal SAS clocking sources,

the clocking drift of these internal SAS clocking sources and the

maximum allowable time which the SOLUTION PROVIDER feels

that the infernal SAS clocking sources will provide accurate (+ 1 ms

accuracy from real time) timing. If in the event that based on the

SOLUTION PROVIDER provided information, that the internal SAS

clocks will NOT provide accurate time information in the event of

both GPS receivers failing, the National Grid Saudi Arabia during the

Base Design will instruct the SOLUTION PROVIDER to utilize the

existing SCADA Master Station(s) Clocks as a tertiary

clocking/synchronization source and incorporate this SCADA Master

Station(s) clock as a tertiary clocking/synchronization source.

4.3.6 Telecontrol

Remote access to each substation data shall be enabled via the control centers

(SCADA Master Stations) upon request. The respective owners in the utility

organization may use some or all information related to the conditions of high

voltage apparatus.

4.3.7 Station HMI-Presentation and Dialogues and Design

a. General

The operator Station HMI shall provide basic functions for supervision and control within the substation.

The Station HMI shall be fully redundant and shall provide the functions for supervision and control of the substation. Access

to the redundant Front End Computers shall be through the

Operator's Workstations and the Engineer's Workstation.

However to meet the redundancy requirements a backup

workstation (included as part of a Maintenance Laptop

Computer) shall be provided with software and firmware fully

loaded which can be used to act as either the Operator's

Workstation or Engineering Workstation in the event of failure

of either the Operator's Workstations or Engineering

Workstation contained as part of the SAS.

The operator shall give commands to the switchgear on the screen via mouse clicks.

TRANSMISSION ENGINEERING STANDARD T

tes-p-107-01-r0

Documents

system performance

system architecture

general system design

support system

local station control

control ied

bay control protection

substation sas configuration