The Saudi Arabian Distribution Code...The Saudi Arabian Distribution Code Page 3 of 99 10...
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The Saudi Arabian
Distribution Code
Issue: 03
Revision:02
October 2018
Prepared By:
Saudi Electricity Company (SEC)
No part of this publication may be reproduced, stored in a retrieval system or
transmitted in any form or by any means electronic, mechanical, photocopying,
recording or otherwise, without written permission of the Electricity & Cogeneration
Regulatory Authority.
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CHRONOLOGY OF SAUDI ARABIAN DISTRIBUTION CODE REVISIONS
Sr. No. Revision No. Date Detail of Revision
01 DCRP-2011-001 8-01-2011 The figure of Medium
Voltage Level, 69KV, given
under clauses DPC2.2,
DCC4.6 & 2.2 was
inconsistent with the figure of
36 KV given in the Clause
DCD52, i.e. definition of
“Medium Voltage”. Clause
DCD52 has been revised with
figure 69Kv.
02 DCRP-2011-002 8-01-2011 Corrections/modifications
made in Clause DCC6.3.1.
03 DCRP-2011-003 8-01-2011 Clause DOC3.1(a) has been
corrected by removing the
word “not” which was
depicting wrong sense of the
sentence.
04 DCRP-2011-004 8-01-2011 There was no part 7
“Reference” in the DC.
Therefore necessary
corrections have been made
under “Part-1” Introduction
& Contents.
05 DCRP-2011-005 8-01-2011 There was no Annexure 2 in
the DC. Therefore Clause
DGC 9.3 has been modified
by changing the words
“Application form can be
obtained through ECRA”.
06 DCRP-2011-006 8-01-2011 Clause DGC6.4 has been
modified by incorporating
the words “as per standard
amendment form which can
be obtained through ECRA”.
07 DCRP-2011-007 8-01-2011 New voltage slab 400/230V
has been added in Table
DPC2.1.
08 DCRP-2011-008 8-01-2011 New voltage slab 400/230V
has been added in Table
DPC2.3.
09 DCRP-2011-009 8-01-2011 New voltage slab 400/230V
has been added in Table
1,clause 2.2
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10 DCRP-2011-010 12-10-2011 Clause 1.3(g), the word
“new” deleted from the
definition of ECRA.
11
DCRP-2011-011
12-10-2011
Clause DCD 42 , The
Definition of “Generator”
was modified.
12 DCRP-2011-012 20-03-2012 Clause DPC 2.7 “Earthing
Requirement (Bundling of
LV neutral &MV Ground)
was modified
13 DCRP-2011-013 20-03-2012 Clause DPC 2.8.1, New KPI
“MAIFI” added in this clause
14 DCRP-2011-014 20-03-2012 Short circuit level for new
voltage slab 400/230V has
been added in Table DCC
4.1.
15 15 Nos. Corrections
Omissions, Typographical
mistakes, in two parts , (11+4)
, have been made along with
insertion of “List of
Abbreviations.” Which was
missing in the DC.
16 DCRP-2011-015 25-03-2012 In Clause DCC 4.1.2 , new
Standard SASO added in
addition to existing standard
IEC.
17 DCRP-2011-016 25-03-2012 New sub Clause DCC 4.1.2
(a) added under clause DCC
4.1.2.
18 DCRP-2011-017 25-03-2012 New sub Clause DCC 4.1.2
(b)) added under clause DCC
4.1.2.
19 DCRP-2011-018 25-03-2012 Existing Clause DCC 4.1.3
has been modified
20 DCRP-2011-019 2-04-2012 In compliance to decree # 324
dated 20-09-1430, a foot note
regarding new voltage slab
230/400 V was added under
Table DPC2.1
21 DCRP-2011-020 In compliance to decree #
2/27/23 dated 21-10-1433,
existing clause DPC2.4 ,
power factor modified to
enhance the power factor.
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TABLE OF CONTENTS
Sr. No Description Page No.
CHRONOLOGY OF SAUDI ARABIAN DISTRIBUTION CODE
REVISIONS
2
FOREWORD 7
PREFACE 8
LIST OF ABBREVIATIONS 9
PART-1 INTRODUCTION 10
1.1 Purpose of the Distribution Code 10
1.2 Structure of Distribution Code 12
1.3 Structure of Electricity Supply Industry 13
1.4 Use of the Distribution System 14
PART-2 GENERAL CONDITIONS 17
DGC1 Introduction 17
DGC2 Scope 17
DGC3 Implementation 17
DGC4 Unforeseen Circumstances 17
DGC5 Hierarchy 18
DGC6 Distribution Code Panel 18
DGC7 Communications between DSP(S) and Users 20
DGC8 Emergency Situations 20
DGC9 Derogations 20
DGC10 Confidentiality 23
DGC11 Force Majeure 24
DGC12 Disputes and Dispute Resolution Procedures 24
PART-3 PLANNING 25
DPC1 Introduction 25
DPC2 Design Standard 25
DPC2.1 Frequency 25
DPC2.2 Voltages 26
DPC2.3 Harmonics 28
DPC2.4 Power Factor 28
DPC2.5 Phase Unbalance 29
DPC2.6 Voltage Stability 29
DPC2.7 Earthing Requirement 30
DPC2.8 Security of Supply 31
DPC3 Transfer of Planning Data 33
DPC3.1 Planning Information to be Provided by the Users 33
DPC3.2 Information to be exchanged 34
DPC3.3 Planning Studies 35
PART-4 CONNECTION CONDITIONS 36
DCC1 Introduction 36
DCC2 Information Required for Connections 37
DCC3 Connection Arrangements 39
DCC3.1 Connection Voltage 39
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DCC3.2 Information Provided by DSP(s) 40
DCC3.3 Ownership Boundaries 40
DCC4 Technical Requirements for Connections 41
DCC4.1 Connection Standards 41
DCC4.2 Protection Requirements 42
DCC4.3 Earthing 44
DCC4.4 Voltage Regulation and Control 45
DCC4.5 Short-Circuit Levels 45
DCC4.6 Insulation Levels 45
DCC4.7 Capacitive and Inductive Effects 46
DCC4.8 Voltage Disturbances 47
DCC5 Metering and Telemetry 47
DCC6 Embedded Generator Requirements 48
DCC6.1 Introduction 48
DCC6.2 Specific Rules for Embedded Generators 48
DCC6.3 Provision of Information 49
DCC6.4 Information Provided by DSP(s) 52
DCC6.5 Technical Requirements 52
DCC6.6 Rate of Change of Frequency 54
DCC6.7 Islanding Disconnection 54
DCC6.8 Energization and Ramping of Generating Units 54
DCC6.9 Energization / ramping of Embedded Power Park Modules 55
DCC.6.10 Active Power Performance 55
DCC.6.11 Active Power Control 56
DCC.6.12 Reactive Power capacity and controllability 58
DCC.6.13 Communication 61
DCC.6.14 Fault Ride through 62
DCC.6.15 Short Circuit Contribution 63
DCC.6.16 Black Start Capability 64
DCC.6.17 Generating Plant Commissioning Tests 64
PART-5 OPEARTION 65
DOC1 Demand Forecasting 65
DOC1.1 Introduction 65
DOC1.2 Scope 65
DOC1.3 Capability of receiving Dispatch Instructions 66
DOC1.4 Information Flow and Co-Ordination 66
DOC1.5 Demand Forecast Data 66
DOC1.6 Information regarding Output and planned shutdowns 66
DOC2 Operational Planning 67
DOC2.1 Introduction 67
DOC2.2 Scope 67
DOC2.3 Provision of Information 68
DOC2.4 Time Scales and Data 68
DOC2.5 Information from Embedded Generators 68
DOC2.6 Information to Users 68
DOC3 Demand Control 69
DOC3.1 Introduction 69
DOC3.2 Scope 70
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DOC3.3 Methods of Demand Control 70
DOC3.4 Implementation of Demand Control 70
DOC4 Operational Communication and Liaison 71
DOC4.1 Introduction 71
DOC4.2 Scope 71
DOC4.3 Procedure 71
DOC4.4 Significant Incidents 72
DOC5 Event Reporting 72
DOC5.1 Introduction 72
DOC5.2 Scope 72
DOC5.3 Procedure 73
DOC5.4 Joint Investigations 73
DOC5.5 Matters to be included in a Written Report of a Significant
Incident
73
DOC6 System Tests 74
DOC6.1 Introduction 74
DOC6.2 Scope 74
DOC6.3 Procedure 75
DOC7 Monitoring, Testing and Investigation 77
DOC7.1 Introduction 77
DOC7.2 Scope 77
DOC7.3 Procedure 77
DOC8 Safety Co-Ordination 78
DOC8.1 Introduction 78
DOC8.2 Objectives 78
DOC8.3 Scope 78
DOC8.4 Procedure 78
DOC8.5 Safety at the DSP(S)/User Interface 79
DOC8.6 Safety Rules 80
PART-6 Glossary 81
ANNEXURE
SECURITY AND PLANNING
STANDARDS FOR THE DISTRIBUTION
SYSTEM (Demand Customers Only)
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FORWARD
This is the second issue of the Saudi Arabian Distribution Code. Such work has been
accomplished by extensive efforts from Saudi Electricity Company (“SEC”) and was
subjected to thorough technical and legal reviews by internationally renowned consultants
including ESBI of Ireland and CMS Cameron McKenna of UK as well as a number of major
Saudi stakeholders and the Electricity & Co-Generation Regulatory Authority
(“ECRA”).
The Distribution Code is designed to indicate the procedures for both planning and
operational purposes and covers both normal and exceptional circumstances. It is
however a live working document. It will be, from time to time, subject to change and/or
revision to reflect stages of development of the regulatory framework of the industry and
changes to comply with legislation and good industry practice. The proposals for
change will be received by the Distribution Code Review Panel (“DCRP”). The rules and
responsibilities of the DCRP are described in chapter DGC6. Upon receipt of such
proposals for change, the DCRP will carry out the necessary process as appropriate to
study these proposals and officially prepare a report of recommendations to ECRA for
its approval. The DCRP is a stakeholders representation panel and its members are
outlined in chapter DGC6.3 of the Distribution Code.
As a User of this Distribution Code, it is your responsibility to ensure that you possess the
most up to date issue. Issues of the Distribution Code can be downloaded from ECRA’s
web site www.ecra.gov.sa.
This Preface is provided to Users and to prospective Users for their information only and
does not constitute a part of the Distribution Code.
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PREFACE
The Saudi Arabian Distribution Code has been developed to define the
rules and regulations for all parties for accessing and using the
Distribution System. The objective is to establish the obligations of the
distribution service providers (DSP's) and other system Users TSP, (Transmission
Service Provider), Embedded Generators, other distribution service providers and
Customers for accessing and using the Distribution System, more specifically to:
(i) define obligations, responsibilities, and accountabilities of
all the parties for ensuring open, transparent, non-
discriminatory, and economic access and use of the system
while maintaining its safe, reliable and efficient operation;
(ii) define minimum technical requirements; and
(iii) Set out the information exchange obligations.
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LIST OF ABBREVIATIONS
A Ampere
ASAI Average System Availability Index
AVR Automatic Voltage Regulator
BIL Basic Insulation Level
CAIDI Customer Average Interruption Duration Index
CHP Combined Heat and Power
CMS Content Management System (Cameron McKenna UK -Law Firm)
DCRP Distribution Code Review Panel
DSP Distribution Service Provider
ECRA Electricity and Co-generation Regulatory Authority
ESBI Electricity Supply Board Ireland
HV High Voltage
HZ Hertz
IEC International Electro-Technical Commission
IEEE Institute of Electrical and Electronics Engineers
IR Index of Reliability
KA Kilo Ampere
KPI Key Performance Indicator
KV Kilo volt
KVA Kilo volt ampere
KW Kilo watt
KWh Kilo watt hour
Kvarh Kilo var hour
LV Low Voltage
MVA mega volt ampere
MV Medium Voltage
Mvar mega var
Mvarh mega var hour
MW mega watt
MWh megawatt hour
RMS root mean square
RMU Ring Main Unit
SAIDI System Average Interruption Duration Index
SAIFI System Average Interruption Frequency Index
SAGC Saudi Arabian Grid Code
SASO The Saudi Standards, Metrology and Quality Organization
SCADA Supervisory Control and Data Acquisition
THVD Total Harmonic Voltage Distortion
TSP Transmission Service Provider
V Volt
VA volt ampere
Var volt ampere reactive
W watt
Wh watt hour
X/R reactance over resistance
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PART 1: INTRODUCTION
Contents
1.1 Purpose of the Distribution Code
1.2 Structure of the Distribution Code
1.3 Structure of the Electricity Supply Industry
1.4 Use of the Distribution System
1.1 Purpose of the Distribution Code
The Distribution Code specifies the technical aspects of the working relationship
between the DSP(s) and all Users of the Distribution system which are necessary to
ensure a stable, reliable and economical electrical Distribution system and to enable
the DSP(s) to fulfill their obligations specified in the Saudi Arabian Grid Code
(SAGC).
The relationship between all Users, the Grid Code and the Distribution Code is shown
diagrammatically in Figure 1.1.
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1.2 Structure of Distribution Code
The Distribution Code is in seven parts, as follows:
Part 1: Introduction
This outlines the purpose of the Code, its relationship with the Saudi Arabian Grid Code (SAGC), the structure of the electricity supply industry, and how the various parts of the Code are relevant to the different Users of the Distribution system.
Part 2: General Conditions
This presents provisions which are of general application to all parts of the Code.
Part 3: Planning
This specifies the technical and design criteria and the procedures to be employed in the
planning and development of the Distribution system.
Part 4: Connection Conditions
These define the minimum standards for methods of connection to the Distribution
System.
Part 5: Operation
This part addresses various operational issues including load forecasting, planning
outages, reporting of operational changes and events, safety matters and procedures for
dealing with emergencies.
Part 6: Definitions
Annexure
SECURITY AND PLANNINGSTANDARDS FOR
THE DISTRIBUTION SYSTEM (Demand Customers Only)
.
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1.3 Structure of the Electricity Supply Industry
The Electricity Supply Industry comprises the following entities:
(a) The Transmission Service Provider (TSP) owns and operates the
Transmission System. The Transmission System transports the electricity,
generated by Generating Units, to the Distribution System, through which
most Customers will be supplied. Some Generating Plant is connected
directly to the Distribution System and is referred to as Embedded
Generation.
(b) The Distribution Service Provider (DSP(s)) is responsible for operating
and maintaining secure, reliable and efficient electricity Distribution
System. The Distribution System transports electricity from the
Transmission System or from Embedded Generating Units to the final
Customer.
(c) Retailers supply electricity to Customers. For this purpose, Retailers will
be entitled to use both the Transmission System and the Distribution
System for the transport of electricity from Generating Units to
Customers.
(d) Traders supply electricity to other licensees and/ or eligible Customers.
For this purpose, Traders will be entitled to use both the Transmission
System and the Distribution System for the transport of electricity
from Generating Units to those licensees or eligible Customers
(e) Generators generate electricity which is fed onto the Transmission or
Distribution Systems. Generating Units are classified according to their
voltage, output power and whether or not they are subject to Central
Dispatch by the TSP.
(f) Customers may purchase electricity from the DSP(s), Traders or
Retailers. Some Customers have their own generating Plant for supplying
all or part of their own needs.
(g) ECRA was established to regulate the Electricity Industry.
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1.4 Use of the Distribution System
Use of the Distribution System may involve any of the following transactions:
(a) Any connection at entry to or exit from the Distribution System, which is
called an interface point. An entry point is the connection between the
Distribution System and the Transmission System or an Isolated/
Embedded Generating Plant. An exit point is the connection between the
Distribution System and the Customer’s premises.
(b) Use of the Distribution System to transport electricity between
entry and exit points.
(c) Construction of a Connection Point.
(d) Work and/or operation associated with equipment at the interface with
the Distribution System.
Users connected to the Distribution System shall comply with the
relevant sections of the Distribution Code. The categories of Users of
the Distribution System are described in Table 1 and the sections of the
Code that apply to each User are shown in Table 2. Users shall also
comply with the requirements of relevant legislation, which from time
to time comes into force.
Customers and Embedded Generators shall be required to have Connection
Agreements with the DSP(s) and Retailers/ Traders shall be required to enter into
Use of System Agreements with the DSP(s) or the TSP as the case may be.
There are a number of technical documents annexed to the Distribution Code.
Users are bound to comply with the requirements of these documents as
appropriate to their circumstances. Users shall also be required to enter into
technical and other agreements. Customers and Generator / Embedded
Generators shall be required to have Connection Agreements with the DSP(s)
and Retailers/ Traders shall be required to enter into Use of System Agreements
with the DSP(s) or the TSP as the case may be.
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Table 1
CATEGORIES OF USERS OF THE DISTRIBUTION SYSTEM
A1 Embedded Generator with a Registered Capacity ≥ 10 MW
A2 Embedded Generator with a Registered Capacity ≥ 2 MW <10 MW
A3 Embedded Generator with a Registered Capacity ≥200kW < 2 MW
A4 Embedded Generator with a Registered Capacity <200kW
B1 Major Customers connected at High Voltage
B2 Customers connected at Medium Voltage
B3 Industrial and commercial Customers connected at Low Voltage
B4 Domestic Customers
C Retailers/ Traders
D The Distribution Service Provider (DSP(s))
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SECTIONS OF THE DISTRIBUTION CODE APPLYING TO PARTICULAR
CATEGORIES OF USERS OF THE DISTRIBUTION SYSTEM
CATEGORY OF USERS
Dist. Code Ref. A1 A2 A3 A4 A5 B1 B2 B3 B4 C D
DGC D D D D D D D D D D D
DPC1 R R R R R R R R R R R
DPC2 D D D D R R R R R R D
DPC3 R R R R R R R R R R R
DCC1 R R R R R R R R R R R
DCC2 R R R R R R R R R R R
DCC3 R R R R R R R R R R R
DCC4 D D D D NA D D D D R D
DCC5 D D D D NA D D R R R D
DCC6 D D D D NA D D D D R D
DOC1 NA D NA NA NA D D NA NA NA D
DOC2 D D D D NA D NA NA NA NA D
DOC5 R R D R R R R R R NA D
DOC7 D D D R NA D NA NA NA NA D
DOC8 D D D R NA D NA NA NA NA D
Table 2 NA : Not Applicable
D : Applicable with specific obligations R : Relevant for information but no specific obligations
Note(1): Customers with all sizes of Embedded Generation (A1 to A4 in Table 2)
must, in addition to compliance with the requirements placed on their specific
category as Generators also comply with the requirements of the relevant
customer category (B1 to B4).]. Note (2): Any User proposing to close, retire, withdraw from service, or otherwise
cease to maintain and keep available for Dispatch in accordance with Good
Industry Practice any Generating Station or Generating Units with Registered
Capacity (3) greater than two (2) MW in aggregate shall give the DSP at least
twenty-four (24) calendar months’ notice of such action. The DSP will notify
the TSP according to agreed timescales in cases where the Registered Capacity
of the retiring Generating Unit (or in aggregate Generating Units) is 10MW or
more.
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PART 2: GENERAL CONDITIONS Contents
DGC1 Introduction
DGC2 Scope
DGC3 Implementation
DGC4 Unforeseen Circumstances
DGC5 Hierarchy
DGC6 Distribution Code Review Panel
DGC7 Communications between DSP(s) and Users
DGC8 Emergency Situations
DGC9 Derogations
DGC10 Confidentiality
DGC11 Force Majeure
DGC12 Disputes and Dispute Resolution Procedures
DGC1: Introduction
While each part of the Distribution Code presents the rules and provisions relating specifically to that part, the Distribution General Conditions (DGC) presents
provisions which are of general application to all parts of the Distribution Code.
DGC2: Scope
The General Conditions apply to all Users of the Distribution System.
DGC3: Implementation
DGC3.1 The Distribution Service Provider Licence imposes a duty upon
DSP(s) to implement and enforce the Distribution Code. In order to
do this DSP(s) may need access across boundaries, services, and
facilities from Users or to issue instructions to Users, for example to
isolate or disconnect Plant or apparatus. It is considered that these
cases will be exceptional and it is not, therefore, possible to
envisage precisely or comprehensively what DSP(s) might
reasonably require in order to carry out its duty.
DGC3.2 All Users are required to abide by the Distribution Code and also to provide the DSP(s) rights of access, services and facilities and to
comply with such instructions as may be reasonably required to
implement and enforce the Distribution Code.
DGC4: Unforeseen Circumstances
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DGC4.1 If circumstances arise which the provisions of the Distribution Code
have not foreseen, DSP(s) shall, to the extent reasonably
practicable in the circumstances, consult promptly and in good faith
with affected Users in an effort to reach agreement as to what
should be done. If agreement cannot be reached in the time
available DSP(s) shall determine what is to be done.
DGC4.2 Whenever DSP(s) makes a determination, it shall have regard,
wherever possible to the views expressed by Users, and in any
event, to what is reasonable in all the circumstances.
DGC4.3 Each User shall comply with all instructions given to it by DSP(s) following such a determination, provided that the instructions are consistent with the then current technical parameters of the
particular User’s System registered under the Distribution Code.
The DSP(s) shall promptly refer all such unforeseen circumstances
and any such determination to the Distribution Code Review Panel (DCRP) in accordance with DGC6.2.
DGC5: Hierarchy
DGC5.1 In the event of any conflict between the provisions of any direction of ECRA on the one hand and the provisions of the Distribution Code on the other, the provisions of ECRA‟s direction shall prevail.
DGC5.2 In the event of any conflict between the provisions of the Distribution
Code and any contract, agreement or arrangement between DSP(s) and a User, the provisions of the Distribution Code shall prevail
unless the Distribution Code expressly provides otherwise.
DGC5.3 In the event of any conflict between the provisions of the Distribution Code and the Transmission Code relating to system operation, the
provisions of the Transmission Code shall prevail [unless the Distribution Code expressly provides otherwise.]
DGC6: Distribution Code Review Panel
DGC6.1 The DSP(s) shall establish and maintain the DCRP, which shall be a
standing body, to carry out the functions referred to in DGC6.2.
DGC6.2 The Panel shall:
(a) keep the Distribution Code and its working under review,
(b) review all suggestions for amendments to the Distribution Code which
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ECRA or any User may submit to a DSP for consideration by the Panel
from time to time,
(c) recommend to ECRA amendments to the Distribution Code that the Panel feels are necessary or desirable and the reasons for the recommendation,
(d) issue guidance in relation to the Distribution Code and its implementation, performance and interpretation when asked to do so by
any User,
(e) consider what changes are necessary to the Distribution Code arising out of any unforeseen circumstances referred to it by DSP(s) under
DGC4,
(f) consider the effect of proposed changes on the Transmission Code,
(g) publish recommendations as to amendments to the Distribution Code that a DSP or the DCRP feels are necessary or desirable and the reasons for
the recommendations, and
(h) Produce an annual report of the activities of the DCRP.
DGC6.3 The Panel shall consist of:
(a) chairperson and two persons appointed by, and representing DSP(s), (b) one person appointed by and representing ECRA,
(c) one person representing the TSP,
(d) one person representing Generators with Embedded generation,
(e) one person representing Major Customers,
(f) one person representing suppliers, and
(g) one representative of the SASO
(h) one representative from KA-CARE
If any of the above parties fails to appoint its representative, (ECRA)
shall appoint one on its behalf.
Each of the above shall be appointed pursuant to the rules issued under clause
DGC6.4.
DGC6.4 The Panel shall establish and comply at all times with its own rules
and procedures relating to the conduct of its business, such rules and procedures to be known as the Constitution and Rules of the Panel, which
shall be approved by ECRA.
The DSP shall consult all Users liable to be affected in relation to all
proposed amendments to the Distribution Code as per standard amendment form (which can be obtained through ECRA) and shall submit
all proposed amendments to the Distribution Code to the DCRP for
discussion prior to such consultation. Unless an amendment is urgently
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required, ECRA will not amend the Distribution Code until all affected
Users have been given a reasonable opportunity to make representations
to ECRA concerning the amendment, and those representations have been taken into account.
ECRA will notify all DSP's and all affected Users of any amendment that ECRA makes to the Distribution Code.
DGC6.6 DCRP shall, from time to time or at the behest of ECRA having regard to the recommendations of the Panel, submit a revised Distribution Code
to ECRA for approval.
DGC7: Communications between DSP(s) and Users
DGC7.1 Unless otherwise specified in the Distribution Code the methods of operational communication and data transfer shall be agreed between
DSP(s) and Users from time to time.
DGC8: Emergency Situations
DGC8.1 Users should note that the provisions of the Distribution Code may be suspended, in whole or in part, pursuant to any directions given and/or
orders made by ECRA in emergency situations, pursuant to provisions of the Electricity Law issued by Royal Decree No. M/56.
DGC9: Derogations
DGC9.1 If a User finds that he is, or will be, unable to comply with any provision of the Distribution Code, then he will, without delay report such non-
compliance to DCRP and will, subject to the provisions of DGC9.2 make
such reasonable efforts as are required to remedy such non-compliance
as soon as reasonably practicable.
DGC9.2 Where the non-compliance is
(a) with reference to Plant and/or apparatus connected to the Distribution System and is caused solely or mainly as a result of a revision to the
Distribution Code,
or
(b) with reference to Plant and/or apparatus which is connected, approved to connect, or for which approval to connect to the Distribution System is
being sought,
and the User believes either that it would be unreasonable (including cost and technical considerations) to require it to remedy such non-compliance or that it
should be granted an extended period to remedy such non-compliance it shall
promptly submit to DCRP a request for a derogation from such provision in
accordance with the requirements of DGC9.3 and shall provide DSP(s) with a copy
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of such application.
DGC9.3 A request for derogation from any provision of the Distribution Code shall contain the following:
(a) the issue number and the date of the Distribution Code provision against which the non-compliance or predicted noncompliance was identified;
(b) identification of the Plant and/or apparatus in respect of which a derogation is sought, and if relevant, the nature and extent to which the
non-compliance exists;
(c) identification of the provision with which the User is, or will be, unable to comply;
(d) the reason for the non-compliance; and
(e) the date by which compliance will be achieved (if remedy of the non-compliance is possible) subject to DGC9.2 (b)
A standard Distribution Code Derogation Application form can be obtained through ECRA.
DGC9.4 If DSP(s) finds that they are, or will be, unable to comply with any provision of the Distribution Code, then they shall, subject to the
remaining provisions of DGC9 make such reasonable efforts as are
required to remedy such non-compliance as soon as reasonably
practicable.
DGC9.5 In the case where DSP(s) requests derogation, DSP(s) shall submit the information set out in DGC9.3 to DCRP.
DGC9.6 On receipt of any request for derogation, DCRP shall promptly consider such request and discuss the potential outcomes of such request with
ECRA. Following such discussion, DCRP shall recommend to ECRA such derogation, provided that DCRP considers that the grounds for the
derogation are reasonable.
DCRP will not recommend to ECRA such derogation if
(a) It would, or it is likely that it would, have a material adverse impact on
the security and stability of the Distribution System, or
(b) It would result in ECRA imposing unreasonable costs on the operation
of the Distribution System or Transmission System or on other Users.
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In its consideration of a derogation request by a User, DCRP may contact the relevant User and/or DSP(s) to obtain clarification of the request or to discuss
changes to the request.
Derogation from any provision of the Distribution Code shall contain the
following:
(a) the issue number and the date of the Distribution Code provision against which the derogation applies;
(b) identification of the provision with which the derogation applies;
(c) identification of the Plant and/or apparatus in respect of which a derogation
applies, and, if relevant, the nature and extent to which the derogation applies
including alternate compliance provision;
(d) the reason for the non-compliance requiring derogation; and
(e) the date by which the derogation ends if compliance will be achieved, or by which such derogation expires.
DGC9.7 To the extent of any derogation granted in accordance with this
DGC9, DSP(s) and/or the User (as the case may be) shall be relieved from its
obligation to comply with the applicable provision of the Distribution Code
and shall not be liable for failure to so comply but shall comply with any
alternate provision as set forth in the derogation. Should a derogation not be
granted, then the User will be required to comply with the applicable provision
of the Distribution Code and will be liable for failure to so comply.
DGC9.8 DCRP shall
(a) keep a register of all derogations which have been granted, identifying
the name of the person in respect of whom the derogation has been
granted, the relevant provision of the Distribution Code and the period
of the derogation, and
(b) on request from any User, provide a copy of such register of
derogations to such User.
DGC9.9 Where a material change in circumstance has occurred, a review of any
existing derogations, and any derogations under consideration, may be
initiated by DCRP at the request of ECRA, DSP(s), or Users.
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DGC10: Confidentiality
DGC10.1 The Distribution Code contains procedures under which the DSP(s) will receive
information from Users relating to the intentions of such Users. The DSP shall
not, except in pursuance of specific requirements of the Distribution Code,
disclose such information to any User or other person without the prior written
consent of the provider of the information, subject to the requirements of the
Distribution License.
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DGC11: Force Majeure
DGC11.1 If a DSP or User would breach the terms of the Distribution Code due to an
event outside the reasonable control of the DSP or User (a “Force Majeure
Event”), then those obligations under the Distribution Code that are
affected by the Force Majeure Event are suspended as long as the Force
Majeure Event continues.
DGC11.2 The DSP or the User must give the other party prompt notice of the Force
Majeure Event including full details, an estimate of likely duration, the
obligations affected by it and the steps taken to remove overcome or mitigate its effects.
DGC12: Disputes and Dispute Resolution Procedure
DGC12.1 any dispute that arises from time to time regarding how the Distribution
Code is being administered and interpreted shall be resolved following the
Dispute Resolution Procedure as set out in DGC12.2.
DGC12.2 The Distribution Code Dispute Resolution Process shall be in accordance with complaints handling procedure submitted by DSP under Implementing Regulations (Article 29).
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PART 3: PLANNING
Contents
DPC 1 Introduction
DPC2 Design Standards
DPC3 Transfer of Planning Data
DPC1: Introduction
DPC1.1 Part 3: Planning specifies the technical and design criteria and the procedures
to be complied with by DSP(s) in the planning and development of the
Distribution System. It also applies to Users in the planning and development
of their installations in so far as they affect the Distribution System.
DPC1.2 The Users‟ requirements may necessitate the reinforcement of, or an extension
to, the Distribution System and for reinforcement of, or extension to, the
relevant Transmission/Distribution interface capacity, such work being
identified by DSP(s) or TSP as appropriate.
DPC1.3 The time required for the planning and development of the Distribution
System and any consequential requirement of the interface with the
Transmission System, will depend on the type and extent of the necessary
reinforcement and/or extension work, the time required for obtaining planning
permission and right of way including any associated hearings, and the degree
of complexity in undertaking the new work while maintaining satisfactory
security and quality of supply.
DPC1.4 Reference is made in Part 3 to DSP(s) supplying information or advice to
Users. For avoidance of doubt, unless the context otherwise requires, such
information or advice shall be provided by DSP(s) as soon as practical
following a request by the User (whether during the application for connection
process or otherwise).
DPC2: Design Standards
DPC2.1 Frequency
The Frequency of supply is outside the control of DSP(s) however the standard
Frequency range is as follows:
The Transmission System Frequency is nominally 60Hz and shall normally be controlled within the limits of 59.9Hz to 60.1Hz.
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The system Frequency could rise to 62.5 Hz or fall to 57.0 Hz in exceptional
circumstances. Design of Generator’s Plant and apparatus must enable
operation of that Plant and apparatus within that range in accordance with the
following:
Below nominal
Frequency (Hz)
Above nominal
Frequency (Hz)
Operation
Requirement
58.8 - 60.0 60.0- 60.5 continuous
57.5 - 58.7 60.6 - 61.5 For period of 30
minutes
57.0 - 57.4 61.6 - 62.5 For period of 30
seconds
Users should ensure their equipment is designed or protected for these
exceptional circumstances.
DPC2.2 Voltages
The voltages listed in Table DPC2.1 shall be used as standard service voltages
at the interfaces with power Customers. The service voltage shall be
maintained within the range defined by the indicated lowest and highest
values, under steady state and normal system conditions and over the full
loading range of the system.
Where two voltages are listed e.g. 220/127V the lower value refers to the phase to neutral voltages. All other values are phase-to-phase voltages. Existing, but non-standard, voltages are listed in Table DPC2.2.
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Nominal Voltage
Lowest Voltage
Highest Voltage
220/127V 209/120V 231/134V
380/220V 360/209V 400/231V
400/230V 380/218.5V 420/241.5V
13.8KV 13.1KV 14.5KV
33KV 31.4KV 34.7KV
69KV 65.5KV 72.5KV
Table DPC2.1 : Standard Service Voltages
Note: * 220/127 V system will be obsolete within 25 years.
**The change of the old system 127/220 V with the new system
230/400 V in ongoing projects and facilities will be completed within 25
years as per the Council of Minister No. 324 dated 20/9/1430AH.
The service voltage shall be maintained [under steady state conditions] within
the range defined by the indicated lowest and highest values, under steady state
and normal system conditions and over the full loading range of the system.
Nominal Voltage
Lowest Voltage
Highest Voltage
11KV 10.45KV 11.55KV
34.5KV 32.78KV 36.23KV
Table DPC 2.2 : Existing, But Non-Standard, Voltages
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DPC2.3 Harmonics
The level of Harmonics in the power system shall comply with the limits set
out in Table DPC2.3, on a continuous basis.
Table DPC2.3: Maximum Continuous Harmonic Levels
Note:
N is the harmonic order, or multiple of the fundamental Frequency. Voltage distortion is
expressed as a percentage of the fundamental voltage.
The indicated values refer to maximum continuous levels.
DPC2.4 Power Factor
a) Each Customer with demand shall maintain a Power Factor of not less
than 0.85 lagging at the interface with DSP(s). No Customer shall present
a leading Power Factor to the DSP(s) system unless resulting from
operation of its Embedded Generation as agreed or instructed by the DSP.
By [date] Customers must improve their Demand related Power Factor to
not less than 0.90 lagging and by [date] to a minimum of 0.95 lagging.
The DSP may require proof that this has been achieved. This
improvement in lagging Power Factor is to enable the DSP(s) to comply
with obligations set down in the SAGC. Customers with both Embedded
generation and Demand shall not exceed any Power Factor or Reactive
Power limits set down in their Connection Agreement or notified to them
by the DSP further to the performance conditions of this Distribution
Nominal Voltage Total Harmonics Voltage
Distortion%
Individual Harmonics Voltage Distortion
Odd Even
230-400V 5.0 4.0 for N<14 2.0
1.5 for N>14
127-380 5.0 4.0 for N<14 2.0
1.5 for N>14
13.8KV 4.0 3.0 1.75
33KV 3.0 2.0 1.0
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Code.
b) Any Customer , classified as Industrial, Government and Commercial,
connected to the Distribution Network , having contracted load more than
1.0 MVA should exercise all precautionary measures to maintain 0.85
power factor. For such customers, the minimum allowable Power Factor
will be 0.9 after five years (from the date of 21-10-1433), and 0.95 after
ten years from the said date. In case of any deviation from this criteria an
additional tariff will be applied for reactive power consumption upon
such customer as per terms and conditions given in the decree # 2/27/23
dated 21-10-1433..
DPC2.5 Phase Unbalance
Under normal system conditions the three phase voltages shall be balanced at
MV, and higher voltages in the system, such that the negative phase sequence
voltage does not exceed 2% of the positive phase sequence voltage.
Customers with a dedicated transformer or those supplied at 13.8kV or a
higher voltage shall balance their loads, such that the load phase unbalance at
the Customer interface meets the above criterion. All other Customers shall
balance their loads over the three phases to the greatest degree possible. The
DSP(s) shall then balance these loads, within the power system, to meet the
above criterion.
DPC2.6 Voltage Stability
Voltage Dips
For non-repetitive voltage variation, or voltage dips, such as those associated
with motor-starting, welding equipment or power system switching, the
voltage variation shall not exceed 7% of the fundamental nominal voltage
under normal circumstances. Such variations shall not occur more frequently
than 3 times per day.
Application
No Customer shall connect equipment to the power system, which causes
voltage fluctuation at the Customer interface in excess of these requirements. The DSP(s) shall ensure that the power supply, at each Customer’s interface,
conforms to these requirements.
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DPC2.7 Earthing Requirements
1. Bonding of LV Neutral and MV Grounds.
LV neutral ground and any grounds associated with MV equipment / system
(e.g. MV metal work, cable screen, etc.) shall always be kept bonded.
2. Recommended ground resistance limits for different installations should be
as under:
System Ground 5 ohms
All Distribution Sub-
station 5 ohms
Surge Arresters 5 ohms
LV Distribution
Panel 10 ohms
3. LV metering Installations
It shall be essential for the Customer to provide grounding at his interface.
The Customer shall bring the ground wire to the grounding terminals
provided in the meter box. The ground wire of the Customer shall be
connected to the ground terminal inside the meter box. The ground terminal
shall be short linked with the neutral.
For more than one KWH -meters at one location, four KWH-meters shall be
connected to one ground rod. In case of additional KWH-meters at the
premises, additional ground rods shall be provided.
4. Ground mounted MV equipment
The equipment covered are RMU, MV switches etc, when separated from Transformer and Bulk Customer Indoor Switchgear. All metal work shall be bonded together and to the substation metalwork grounding system. Each continuous piece of metal that could form part of the path of a ground fault current shall be bonded to its neighbors so that continuity of grounding circuit does not depend on mechanical connections between components.
Licensed Distributors shall advise on the method of Earthing of the
Distribution System, for example, whether it is connected solidly to Earth or
through impedance. The specification of associated apparatus and Plant of the
Distribution System User shall meet the voltages that will be imposed on the
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apparatus and Plant as a result of the method of Earthing.
Notwithstanding the above, the DSP(s) shall provide a complete separate Earthing
code to define the Earthing requirements for safe use of the system. This code shall
constitute an integral part of the Distribution code.
Distribution System Users shall take precautions to limit the occurrence and effects of circulating currents in respect of the neutral points connected with Earth where there is more than one source of electricity.
DPC2.8 Security of Supply
DPC2.8.1 The Security Standard for the Distribution System is as follows:
Security of supply (also known as continuity) is evaluated in terms of five
indices, as follows:
(1) System Average Interruption Frequency Index (SAIFI)
SAIFI = Total Customer Interruptions
Total Connected Customers
- Measured in interruptions per 100 connected Customer
Years
(2) System Average Interruption Duration Index (SAIDI)
SAIDI =Total Customer Hours of Interruptions
Total Connected Customers
- Measured in Customer hours of interruptions per
connected Customer year
(3) Customer Average Interruption Duration Index (CAIDI)
CAIDI = SAIDI
SAIFI
- Measured in hours of interruption
(4) Index of Reliability (IR)”Average system availability Index” (ASAI)
IR (ASAI)= 8760 Hours/Year - SAIDI x 100 8760 Hours/Year
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(Expressed as a percentage)
(5) Momentary Average Interruption Frequency Index (MAIFI)
MAIFI = Total number of customer interruptions less than five minutes
Total number of customers served
The DSP(s) will have to comply with the security of supply standards limits as published by ECRA from time to time.
DPC2.8.2 DSP(s) shall use reasonable endeavors to maintain a supply from the
system. This cannot be ensured, since faults, planned maintenance and new
works outages and other circumstances outside DSP(s) control can cause
interruptions. On such occasions, DSP(s) shall use reasonable endeavors to
restore the supply or connection as soon as practicable but shall be under no
liability for any direct or indirect damage or associated loss incurred by the
User.
DPC2.8.3 Restoration times for different outage types are as follows:
Fault Outages: DSP(s) shall endeavor to restore access to the system as soon as
practically possible taking into consideration the KPI set values
approved by ECRA
Planned Outages: DSP(s) shall give five days’ notice to relevant Users of planned
supply interruptions. In some situations , to facilitate emergency
repairs or local outages affecting a small number of Customers,
shorter notice may be given.
Supply Curtailments: In some circumstances, it may be necessary to request Customers
to reduce load or to use standby supplies where appropriate. In these
situations DSP(s) shall endeavor to maintain access to the System.
In extreme cases where this may not be possible DSP(s) shall
endeavor to provide two days‟ notice to the Users.
Load Shedding: In extreme situations there may be generation shortages and load
shedding may be required. In these circumstances DSP(s) shall
notify Customers if possible but as this is an emergency situation it
may not be possible to do so. DSP(s) shall prepare a Load Shedding
Criterion and submit it to ECRA for approval. This criterion shall
detail the methodology for selection of load(s) to be shed.
DPC2.8.4 DSP(s) may disconnect Users under certain circumstances. These
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circumstances shall include:
(a) Where the Customer’s installation or use of electricity is such as to interfere
with the satisfactory operation of the Distribution or Transmission system or
to cause disturbance to other Customers.
(b) Where DSP(s) considers that the Customer’s installation is in a dangerous
condition.
(c) Where alterations, repairs, renewal or maintenance of the Distribution System
or DSP(s) assets or means of connection require the de-energisation of the
Connection Point.
(d) Where a Customer extends supply for use by another party whom DSP(s)
considers to be a separate Customer.
(e) In any other circumstances in which discretion is necessary or appropriate to
enable DSP(s) to comply with the Distribution Code and/or to operate the
Distribution System in accordance with Good Industry Practice or is required
by any law, direction, rule or regulation having the force of law.
DPC3: Transfer of Planning Data
DPC3.1 Planning information to be provided by Users.
DPC3.1.1 Users of the Distribution System shall provide sufficient planning data/
information as can reasonably be expected to be made available, when
requested by DSP(s) from time to time to enable DSP(s) to comply with the
requirements under its Distribution License.
DPC3.1.2 Users of the Distribution System shall provide planning data for specific
future time periods updated annually as necessary and including projected
Demand requirements, anticipated changes in maximum Demand, or
generating capacity, as appropriate. The data and timescales over which the
data is required are given in Distribution Operating Code 1 (DOC1).
DPC3.1.3 In addition to periodic updates of planning information, a User shall give
adequate notice of any significant change to their system or operating regime
to enable DSP(s) to prepare its development plans and implement any
necessary system modifications. In the event of unplanned changes in a User’s
System or operating regime a User shall notify DSP(s) as soon as is
practically possible to ensure any necessary measures can be implemented.
DPC3.1.4 Users shall also provide details of reactive compensation Plant directly or
indirectly connected to the Distribution System other than at Low Voltage,
including its rating and operational control.
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DPC3.1.5 Users may be required to provide DSP(s) with detailed data relating to the
interface between their System and that of the Distribution System covering
circuit parameters, switchgear and Protection arrangements of equipment
directly connected to or affecting the Distribution System to enable DSP(s) to
assess any implications associated with these points of connection.
DPC3.2 Information to be exchanged.
DPC3.2.1 On the request of a User, DSP(s) shall provide such information as may be
reasonably required on the design and other characteristics of the
Distribution System.
DPC3.2.2 Where DSP(s) proposes to make certain modifications to its system or
where it has received information from a User under DPC3.1 above, which
may impact on other User installations then DSP(s) will notify Users of the
proposal, subject to any constraint of confidentiality or timing.
DPC3.2.3 DSP(s) shall provide information on request to Users regarding the local
network conditions to enable them to determine their Protection
requirements.
DPC3.2.4 Where the User’s installation is connected to the bus bars of the Distribution
System, sufficient details may need to be exchanged with respect to User/
DSP(s) Ownership Boundary to enable an assessment to be made of transient
over voltage effects. The request for information may be initiated by either
DSP(s) or the User.
DPC3.2.5 Information may be exchanged between DSP(s) and the User on fault in feed levels at the feeding bus bar or point of connection to the Distribution System as appropriate, in the form of
- Three phase and single phase to earth short circuit in feed.
- The X/R ratio under three phase fault conditions.
DPC3.2.6 Information shall be exchanged between DSP(s) and User on Demand
Transfer Capability where the same Demand can be supplied from alternate
User points of supply. This shall include the proportion of Demand normally
fed from each point of supply and the arrangements (manual or automatic) for
transfer under planned/fault outage conditions.
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DPC3.3 Planning Studies
DPC3.3.1 In order to facilitate connections to the Distribution System DSP(s) shall prepare on request a study showing the implications of a connection at a particular point on the system.
DPC3.3.2 Under the terms of the Distribution Licence a reasonable charge (as submitted by DSP(s) and approved by ECRA) may be levied by DSP(s) for the planning study.
DPC3.3.3 A User or potential Users shall provide DSP(s) with information regarding the proposed facility including load details, interface arrangements, proposed Connection Point and import/export requirements.
DPC3.3.4 The studies shall normally be prepared within 28 days after the date of receipt
of the information or the agreement of the person making the request to pay
the cost of the study, whichever is the longer. In the case of Generators and
Major Customers seeking connection, depending on the nature and
complexity of the request, this period may extend up to 100 days or a further
28 days from the receipt of planning information from the TSP whichever is
the greater.
DPC3.3.5 Details of the procedures for application for connection to the Distribution
System are contained in [CUSTOMER SERIVICE MANUAL] as prepared
by DSP(s) and approved by ECRA.
DPC3.3.6 Where such information is available DSP(s) shall provide on request a
statement of present and future circuit capacities, forecast power flows and
loadings on part or parts of the Distribution System specified in the request
and shall include Fault Levels at each Distribution node covered by the request.
DSP(s) may levy a charge for the provision of this statement as approved by
ECRA on account of the reasonable costs incurred by DSP(s) in preparing
this statement. The statement shall be prepared within 28 days after the date of
receipt of the information or the agreement of the person making the request
to pay the cost of the statement, whichever is the longer. In the case of
Generators and Major Customers seeking connection this period may extend
up to 100 days depending on the nature and complexity of the request.
DPC3.3.7 The dates given in this DPC3.3 are target dates only and do not constitute a
legal commitment. DSP(s) shall however use reasonable endeavors to abide
by them.
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PART 4: CONNECTION CONDITIONS
Contents
DCC 1 Introduction
DCC2 Information Required for Connection
DCC3 Connection Arrangements
DCC4 Technical Requirements for Connections
DCC5 Metering and Telemetry
DCC6 Generator Requirements
DCC1: Introduction
DCC1.1 It is necessary to require certain minimum technical, design and operational
criteria to be met by User’s Plant and apparatus in order to maintain, insofar as
is permitted by Good Industry Practice, stable and secure operation of the
Distribution System for the benefit of all Users and for the Protection of the
Distribution System and User’s. Plant and apparatus directly connected to the
Distribution System.
DCC1.2 The Connection Conditions define the minimum standards for the method of
connection to the Distribution System and the technical, design and
operational standards to which Users connecting to the Distribution System
shall comply.
DCC1.3 The Connection Conditions specify the technical arrangements required at the
Ownership Boundary between the Distribution System and the installation of
the User and are applicable to all voltage levels covered by the Distribution
Code.
DCC1.4 The Connection Conditions specify the information to be provided by Users
to ensure that adequate provision can be made by DSP(s) for new connections
or increases in existing load. It also applies to Generators who operate in
parallel with the Distribution System, where a connection is required.
Prospective Users shall provide to DSP(s) in good time all the details set out
in this section.
DCC1.5 In conjunction with the Connection Conditions, there are Connection
Agreements, which are bilateral agreements between DSP(s) and each User,
and which contain the detail specific to each User’s connection to and use of
the Distribution System. The Connection Agreement requires the User and
DSP(s) to comply with the terms of the Distribution Code.
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DCC2: Information Required for Connection
DCC2.1 For connections at Low Voltage it is possible in most cases to assess whether
a proposed connection is acceptable, and to determine the necessary supply
arrangements, from analysis of the following data:
(a) maximum kVA requirements.
(b) if applicable, type and electrical loading of equipment to be connected,
such as number and size of motors, cookers, showers, air conditioning,
space and water electrical heating loads and nature of Disturbing
Loads e.g. welding equipment.
(c) if applicable, type and electrical rating of Embedded generating
equipment to be connected, such as number, size of PV inverter, CHP
generator;
(d) if applicable, the expected performance of Embedded generating
equipment to be connected during and immediately after faults on the
relevant part of the LV System;
(e) if applicable, typical daily and seasonal load and generation patterns;
(f) single-line diagram of the installation
(g) the date when connection is required; and
(d) a plan showing the are covered by the installation and the location.
If a preliminary examination of this data indicates that more detailed information is reasonably required then it shall be provided to DSP(s) upon request.
DCC2.2 Information Requirements and timeframes for quotation and connection are
provided in [Customer service manual] as prepared by DSP(s) and approved
by ECRA. Copies of this manual are available on request from DSP(s).
DCC2.3 For connections at distribution level the provisions of DCC2.1 also apply.
Additionally, the following information is required, unless provision of part or
all the data is excused by the DSP:
(a) All Types of Demand
(i) Maximum Active Power requirements.
(ii) Maximum and Minimum Reactive Power requirements.
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(iii) Type of load and control arrangements (e.g. type of motor
start, controlled rectifier or large motor drives).
(iv) Maximum loading on each phase.
(v) Maximum harmonic currents that may be imposed on the
Distribution System.
(vi) Details of cyclic load variations or fluctuating loads (as
below).
(b) All types of generation
(i) The type of Embedded Generation proposed (e.g.
Asynchronous generator - solar PV and inverter type /size and
overload capacity, wind powered – DFIG, FSIG or fully
converted and any special arrangements for network support;
Synchronous generator – fuel type).
(ii) The maximum (and, if appropriate minimum stable) MW
Output of the Generating Unit.
(iii) The kVAr or MVAr capability of the Generating Unit.
(iv) Where the Generating Unit is composed of separate units, a
diagram showing how these are arranged and protected.
(v) Information regarding the control arrangements:
arrangements for Frequency control / response;
arrangements for Voltage / Reactive Power / Power Factor
control.
(vi) If appropriate, the starting current and Power Factor during
starting and after faults.
(vii) Maximum phase-imbalance and harmonic currents which may
be imposed on the Distribution System during starting and
normal operation.
(b) Disturbing Loads
Comprehensive schedule of installed new equipment including details
of Disturbing Loads. These are loads which have the potential to
introduce Harmonics, Flicker or unbalance to the system. This could
adversely affect the supply quality to other Customers. Disturbing
loads could be non-linear loads, power converters/regulators and loads
with a widely fluctuating Demand. The type of load information
required for motive power loads, welding equipment, harmonic
producing/ non-linear loads and generating equipment can be obtained
from DSP(s) on request.
In the case of compensating equipment associated with Disturbing Loads, details and mode of operation to be provided so as to ensure
compliance with emission limits specified in DCC4.8.3.
(c) Fluctuating Loads
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Duty cycle, including details of cyclic or other variation of Active
Power and Reactive Power, in particular:
(i) the rates of change of Active Power and Reactive Power, both
increasing and decreasing;
(ii) the shortest repetitive time interval between fluctuations in
Active Power and Reactive Power; and
(iii) the magnitude of the largest step changes in Active Power and
Reactive Power, both increasing and decreasing.
DCC2.4 In some cases, more detailed information may be required to permit a full
assessment of the effect of the User’s load on the Distribution System. Such
information may include an indication of the pattern of buildup of load and a
proposed Commissioning programme. This information shall be specifically
requested by DSP(s) when necessary and shall be provided by the User within
a reasonable time.
DCC2.5 Users shall contact DSP(s) in advance if it is proposed to make any
significant change to the connection, electric lines or electric equipment,
install or operate any generating equipment or do anything else that could
affect the Distribution System or require alterations to connection.
DCC2.6 Users shall provide to DSP(s) any information reasonably required by
DSP(s) about the nature, or use by the User, of electrical equipment on the
User’s premises.
DCC3: Connection Arrangements
DCC3.1 Connection Voltage
DCC3.1.1 During the application for connection process DSP(s) shall, in consultation
with the User, specify the voltage level to which a User will be connected in
accordance with normal practice for the type of load to be supplied and
network characteristics.
DCC3.1.2 Generally, the voltage level will be the minimum nominal voltage in
standard use on the System, assessed against
(a) satisfactory operation of the installation,
(b) isolation of disturbance from other Customers,
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(c) lifecycle costs, and
(d) cost of connection
DCC3.1.3 DSP(s) may, on occasion, specify higher connection voltage in order to avoid
potential disturbances caused by the User’s apparatus to other Users of the
Distribution System or for other technical reasons or may agree alternative
methods for minimizing the effects of Disturbing Loads.
DCC3.2 Information Provided by DSP(s)
Based on the information provided by the User for a connection to the Distribution System, DSP(s) shall prepare a statement containing as many of
the following elements as are necessary for, or relevant to, the proposed
installation:
a) nominal voltage at which connection will be made;
(b) method of connection, extension and/or reinforcement details;
(c) the normal impedance to source at the point of connection;
(d) method of Earthing;
(e) maximum IMPORTED CAPACITY;
(f) individual Customer limits relating to
(i) Harmonic Distortion
(ii) Flicker
(iii) Phase Unbalance
(g) expected lead time of providing connection (following formal
acceptance of terms for supply); and
(h) Cost of connection.
DCC3.3 Ownership Boundaries
DCC3.3.1 The point or points at which supply is given or taken between the Distribution
System and Use r’s installation shall be agreed between DSP(s) and the User as
stipulated in the Connection Agreement between DSP(s) and the User.
DCC3.3.2 For LV supplies DSP(s) responsibility extends up to the Customer’s Connection
Point, which is normally at DSP(s) main Circuit Breaker as further specified in
the Connection Agreement between DSP(s) and the User.
DCC3.3.3 For Medium Voltage supplies the ownership boundaries shall be subject to
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specific agreement between the parties in each case. Changes in the
boundary arrangements proposed by either party shall be agreed in advance.
DCC3.3.4 All equipment at the Ownership Boundary shall meet the design
principles contained in DPC2 and DCC3. Connections for entry to and exit from the Distribution System shall incorporate a means of disconnection of the User’s installation by DSP(s).
DCC4: Technical Requirements for Connections
DCC4.1 Connection Standards
DCC4.1.1 A connection to the Distribution System may be by means of an overhead line, an
underground cable or a combination of both as detailed in the Connection
Agreement between DSP(s) and the User. The network configuration at the
Connection Point may take a number of forms suitable to the nature of the load
and network arrangements.
DCC4.1.2 From the time this code issued all equipment in an installation connected to
the Distribution System shall be designed, manufactured, tested and installed
in accordance with all applicable statutory obligations and shall conform to
relevant SASO standards or equivalent IEC standards with the latest version
at the time of the connection of the installation to the Distribution System.
a) For other equipment required to be connected to the Distribution System in an
existing or previous installation, installed before issuing this code, that are
comply with other different standards such as ANSI, ASTM, IEEE, UL, EN,
DIN, BS, … etc , those relevant standards can be applied for further period, in
condition that they shall have at least an equivalent degree of conformity
specified in SASO or equivalent IEC standards, and shall satisfy the service
conditions of Kingdom of Saudi Arabia. However the acceptability of any
alternative standards or codes is at the discretion of the DSP(s).
b) In case of any conflict between SASO standards and the other standards (or
codes), SASO or equivalent IEC standards shall be applied.
DCC4.1.3 If there is no relevant SASO standards or equivalent IEC standards available,
and/ or if DSP(s) considers it necessary, DSP(s) may notify Users that
supplemental specifications and/or standards shall be complied with, in which
case User Plant and apparatus shall so comply.
DCC4.1.4 All equipment in an installation connected to the Distribution System shall be
suitable for use at the operating Frequency of the Distribution System and at
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the voltage and short-circuit rating of the Distribution System as shown in
Tables DPC2.1 and DCC4.1 at the Connection Point. DSP(s) may require
certification that the equipment has been designed and installed in a
satisfactory manner. DSP(s) may also seek evidence that the equipment has
been tested for conformity with the standards.
DCC4.1.5 For Users connected at Low Voltage, installations shall comply with the
standards as in DCC4.1.2 and DCC4.1.3. Users complying with these rules and
regulations shall be deemed to comply with the requirements of the
Distribution Code as regards design and safety. DSP(s) may seek evidence
that the equipment has been tested for compliance with standards.
DCC4.1.6 Before connecting any User to the Distribution System it will be necessary for
DSP(s) to be reasonably satisfied that the User’s System complies with the appropriate requirements of the Distribution Code. An itemized statement of
compliance will be requested from each User prior to connection.
For all Embedded Generating Units, an equipment certificate and detailed data prepared by the equipment supplier or validated by a competent person shall be
additionally provided for compliance verification.
For Embedded Generating Units with a Registered Capacity of 2MW or greater,
the DSP has the right to carry out, or to witness certain testing to ensure
compliance verification. The DSP will indicate, in a timely manner, any tests so required, or tests to be witnessed by the DSP’s staff or appointed experts.
For Power Park Modules, it may not be possible initially to test certain requirements of the facility e.g. LVRT. Where the Power Park Module is
otherwise compliant, it shall receive an Temporary Connection Certificate. The
facility shall be equipped with an Event Recorder to a specification set down by the DSP and the performance shall be assessed for a period of nine months, after
which time, unless the Power Park Module fails to achieve the performance
standard set down in this Code, a Final Connection Certificate will be issued.
DCC4.2 Protection and Control Requirements
DCC4.2.1 Users shall ensure that faults in the User’s Plant and apparatus do not
unreasonably cause disturbances to the Distribution System or to other Users.
Without limiting this obligation, a User shall, prior to connection of the User’s
installation to the Distribution System, install the Protection equipment
specified in DCC4.2.4.
DCC4.2.2 Unless provided against, faults on the Distribution System can cause damage
to User’s Plant and apparatus through, for example, loss of a phase, over
voltage, or under voltage. The User shall take account of the established
practices of the particular network to which a connection is to be made, and
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ensure that Protection installed is compatible with that used by DSP(s). The
adequacy of the Protection installed by the User is the User’s responsibility.
DCC4.2.3 The User’s Protection arrangements at the Ownership Boundary, including
types of Equipment and Protection settings, shall be compatible with existing
system conditions and the Distribution System Protection practice as specified
by DSP(s) at the time of application. In particular
(a) the maximum clearance times (from fault current inception to arc
extinction) shall be within the limits established by DSP(s) in
accordance with Protection and equipment short circuit rating policy
adopted for the Distribution System;
(b) in connecting to the Distribution System the User should be aware that
fast and slow-speed automatic re-closing is a feature of Power System
operation. This is characterized by sudden de/re-energization of the
power supply. Dead times are typically 0.3s, 1s and 10s at Medium
Voltage and 3s and 60s on 38kV systems; and
(c) Users should also be aware that disconnection of one or two phases
only of a three phase system may be effected by Distribution
Protection arrangements for certain types of faults.
DCC4.2.4 The minimum Protection required for a User installation connected to the
Distribution System will vary according to type, size, and method of
connection (loop/tail/tee) and Earthing of the User System. It is anticipated
that a new connection may require all or some of the following Protection
facilities:
(a) three phase over current;
(b) earth fault Protection (suited to the local supply system);
(c) distance;
(d) inter-tripping; and
(e) Others.
DCC4.2.5 Where interface Circuit Breakers are used they shall be fitted with relays of a
type acceptable to DSP(s). These relays shall have three phases over current
elements and one earth fault element and shall have time-current
characteristics complying with standard types A, S and C of IEC 244.
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Maximum permissible relay settings at the ownership boundary, necessary to
provide selectivity any time in the future will be provided by DSP(s).
Distribution Protection aims to minimize the impact of faults including voltage
dip duration and must not be adversely affected by Customer’s Protection
limitations.
(a) In order to ensure satisfactory operation of the Distribution System,
Protection systems, operating times, discrimination, and sensitivity at
the ownership boundary shall be agreed between DSP(s) and the User
during the application for connection process, and may be reviewed
from time to time by DSP(s).
(b) In order to provide against the failure of a Circuit Breaker, or
equipment having a similar function, to operate correctly by
interrupting fault current on the system, back-up Protection shall
normally be provided by operation of other Circuit Breakers or
equipment having a similar function.
(c) Unless DSP(s) advises otherwise, the use of Protection and associated
equipment to limit the fault current in feed from the User’s system to
the Distribution System is not acceptable if the failure of that Protection
and associated equipment to operate as intended in the event of a fault
could cause equipment owned by DSP(s) to operate outside its short-
circuit rating.
DCC4.2.6 Protection relays shall be commissioned on site by the User who shall ensure
that the settings are below the maximum permitted levels. In certain cases
DSP(s) may wish to witness these tests and it shall be the responsibility of the
User to ensure that sufficient notice is given to DSP(s) in such cases. Users
shall ensure that the Protection settings remain below the maximum permitted
levels. This may require regular testing of the relays.
DCC4.3 Earthing
DCC4.3.1 Earthing of the part of the User’s installation that is connected to the
Distribution System shall comply with the requirements of DPC2.7.
DCC4.3.2 The arrangements for connecting the User’s installation with earth shall be
designed to comply with relevant international and national standards.
DCC4.3.3 The method of Earthing the Distribution System whether, for example, it is
connected to earth solidly or through impedance, shall be advised by DSP(s).
The specification of associated equipment shall be appropriate to the voltages
that will be imposed on the equipment as a result of the method of Earthing.
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DCC4.3.4 Where there is more than one source of energy, Users shall take precautions to
limit the occurrence and effects of circulating currents in respect of neutral
points connected with earth.
DCC4.4 Voltage Regulation and Control
DCC4.4.1 Extensions or connections to the Distribution System shall be designed so that
they do not hinder the necessary control of voltage on the Distribution System.
Information on the voltage regulation and control arrangements shall be made
available by DSP(s) if requested by the User.
DCC4.5 Short-Circuit Levels
DCC4.5.1 The short circuit rating of User’s equipment at the Connection Point shall not
be less than the design Fault Level of the Distribution System as shown in
Table-DCC4.1 below. DSP(s) shall take into account the contribution to Fault
Level of the User’s connected system and apparatus in the design of its system.
Table DCC4.1: Short Circuit Ratings
DCC4.6 Insulation Levels
DCC4.6.1 The basic insulation level (BIL) and power Frequency withstand voltage
for medium system voltages are as tabulated below:
Connection Voltage
Size of Load (KVA)
Short Circuit Level RMS Symmetrical (KA)
220/127V ≤152 21
>152 45
380/220V ≤500 20
>500 30
400/230V ≤500 20
>500 30
13.8KV All 21
33KV All
25
69KV All
31.5
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Note: The dry/wet power frequency withstand voltages are: Dry for one (1) minute
and wet for (10) seconds.
The basic insulation level (BIL) and power Frequency withstand voltage for low
system voltages are as tabulated below:
DCC4.7 Capacitive and Inductive Effects
DCC4.7.1 The User shall, when applying to make a connection, provide DSP(s) with
information as detailed in DPC3. Details shall be required of any capacitor
banks and reactors connected at Medium Voltage, which could affect the
Distribution System and which it is proposed to connect if agreed with DSP(s).
When requested by DSP(s), details shall also be provided of distributed circuit
capacitance and inductance. Sufficient detail is required for the following:
System Nominal Voltage
(KV RMS)
Altitude Above Mean Sea Level
up to 1000 meters above 1000 meters
69
BIL (KV peak) 325 350
Power Frequency Withstand Voltage (KV RMS)
140 160
33/34.5
BIL (KV peak) 170 200
Power Frequency Withstand Voltage (KV RMS)
70 80/75
11/13.8
BIL (KV peak) 95 110
Power Frequency Withstand Voltage (KV RMS)
38 50/45
System Nominal
Voltage (V)
BIL (KV Peak) Power Frequency Withstand
Voltage (KV RMS)
277/480
6
Equipment Panel wiring
230/400
3 2 220/380
127/220
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(a) to verify that controlling equipment of the Distribution System is
suitably rated;
(b) to show that the performance of the Distribution System will not be
impaired.
DCC4.8 Voltage Disturbances
DCC4.8.1 Users of the Distribution System must not generate voltage disturbances at a
level that would affect other Users. Users should in their own interest select
equipment that is capable of functioning satisfactorily in the presence of
disturbances at the levels that can be expected on the Distribution System as
stated in the DPC
DCC4.8.2 It is a condition of connection that equipment connected directly or indirectly
to the Distribution System shall conform to the requirements of the
Distribution Code as amended from time to time.
DCC4.8.3 Loads and installations shall comply with the emission limits, which are set
out in DPC2.3 (Harmonics), DPC2.4 (Power Factor), DPC2.5 (Phase
Unbalance) and DPC2.6 (Voltage Stability).
Special conditions for Generators are presented in DCC6.
DCC5: Metering and Telemetry
DCC5.1 The User may be required to provide such voltage, current, Frequency, Active
Power and Reactive Power pulses as are considered necessary by DSP(s) to
ensure adequate system monitoring. Details will be specified in the User’s
Connection Agreement.
DCC5.2 Centrally dispatched Generating Units, shall provide signals to the TSP as
required by the Saudi Arabian Grid Code (SAGC).
DCC5.3 If it is agreed between the parties that DSP(s) shall control the switchgear on
the User’s system, DSP(s) shall install the necessary telecontrol outstation.
Notwithstanding the above, it shall be the responsibility of the User to provide
the necessary control interface for the switchgear of the User which is to be
controlled.
DCC5.4 Metering principles applying to certain Users connected to the Distribution
System shall be specified in the User’s Connection Agreement.
DCC5.5 Specific metering arrangements depend on the load type, size and nature of
the installations being connected.
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DCC5.6 Specific Arrangements
DCC5.6.1 The specific arrangements for connection, including substation layout
requirements, User equipment, and Metering are set out clearly in the
Distribution Code and/ or Customer Service Manual as prepared by DSP(s)
and approved by ECRA. Users must comply with the provisions of the
documents relevant to their installations.
DCC6: Embedded Generator Requirements
DCC6.1 Introduction
DCC6.1.1 Distribution Connection Code 6 (DCC6) is applicable to all existing or
prospective Embedded Generators.
DCC6.1.2 In addition to meeting the requirements of DCC6, Embedded Generators shall
also comply with the requirements of the General Conditions, the Planning
Code, the Connection Conditions and other relevant sections of the
Distribution Code. Embedded Generators that are subject to Central Dispatch
shall additionally have to comply with the Saudi Arabian Grid Code (SAGC).
DCC6.1.3 If existing generating Plant does not comply with the standards set down in, or cannot comply (for technical or economic or other reasons) with the
requirements of this section, the Generator shall seek derogation from the
provision from ECRA.
DCC6.1.4 The Generator shall initiate discussions at a sufficiently early stage in design to allow DSP(s) to examine the impact of the Generating Unit(s) on the Distribution System.
DCC6.1.5 DSP(s) may refuse permission for the connection of a Generating Unit at a
point on the Distribution System or require revision to design or technical
parameters of the generation unit, or impose certain restrictions in order to
ensure that security and quality of supply standards as specified in DPC2 are
maintained. In such instances, DSP(s) shall provide sufficient supporting
information to justify the refusal or the required revisions.
DCC6.2 Specific Rules for Embedded Generators
DCC6.2.1 The integrity of the Distribution System and the security and quality of supply
to existing Users shall not fall below standard as a result of Generators
operating in parallel (synchronized) with the Distribution System. Conditions
for operation shall guarantee the safety of
- members of general public
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- personnel
- distribution equipment
Supply quality to other Customers shall not fall below standard as a result of
the presence or operation of Generating Units.
DCC6.2.2 Generating Units connecting to the Distribution System and operating in
parallel with, or which are capable of being operated in parallel with the
Distribution System, shall comply with the relevant DSP(s) document. This
document sets out the conditions with which Generating Units operating in
parallel with the Distribution System shall comply.
DCC6.2.3 Protection conditions and requirements are to protect the Distribution System.
The Generator is responsible for Protection of its personnel and equipment and
the efficient operation of its Generating Unit.
DCC6.2.4 Where a Generating Unit is to be installed on premises, DSP(s) shall be
informed. DSP(s) shall have the right to inspect generating installations to
ensure that the requirements are met. In some cases DSP(s) may require a
demonstration by operation of the Generator. Such demonstrations shall be by
agreement with the User.
DCC6.3 Provision of Information
DCC6.3.1 Information Required from Embedded Generators
Embedded Generators shall provide to DSP(s) information on (a) the
Generating Plant and (b) the proposed interface arrangements between the
Generating Plant and the Distribution System. The information required by
DSP(s) before entering into an agreement to connect any Generating Plant to
the Distribution System is shown below.
(a) Embedded Synchronous Generator Plant Data
(i) Terminal Volts (kV)
(ii) Rated kVA
(iii) Rated kW
(iv) Maximum Active Power sent out (kW), Reactive Power
requirements (kVAR)
(v) Type of Generating Plant - synchronous, asynchronous, etc.
(vi) Type of prime mover
(vii) Anticipated operating regime of generation e.g. Continuous,
intermittent, peak lopping (viii) Fault Level Contribution - a calculation sheet showing the
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fault current available from the Generators due to a metallic three-phase short circuit at the main incoming Circuit Breaker when all the Generators are operating. Account should be taken of any large motors in the installation (ref: IEC909)
(ix) Method of voltage control
(x) Generator transformer details, as applicable; and
(xi) Requirements for Top-up Supplies and/or Standby Supplies
Details will also be required on the following parameters:
(i) Inertia Constant MW sec//MVA (whole machine)
(ii) Stator Resistance
(iii) Direct Axis Reactance Sub-transient Synchronous
(iv) Time Constraints: Direct Axis Sub-transient
(v) Zero Sequence Resistance
Reactance (vi) Negative Sequence Resistance
Reactance
(vii) Generator Transformer
Resistance Reactance MVA Rating
Tap arrangement
Vector Group Earthing
(viii) Plant and Other Equipment
Details:
(a) A comprehensive schedule of installed new equipment
including details of Disturbing Loads is required.
(b) Interface Arrangements
(i) The means of synchronization between DSP(s) and User;
(ii) Details of arrangements for connecting with earth that part of
the Generating Plant directly connected to the Distribution
System;
(iii) The means of connection and disconnection which are to be
employed; and
(iv) Precautions to be taken to ensure the continuance of safe
conditions if any earthed neutral point of the Generators System
operated at High Voltage become disconnected from earth.
(b) Embedded Power Park Module Plant data
(i) Terminal Volts (kV)
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(ii) Number of inverter and for each of them
(iii) Rated kVA
(iv) Rated kW
(v) Maximum Active Power sent out (kW), Reactive Power requirements
(kVAR)
(vi) If applicable, number, surface and orientation of PV panels
(vii) Anticipated operating regime of generation e.g. continuous,
intermittent, peak lopping
(viii) Fault Level Contribution – a calculation sheet showing the fault
current available from the Generators due to a metallic three-phase
short circuit at the main incoming Circuit Breaker when all the
Generators are operating. Account should be taken of any large motors
in the installation (ref: IEC909)
(ix) Method of voltage control
(x) Generator transformer details, as applicable; and
(xi) Requirements for “top-up supplies” and/or “standby supplies”.
DCC6.3.2 The details of information required will vary depending on the type and size
of the Generating Unit or the point at which connection is to be made to the
Distribution System. This information shall be provided by the Generator at
the reasonable request of DSP(s).
DCC6.3.3 DSP(s) will use the information provided to model the Generating Unit to
determine a technically acceptable method of connection. If DSP(s) reasonably
concludes that the nature of the proposed connection or changes to an existing
connection requires more detailed analysis then further information than that
specified in DCC6.3.1 may be required.
DCC6.3.4 Additional information may be required from Embedded Generators with a
Registered Capacity greater than 2MW or connected at a voltage level above
13.8kV
(a) Technical Data
(i) Generating Plant information (impedance per unit on rating)
Type of prime mover
Rated MVA
MW
Type of excitation system
(ii) Automatic Voltage Regulator (AVR):
A block diagram for the model of the AVR system including the
data on the forward and feedback gains, time constants and
voltage control limits.
(iii) Speed Governor and Prime Mover Data:
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A block diagram for the model of the Generating Plant governor;
detailing the governor fly ball, if applicable, and system control
and turbine rating.
(iv) Generator Excitation System.
(b) Capacity and Standby Requirements
(i) Registered Capacity and minimum generation of each
Generating Unit and power station in MW.
(ii) Generating unit and power station auxiliary Demand (Active
Power and Reactive Power) in MW and MVAr, at Registered
Capacity conditions.
(iii) Generating unit and power station auxiliary Demand
(Active and Reactive Power) in MW and MVAR, under
minimum generation conditions.
DCC6.3.5 In normal circumstances the information specified above will enable DSP(s)
to assess the connection requirements. Occasionally additional information
may be required. In such circumstances, the information shall be made
available by the Generator, at the reasonable request of DSP(s).
DCC6.4 Information Provided by DSP(s)
DCC6.4.1 DSP(s) shall prepare a statement as per DCC3.2 for Generators applying for
connection to the Distribution System.
DCC6.4.2 Where Generator paralleling or power export is intended the following
additional information shall be provided including:
(a) Interface Protection settings
(b) Equipment, cabling, switchgear, metering requirements
(a) Substation site and building requirements (dimensions, access,
planning permission, Earthing, lighting and heating). DCC6.5 Technical Requirements
DCC6.5.1 Generating Plant Performance Requirements
(a) All centrally dispatched Generators shall comply with the relevant
sections of the Saudi Arabian Grid Code (SAGC).
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(b) For Embedded Generators not subject to Central Dispatch the
electrical parameters to be achieved at the Generating Unit terminal
shall be specified by DSP(s) with the offer for connection.
(c) Protection associated with Embedded Generating Plant shall be
required to co-ordinate with the Distribution System Protection
regarding:
(i) Clearance times for fault currents.
(ii) Co-ordination with auto recloser requirements. (iii) Protection settings of the controlling Circuit Breaker.
Protection settings shall not be changed without a written agreement
from DSP(s). These Protection requirements are additional to normal
interface Protection requirements of the User.
(d) User’s developments shall meet the following power quality
requirement assessed at the Connection Point:
harmonic distortion shall be not more than permitted in the most
recent approved version of IEC.61000-3-6;
voltage fluctuations shall be within the limits defined in the most
recent approved version of IEC 61000-3-7;
phase unbalance of currents shall not exceed 1%.
Any embedded generator except Stand-by Generators must be designed for
normal operation in the presence of disturbances at the levels that can be
expected, as indicated in the above standards.
The following table applies to harmonic penetration:
Table DCC6.1: Generator Total Harmonic Voltage Distortion Limits
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The Planning Levels for the Total Harmonic Distortion are
THDup to 33kV = 6,5% and THDabove 33kV= 3 %
Additionally, no direct current (DC) shall be injected into the grid.
DCC6.6 Rate of Change of Frequency
All Embedded Synchronous Generating Units must be capable of
withstanding any rate of change of frequency up to 1Hz/s without
disconnection from the network other than when triggered by loss of mains
protection. The rate of change of frequency shall be measured over a sliding
500ms time period.
All Embedded Power Park Modules must be capable of withstanding a rate
of change of frequency in excess of 1Hz/s without disconnection from the
network other than when triggered by loss of mains protection. The rate of
change of frequency shall be measured over a sliding 500ms time period. (For
the avoidance of doubt, this requirement is set so that Power Park Modules
will not trip before Synchronous Generating Units to avoid worsening
frequency stability of the
DCC6.7 Islanding Disconnection
DCC6.7.1 It is conceivable that a part of the Distribution System, to which an Embedded
Generation Unit is connected can, during emergency conditions, become
detached from the Total System. Unless, in the reasonable opinion of the
appropriate DSP, a Power Producer’s Plant can remain connected and
continuously control voltage and frequency within the limits set down in this
Distribution Code, it must detect any condition whereby it is isolated from the
Total System and cease to supply energy to Customers (other than itself) within
500ms. For the avoidance of doubt, unless within an area stablished by
adequate levels of Synchronous generation, Asynchronous Generating Units
must trip within 500ms of becoming islanded.” The DSP will provide advice
on methods/sliding time period of islanding protection which are deemed
acceptable.
DCC6.7.2 If no facilities exist for the subsequent automatic resynchronization with the
rest of the Distribution System then the Embedded Generators shall under
DSP(s) instruction ensure that the Generating Plant is disconnected for
resynchronization.
DCC6.8 Energisation and Ramping of Generating Units
DCC6.8.1 Synchronization of Synchronous Generating Units Unless proven facilities
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exist for the automatic resynchronization of Synchronous Generating Units with the rest of the Distribution System then the Embedded Power Producers shall ensure that their Synchronous Generating Plant is disconnected and, under the DSP’s instruction, prepared for manual resynchronization.
DCC6.8.2 Synchronous Embedded Generating Units shall not be reconnected to the Distribution System before the Total System Frequency is within the range 58.8Hz – 60.05 Hz and before the voltage at the Connection Point has remained within the range 95% - 105% of nominal for a minimum of 60 seconds.
DCC6.8.3 Synchronization of an Embedded Generating Unit with the Distribution System should not create a transient voltage variation of more than 4%.
DCC6.9 Energisation / ramping of Embedded Power Park Modules
DCC6.9.1 Following emergency or planned disconnection from the Distribution System
(other than as part of normal climatic operation of an Embedded Power Park
Module) each Embedded Power Park Module with a Registered Capacity of
2MW or more, and which is not Centrally Dispatchable, shall not be re-
connected to the Distribution System without the prior permission of the DSP,
who may seek permission from the TSP.
DCC6.9.2 Embedded Power Park Modules shall not reconnect or increase output when
the System Frequency is above 60.2Hz.
DCC6.9.3 For Embedded Power Park Modules, facilities shall exist and be switchable in
or out, whereby a settable power ramping rate may be applied to the Active
Power output so that the output shall not be increased with a gradient above
the set value. Unless otherwise agreed with the DSP a value of 10% of the
Registered Capacity per minute shall be set. The DSP shall confirm any
different value in the Connection Agreement and notify any change in the
value from time to time. The DSP shall also confirm whether the facility shall
initially be switched in or out of service and may instruct a change in this from
time to time.
DCC6.10 Active Power Performance
DCC6.10.1Table DPC2.1 indicates the periods for which Generating Units must tolerate
Frequency deviations on the Saudi Arabian Total System.
DCC6.10.2All Embedded Generating Units with a Registered Capacity of 2MW or more,
must be capable of continuously supplying Output in accordance with the
power curve (as set out in the Connection Agreement) within the System
Frequency range 58.8 Hz to 60.5 Hz. For Generating Units seeking connection
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after [30th June 2017] there must be no reduction in Output within the
Frequency range 58.8 Hz to 60.5 Hz whilst Frequency is falling. Within the
Frequency range 58.8 Hz to 57.0 Hz, any decrease in Output must not be more
than pro-rata with any decrease below nominal Frequency. In the case of
Embedded Renewable Resource Generating Units the Output is dependent
upon the availability of Renewable Resource, therefore when assessing
compliance with the requirements of this paragraph, the maintenance of (or
change of) Output will be compared to values stated in the power curve or
table as specified/set out in the Connection Agreement.
DCC6.10.3Below 57.0Hz Power Producers may disconnect to protect their Generating
Units and associated equipment.
DCC6.11 Active Power Control
DCC6.11.1All Embedded Generating Units with a Registered Capacity of 2MW or more
approved for connection after [1st June 2017] shall be capable of operation in
Frequency Sensitive Mode. When in Frequency Sensitive Mode the following
control facility shall be operational with settings agreed with the DSP.
DCC.6.11.2The Frequency Sensitive Mode Active Power controller shall permit the
setting of separate Deadbands and Droops for Frequencies above and below
60Hz. Deadbands shall be settable with a lower limit between 59.0 Hz and
60.0 Hz in steps of 0.05 Hz and an upper limit between 60.0 Hz and 61.0 Hz
in steps of 0.05 Hz. The Active Power Droop shall be adjustable within the
range 2% and 8% is steps of a maximum of 1%. Unless otherwise instructed
by the DSP, Deadbands shall be set at +0.2HZ and -0.2Hz of 60Hz and Droop
at 4%.
DCC6.11.3With these settings, Generating Units shall be capable of regulating their
Active Power Output in the frequency range 57HZ to 59.8Hz and 60.2Hz to
62.5Hz through modulation of the Active Power as a function of frequency
deviations below 59.8 Hz or above 60.2Hz respectively. Figure 6.9.1 shows
the requirement graphically.
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Graphic representation of the “Governor” function for both Synchronous and
Asynchronous Generating Units
DCC6.11.4The Active Power output of the Embedded Renewable Resource Generating
Units with Registered Capacity of 2MW or greater shall be controllable as
long as technically feasible based on the available Renewable Resource
energy.
DCC6.11.5Each Power Park Module with a capacity greater than 2MW shall be
controllable remotely by the DSP, shall obey a properly formatted Dispatch
Instruction received from the DSP and shall be deemed to have complied if its
Active Power matches the instructed amount to the extent that prevailing
climatic conditions permit (as further specified in point (iii) of this clause).
Embedded Power Producers shall ensure that the following interface control
and performance requirements are met in respect of each of their Renewable
Resource Generating Units:
(i) capability to receive Dispatch Instructions through an automatic remote
control or SCADA system, to switch in or out Frequency Sensitive Mode
based upon Active Power Delta Regulation, to adopt a set point of Active
Power output, to set an Absolute Active Power Limitation and to switch
in or out and control ramp rate by setting an Active Power Gradient;
(ii) automatic confirmation, enactment of Dispatch Instructions received
further to DCC 6.9 (i) and confirmation that the instructed action has been
achieved;
(iii) with respect to accuracy of the set point adjustment and the resulting
control action, there shall not be any deviation of more than 2% of the set
point value or by 0.5% of the rated power, whichever provides the closer
tolerance and the action shall be completed in less than 10 minutes after
receipt of the Dispatch Instruction. In making such assessment due regard
shall be taken of the available Renewable Resource and the power curve
as specified/set out in the Connection Agreement.
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DCC6.12 Reactive Power capacity and controllability
DCC6.12.1 Embedded Generating Units with Registered Capacity less than 2MW:
(i) Embedded Generating Units with a Registered Capacity less than 2MW shall as a
minimum be able to control Power Factor to a value agreed with the DSP. The
Generating Unit’s Reactive Power capability must as a minimum to lie within the
range 0.95 absorbing to 0.95 generating when the Generating Unit is operating
full Active Power Registered Capacity. Embedded Generating Units approved for
connection after [Date] shall additionally be equipped to vary their Reactive Power so as to control voltage local to the Embedded Power Producer’s facility,
but nothing shall compel a Power Producer to operate beyond the equipment
rating or stability limits set down in the relevant Connection Agreement.
(ii) Where the Generating Unit is to be operated on a fixed Power Factor, this will be
stated in the Connection Agreement and may be varied from time to time by the
DSP within the range stated above or as further agreed in the Connection
Agreement (as allowed for in DGC5.2).
(iii) For Embedded Power Park Modules of less than 2MW, when the Active Power
output is below 20% of Registered Capacity, the Embedded Power Park Module
will maintain its absolute Reactive Power below 4% of Registered Capacity for
nominal voltage unless equipped to perform as a Power Park Module of larger
size. Deviation of Reactive Power Output due to voltage deviation is accepted on
a proportional basis.
(iv) Additionally, the Embedded Power Park Modules with a Registered Capacity
greater than 200kW and less than 2MW will have the capability to maintain their
power factor below 0.95 lagging if the voltage at Connection Point is below 90%
of nominal voltage and below 0.95 leading if the voltage at Connection Point
above 110% of nominal voltage. Between these limits of voltage, power factor
should be linearly adapted to reach unity power factor at nominal voltage. The
figure below illustrates in the hatched area the acceptable range of operation. This
chosen operating mode fixed power factor or power factor as a function of the
voltage is defined by the DSP in the Connection Agreement.
DCC6.12.2 Generators having a Registered Capacity greater than 2MW:
(i) Embedded Synchronous Generating Units
a. Each Embedded Synchronous Generating Unit with a Registered Capacity
of 2MW or greater must be capable of supplying its Registered Capacity
in MW at any point between the limits 95% Power Factor (absorbing) and
95% Power Factor (generating) measured at the Connection Point when
voltage is nominal. Deviation from these ranges due to voltage deviation
is accepted on the basis set down in Figure 6.10.3.
b. Each Embedded Synchronous Generating Unit with a Registered Capacity
of 2MW or greater shall be equipped with high-speed response Excitation
System with a continuously and fast-acting Automatic Voltage Regulation
(AVR) system targeted at controlling the Generating Unit terminal
voltage. The AVR shall be designed and operated to maintain the steady-
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state terminal voltage within ± 0.5% of the set point in the normal voltage
range specified in DPC2.1 without instability over the entire operating
range of the Generating Unit. Power Producers shall not disable this
automatic voltage control mode without prior approval of the DSP.
c. Each embedded Synchronous Generating Unit with a Registered Capacity
greater than 2MW shall be required with VAr limiting equipment.
(ii) Embedded Power Park Modules with Registered Capacity of 2MW or greater:
a. Each Embedded Power Park Module with Registered Capacity of 2MW
or greater when the voltage is nominal shall be capable of absorbing or
supplying Reactive Power Output at the Connection Point and within the
range Q= [-0.33pu, +0.33pu] of Registered Capacity (assessed in MW for
Active Power). This requirement applies when the level of output is above
20% of rated power, unless an alternative value of Active Power threshold
is agreed upon by the DSP in the Connection Agreement (as allowed for
in DGC5.2). The required Reactive Power performance is control mode
dependent as shown in Figure 6.10.1. Figure 6.10.1 also shows the
required performance when the level of Active Power output is below
20%. Deviation from these ranges due to voltage deviation is accepted on
the basis set down in Figure
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Minimum Reactive Power requirement for Embedded Power Production Modules ≥ 2MW
depending upon the selected control modes
Per Unit Reactive Power at the Connection Point based upon 1 PU Active Power rating
b. For values of Active Power Output below 20% of Registered Capacity,
each Embedded Power Park Module with Registered Capacity of 2MW
or greater shall be capable of limiting its Reactive Power Output at the
Connection Point within the range Q=[-0.05 to +0.05] of rated power
(based upon nominal voltage at the Connection Point). The
implementation of these limits shall be instructed by the DSP and any
alternative to the 20% value of Active Power threshold may be agreed by
the DSP in the Connection Agreement. Deviation from these ranges due
to voltage deviation is accepted on a basis agreed by the DSP in the
Connection Agreement.
c. Power Park Modules with a Registered Capacity of 2MW or more shall
not consume on average more Reactive Power in the 10 seconds following
a disturbance on the Distribution System than they did on average in the
10 minutes before the occurrence of the disturbance. Where a Power Park
Module is supporting the Distribution System voltage through Reactive
Power export, it shall not draw Reactive Power during or immediately
following the disturbance.
d. Each Embedded Power Park Module with a Registered Capacity greater
than 2MW shall be equipped to automatically control its Reactive Power
during normal operation according to a control mode and settings advised
from time to time by the DSP. The initial control mode and settings will
be provided in the Connection Agreement. Each Embedded PPM shall be
capable of the following control modes:
i. Voltage Control mode;
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ii. Reactive Power control mode;
iii. Power Factor control mode;
e. The Voltage Control mode shall be targeted to maintain the steady-state
voltage to a set-point value measured at the Connection Point. The
tolerance to be achieved is ± 0.5% of the nominal voltage.
f. In the event that voltage exceeds the normal range specified in DPC2.1
and where Reactive Power or Power Factor control mode are employed,
the Generating Unit must switch as an emergency to Voltage control mode
and target both Reactive Power and then Active Power to return the
voltage to within the range specified in DPC2.1.
g. In the event that the above emergency action by the Generating Unit
cannot achieve a Voltage within a limited time excursion value the
Generating Unit must trip as shown in Figure 6.10.3.
h. When the Voltage has been stabilised to within the normal range for 10
minutes continuously, the Generating Unit shall revert to the normal
control mode as previously instructed by the DSP.
Deployment of modes of Reactive Power control for Power Park Modules (1.05pu -0.95pu
is normal voltage range on Distribution System)
DCC6.13 Communication
DCC6.13.1 Each Embedded Generator shall ensure that it complies, in respect of each
Generating Unit within its facility, with [Schedule###] of this Code, which
details the destination, list and format of signals required to enable information
and normal and emergency control of the GU. The DSP will have the right to
test performance of these signals and the DSP may withhold a Connection
Certificate (Temporary or Final) or replace a Final Certificate with a Limited
Performance Certificate until such time as the problem has been rectified and
the communication is proven to work.
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DCC6.13.2 Each party (TSP, DSP and SSEC) empowered to issue and receive signals
from Users is required [by the terms of its Licence] to have proper regard for
the security of the System from cyber threats and all control centres, DSP(s)
and Users of the Distribution System are required to cooperate to the fullest
extent in establishing and maintaining procedures and practices aimed at
reducing such risks drop to between 70% and 80% of the nominal voltage for
a period of up to 300 millisecond in any one phase or combination of phases,
followed by a period of one (1) second where voltage may vary in the range
80-110% of the nominal voltage.
DCC.6.13.3 In the event of a step change in voltage each Embedded Power Park Module
of 2MW or greater shall remain connected to the Distribution System as
specified in the Figure
DCC6.14 Fault Ride Through
DCC6.14.1 Under transient conditions, Embedded Generators with a Registered Capacity
greater than 200kW and less than 2MW must be capable of withstanding
Faults on the Distribution System which may cause the voltage at the
Connection Point to drop to between 70% and 80% of the nominal voltage for
a period of up to 300 millisecond in any one phase or combination of phases,
followed by a period of one (1) second where voltage may vary in the range
80-110% of the nominal voltage.
DCC6.14.2 In the event of a step change in voltage each Embedded Power Park Module
of 2MW or greater shall remain connected to the Distribution System as
specified in the Figure
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time based requirement for a Power Park Module of Registered Capacity ≥ 2MW to
remain Connected to the Distribution System during periods of reduced
voltage on that System
DCC6.15 Short-Circuit Contribution
DCC6.15.1 It is preferable that in the case of single-phase to earth faults, the short-circuit
current contribution of Embedded Generating Units shall not exceed the short-
circuit current in each phase occurring during a solid 3-phase fault. This is to
ensure that equipment ratings are not exceeded. In the event that calculation
by a User shows that single-phase to earth fault-current will be higher than the
phase currents during a 3-phase fault, the Power Producer must draw the
matter to the attention of the DSP who will assess the situation on a case-by-
case basis and advise the Power Producer. In the event that the DSP’s
assessment still shows that action is needed by the Power Producer, it will be
the Power Producer’s responsibility to provide a technically sound solution in
line with Good Industry Practice.
DCC6.15.2 For three-phase Embedded Generators, the 1-phase short-circuit current shall
not be below 60% of the 3-phase short-circuit current in order to facilitate
protection selectivity.
DCC6.15.3 Asynchronous Generating Units (including invertors) above 2MW may be
required to make a contribution to fault-level in order to ensure the proper
operation of system protection. The minimum contribution will be specified
in the Connection Agreement as a current and phase-angle to the system
voltage which maybe on a sliding scale with retained System voltage. (as
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allowed for in DGC5.2).
DCC6.16 Black Start Capability
DCC616.1 Embedded Synchronous Generators with a Registered Capacity greater than 2MW shall notify DSP(s) if its Generating Plant has a restart capability without connection to an external power supply.
DCC6.16.2 Embedded Asynchronous Generating Units (Power Park Modules) will not be required to provide Black Start capability and will not be used as part of any Black Start plan until a stable Synchronous system or part thereof has been established.
DCC6.17 Generating Plant Commissioning Tests
DCC6.17.1Where the Generating Plant requires connection to the Distribution System in
advance of the Commissioning date, for the purposes of testing, the Generator
shall comply with the requirements of the Connection Agreement. The
Generator shall provide DSP(s) with a Commissioning programme, approved
by DSP(s) if reasonable in the circumstances, to allow Commissioning Tests
to be co-ordinated.
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PART 5: OPERATION
Contents
DOC1 Demand Forecasting
DOC2 Operational Planning
DOC3 Demand Control
DOC4 Operational Communications and Liaison
DOC5 Event Reporting
DOC6 System Tests
DOC7 Monitoring Testing and Investigation
DOC8 Safety Co-Ordination
DOC1: Demand Forecasting
DOC1.1 Introduction
DOC1.1.1 In order for DSP(s) to operate the Distribution System efficiently and to ensure
maximum system security and system stability, there is a need for those Users
specified in DOC1.2 to provide loading and generation output information to
DSP(s).
DOC1.1.2 Demand forecasting specifies the information to be provided to DSP(s) by
other Users of the Distribution System so that these requirements can be met.
DOC1.1.3 Demand forecasting sets out the Demand forecasting and the generating Plant
output information to be provided by Users to enable DSP(s) to operate the
Distribution System; and specifies the information to be provided by Users to
the DSP(s).
DOC1.1.4 Where Demand data is required from the User, this means the MW Demand
of electricity at the Connection Point. DSP(s) may in certain cases specify that
the Demand data shall include the MVAR Demand.
DOC1.1.5 The means of providing the information to DSP(s) and its confirmation
includes any non-transitory written form, or any other suitable means of
electronic transfer which enables the recipient to retain information. DOC1.2 Scope
DOC1.2.1 Demand forecasting applies to the following Users of the Distribution System
(a) Major Customers connected to the Distribution System and Medium
Voltage Customers where DSP(s) considers it appropriate.
Embedded Power Producers with a Registered Capacity greater 2MW and whose
Generating units are not subject to Central Dispatch.
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DOC1.3 Capability of receiving Dispatch Instructions
DOC1.3.1 Dispatch Instruction given by the DSP to a non-Renewable Resource
Generator for each Embedded Generating Unit above 2MW may involve a
change in the Active Power Output, a change in the Reactive Power Output,
Synchronizing and de-synchronizing time (if appropriate), a change to the
mode of operation, or to provide one or more of the contracted System
Services.
DOC1.3.2 Dispatch Instruction to Renewable Resource Generating Units with a
Registered Capacity greater than 2MW will be given by the TSP through the
Saudi Sustainable Energy Control Center.
DOC1.4 Information Flow and Co-Ordination
DOC1.4.1 DSP(s) shall co-ordinate Demand Forecast information for each Bulk Supply
Point to meet the requirement of the Saudi Arabian Grid Code (SAGC).
DSP(s) shall aggregate forecast information provided by Users, where
appropriate, and provide forecast information to the TSP where Demand, or
change in Demand, is greater than 10MW at any Connection Point.
DOC1.4.2Information from Embedded Power Producers for Generating Units in the
Distribution System, which are not subject to Central Dispatch, shall be
provided where specified to DSP(s). Production Embedded Generators with a
Registered Capacity greater than 200kW may also be required to supply
information.
DOC1.4.3 Information regarding Renewable Resource Generating Units, shall be
provided to DSP(s) (on request) through the Saudi Sustainable Energy Control
Center..
DOC1.5 Demand Forecast Data
DOC1.5.1 Major Customers shall provide to DSP(s) information regarding Demand and
planned shutdowns for specified future periods. This shall be provided on an
annual basis when requested by DSP(s).
DOC1.6 Information regarding Output and planned shutdowns
DOC1.6.1 Generating Units with a Registered Capacity up to 2MW need not provide
DSP(s) with information regarding Output and planned shutdowns for
specified future periods unless specifically requested to do so by the DSP. If so
requested, Power Producers shall comply with a reasonable timeframe for the
provision of the data as set by the DSP. The DSP will not require such
information from Power Producers with Renewable sourced Generating units
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with a Registered Capacity less than 200kW.
DOC1.6.2 Generating Units with a Registered Capacity above 2MW not based upon
Renewable Resource and not subject to Central Dispatch shall provide DSP(s)
with information regarding Output and planned shutdowns for specified future
periods. This shall be provided on an annual basis according to a timetable set
by DSP(s).
DOC1.6.3 Generating Units with a Registered Capacity above 2MW based upon
Renewable Resource and not subject to Central Dispatch shall provide SSEC
with information regarding Output and planned shutdowns for specified future
periods. This shall be provided on an annual basis according to a timetable set
by SSEC which shall have regard to the timetable set down by the TSP in the
SAGC.
DOC1.6.4 Generating Units with a Registered Capacity above 2MW (whether based upon
Renewable Resource or otherwise) and subject to Central Dispatch shall
provide TSP(s) with information regarding Output and planned shutdowns for
specified future periods. This shall be provided on an annual basis according
to a timetable set by down in the SAGC.
DOC2: Operational Planning
DOC2.1 Introduction
DOC2.1.1 Operational Planning;
(a) Sets out the operational planning procedure and typical timetable for
the co-ordination of outage requirements for Plant and apparatus to be
provided by Users to enable DSP(s) to operate the Distribution System
and
(b) Specifies the information to be provided by Users to DSP(s) to allow
it to comply with the Saudi Arabian Grid Code (SAGC).
DOC2.1.2 The means of providing the information to DSP(s) and its confirmation
includes any non-transitory written form, or any other suitable means of
electronic transfer which enables the recipient to retain information.
DOC2.1.3 In order for the DSP(s) to fulfill the requirements of DOC2 it should be noted that the information set out in the Saudi Arabian Grid Code (SAGC), to be
provided by the TSP will form the basis of operational planning under DOC2.
DOC2.2 Scope
DOC2.2.1 DOC2 applies to the following Users of the Distribution System:
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(a) Major Customers connected to the Distribution System where DSP(s)
considers it appropriate;
(b) Embedded Power Producers with Generating Units connected to the
Distribution System
DOC2.3 Provision of Information
DOC2.3.1 Information on Embedded Generating Plant with a Registered Capacity
greater than 2MW and which is not subject to Central Dispatch (including
Customers with CHP and Customers with Auto-production) shall be provided,
where specified, directly to DSP(s).
DOC2.3.2 Information on Renewable Resource Generation shall be provided, where
specified, to DSP(s) through the Saudi Sustainable Energy Control Center.
DOC2.3.3 Centrally Dispatched Generating Units shall comply with the requirements of
the Saudi Arabian Grid Code (SAGC). Information shall be provided directly
to the TSP.
DOC2.4 Time scales and Data
DOC2.4.1 Detailed implementation of data gathering and timescales shall be determined
by DSP(s) and each User. Due recognition shall be given by DSP(s) to
voltage levels and capacities of Plant and apparatus when assessing
information requirements.
DOC2.4.2 The information may be required for different timescales as may be
determined by DSP(s) planning needs.
DOC2.5 Information from Embedded Generators
DOC2.5.1 Information from Embedded Generating Plant with a Registered greater than
2MW and not subject to Central Dispatch shall include details of Planned Outages for maintenance or other purposes as well as the expected time of return of service.
DOC2.5.2 Information regarding the details of Planned Outages for maintenance or other purposes as well as the expected time of return of service of Renewable Resource Generation with a Registered Capacity greater than 2MW, will be given by to the DSP on annual basis through the Saudi Sustainable Energy Control Center
DOC2.5.3 The Generator shall not synchronize without first obtaining permission from
DSP(s) unless prior agreement has been reached with DSP(s). Automatic
resynchronization as defined is DCC6.8 is a prerequisite for such an agreement.
DOC2.6 Information to Users
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DOC2.6.1 DSP(s) shall advise Major Customers or Generators who may be significantly
affected by particular outages of Distribution Plant and apparatus, of the likely
dates and duration of the outages. If there are objections from Users these shall
be considered by DSP(s) and alternative arrangements proposed if possible.
DOC3: Demand Control
DOC3.1 Introduction
DOC3.1.1 DOC3 is concerned with provisions to be made by DSP(s) or Users of the
Distribution System, in certain circumstances, to permit reductions in
Demand. Reductions would be permitted:-
(a) In the event of insufficient Generating Plant and transfers from external
interconnections are not available to meet Demand;
(b) To avoid disconnection of Customers; or
(c) (c) In the event of breakdown and/or operating problems (such as in respect
of system Frequency, system voltage levels or system thermal overloads) on
any part of the Transmission or Distribution System.
DOC3.1.2 The Demand control procedures ensure that hardship to Users and Customers
is minimized and that in so far as is practicable, all parties affected are treated
equitably.
DOC3.1.3 DOC3 deals with the following means of reducing Demand:
(a) automatic low Frequency or voltage Demand disconnection;
(b) Customer Demand reduction including Voltage Reduction;
(c) Customer Demand management initiated by Suppliers or other parties,
other than following an instruction by DSP(s) or TSP;
(d) Customer Demand reduction instructed by DSP(s) or TSP ;and
(e) Emergency manual Demand disconnection.
The term Demand Control is used to describe any or all of these methods of
achieving a Demand reduction.
DOC3.1.4 Where Demand Control is exercised by DSP(s) or the TSP it shall be done in
a manner that in so far as reasonably practicable does not discriminate against
any Customer or supplier and shall use reasonable endeavors to ensure that
the burden is shared fairly among Customers. Exemptions may apply to vital
and priority Customers as defined in the Distribution load shedding criterion/
plan submitted by DSP(s) and approved by ECRA.
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DOC3.2 Scope
DOC3.2.1 DOC3 applies to DSP(s) and all Users of the Distribution System.
DOC3.2.2 Implementation of Demand Control by DSP(s) may affect all Customers of
Suppliers connected to the Distribution System and where applicable,
contractual arrangements between Suppliers and their Customers may need to
reflect this.
DOC3.3 Methods of Demand Control
DOC3.3.1 Customer Demand may be disconnected automatically at selected locations
in accordance with the requirements of the Saudi Arabian Grid Code, in the
event of a sudden fall in Frequency. Such an arrangement shall be carefully
coordinated as part of an overall scheme and may take into account any
operational requirements or essential load.
DOC3.3.2 Automatic disconnection by under voltage relay may be used discriminately to
disconnect load at 33kV or 13.8kV in order to maintain voltage within
acceptable limits, so as to avoid widespread load shedding.
DOC3.3.3 Deliberate reduction of voltage may be used to achieve a temporary reduction in load Demand.
DOC3.3.4 Deliberate reduction in system Frequency may also be used to achieve a
temporary reduction in load Demand in accordance with the Saudi Arabian
Grid Code (SAGC).
DOC3.3.5 Emergency manual load shedding may be carried out on the Distribution or
Transmission Systems for reasons of shortfall in supply or other reasons.
DOC3.3.6 In the event of a sustained period of shortfall then planned Rota load shedding
may be used to share the available power among affected Customers.
DOC3.4 Implementation of Demand Control
DOC3.4.1 Where a Demand Control is exercised by DSP(s) in order to safeguard the
Distribution System, DSP(s) shall liaise with and inform Users accordingly as
far as is practicable.
DOC3.4.2 Where Demand Control is exercised by DSP(s) on instruction or request from
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the TSP in order to safeguard the total System then DSP(s) is required to
respond to these requests promptly but shall liaise with and inform other Users
so far as is practicable.
DOC3.4.3 Procedures for load shedding including exemption policies, load shedding
Rota and Customer communications are contained in the Distribution load
shedding criterion/ plan approved by ECRA.
DOC4: Operational Communications and Liaison
DOC4.1 Introduction
DOC4 sets out the requirements for the exchange of information in relation
to Operations and/or Events on the Distribution System or the installation
of any User connected to the Distribution System which have had or
may have had, or will have or may have an Operational Effect on the
Distribution System or the installation of any other User.
DOC4.2 Scope
DOC4 applies to the following Users of the Distribution System:
(a) Major Customers connected to the Distribution System where DSP(s)
considers it appropriate;
(b) Embedded Generating Plant with a capacity greater than 2MW, or
according to CA/PPA between DSP and Generators.
DOC4.3 Procedure
DOC4.3.1 DSP(s) and Users connected to the Distribution System shall nominate persons
and/or contact locations and agree communication channels for the necessary
exchange of information to make effective the exchange of information
required by DOC4.
DOC4.3.2 SCADA equipment may be required at a User’s site for transmission of information and data to and from the DSP(s). The requirement to provide this
information shall normally be included in the relevant Connection Agreement.
DOC4.3.3 Information between DSP(s) and Users shall be exchanged on the reasonable
request of either party. The request may follow a specific Operation, or be in accordance with a prior agreement to exchange information on particular types
of Event. This does not preclude the voluntary exchange of information which
may be perceived as being relevant to the operation of the Distribution or User
Installation, in accordance with Good Industry Practice.
DOC4.3.4 DSP(s) shall notify the User of any Operation on the Distribution System (or
of any Operation on the Transmission System of which it has received notice)
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which, in the opinion of DSP(s), will have or may have an Operational Effect
on the installation of the User.
DOC4.3.5 A User shall notify DSP(s) of any Operation on the installation of that User
which will have or may have an Operational Effect on the Distribution
System.
DOC4.3.6 A notification under DOC4 shall include the name of the individual reporting
the Operation and, although it need not state the cause, shall be in sufficient
detail to describe the Operation and to enable the recipient reasonably to know
and consider the implications and risks arising there from. The recipient may
ask questions to clarify he notification.
DOC4.3.7 A notification under DOC4 shall be given as far in advance as possible to allow
the recipient to consider and assess the implications and risks arising.
DOC4.4 Significant Incidents
DOC4.4.1 Where an Event on the Distribution System has had or may have had a
significant effect on the User’s installation or where an Event in the User’s
installation has had or may have had a significant effect on the Distribution
System, DSP(s), in consultation with the User, shall deem the Event to be a
Significant Incident. Significant incidents shall be reported in writing to the
affected party in accordance with the provision of DOC5.
DOC4.4.2 Significant Incidents shall include Events which result in, or may result in, the
following:
(a) Voltage outside statutory limits;
(b) System Frequency outside statutory limits; or
(c) System stability failure.
DOC5: Event Reporting
DOC5.1 Introduction
DOC5.1.1 DOC5 sets the requirements for reporting in writing those Events deemed to
be “Significant Incidents” under DOC4.
DOC5.1.2 DOC5 also provides for the joint investigation of Significant Incidents by the
Users involved.
DOC5.2 Scope
DOC5.2.1 DOC5applies to the following Users of the Distribution System:
a) Major Customers connected to the Distribution System where DSP(s)
considers it appropriate; b) Embedded Generating Plant with a capacity greater than 2 MW, or according
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to CA/PPA between DSP and Generators
DOC5.3 Procedures
DOC5.3.1 DSP(s) and each User specified in DOC5.2.1 shall nominate officers and
establish communication channels to ensure the effectiveness of DOC5.
Such officers and communication channels may be the same as those
established under DOC4.
DOC5.3.2 Communication shall, as far as possible, be direct between the User and
DSP(s). This does not, however, preclude communication with the Users
nominated representative.
DOC5.3.3 In the case of an Event that has been reported to DSP(s) under DOC4 and subsequently has been determined by DSP(s) to be a Significant Incident, a
written report shall be given to DSP(s) by the User in accordance with DOC5.
DOC5.3.4 In the case of an Event that has been reported to the User under DOC4 and subsequently has been determined by DSP(s) to be a Significant Incident, a
written report shall be given to the User by DSP(s) in accordance with DOC5.
DOC5.3.5 A Report shall be in writing or in electronic form and shall be sent to DSP(s)
or User, as the case may be. It shall contain confirmation of the notification
given under DOC4 together with more details relating to the Significant
Incident including information which has become known relating to the
Significant Incident since the notification. The report shall, as a minimum,
contain those matters specified in DOC5.
DOC5.3.6 A report under DOC5 shall be given as soon as reasonably practical after the
notification under DOC4.
DOC5.4 Joint Investigations
DOC5.4.1 Where a Significant Incident has been declared and a report submitted under
DOC5 either party or parties may request in writing that a joint investigation
be carried out.
DOC5.4.2 The composition of such an investigation panel shall be appropriate to the
incident to be investigated and agreed by all parties involved.
DOC5.4.3 A joint investigation shall only take place where all parties affected by it agree
to it. The form and rules of, and procedures for, and all matters relating to the
joint investigation shall be agreed at the time of a joint investigation and in
the absence of agreement the joint investigation shall not take place.
DOC5.5 Matters to be Included in a Written Report of a Significant Incident
DOC5.5.1 Matters applicable to DSP(s) and Embedded Generators are as follows:
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(a) date and time of Significant Incident;
(b) location;
(c) equipment involved;
(d) brief description of Significant Incident;
(e) details of any Demand Control undertaken;
(f) conclusions and recommendations if applicable
DOC5.5.2 Matters applicable to DSP(s) are as follows:-
Effect on Users where appropriate:
(a) Duration of incident; and
(b) Estimated date and time of return to normal service.
DOC5.5.3 Matters applicable to Embedded Generators as follows:
(a) date and time of Significant Incident;
(b) location;
(c) equipment involved;
(d) brief description of Significant Incident;
(e) details of any Demand Control undertaken; (f) conclusions and recommendations if applicable
DOC6: System Tests
DOC6.1 Introduction
DOC6.1.1 DOC6 sets out the responsibilities and procedures for arranging and carrying
out System Tests which have or may have an effect on the Systems of DSP(s)
or Users. System Tests are those which involve either simulated or the
controlled application of irregular, unusual or extreme conditions on the Total System or any part of the Total System, but which do not include
Commissioning or re-Commissioning tests or any other tests of a minor
nature.
DOC6.2 Scope
DOC6.2.1 DOC6 applies to the following Users of the Distribution System:
(a) Major Customers connected to the Distribution System where
DSP(s) considers it appropriate;
(b) Embedded Generating Plant with a capacity greater than
2MW, or according to CA/PPA between DSP and Generators.
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DOC6.3 Procedures
DOC6.3.1 If the System Test is proposed by DSP(s) or the User connected to the
Distribution System then the provisions of DOC6 shall apply.
DOC6.3.2 If the system test will or may have an effect on the Transmission System, then
the provision of the Saudi Arabian Grid Code shall apply.
DOC6.3.3 System Tests which have a minimal effect on the Distribution System or the
systems of others will not be subject to this procedure; minimal effect shall be
taken to mean variations in voltage, Frequency and waveform distortion of a
value not greater than those figures which are defined in the Distribution
Planning Code.
DOC6.3.4 When DSP(s) or a User intends to undertake a System Test which may have
significant effect on the System of others normally twelve months notice, or
as otherwise agreed by DSP(s), shall be given by the person proposing the
System Test (Test Proposer) to DSP(s) and to those Users who may be
affected by such a System Test.
DOC6.3.5 The proposal shall be in writing and shall contain details of the nature and
purpose of the proposed System Test and shall indicate the extent and situation
of the Plant or apparatus involved.
DOC6.3.6 If the information set out in the proposal notice is considered insufficient by
the recipient they shall contact the Test Proposer with a written request for
further information which shall be supplied as soon as reasonably practicable.
DSP(s) shall not be required to do anything under DOC6 until they are satisfied
with the details supplied in the proposal or pursuant to a request for further
information.
DOC6.3.7 If DSP(s) wishes to undertake a System Test, DSP(s) shall be deemed to have
received a proposal of that System Test.
DOC6.3.8 DSP(s) shall have overall co-ordination of the System Test, using the
information supplied to it under DOC6 and shall identify in its reasonable estimation, which Users other than the Test Proposer, may be affected by the
proposed System Test.
DOC6.3.9 Following receipt of the System Test proposal DSP(s) shall evaluate the impact
of the System Test and discuss the proposals with Users identified as being
affected.
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DOC6.3.10 Within one month of receiving the System Test proposal DSP(s) shall submit
a report to the Test Proposer which shall contain:
(a) proposals for carrying out the System Test (including the manner in
which it is to be monitored);
(b) an allocation of costs between the affected parties, (the general
principle being that the Test Proposer will bear the costs); and
(c) such other matters that DSP(s) consider appropriate; an outline of the
procedure to be followed and the proposed test schedule and advice of
any costs.
DOC6.3.11 the proposal report shall be submitted to all those who received a notice
under DOC6.3.4.
DOC6.3.12 If the proposal report (or a revised proposal report as agreed between DSP(s)
and the Test Proposer) is approved by all recipients, the System Test can
proceed.
DOC6.3.13 At least one month prior to the date of the proposed System Test, DSP(s)
shall submit to all recipients of the proposal notice a programme which in
DOC6 shall be called a Final Test Programme stating the switching sequence
and proposed timings, a list of those staff involved in carrying out the System
Test (including those responsible for site safety) and such other matters as
DSP(s) deem appropriate.
DOC6.3.14 The final test programme shall bind all recipients to act in accordance with
the provisions contained within the programme in relation to the proposed
System Test.
DOC6.3.15 At the conclusion of the System Test, the Test Proposer shall be responsible
for preparing a written report (the “Final Report”) of the System Test for
submission to DSP(s).
DOC6.3.16 The Final Report shall include a description of the Plant and/or apparatus
tested and of the System Test carried out, together with the results, conclusions
and recommendations.
DOC6.3.17 Results of tests shall be reported to relevant parties, taking into account confidentiality issues.
DOC6.3.18 all system test procedures shall comply with all applicable legislation.
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DOC7: Monitoring Testing and Investigation
DOC7.1 Introduction
DOC7.1.1 In order to discharge its responsibilities in respect of safe, secure and
economic operation of the Distribution System and in accordance with its
licence conditions DSP(s) shall organize and carry out monitoring, testing and
investigation on the effect of User’s electrical apparatus or electrical
installation on the Distribution System.
DOC7.2 Scope
DOC7.2.1 DOC7 applies to the following Users of the Distribution System:
(a) all Embedded Generators (b) all Customers who are connected to the Distribution System
DOC7.3 Procedures
DOC7.3.1 DSP(s) shall, from time to time, determine the need to test or monitor the
quality of supply at various points on the Distribution System.
DOC7.3.2 The requirements for specific testing and/or monitoring may be initiated by the receipt of specific complaints as to the quality of supply on the Distribution System.
DOC7.3.3 Where testing or monitoring is required at the Connection Point with a User
then DSP(s) shall advise the User involved and DSP(s) shall make available
the results of such tests to the User.
DOC7.3.4 Where a User is found to be operating outside the technical limits specified in
the Distribution Code then the User shall rectify the situation or disconnect the
apparatus causing the problem from its electrical system connected to the
Distribution System immediately or within such time as agreed with DSP(s).
DOC7.3.5 Continued failure to rectify the situation shall result in the User being
disconnected.
DOC7.3.6 DSP(s) shall, from time to time, monitor the effects of the User on the
Distribution System.
DOC7.3.7 The monitoring shall normally be related to the amount of Active Power and
Reactive Power or Flicker or Harmonics transferred across the Connection
Point.
DOC7.3.8 Where the User is exporting or importing Active Power or Reactive Power in
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an amount causing disturbances, DSP(s) shall inform the User and the User
shall restrict the power transfer to within the specified parameters.
DOC7.3.9 DSP(s) may check from time to time that Users are in compliance with
agreed Protection requirements and Protection settings.
DOC8: SAFETY CO-ORDINATION
DOC8.1 Introduction
DOC8.1.1 DOC8 specifies the safety rules and procedures to be applied by the DSP(s) to meet statutory requirements and Distribution License conditions and obligations.
DOC8.1.2 Similar safety rules and procedures shall be provided by other Users of the
Distribution System when carrying out work or tests at the operational
interface with the DSP(s).
DOC8.2 Objectives
DOC8.2.1 The objectives of safety co-ordination procedures are to lay down the Safety Management criteria to be applied, to ensure safety of persons working on the
Distribution System and/ or across operational and ownership boundaries.
DOC8.3 Scope
DOC8.3.1 DOC8 specifies the safety rules and procedures that apply to the DSP(s) and
the following Users of the Distribution System:
a) Embedded Generators
b) Major Customers
c) Any other party reasonably specified by the DSP(s) including Users connected
at Medium or Low Voltage for appropriate sections of DOC8 when necessary
d) Agents of the DSP(s) or Users working on the Distribution System or at or
across operational boundaries.
DOC8.4 Procedures
DOC8.4.1 The Safety Management principles and procedures (Safety Management
System) for ensuring the health and safety of all relevant personnel shall be
specified by DSP(s) and Users for work on their respective Systems or Plant
apparatus connected to them.
DOC8.4.2 There shall be joint agreement by DSP(s) and Users on which Safety
Management System is to be used for sites or locations where an operational
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boundary exists and proper documentation of the safety precautions to be
taken shall be maintained.
DOC8.4.3 There shall be written authorization of personnel who do the work of control,
operation, work or testing of Plant apparatus forming part of, or connected
to, the Distribution System.
DOC8.4.4 There shall be joint agreement between DSP(s) and Users which specifies
responsibility for system or control equipment which shall ensure that only
one party is responsible for any item of Plant or apparatus at any one time.
DOC8.4.5 DSP(s) and each User shall at all times have nominated a person or persons
responsible for the co-ordination of safety on the respective system.
DOC8.4.6 DSP(s) and each User shall maintain a suitable system of documentation
which records all relevant Operational Events that have taken place on the
Distribution System or other system connected to it and the co-ordination of
relevant safety precautions for work.
DOC8.4.7 System diagrams which show sufficient information for control personnel to
carry out their duties shall be exchanged between DSP(s) and User as required.
DOC8.5 Safety at the DSP(s) / User Interface
DOC8.5.1 The following procedures set down the basic safety requirements at the
operator and DSP(s) interfaces. These procedures are necessary to ensure the
safety of all who may have to work at either side of the interface or on the
interface (boundary).
(a) Written rules for safety working and communicating procedures shall
be available and used by all persons who may have to work at or use
the facilities provided at the Interface.
(b) Electrical equipment connected to either side of the interface and
interface equipment shall be under the control of a named person at
either side.
(c) Each item of equipment shall be controlled by only one identifiable
person at any one time.
(d) Adequate means of isolation shall be provided at the interface to allow
work to be carried out safely at either side of the interface.
(e) Where necessary to prevent danger adequate facilities for Earthing
shall be provided at either side of the interface to allow work to be
carried out safely at the interface or at either side of the interface.
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(f) Adequate working space, adequate means of access and egress and,
where necessary, adequate lighting shall be provided at all electrical
equipment, on or near which work is being done in circumstances
which may cause danger.
(g) All electrical equipment shall be suitably identified where necessary
to prevent danger.
(h) Electrical installations and equipment shall comply with the relevant
statutory requirements.
DOC8.6 Safety Rules
DOC8.6.1 Operation and Maintenance of the User’s equipment shall only be carried out by authorized personnel. Before first Commissioning the Plant, operating procedures shall be agreed with the DSP(s).
DOC8.6.2 Instructions for operating and / or Earthing the User’s electrical equipment shall
be clearly displayed in the User’s Medium and High Voltage switch room.
DOC8.6.3 Safety Procedures for personnel working on or in close proximity to the
Distribution System Plant and apparatus shall be governed by the DSP(s).
DOC8.6.4 In the event of a conflict between the provisions of this Code and the
provisions of the TSP safety rules, the provisions of the TSP Safety Rules shall
take precedence.
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PART 6: GLOSSARY
DCD1 Active Power
The product of voltage and the in-phase component of alternating current (normally measured in kilowatts (kW) or megawatts (MW)).
DCD2 Ambient Temperature
The surrounding temperature (in the absence of the equipment) of the
immediate environment in which equipment is installed. This temperature
normally varies. A derived constant value is taken for the purposes of designing
or rating equipment.
DCD3 Apparent Power
The vector addition of Active Power and Reactive Power measured in units of
VA, kVA and MVAr
DCD4 Asynchronous
Refers to generating Plant and electric drives, and has the meaning that the
Plant or drive is not linked to the System Frequency by a Synchronising torque.
In general, this means that there is no natural contribution to the inertia of the Total System, although control mechanisms may be employed to synthesise a
contribution which assists in stabilising the Total System after a disturbance.
DCD5 AVR
Automatic Voltage Regulator
DCD6 Back-Up Protection
That Protection system which will open a Circuit Breaker or other fault-
current interrupting device in the absence of the current Protection operation
of another Protection system
DCD7 Black Start
The procedure which is necessary for recovery from a total or partial system
shutdown
DCD8 Bulk Supply Point
A point of connection between the Transmission System and the Distribution
System or between the Transmission System and a directly connected
Customer
DCD9 Central Dispatch
The Dispatch of Generating Units by the Transmission Service Provider
(TSP), and Centrally Dispatchable shall be construed accordingly
DCD10 Centrally Dispatched Generating Units Generating Units subject to Dispatch by the TSP
DCD11 Circuit Breaker
A mechanical switching device, capable of making, carrying and breaking
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currents under normal circuit conditions and also of making, carrying for a
specified time and breaking currents under specified abnormal circuit
conditions, such as those of short circuit
DCD12 CHP - Combined Heat and Power
The simultaneous production of utilizable heat and electricity from an
integrated thermo-dynamic process
DCD13 Commissioning
The final process of testing part of a system prior to that part of the system
being considered suitable for normal use
DCD14 Connected Load
The sum of the nameplate ratings of all present and future electrical equipment
installed by a Customer. Connected load is measured in volt-amperes (VA).
DCD15 Connection Agreement
An agreement between DSP(s) and each User setting out terms relating to a
connection with the Distribution System
DCD16 Connection Point
The physical point at which User’s Plant or apparatus is joined to the
Distribution System.
DCD17 Customer
A User whose premises are connected to the Distribution System for the purpose of obtaining a supply of electricity at that premises
DCD18 Customer with Auto-Production
A Customer generating electricity for their own use.
DCD19 Deadband
In relation to a control system is that range of a controlled parameter over
which the control system remains inactive.
DCD20 Delta Regulation
Refers to a control system applied to a Renewable Resource Generating Unit
whereby the Generating Unit continually operates at a settable fixed fraction
below its instantaneous maximum Output so as to have energy available to
assist in Frequency control of the Total System.
DCD21 Demand
The electric power which is drawn for the system by a Customer, usually
expressed in MW, MVA or MVAR.
DCD122 Demand Load
The maximum load drawn from the power system by a Customer at the
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Customer’s interface (either estimated or measured).
DCD123 Dis-connector
A device which provides in the open position a means of disconnecting
apparatus from the Distribution System in accordance with specified requirements
DCD24 Dispatch
The issue of instructions for Generating Units to achieve specific Active Power and Reactive Power outputs within Registered Data parameters and by stated times.
DCD25 Distribution Code
This code, required to be prepared by DSP(s) pursuant to condition 14
(Compliance with transmission, distribution and market codes) of he
Distribution Licence and approved by ECRA as revised from time to time
with the approval of, or by the direction of, ECRA.
DCD26 Distribution Code Review Panel
The panel with the functions which are set out in DGC6.
DCD27 Distribution License
A distribution license granted under Article 5 and 6 of the Electricity Law
promulgated on 20/10/1427 AH (21/11/2006 AD) by Royal Decree M/56
and ECRA Charter dated 17/05/1425 AH (05/07/2004 AD).
DCD28 Distribution System
The system which consists of electric lines, electric Plant, transformers and
switchgear and which is used for conveying electricity to final Customers.
DCD29 Distribution Service Provider (DSP)
The legal entity that is licensed to own and maintain a network on the Distribution System (or has such right by virtue of its historic existence for this purpose).
DCD30 Distribution Use of System Agreement
The agreement between DSP(s) and Retailers/ Traders for transport of
electricity from the Transmission System or Embedded Generators through
the Distribution System to Customers.
DCD31 Disturbing Loads
Loads which have the potential to introduce waveform distortion (Harmonics,
Flicker) or phase unbalance into the system.
DCD32 Droop
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In relation to the operation of the governor of a Generating Unit, the
percentage drop in Saudi System Frequency which would cause the
Generating Unit under free governor action to change its output from zero to
full load.
DCD33 Earthing
The provision of a connection between conductors and earth by means of an
Earthing Device.
DCD34 Earthing Device
A means of providing a connection between a conductor and earth of adequate
strength and capability for its intended purpose.
DCD35 ECRA Electricity and Co-Generation regulatory Authority.
DCD36 Effectively Earthed System
A power system in which the neutral is connected to earth either directly or through a neutral resistor.
DCD37 Embedded
Having a direct electrical connection to the Distribution System.
DCD38 Event An unscheduled or unplanned (although it may be anticipated) occurrence on or relating to a System including, without limiting that general description, faults, incidents and breakdowns.
DCD39 Event Recorder A certified device that measures and records data at locations on the Saudi System
DCD40 Fault Level
Prospective current that would flow into a short circuit at a stated point on the
System. It is expressed in kA or in MVA.
DCD41 Final Connection Certificate
Is a document issued by the DSP to a User indicating that the User’s
installation is Distribution Code compliant, or is compliant with the
Distribution Code as derogated.
DCD42 Flicker Periodic fluctuations in voltage, at frequencies below the fundamental Frequency. These are generally expressed as percentage variations, relative to the fundamental voltage.
DCD43 Frequency
The rate of oscillation of the AC supply. This is generally expressed as a
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Frequency range, in terms of a nominal Frequency in Hz (cycles per second),
with plus and minus percentage limits.
DCD44 Frequency Control
The control of the Frequency on the Total System
DCD45 Frequency Response
The automatic adjustment of Active Power output from a Generation Unit(s) in response to Frequency changes.
DCD46 Frequency Sensitive Mode
The operation of a Generating Unit whereby its generation level is varied automatically to compensate for variations in the Frequency of the System
DCD47 Fundamental Frequency
The operating or system Frequency of the Power System. Parameters whose
Frequency is the same as the fundamental Frequency are referred to as
fundamental parameters.
DCD48 Generating Plant
A power station with one or more Generating Units.
DCD49 Generating Unit An electrical generator and its associated prime mover, together with all associated Plant and apparatus and any generator transformer, which relate exclusively to the operation of that generator, which in the case of:
a steam turbine will include the boiler and heat exchanger and in addition in the case of a solar concentrator the solar collectors, a gas turbine will include the gas generator/combustion turbine, and a fuel engine will include the engine any gearbox and the prime
mover. In the case of:
wind generation: a wind turbine Generating Unit comprises one or more wind turbine generators that are controlled together, including all Plant and apparatus and any step-up transformer which relates exclusively to the operation of those wind turbine generators. solar generation: a solar Generating Unit is a group of devices which are controlled together to collect or concentrate the sun’s rays within a solar power production facility, together with all Plant and apparatus and any step-up transformer which relates exclusively to the operation of that part of the solar power production Facility.
Generating Units could be Synchronous or Asynchronous.
DCD50 Good Industry Practice
The standard of practice attained by exercising that degree of skill, diligence,
prudence and foresight which would reasonably and ordinarily be expected
from a skilled and experienced operator engaged in the same type of
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undertaking under the same or similar circumstances.
DCD51 Grid Code
The Saudi Arabian Grid Code
DCD52 Harmonics
Sinusoidal currents with a Frequency equal to an integer multiple of the
fundamental Frequency.
DCD53 High Voltage
A voltage, used for the supply of electricity, the lower limit of nominal RMS
value of which is greater than 100kV.
DCD54 IEC
International Electrotechnical Commission.
DCD55 Isolated
Disconnected from associated equipment by an isolator or adequate physical separation.
DCD56 kVA
Kilo-Volt ampere.
DCD57 Limited Performance Certificate
Is a document issued by the DSP to a User indicating that the User’s installation is Distribution Code compliant (or is compliant with the Distribution Code as derogated) except for certain matters which have were previously but are no longer compliant. For the avoidance of doubt, such a certificate can only be issued were the Plant is deemed safe for operation
DCD58 Low Voltage
A voltage used for the supply of electricity, the upper limit of nominal RMS
value of which does not exceed 1kV.
DCD59 Major Customer
A Customer who is supplied at Medium Voltage whose Load is greater than
1MVA
DCD60 Medium Voltage
A voltage used for the supply of electricity, the nominal value of which is between 11kV and 69kV.
DCD61 Normal Operating Frequency
The Frequency at which the system normally operates i.e. 60Hz.
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DCD62 Operation A scheduled or planned action carried out on a system.
DCD63 Operational Effect
The effect of any Operation which causes the Transmission System or the
Distribution System, or the system of other Users, to operate (or be at a
materially increased risk of operating) differently from the way in which they
would or may have operated in the absence of such Operation.
DCD64 Output
As the context requires, the Active Power delivered in MW, the Reactive
Power delivered or absorbed in MVAr or the Apparent Power in MVA of a
Generating Unit, measured by certified meters at the Connection Point or
measured at some other point and adjusted by adjustment factors.
DCD65 Planned Outage
An outage of Generating Plant or of part of the Transmission System or of part
of the Distribution System other than a forced outage.
DCD66 Plant
Fixed and movable items used in the generation and/or supply and/or transmission and/or distribution of electricity other than apparatus.
DCD67 Power Factor
The ratio of Active Power to apparent power.
DCD68 Power Park Module
An Asynchronous Renewable Energy Generating Unit which, for the
avoidance of doubt, is based upon a single device or group of devices
generating electricity, which:
are connected to the network Asynchronously or through power
electronics,
has a single Connection Point to the Distribution System, and
is/are controlled to behave as one Generating Unit.
DCD69 Power Producer
The person who generates electricity
DCD70 Protection
The provisions for detecting abnormal conditions in a System and initiating
fault clearance or actuating signals or indications.
DCD71 Reactive Power
The product of voltage and current and the sine of the phase angle between
them which is normally measured in Kilo vars (kVAR) or Mega vars
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(MVAR).
DCD72 Registered Capacity
Refers to a Generating Unit and is the normal full Load capacity of that
Generating Unit in MW measured at the Connection Point and set down in the
Connection Agreement having regard to Reactive Power or Power Factor
requirements under this Distribution Code.
DCD73 Renewable Resource
Refers to energy sources deemed to cause no or low carbon emissions and
includes solar, wind, geothermal and energy from waste. Hybrid technologies
are assessed as renewable when operating solely on renewable resources.
DCD74 Retail Business The business of bulk purchase for the purpose of retail sale of electricity to Consumers or large consumers authorized by a license.
DCD75 Safety Management
The procedure adopted by the DSP or a User to ensure the safe operation of
its system and the safety of personnel required to work on that system.
DCD76 Safety Procedures
The procedures which are specified within a Safety Management system.
DCD77 Significant Incident
An Event which has had or which may have an Operational Effect on the
Transmission or Distribution system or on a User’s installation.
DCD78 Stand-by
In relation to an electricity generator, means a Plant which is not connected in
such a way as to be Synchronised with the Total System. Such a generator is
not to be operated in parallel with the Total System and, for the avoidance of
doubt, is not a Generating Unit within the meaning of the Distribution Code.
DCD79 Step Change in Voltage
A step change is defined as a single, rapid change of the RMS voltage.
Distribution System voltage step changes can occur due to switching in and
out of capacitors, lines, cables, transformers and other Plant.
DCD80 Synchonise
The condition where a Generating Unit, or a System, is connected to the
busbars of another system or the Total System, so that the Frequencies and
phase relationships of that Generating Unit or System are identical (within
operational tolerances) to those of the other system or the Total System
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DCD81 Synchronous
Refers to a Generating Unit or drive and has the meaning that the Plant or
drive is linked to the System Frequency by a Synchronising torque. In general,
this means that there is a natural contribution to the inertia of the Total System,
which assists in stabilising the Total System after a disturbance.
DCD82 System Tests
Those tests which involve simulating conditions or the controlled application
of irregular, unusual or extreme conditions on the Total System or any part
of it, but not including routine testing, Commissioning or re-commissioning tests.
DCD83 Temporary Connection Certificate
Is a document issued by the DSP to a User indicating that the User’s installation is Distribution Code compliant (or is compliant with the
Distribution Code as derogated) except for certain matters which have not
yet been tested.
The matters to be demonstrated and the period of validity of the Temporary Compliance Certificate are stated in the certificate together with the
consequences of:
insufficient System conditions to determine compliance within the
validity period of the certificate; and
inadequate performance of the Plant under actual System conditions.
.
DCD84 Total Harmonic Distortion
Total harmonic distortion is the aggregate of the harmonic distortions at all
harmonic frequencies. This is expressed as the root mean square value of
harmonic distortions, at all harmonic frequencies.
DCD85 Total System
The Distribution System together with its connected Customer
installations in Saudi Arabia or part thereof (as the context requires)
and including (as the context requires) the effects of connection to
the Transmission System.
DCD86 Trading Business
The business of bulk purchase for the purpose of sale of electricity from/ to
other Licensees or large Consumers authorized by a license.
DCD87 Transmission System
Reference shall be made to the Saudi Arabian Grid Code (SAGC) for detailed
definition.
DCD88 Transmission Service Provider (TSP)
The legal entity that is licensed to own and maintain a network on the Transmission System (or has such right by virtue of its historic existence for
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this purpose).
DCD89 User
A term used in various sections of the Distribution Code to refer to the persons using the Distribution System, more particularly identified in each section of the Distribution Code.
DCD90 Voltage
Electrical pressure
DCD91 Voltage Control
The retention of the voltage on the System within acceptable limits
DCD92 Voltage Reduction
A method to control Demand temporarily by reduction of system voltage.
DCD93 Voltage Unbalance
In three-phase networks, the conditions in which the RMS values of the phase voltages, or the angles between consecutive phases, are not equal.
DCD94 Zero Phase Sequence
A set of phases of equal magnitude and zero phase angle, relative to each
other. The 3-phase values are thus in phase with each other. The term zero
sequence may be applied, in the same sense, to AC voltages and currents.
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SECURITY
AND PLANNING STANDARDS
FOR THE DISTRIBUTION SYSTEM (Demand Customers Only)
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CONTENTS 1.0 INTRODUCTION
1.1 General 93
1.2 Definition 93
1.3 Aim of Planning 95
2.0 DISTRIBUTION SYSTEM 96
2.1 Standard Configuration 96
2.2 Voltage Levels 97
2.3 Effects of Disturbing Loads 97
3.0 ASSESSMENT OF NEW LOAD 98
3.1 Application Form 98
3.2 Information Required from Customers 98
3.3 Need for room substation 99
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INTRODUCTION
1.1 General
The DSP(s) is required to operate and ensure the maintenance of and develop, as
necessary, a safe, secure, reliable, economical and efficient electricity
Distribution System.
To this end, this document, “Security and Planning Standards for the Distribution System” has been prepared in accordance with the Distribution Code.
It outlines DSP(s)‟s approach to the development of the network, giving details of
how the connection of new loads and Embedded Generators to the Distribution
System are assessed. It is intended as a guide to Users of the Distribution System.
While this guide refers to Customer’s loads, the same factors will apply, in general,
to Generators also. There are however, some specific requirements relating to
Generators and these are included under a separate heading (part- 4).
1.2 Definitions
In general the terms used in this document have the meanings intended in the
Distribution Code. As a brief guide, the terms used in this document are defined below:
Term Definition
Connection
Asset
The network erected to connect the Connection Point
to the existing Distribution System. The connection
asset forms part of the Distribution System and is not
shared by other Users.
Continuity or
Continuity of
Supply
This describes the quality of a supply as it relates to
outages, whether caused by faults or planned work.
A set of measures are required to describe continuity
but, in general, the lower the incidence of outages
and the shorter their duration, the higher the
continuity.
Distribution System The electric lines, Plant and switch-gear used to
convey electricity to final Customers (excluding
Customers connected directly to the Transmission
System (grid)).
Disturbing Load An electrical load that of its nature may affect the
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quality of electricity supply of other Customers.
Examples are welders, large electric motors etc.
Flicker
Voltage fluctuations, caused by a disturbing load
(or rapid variations in Generator output), the major
effect of which is Flickering of standard
(incandescent) light bulbs.
Looped Connection
As described in DPS
Losses
Electrical losses are the difference between the
energy entering the Distribution System and that
delivered to Customers. Losses are the energy lost
in the network due to the heating effect of the
electricity passing through it.
Maximum Import
Capacity
This is the maximum load that the Customer has
contracted with DSP(s).
Normal Feeding
The network configuration under normal
conditions and when all distribution Plant is in
service. The normal feeding arrangement is
typically designed to provide best voltage
performance, to minimize network losses and to
make optimum use of the capacity of feeding
substations.
Security of Connection
The expectation that the Connection Point will
remain energized.
Short Circuit Level
The short circuit level is a measure of the
“strength” of the network i.e. the ability to limit the
impact of Disturbing Loads and to maintain
voltage stability. The size of the Customer
switched load relative to the short circuit level
determines the magnitude of its impact on the
voltage.
Short Circuit Rating
This refers to the short circuit rating of the item of
Plant concerned.
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Standby Feeding The feeding arrangement when one or more items
of network Plant is out of service. The exact feeding
arrangement will depend on which items are out of
service. As standby feeding is a temporary
arrangement, different standards of voltage apply.
Bulk Customer
substation
A standard structure owned and operated by
substation DSP(s) containing the distribution
equipment necessary to connect a Customer to the
Distribution System. Terminal substations are
operated at the connection voltage of the Customer
i.e. transformation is not required.
Distribution
substation
A standard structure owned and operated by
Substation DSP(s) containing one or more
transformers, to convert electricity at one standard
distribution voltage to a lower standard voltage.
1.3 Aim of Planning
The aim of planning is to ensure that the Distribution System is developed in an
orderly and cost effective manner. It is necessary to ensure that there is capacity
available to meet new loads as they arise, and to meet ongoing growth
requirements. It is also necessary to ensure that new connections are made:
1. in an economic fashion
2. with a view to the possible future needs of the Customer and the network 3. in a way that is technically acceptable
In general the MV networks are planned to a single contingency standard. This
means that the system is designed to withstand a single contingency, and any
outages experienced for this single contingency are only for such time as is
required to transfer load from faulted Plant. In summary, DSP(s) will provide
Customer connections which will deliver the required capacity to an acceptable
standard as detailed in the Distribution Code and will comply with the Saudi
Arabian Grid Code (SAGC) at all points of connection to the Transmission System.
A higher standard of installation or a higher security of connection arrangement
can be provided at the Customer’s request, with the provision that any additional
costs will be attributed in full to the Customer.
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2.0 DISTRIBUTION SYSTEM
2.1 Standard Configuration
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2.2 Voltage Levels
There are a number of standard voltages in use on the Distribution System and
Customers will be connected at one of these levels. Voltage Levels at which a
connection can be provided are as follows:
Voltage Level
Nominal Voltage
Low
Voltage
(LV)
220/127V (phase-phase/phase-
neutral)
380/220V (phase-phase/phase-
neutral)
400/230V (phase-phase/phase-
neutral)
Medium
Voltage
(MV)
13.8kV, 33kV , 69kv(standard)
11kV, 34.5kV (existing but non-
standard)
Table 1: Distribution System Nominal Voltages
2.3 Effects of Disturbing Loads
Certain types of equipment such as motors and welders may cause
fluctuations in the supply voltage which cause disturbances to the
connection of other Customers. Where Customers intend to install any
equipment likely to cause supply disturbances, this equipment must be
evaluated to assess the likely impact. The limits imposed on Disturbing
Loads are specified in the Distribution Code. It may be necessary,
depending on the characteristics of the equipment, for a Customer
connection to be made using a different network configuration via a
higher voltage, a dedicated substation or other method.
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3.0 ASSESSMENT OF NEW LOAD
3.1 Application Form
The assessment of the connection for a new load requires details of the
load. The details should be provided by completing an application form.
3.2 Information Required from Customers
Details of the information required from Demand Customers and
Generators seeking connections or extensions to the Distribution System
are provided in the Distribution Code. Application forms for connection
are available from DSP(s) offices, and are on the DSP(s)‟s website.
Specifically the following information may be requested, depending on
the nature of the load:
3.2.1 Geographical Location
Site location maps and site layout plans in order to determine the location
of the proposed load in relation to the existing network and plan cover
area
3.2.2 Maximum Import Capacity (MIC)
Maximum Import Capacity (MIC) required, the size and nature of the
load, diversity of the load and proposed phasing of the development i.e.
the pace at which the load is expected to increase from a specified initial
Demand to the full Demand.
3.2.3 Disturbing Loads
Details of any disturbing elements of the load are required such as:
Large motors - details of starting arrangements for all large motors. Disturbing Loads i.e. electric welding, and details of the nature and
usage pattern of the disturbing load.
Harmonics - details of any non-linear equipment likely to produce
Harmonics on our system and any filtering arrangements which the
Customer may have already in place. The Customer should also
provide details of compensation or balancing equipment connected. Unbalanced Loads - Where a Customer has a three phase supply, load
should be balanced as evenly as possible over the three phases.
The above is an example of the information which may be requested.
Depending of the size and complexity of the load, additional information
may also be requested.
Power Factor - The Power Factor of the Customers load as seen by the
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network must be 0.85 or higher. No Customer may present a leading
Power Factor load to the DSP(s) system.
3.2.4 Multiple Customer Development Versus Single Load Whether the
application is for infrastructure to facilitate connections to multiple end
Customers within a development or is for connection of a single
Customer.
3.2.5 Specific Requirements
Details of any specific Customer requirements for connection of the load.
3.2.6 Load Coincidence
Customers should note when assessing the Capacity requirements that
not all of the equipment will be operating at full load at the same time.
The Customer should apply a coincidence factor to each component of
the load, as well as to the overall load in order to assess the capacity
required. Coincidence factors will vary depending on the nature of the
load.
3.3 Need for room substation
As per DSP(s) Customer service manual.