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EMPLOYERS REQUIREMENTS
MV NETWORK PLANNING STANDARD
NEOM-NDS-EMR-005 Rev 1.0, November 2024
©NEOM [2024]. All rights reserved.
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Document history
Revision code
Description of changes
Purpose of issue
Date
V1.0
Updated Document
First version for publication
DD.12.24
Document approval
Prepared by
Reviewed by
Approved by
Name
Anuj Chhettri
Gavin Anderson
Rimnesh Shah
Job Title
DSO Principal Planning
Engineer
DSO Principal Planning Engineer
Head of Grid
Development
Planning
Signature
Date
DD.12.2024
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Contents
1
PURPOSE ............................................................................................................................. 6
2
SCOPE .................................................................................................................................. 7
3
DEFINITIONS ....................................................................................................................... 7
3.1
Terms .................................................................................................................................... 7
3.2
Abbreviations ......................................................................................................................10
4
REFERENCES ....................................................................................................................11
4.1
DSO Documents .................................................................................................................11
4.2
International Standards .......................................................................................................11
4.3
Other Documents ................................................................................................................11
5
REGULATIONS AND DOCUMENT APPLICATION ..........................................................12
6
MV SYSTEM CHARACTERISTICS ...................................................................................12
6.1
Background .........................................................................................................................12
6.2
Voltage Levels .....................................................................................................................14
6.3
Network Frequency Limits...................................................................................................14
6.4
System Reliability ................................................................................................................14
6.5
Power Quality ......................................................................................................................14
6.6
System Phasing and Vector Groups ...................................................................................14
6.7
Short Circuit Levels .............................................................................................................15
6.8
Network Losses ...................................................................................................................16
6.9
Power Factor Correction .....................................................................................................17
6.10
System Earthing ..................................................................................................................17
7
MV NETWORK DEVELOPMENT .......................................................................................18
7.1
System Design ....................................................................................................................19
7.2
MV Feeder Configuration ....................................................................................................19
8
CONNECTION DESIGN .....................................................................................................20
8.1
Types of Supply ..................................................................................................................20
8.2
MV Connection Capacity.....................................................................................................21
9
DEMAND ESTIMATION .....................................................................................................22
9.1
LV / MV Customers .............................................................................................................22
9.2
MV Network Demand ..........................................................................................................22
9.3
Load Forecasting ................................................................................................................23
9.4
Power Supply Request Forms ............................................................................................23
10
SECURITY OF SUPPLY AND NETWORK CAPACITY ....................................................23
10.1
Security of Supply ...............................................................................................................23
10.2
Customers Resiliency .........................................................................................................26
10.3
Guaranteed Standards ........................................................................................................26
10.4
MV Network Capacity ..........................................................................................................27
11
MV SYSTEM CONFIGURATION .......................................................................................29
11.1
General................................................................................................................................29
Internal
Internal
11.2
PSS, MVSS and MVSW......................................................................................................29
11.3
Standard MV Feeders .........................................................................................................30
11.4
MV Connections ..................................................................................................................32
11.5
MV Feeder Restoration .......................................................................................................32
11.6
Customer Connection Co-ordination ...................................................................................33
11.7
Metering Arrangements and Specifications ........................................................................34
11.8
Interfaces with Connected Parties ......................................................................................34
12
DISTRIBUTED ENERGY RESOURCES AND MICROGRIDS ..........................................34
13
STANDARD PLANT ...........................................................................................................36
13.1
Transformers .......................................................................................................................36
13.2
MV Switchgear ....................................................................................................................38
13.3
Cable Circuits ......................................................................................................................41
13.4
Fibre Optic Cable ................................................................................................................47
13.5
MV System Protection .........................................................................................................48
13.6
MV System Analogue Measurement ..................................................................................50
14
SYSTEM STUDIES AND MODELLING .............................................................................50
14.1
System Studies ...................................................................................................................50
14.2
System Model .....................................................................................................................51
15
SYSTEM REINFORCEMENT AND REPLACEMENT .......................................................51
15.1
Reinforcement .....................................................................................................................51
15.2
Replacement .......................................................................................................................51
15.3
Performance Criteria ...........................................................................................................51
16
PLANT LOCATION AND ROUTING CIRCUITS ................................................................52
16.1
Location of substation .........................................................................................................52
16.2
Routing of Underground Cables ..........................................................................................52
APPENDIX I: MV NETWORK CONFIGURATION ...............................................................................54
APPENDIX II: TYPICAL SUBSTATION DIAGRAM ............................................................................56
APPENDIX III: MV STANDARD CONNECTION ARRANGEMENT ...................................................61
APPENDIX IV: MV DEMAND ESTIMATION METHODOLOGY ..........................................................68
APPENDIX V: POWER REQUEST APPLICATION.............................................................................71
List of Figures
Figure 1: MV System Overview............................................................................................................ 13
Figure 2: NEOM standard vector relationship ...................................................................................... 15
Figure 3: MV Network Design Approach .............................................................................................. 18
Figure 4: Typical demand groups (section of network) in a network ................................................... 24
Figure 5: Firm supply (2xCircuits) for a two-transformer substation .................................................... 28
Figure 6: Firm supply (3xCircuits) for a three-transformer substation ................................................. 28
Figure 7: Restoration sequence for MV feeder following first circuit outage condition ....................... 33
Figure 8: Typical MV switchgear types ................................................................................................ 39
Figure 9: Examples where do duct de-rating is required ..................................................................... 42
Figure 10: 13.8 kV underground cable configuration ........................................................................... 54
Figure 11: 33 kV underground cable configuration .............................................................................. 55
Figure 12: Example of two transformer MVSS with a 30 MVA firm capacity ....................................... 57
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Figure 13: Example of two transformer MVSS with a 40 MVA firm capacity ....................................... 58
Figure 14: Example of two transformer MVSS with a 50 MVA firm capacity ....................................... 59
Figure 15: Example of three transformer MVSS with a 60 MVA firm capacity .................................... 60
Figure 16: Connection Arrangement 1.1 .............................................................................................. 61
Figure 17: Connection Arrangement 1.2 .............................................................................................. 62
Figure 18: Connection Arrangement 1.3 .............................................................................................. 63
Figure 19: Connection Arrangement 1.4 .............................................................................................. 63
Figure 20: Connection Arrangement 2.1 .............................................................................................. 64
Figure 21: Connection Arrangement 2.2 (option 1) ............................................................................. 65
Figure 22: Connection Arrangement 2.2 (option 2) ............................................................................. 65
Figure 23: Connection Arrangement 3.1 .............................................................................................. 66
Figure 24: Connection Arrangement 3.2 .............................................................................................. 67
Figure 25: MV demand calculation example ........................................................................................ 69
List of Tables
Table 1: System short-circuit design levels .......................................................................................... 15
Table 2: Standard NER values............................................................................................................. 18
Table 3: Classification of Types of Connection .................................................................................... 21
Table 4: Nominal capacity for standard connection arrangement ..................................................... 21
Table 5: Network Demand Coincident Factors .................................................................................... 23
Table 6: Security of Supply for MV groups (in accordance with NEOM Grid NESSS) ........................ 25
Table 7: Maximum loading of different types of feeders ...................................................................... 30
Table 8: DERs integration voltage level in accordance with their power capacities ............................ 35
Table 9: Typical Transformer Impedance for 33/13.8 kV transformer ................................................. 37
Table 10: 33/13.8 kV Power Transformer Standard Ratings ............................................................... 37
Table 11: MV Switchgear continuous current ratings .......................................................................... 39
Table 12: MV RMU rated voltage and short-circuit ratings .................................................................. 40
Table 13: Standard MV cable ratings (Unarmored cable) .................................................................. 43
Table 14: Standard MV cable ratings (Armored Cable) ....................................................................... 43
Table 15: Typical MV subsea cable ratings (Armored Cable) ............................................................. 44
Table 16: Cable derating factors for multiple cable installation as per NEOM-NDS-STD-221 ............ 44
Table 17: Standard cable sizes for transformer tails ........................................................................... 45
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1
PURPOSE
The purpose of this document is to provide guidance on the economic design, considering
source of 100% renewable generation, energy efficient network development, safe and
reliable operation of Medium Voltage (MV) network (i.e., 33 kV, 22 kV and 13.8 kV) across
the NEOM regions.
The purpose of this document is to provide a high-level standard for the design of NEOM’s
MV networks including the railway Non-Traction Power System for Line Side Facilities which
is separarely covered in NEOM-NEG-EMR-007, so that a consistent approach can be
applied to all networks in the NEOM regions, whilst permitting System Planners freedom for
original thinking to resolve each unique network problem with a bespoke solution that takes
advantage of local circumstances while considering the whole life implications for the
associated assets.
The aim of a carbon neutral electricity network across the NEOM regions can largely be
rationalized by standardization of the specifications for plants (cable, transformer &
switchgear), protection system, remote control, network automation, and earthing. These
standards dictate the building blocks from which the system can be developed.
It is expected that MV network design is economically efficient and for this reason, standard
network configurations are presented in this document. Such configurations may not be
wholly feasible in all circumstances but they provide the basis of the principles and network
configuation preferred. The NEOM region exhibit contrasting differences in the geography,
load density and the nature and expectation of the customers load demand. Hence,
bespoke network configurations are expected but they are out of scope of this document.
This document sets out the applicable parameters of an electricity supply, such as system
frequency, continuity and quality of supply, and voltage limits. Thus, ensuring that
customers have satisfactory performance for their electrical equipment, that the electricity
demands continue to be met from renewable sources, and that the capital and operating
costs associated with doing are kept to a minimum.
This document requires compliance with the Distribution License Conditions of KSA, i.e.,
KSA DCODE, in the interim and also factors the principles of the NEOM Grid Code being
developed at the time of this document’s publishing.
This document has been developed with consensus and in coordination with all ENOWA
GRID departments.
This document is applicable to the private network operators interfacing with the NEOM
Electricity distribution systems.
This document will remain under close review as the MV system develops and whilst
reasonable efforts are made to ensure the accuracy of technical content, the ENOWA GRID
disclaims liability for the way this document is used or for any misinterpretation. The user of
this document is responsible for ensuring the correct interpretation and use the latest
version of this document.
This document should be read in conjunction with the KSA DCODE, NEOM Grid Code,
NEOM Grid Connection Technical Requirements (NGCTR), NEOM Distribution System
Design Standard NEOM-NDS-EMR-003 and LV Network Planning Standard NEOM-NDSEMR-006.
NOTE:
The following terms are used throughout this standard to define the flexibility of each
requirement:
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a) Must/Shall: denotes a requirement that is mandatory. Designs and/or solutions that do
not comply the requirement will not be considered. These are pass or fail criterions.
b) Should: denotes a requirement for which the third party (or parties) undertaking the task
may put forward an alternative solution. Requirements denoted by should are pass or fail
criterion unless NEOM or its representatives accept the alternative solution.
c) Prefer/Preference: denotes a desirable feature or parameter. Compliance or otherwise
with such desired characteristics will form part of the evaluation of each solution.
d) May/Might: denotes a deviation from the specification that is not preferred but which
NEOM or its representatives may accept if there are compelling reasons to do so.
e) Will: denotes an activity that NEOM or its representatives will undertake or provides
information as to the application for the equipment and the way it is used. These clauses
are normally informative and do not normally denote a requirement withing the scope for
the third party (or parties).
2
SCOPE
This standard applies to
•
The planning and design of ENOWA DSO MV networks including the railway NonTraction Power System for Line Side facilities , i.e., AC system medium voltages;
•
All assets with a nominal operating voltage from 1 kV upto 33kV (i.e., 13.8 kV, 22
kV and 33 kV), including the MV switchgear at HV to MV substations, 33/13.8 kV
transformer at MV substations (MVSS), MV switching station, and MV switchgear at
Distribution Substation (DSS);
•
The development of the MV network, including new connections, system
reinforcement, and asset replacement.
Where distributed generation is embedded within a lower or medium voltage system and
may have an impact on the MV distribution system, this standard shall be supported by
good practices technically applicable to the network.
The requirements that are excluded from the scope of this document are listed as follows:
3
•
Planning and design of electrical infrastructure on the consumer side of the meter,
•
Planning and design of overhead line assets, and
•
Planning and design of MV DC systems.
Definitions
•
3.1
For a comprehensive list of definitions for the terms and abbreviations used at
NEOM, see the List of Definitions and Abbreviations (NEOM-NEN-SCH-006).
Terms
Term
Definition
Company
The owner of the Neom region is named "NEOM".
Coincident Demand
Load (CDL)
It is the maximum (coincident) demand load of a customer's building
with multiple units over a specified interval of time. It must be
calculated from the Total Demand Load of that customer's building
multiplied by the approved coincidence factor of that customer's
building. It is expressed in Volt-Amperes (VA).
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Term
Definition
Coincident Factor
It is the ratio of the Coincident Demand Load of a customer's building
with a group of units (kWh meters) to the Total Demand Load of that
customer's building, both taken at the same point of supply.
Connected Load
Total load connected at a customer premises (Demand factor is
applied to derive the Maximum Demand for the customer). It is also
often referred to as Total Connected Load (TCL).
Customer
Entity with a metered electricity supply
Demand factor
Ratio of the maximum demand for a customer to the connected load
of that customer's premises
Distribution Network
The system, consisting of (wholly or mainly) electric lines and
associated switchgear and transformers, owned or operated by the
DSO and used for the distribution of electricity
Distribution System
Operator (DSO)
A business unit of ENOWA and, for the purposes of interpreting this
Technical Specification/Standard/Strategy, the representative of the
company
Demand Side
Response (DSR)
Demand that is controlled in response to an instruction issued as part
of an agreed demand-side management arrangement with the DSO.
Distribution
substation
Site containing a MV Switchgear, distribution transformer(s) (13.8/0.4
kV, 33/0.4 kV, 22/0.4 kV) and LV switchboard
Diversity factor
Co-efficient applied to the Maximum Demand for a group of customers
to account for the diversity of demand usage across that group
ENOWA
Subsidiary of the Company
Firm Capacity
The maximum connection capacity that the specified connection
arrangement can secure following a first circuit outage or loss of the
system's main item of plant.
First Circuit Outage
Condition
A network's operational states where one piece of equipment is out of
service because of a fault or due to a planned outage or
reconfiguration to facilitate maintenance or repairs are referred to as
the first circuit outage. It is also referred as N-1 condition.
Generator
Source of electrical energy and all associated interface equipment
able to be connected to an electric circuit and designed to operate in
parallel with the NEOM Distribution Network
Grid Code
The KSA Grid Code in conjunction with the NEOM Grid Connection
Technical Requirements (NGCTR).
Group Demand
DSO’s estimate of the maximum demand of the group being assessed
for security of supply compliance with appropriate allowance for
diversity
KDAF
Refers to a transformer that has the same transformer oil as KNAN,
but with directional forced circulation of oil via pump over the cooling
surface and forced air cooling.
KDAN
Refers to a transformer that has the same transformer oil as KNAN,
but with directional forced circulation of oil via pump over the cooling
surface.
KNAF
Refers to a transformer that has the same transformer oil as KNAN,
but with external forced air cooling.
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Term
Definition
KNAN
Refers to a transformer that uses less flammable non-mineral (i.e.,
natural ester) oil as the insulating fluid, such as natural ester, with a
fire point greater than 300°C having cooling obtained by the natural
circulation of air over the cooling surface.
Latent Demand
Demand (also called as Gross Demand) that would appear as an
increase in measured demand if the Generation was not operating,
and the DSR was not implemented.
Maximum demand
Maximum load expected to be drawn by a customer or group of
customers. Maximum demand for individual customers is the ratio of
the Total Demand Load (TDL) and Demand Factor (DF), whereas the
maximum demand load for a group of customers is the Coincident
Demand Load (CDL), which is the ratio of Total Demand Load (TDL)
for a group of customers and Coincident Factor (CF).
Manufacturer/Supplier
The party (or parties) that manufactures and/or supplies
equipment/materials, technical documents/drawings, and services to
perform the duties specified by the Company.
NEOM Grid
Connection Technical
Requirements
The NEOM Grid Connection Technical Requirements sets out the
specific requirement for connection to NOEM 100% renewable grid
and shall be read in conjunction with the KSA Grid Code, NGCTR will
be included in the Grid Connection Agreement
Point of Common
Coupling
The point on the DSO Network, electrically nearest the Customer’s
Installation, at which other Customers are, or maybe, connected.
NOTE: The Point of Common Coupling is normally the same as the
Point of Connection.
Point of Connection
The point on the existing DSO network to which new assets supplying
Customer(s) are or will be connected. Point of Connection may also
be referred to as Connection Point.
NOTE: The Point of Connection is normally the same as the Point of
Common Coupling.
Point of Supply
The point of electrical connection, specified in the connection
agreement, between the System Operator and apparatus owned by a
customer (demand/generation).
Second Circuit Outage
Condition
A network's operational states where two piece of equipment is out of
service simultaneously. This is usually due to the occurrence of a fault
at the same time as a planned outage. It is also referred as N-2
condition.
SERA
The Saudi Electricity Regulatory Authority (SERA) regulates the Saudi
Electricity Company (including generation, transmission, distribution,
trading, and retail sales) and its subsidiaries in accordance with the
Electricity Law and its implementing rules.
Subcontractor / Subsupplier
The party (or parties) that is performing all or part of those services
under a separate contract with the Manufacturer / Supplier.
Total installed
capacity
The total aggregated continuous rating of the generator(s) inverters.
NOTE: In cases where the amount of generation (e.g., battery export)
installed behind an inverter is greater than the inverter rating, the
Installed Capacity shall still be taken as equal to the inverter rating (as
the inverter limits the power seen at the Point of Connection).
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3.2
Abbreviations
Abbreviation
Definition
AC
Alternating Current (also “a.c.”)
Al
Aluminum (conductor)
CB
Circuit-Breaker
CBA
Cost Benefit Analysis
CDL
Coincident Demand Load
CF
Coincident Factor
CT
Current Transformer
Cu
Copper (conductor)
DC
Direct Current (also “d.c.”)
DETC
De-energized Tapchanger
DF
Demand Factor
DSO
Distribution System Operator
DSS
Distribution Substation (e.g., 33/0.4 kV, 22/0.4 kV and 13.8/0.4 kV)
HV
High Voltage (sytem voltage less than or eqaul to 380 kV a.c. and
greater than 33 kV a.c.)
IEC
International Electrotechnical Commission
IEEE
Institute of Electrical and Electronics Engineers
IP
Ingress Protection
LV
Low Voltage (system voltage normally exceeding extra-low voltage (50
V) but not exceeding 1000 V a.c. or 1500 V d.c. between conductors
or 600 V a.c. or 900 V d.c. between conductors and earth).
MV
Medium Voltage (system voltage less than or equal to 33 kV a.c. but
greater than 1 kV)
MVSS
Medium Voltage Substation (33/13.8 kV)
MVSW
Medium Voltage Switching Station (33 kV, 22 kV, or 13.8 kV switching
station)
NGCTR
NEOM Grid Connection Technical Requirements
PSCC
Prospective Short Circuit Current
PCC
Point Of Common Coupling
PSS
Primary Substation (132/33 kV, 132/22 kV and 132/13.8 kV)
SERA
Saudi Electricity Regulatory Authority
SCADA
Supervisory Control and Data Acquisition
TCL
Total Connected Load
TDL
Total Demand Load
VT
Voltage Transformer
XLPE
Cross Linked Polyethylene
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4
References
4.1
DSO Documents
4.2
Document no.
Document title
NEOM-NEG-EMR-002
Design Basis Document, Part 2 - Design
NEOM-DSO-EMR-003
Distribution System Design Standard for MV Grid
NEOM-NDS-EMR-006
LV Network Planning Standard
NEOM-NDS-SPC-001
XLPE Insulated Power Cables for Rated Voltages of 13.8 kV and 33
kV
NEOM-NDS-SPC-008
LV AC Auxiliary Distribution Board Assemblies for Major Substations
NEOM-NDS-SPC-011
Specification for Fibre Optic Cables
NEOM-NDS-SPC-009
3-Phase Oil Immersed Power Transformers for 33/13.8 kV up to 60
MVA
NEOM-NDS-SPC-165
Specification for 110V and 24V Auxiliary DC Power Supplies
NEOM-NDS-SPC-019
33 kV and 13.8 kV Metal-enclosed Switchgear for Distribution
Substations
NEOM-NDS-STD-008
Earthing Standard
NEOM-NDS-STD-202
Installation Requirements for LV and MV (13.8 kV, 22 kV and 33 kV)
Underground Cables
NEOM-NDS-STD-221
MV Cable Ratings for 13.8 kV and 33 kV Underground Cables
NEOM-NEG-EMR-007
Design Basis Document Non-Traction Power System Requirements
International Standards
Document no.
Document title
IEC 60076-7
Power transformers – Part 7: Loading guide for mineral-oil-immersed
power transformers
IEEE 1547
IEEE Standard for Interconnection and Interoperability of Distributed
Energy Resources with Associated Electric Power Systems Interfaces
IEC62128-2022
50122-1: 2022)
4.3
(EN
Railway Applications – Fixed Installations Electrical Safety, Earthing
and the Return Circuit – Part 1: Protective Provisions Against Electric
Shock.
Other Documents
Document Type
Document title
NEOM Grid
Connection Technical
Requirements
The NEOM Grid Connection Technical Requirements sets out the
specific requirement for connection to NOEM 100% renewable grid and
shall be read in conjunction with the KSA Grid Code, NGCTR will be
included in the Grid Connection Agreement
SA DCODE
Saudi Arabia Distribution Code, April 2021
SEC DPS
SEC Distribution Planning Standard (SDPS), 2018
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5
Regulations and Document Application
At the time of this document’s publication, the NEOM Grid Code was in final the stages of
development. The prevailing document or code that applies until the NEOM Gird Code is
ratified in the Neom Grid Code Technical Requirements (NGCTR) and Saudi Arabia
Distribution Code (SA DCODE). There are certain network characteristics stipulated in this
document which are explicitly referred in the NEOM Grid Code.
This document is applicable to all new MV network development within NEOM regions
including the Non-Traction Power System for the railway Line Side Facilities (NEOM-NEGEMR-007 which is specific to the railway power distribution system)
However, any reinforcement or alteration to the existing system will be required to comply
with this standard. Detailed guidance relating to individual MV system design proposals is
outside the scope of this document. The MV system design proposal shall be produced on
an individual basis, following the parameters set out in this document.
The requirements outlined in this document will apply to most of the situations where the
MV system will be developed. However, there will be exceptional cases where special
arrangements, which are not strictly in accordance with this document, may be more
appropriate and such variations can be considered where there are benefits to both NEOM
and its customers. Any such deviations, which shall be broadly in line with the principles
described in this document, shall be agreed upon with the Head of Grid Planning &
Development at an early stage of the planning process, with notification provided to the
GRID DSO team where the deviation has strategic implications.
This Standard shall be read in conjunction with NEOM Design Basis Documents and
relevant Industry standards.
6
MV SYSTEM CHARACTERISTICS
6.1
Background
The ENOWA GRID Planning department is responsible for the system planning and
development of the 13.8 kV, 22 kV, and 33 kV electricity networks. The scheme
assessment, optimization, capital cost estimation, scheme justification, and authorization for
the definition of the system parameters are deemed to be carried out by the DSO planning
department.
The main purpose of the MV system development is to distribute electricity in different
geographical areas of NEOM with varied loads and load densities in an economic, efficient,
safe, and secure manner, meeting the current and future needs of the electricity supply
customers. The MV system supplies will be at the MV level to distribution substations,
larger demand customers, generation customers, and customer loads operated by Private
Network Operators.
The selection of an appropriate MV voltage level for any design shall be based on
consideration of the load to be connected, the distance of load from the source substation,
as well as cost justifications. It is the DSO’s expectation that the future MV network
architecture will be based on either 13.8 kV or 22 kV. However, at the time of this
document’s publishing the necessary 22 kV architecture and equipment are in development,
so the preference should be for 13.8 kV. Any design that proposes to utilize 22 kV shall be
referred to the DSO planning team for approval, along with the relevant technical and
economic justification. Information contained in this document making reference to 22 kV is
intended at this time for future utilization. Figure 1 depicts an high level overview of the MV
system offerting offering a a clear understanding of its structure and functionality.
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Infeed
Substation Types:
Primary Substation (PSS): 132/33kV, 132/22kV and 132/13.8kV
Medium Voltage Substation (MVSS): 33/13.8kV
Medium Voltage Switching Station (MVSW): 33/33kV and 13.8/13.8kV
Distribution Substation (DSS): 33/0.4kV, 22/0.4kV, 13.8/0.4kV
132kV
Primary Subatation
Transmission
(Illustrated)
Primary Subatation
Primary Subatation
Transmission
(Illustrated)
Primary Substation
3 x 132/33kV
80/100MVA
YNynO+d1
+10% / -15%, Steps 1.25%
2 x 132/33kV
80/100MVA
Dyn1
+10% / -15%,
Steps 1.25%
2 x 132/13.8kV
50/67MVA
Dyn1
+10% -15%, Steps 1.25%
33kV
2 x 132/22kV
50/67MVA
Dyn1
+10% -15%, Steps
1.25%
33kV
33 kV
MV
CUSTOMER
Medium Voltage Substation
MV DISTRIBUTION
Medium Voltage Switching Station
Medium Voltage Substation
33kV
33kV
2 x 33/13.8kV
30/40/50/60MVA
Dyn1
+10%/ -15%, Steps
1.25%
3 x 33/13.8kV
30/40/50/60MVA
Dyn1
+10%/ -15%, Steps
1.25%
13.8kV
MV
CUSTOMER
33kV
Medium Voltage Switching Station
22 kV
MV DISTRIBUTION
13.8kV
13.8kV
MV
CUSTOMER
22kV
MV
CUSTOMER
13.8 kV
MV
CUSTOMER
13.8 kV
Distribution Substation
Distribution Substation
Distribution Substation
NO
13.8 kV
13.8 kV
2 x 13.8/0.4kV
0.5/1/1.5/2 MVA
Dyn11
+/- 5%, Steps 2.5%
2 x 13.8/0.4kV
0.5/1/1.5/2MVA
Dyn11
+/- 5%, Steps 2.5%
0.4 kV
0.4 kV
13.8 kV
Distribution Substation
13.8 kV
1 x 13.8/0.4kV
0.5/1/1.5/2MVA
Dyn11
+/- 5%, Steps 2.5%
Distribution Substation
1 x 13.8/0.4kV
0.5/1/1.5/2MVA
Dyn11
+/- 5%, Steps 2.5%
0.4 kV
Distribution Substation
22kV
33 kV
1 x 33/0.4kV
0.5/1/1.5/2MVA
Dyn11
+/- 5%, Steps 2.5%
0.4 kV
1 x 22/0.4kV
0.5/1/1.5/2MVA
Dyn11
+/- 5%, Steps 2.5%
0.4kV
0.4kV
LV DISTRIBUTION
0.4 kV
LV DISTRIBUTION
LV
LV
CUSTOMER CUSTOMER
LV
CUSTOMER
LV
CUSTOMER
LV
CUSTOMER
LV
CUSTOMER
Figure 1: MV System Overview
Internal
LV
CUSTOMERS
LV
CUSTOMER
Internal
6.2
Voltage Levels
The ENOWA GRID MV system shall operate at the nominal voltages i.e., 33 kV and
13.8 kV. To achieve this, the 13.8 kV and 33 kV busbars at medium voltage substations
respectively will be controlled by the means of Automatic Voltage Control (AVC) relays
controlling the on-load tap changers (OLTC) of the transformer feeding the busbar.
The operating voltage of the MV system directly influences the operating voltage of the LV
system where de-energised tap-changers (DETC) are fitted to MV/LV transformers; in such
cases, care must be taken to manage the nominal voltage at the LV busbar.
In case of customers connected to a MV supply operating at a DSO voltage of 33 kV and
below, the variation must not exceed 5% above or below the declared voltage in
accordance with the SA DCODE. The MV system shall therefore normally be designed to
limit the absolute voltage variation to ±5% of the respective nominal voltage.
Under all conditions, it is mandatory for all customers, including LV customers, to receive
supply voltage within ±5% limits.
6.3
Network Frequency Limits
Standard Frequency: The standard system frequency shall have a nominal value of 60 Hz
which shall be maintained within the limits of 59.9 and 60.1 Hz during normal system
operation, in accordance with the Saudi Arabian Distribution Code.
The system frequency could rise to 62.5 Hz or fall to 57.0 Hz in exceptional circumstance;
refer to the KSA Distribution Code for those exceptional circumstances.
6.4
System Reliability
Any development of the MV system should seek to improve the quality and reliability of the
supply provided, i.e., reduce the number of potential Customer Interruptions (to improve
reliability) and Customer Minutes Lost (to improve availability).
Where system development focusing on improving quality of supply performance is being
designed, the DIgSILENT PowerFactory application shall be used to assess the reliability of
circuits and to design system and protection arrangements that optimize reliability and
customer service benefits.
This policy provides guidance on the use of Remote Control and Automation (refer to
Section 11.3.1) to improve the performance of the MV networks.
6.5
Power Quality
Electrical power quality parameters such as voltage disturbance, voltage flicker, voltage
unbalance, and harmonic voltage distortion by non-linear or disturbing loads shall be
managed for all new connections in accordance with the limits stipulated in the SEC
distribution planning standard document.
Electrical power quality parameters for the railway Non-Traction Power System for the Line
Side Facilities shall be in accordance with EN 50121 – Railway Applications.
Electromagnetic Compatibility
A detailed design for all disturbing loads, such as large motors, welders, and harmonic
distortion equipment must be carried out by the DSO planning team before a new
connection is energised. In some cases, a proposed MV connection for a large disturbing
load may only be accepted if suitible mitigation or reinforcement is carried out.
6.6
System Phasing and Vector Groups
The DSO system shall have a R-Y-B counter-clockwise phase rotation (positive phase
sequence). The transformer vector group and phase connections on the MV system shall be
in accordance with the upstream electricity network.
Internal
Internal
The standard vector group for power transformers at PSS is YNyn0+d1 and MVSS is Dyn1.
The standard vector group for power transformers at DSS is Dyn11.
Figure 2 depicts the vector phase diagrams for the transmision (132 kV), MV, and LV
networks.
Dyn11: D = Delta connection at primary,y =
Star connection at secondary, and n = neutral
point connected at secondary. Dyn 11 means
that the voltage of the secondary star winding
leads the primary phase voltage by 30
degrees and corresponds to 11 o'clock.
R
33kV, 22kV and 13.8kV Voltage Vectors
-300
-1500
+900
R
Y
B
B
Y
R
0.4kV Voltage Vectors
00
-1200
+1200
R
Y
B
B
Y
Figure 2: NEOM standard vector relationship
6.7
Short Circuit Levels
Design short circuit current levels on the MV system are those which can be expected at or
close to HV to MV substations or MV to MV substations. The impedance of cables and
transformers causes the short circuit current to reduce significantly at points on the system
which are remote from such substations.
Short-circuit current is generally higher for phase-to-phase faults than for single-phase to
earth faults due to earthing arrangements and vector group of the source transformer at HV
level, thus particular attention is required for selection of fault current ratings for MV system
equipment to avoid overstressing of the equipment under phase-to-phase fault conditions.
When assessing the capability of MV switchgear, consideration shall be given to the X/R
ratio of the system.
Table 1: System short-circuit design levels
System Voltage
kV
Design Fault
Level
kA
MVA
20
1143
33 (Primary)
Switchgear Short Circuit Ratings
Break
Make
Break and X/R Ratio
(kA rms)
(kA Peak)
(kA rms [X/R])
31.5*
82
31.5* [16.96]
20
52
20 [16.96]
25
65
25 [16.96]
20
52
20 [16.96]
33 (Secondary)
13.8 (Primary)
20
478
13.8 (Secondary)
NOTE 1: Prospective short circuit currents must be kept below equipment nameplate ratings in all new
connection and system changes related to network reinforcement or modification to the ENOWA
network. It is necessary to confirm that the switchgear is sufficiently rated under both normal and
credible abnormal system configurations. The network design fault levels indicated in Table 1 should
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be regarded as the highest threshold level during system planning studies and should not be
surpassed.
NOTE 2: During the planning stage, the operating fault level margin is set at 5%. This means that if
potential short circuit currents exceed 95% of the equipment's assigned rating, the network will be
evaluated to see whether network reinforcement is necessary.
NOTE 3: The short circuit rating of switchgear is a dual rating at an X/R ratio of 16.96 (45 ms) and
45.24 (120 ms).
NOTE 4: A short-time duration of 3 seconds for short circuit should be used when specifying 13.8 kV,
22 kV, and 33 kV switchgear.
NOTE 5: The break fault level rating of a 33 kV switchgear shall be rated at 31.5 kA. When the fault
level duty is much lower as mentioned in NOTE 2 above, the rated short circuit current may be
lowered to 25 kA on a case-by-case basis.
System fault levels shall be constrained within the design limits for each voltage level as
summarised in Table 1. Switchgear installed on the MV system shall be specified with a
minimum three-phase symmetrical short circuit breaking rating as shown in Table 1 which
will allow sufficient fault level headroom for connection of generation and motive loads.
Any modification, extension or addition to the system shall take account of the resultant
changes to the prospective fault currents and ensure that these design limits detailed are
not breached. For example, it is important to conisder short-circuit levels closely when a
system has distributed generation connected or expected to be connected in the future (if it
is economical to do so), to avoid localized increase in short-circuit current and exceedance
of the limits in Table 1.
All equipment connected to the network should be routinely assessed to ensure the network
fault level has not increased above specified equipment ratings. This should be carried out
annually for equipment rated at 33 kV and every five years for equipment rated below 33 kV.
6.8
Network Losses
Losses are inherent in the distribution of electricity, where losses on the LV and MV
systems account for the majority of the losses. To optimize the cost of losses, the MV
system shall be designed to achieve maximum energy efficiency over the life cycle of the
network assets. The following parameters help to assess the cost of losses on the system:
•
Voltage drop
•
Capital cost and installation cost.
•
Copper I²R losses during life cycle
•
Financial losses (Energy losses) during life cycle
•
Spatial requirements of assets and translation into the cost.
•
Plant installation and replacement requirements along with financial assessment
Losses assessment shall be carried out as part of the bulk procurement process and on a
bespoke basis where the specification of equipment is outside the bulk purchasing process.
Losses assessment in the NEOM MV network shall be required at the design stage. For
typical MV network system development, the use of optimum cable sizes and transformers
based on economic loading and MV system configuration may be considered sufficient to
ensure minimum load losses. However, for complex MV system configuration options,
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comparative losses and an economic study must be carried out and submitted to the
planning department for review and approval.
6.9
Power Factor Correction
In accordance with the NEOM Grid Code, all customers connect to the MV system with
demand shall maintain a power factor of not less than 0.95 lagging at the interface with the
DSO; lagging power factor refer to importing VARs for demand customer and exporting
VARs for generator customer. No customer shall present a leading power factor to the DSO
unless it is for export, the details of which have been agreed. Power factors presented at the
DSO interface which are outside of agreed limits may trigger penalty charges.
Reactive power compensation is assumed to be provided, preferably by capacitors, to
achieve a power factor of at least 0.95 lagging at the MV level based on a network
configuration to assist in the control of the voltages at the secondary substations i.e. DSS
and MVSS. The equipment for power factor correction shall be either installed at the MV
level or connected to LV switchboard. Solutions based on the combination of these two are
also acceptable and shall be reviewed/approved by the planning department.
For large motors and distributed generation, reactive power is provided locally by power
factor correction and not from distant power substations. If there is strong case to rely on
MV substation level power factor correction, the solution must be approved by the ENOWA
Operational Grid Planning & Development department.
Sytem Planners shall ensure that each substation maintains a power factor of no less than
the specified value mentioned above at the Point of Common Coupling (PCC). Furthermore,
to allow maintenance of system voltage and avoid the propogation of harmonics into the
distribution network, the Contractor shall provide automatic power factor correction and
automatic harmonic filtration equipment. The automatic and dynamic power factor correction
and automatic harmonic filtering equipment shall be installed at the customer end where the
disturbing or non-linear loads are situated.
The Contractor shall ensure that all reactive power and harmonics calculations, mitigation
solutions and validation are provided and approved by the Company.
6.10
System Earthing
The MV network earthing system shall be designed in accordance with the DSO Earthing
Standard (NEOM-NDS-STD-008). The MVSS transformer shall normally have a star
secondary winding where it is earthed via a neutral earthing resistor (NER). There is a
requirement to ensure that following a fault on the MV system supplied from an MVSS,
sufficient fault current flows to enable the fault to be detected without overloading any plant.
This is accomplished by using NERs attached to the neutral connection of the lower voltage
transformer terminals to reduce the earth fault current at MVSS. Typically, the MV earth
fault current of MVSS is limited by the rating of the NER to 600 A per transformer, whereas
the MV earth fault current of PSS is limited rating of NER to 1000 A as defined in the Table
2 below. Hence, a two transformer MVSS will have a gross earth fault level of 1200 A
whereas a three transformer MVSS will have a gross earth fault level of 1800 A depending
upon the LV side voltage of the transformer.
The earthing and bonding of the railway Non-Traction Power System for the railway’s line
side facilities shall be in accordance with the requirements of IEC 62128-2022 (EN 501221).
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Table 2: Standard NER values
7
Transformer LV
side Voltage
Voltage
Rating
Current
Rating
(Phase to Phase)
(kV)
(A)
13.8 kV
7.97
600
33 kV
19.05
1000
Rated Time
Continuous
Current
Resistance
@25°C
(A)
(Ω)
10
<30
19.05
10
<50
6.35
(s)
MV Network Development
The NEOM MV network will be developed from new connections to NEOM developments.
The DSO MV system shall be designed in coordination with upstream and downstream
networks to provide an economic, efficient, and flexible interface to customers private
network and enable the future addition of load or distributed generation.
Figure 10 and 11 in Appendix 1 illustrate the basic MV system configurations. Network
design for new connections or network alterations shall be undertaken using the steps
outlined in Figure 3.
Demand Estimation – determine the
expected demand for the MV Group or
Substation (Section 8)
Determine the required Network
Capacity to satisfy required headroom,
and security of supply (Section 9)
Determine the configuration of the
Group or Substation (Section 10)
MV System will be based on a Standard
Configuration?
NO
YES
Determine appropriate configuration
and equipment, conforming to DSO
specifications
Select Standard Transformer (12.1)
Select Standard Switchgear (12.2)
Select Standard Cable (12.3)
Network Losses assessment
(Section 5.8)
Complete a Network Study (13)
MV network design complete
Figure 3: MV Network Design Approach
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7.1
System Design
NEOM MV system will be mainly underground systems which will operate at 13.8 kV and 33
kV. A typical MV underground network arrangement for 13.8 kV and 33 kV system is shown
in APPENDIX I, which provides some critical rules for network development and sets out
some restrictions as well. But this document does not cover guidelines for every MV system
design proposal to guarantee that work on the MV system conforms with Planning standard.
Design proposals for MV systems, which may be specific to NEOM projects, must be
created individually, adhering to the guidelines outlined in this document.
NOTE: The MV network design for 33 kV system has limitation hence it should be adopted
on a special case only where it is proven to be an economical design and meets the
protection clearance requirements.
7.2
MV Feeder Configuration
This section covers network topology for the development of the MV network.The schematic
diagram to provide an overview of an underground system for various MV feeder
configulation is provided on the APPENDIX I. The loading requirements associated with the
feeder configuration is provided in the Table 7. MV systems shall operate using a ring
feeder (interconnected radial) to achieve a first circuit outage resiliency with two or multiple
MV loops interconnected via an open point. This is most common in urban and semi-urban
areas and provides alternative supply for supply restoration for both planned/unplanned
events, either by manual, remote, or automated switching. In the event of MV feeder
outages, the alternative MV feeder should be capable to meet the whole demand until the
repair work is completed. There are instances where the MV network will be operated using
radial feeders, especially in remote areas where it is not possible to maintain ring main
feeders due to the long MV network or other network constraints. The different types of
feeder configurations for the network design are detailed below.
7.2.1
Single loop
A single loop feeder, also referred to as a ring main feeder offers an acceptable degree of
reliability but at a higher initial cost. A single loop consists of two radial MV feeders
interconnected via a normally open point and operated radially. Such radial feeders should
be looped between two neighboring substations. Alternatively, they may be looped between
different busbars of the same substation. Wherever practical and economical, loop supply
should be provided with diversified sources. The network shall be operated radially and the
total load of the MV loop shall not exceed the circuit loading as per the Table 7. This type of
feeder arrangement offers an acceptable degree of reliability but at a higher capital cost.
7.2.1.1
Single loop (Option 1)
The most desirable MV feeder design is to interconnect one MV loop with the other MV loop
from two different source substation wherever possible as shown in the APPENDIX I via a
normally open point in a strategic location. The optimal placement of the normally open
point makes sure that each MV loop shares a similar load and maximizes load transfer
capability between the two source substations.
7.2.1.2
Single loop (Option 2)
If there isn't another source substation in the same zone, the circuits at the same substation
can be looped onto different bus sections as an alternative to supply from a separate source
substation as shown in APPENDIX I. This configuration has a limitation in that the load
transfer capabilities won't be achieved.
7.2.2
Multi-loop
Multi loop configuration consists of more than two feeders and is used to increase reliability
between MV feeders if more than one source substation is available in the same zone.
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NOTE: Due to the implication on the protection scheme, a multi-loop feeder shall not be
permitted for a 33 kV system.
7.2.3
Radial System
APPENDIX I shows that MV customers will be supplied through underground cables in a
radial arrangement. Radial arrangement is not a preferred option and shall only be used if
the interconnection between MV feeders may be limited due to the unavailability of
neignbouring MV feeders. This configuration is well suited for large bulk or customers in a
remote area, where it offers the most economical type of supply but offers minimum
relaibilty for planned and unplanned outages.
8
Connection Design
During the connection design for customer installation, System Planners should take into
consideration the NEOM GRID code and relevant standards for network design and power
quality assessments. The initial assessment of the existing network capacity should be
based on standard ratings for the assets, such that the connection offer is based on an
unconstrained basis. Where the requested capacity cannot be economically provided on an
unconstrained basis to meet the customer’s capacity requirements, an alternative
connection design may be considered where the capacity can be provided in full or limited
on a constrained basis. Since NEOM is a startup with new installations, it is not expected to
use the enhanced rating of the assets to provide an unconstrained or seasonally
constrained basis.
Any alternative connection cost (including any enduring operational costs) should be
compared against the cost of reinforcement to ensure that NEOM is developing,
maintaining, and operating an efficient, coordinated, and economic system.
NOTE 1: The customers shall be provided with connections from an existing MV network if
both technical and physical constraints can be met. If not, the customer will be provided with
connections from new MV feeders.
NOTE 2: When developing an MV network or feeding public customers via network
substation, the maximum load on the MV feeder allowed is 80% of the circuit rating,
wherever it is possible to achieve a robust, economical, and efficient MV system.
NOTE 3: When feeding dedicated customers using a new MV feeder where the connection
charges are paid by the customer entirely to meet the customer connection request, the
maximum load allowed is 100% of the circuit rating.
8.1
Types of Supply
The type of supply or connection offered to the customer depends on the customer’s
capacity requirements and the level of network resilience requested. Depending on how
many circuits supply the substation and how those circuits are arranged for restoration of
supplies, a connection might be considered firm, switched-firm, and non-firm supply, which
are detailed below.
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Table 3: Classification of Types of Connection
Type of supply
Description
1. Firm
Two or more circuits feed into the substation. No loss of
supply for an outage of an individual circuit.
2.1. Switched firm (manual)
Two circuits feed into the substation. Substation off
temporarily for a circuit outage. Post fault restoration times
will depend upon the time it takes an engineer to travel to site
and do physical switching. Supply restored via manual
switching (potentially up to a few hours).
2.2. Switched firm (automatic)
Two circuits feed into the substation. Substation off
temporarily for a circuit outage. Post-fault restoration times
will depend on the time it takes to carry out the switching.
Supply restored via automatic switching (potentially up to
seconds or minutes).
3. Non-firm
One only circuit feed into the substation. Substation out of
supply for a circuit outage. Post fault restoration times will be
driven by fault detection and repair time.
NOTE: The firm/non-firm supply and firm/non-capacity are not the same; hence, they should not be
mixed during design considerations.
8.2
MV Connection Capacity
The design of the network, for which connections are provided, shall be in accordance with
ENOWA Grid. Table 4 below provides guidance on the maximum capacities that can be
connected based on the standard equipment that ENOWA Grid approves for each of the
standard arrangements. Some of the connections may not be available at the rating
prescribed if technical or physical constraints arise on the network. Standard customer
connection arrangement is provided in APPENDIX III for different levels of resilience. The
load levels are the maximum contracted capacity, and where it is considered that loads will
exhibit a degree of unbalance, it will be necessary to ensure that plant thermal ratings are
not exceeded. Where a MV customer requires a capacity more than 2 MVA, the connection
shall be controlled via a metered MV circuit breaker. The nominal MV capacity that can be
provided is based on the standard equipment that NEOM has approved for each of the
standard customer connection arrangements. But if a capacity in excess of that mentioned
in the table below is required, a higher rated cable shall be installed to meet the customer
capacity requirements, provided that the Security of Supply Standards are met.
Table 4: Nominal capacity for standard connection arrangement
Voltage
Nominal maximum Capacity
Customer Connection Arrangement
(kV)
(MVA)
(Refer to APPENDIX I)
13.8
81
1.1, 1.2, 1.3, 1.4, 3.1, 3.2
42
2.1, 2.2
17.43
1.1, 1.2, 1.3, 1.4, 3.1, 3.2
8.7 4
2.1, 2.2
33
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NOTE 1: The MVA rating is limited by 500mm2 Al 13.8 kV armoured cable with STR value of 2 K.m/W.
NOTE 2: The MVA rating is based on 50% loading to achieve first circuit outage resiliency for a ring
circuit where MV loops are radially operated on a ring. The cable considered is 500mm2 Al 13.8 kV
armoured cable with STR value of 2 K.m/W.
NOTE 3: The rating is limited by 400mm2 Al and 240mm2 Cu 33 kV armoured cable with STR value of
2 K.m/W.
NOTE 4: The rating is based on 50% loading to achieve first circuit outage resiliency for a ring circuit
where MV loops are radially operated. The cable considered is the 400mm2 Al and 240mm2 Cu 33 kV
armoured cable with STR value of 2 K.m/W.
9
Demand Estimation
9.1
LV / MV Customers
If the customers are connected to the MV network or downstream, the demand will fall into
one of the following two categories as follows:
•
LV Customer demand
Most of the general customer demand will consist of groups of domestic and
commercial customers, supplied on the LV network via DSS.
LV customer demand shall be calculated in accordance with NEOM-NDS-EMR-006,
LV Network Planning Standard, which also provides further detailed information and
explanation of different asset classes, load types and corresponding load densities,
demand and coincidence factors.
•
MV Customer demand
The demand of customers with an MV point of supply shall be assessed based on
the requested load, load forecasting (see 9.3) and Power Supply Request (PSR)
forms (see 9.4).
Application of diversity/growth factors shall be applied to MV point of supply
connections as follows:
For connection at MV should be subject to an attrition factor, i.e., not all applications
will proceed to construction, and the network capacity should not be sterilised by
future proposed connections. In the absense of historical data to inform an attrittion
factor, then a value of 30% may be applied i.e. 1/3 of all proposed electrical
demand/generation may not be realised.
9.2
MV Network Demand
MV network demand is a combination of LV customer demand and MV connected
customers. The MV network demand is derived from applying coincident factors to customer
demand load based on the number of DSS on an MV feeder, and the number of MV feeders
out of a MVSS.
Table 5 provides values for the coincident factors to be applied. System Planners may use
alternative values with justifications based on customer load information. The MV network
demand estimation methodology is provided in Appendix IV.
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Table 5: Network Demand Coincident Factors
Newtwork Demand Coincident Factors
9.3
Coincidence Factor for Demand at MV feeder level
0.9
Coincidence Factor for Demand at PSS/MVSS level
0.9
Load Forecasting
DSO team will review load forecasting and phasing of project development throughout
NEOM regions. Load forecasting team, DSO, TSO, and project proponents within NEOM
regions will be stakeholders and jointly support forecasting of loads and help develop yearly
load forecasting.
The frequency (expected to be at least quarterly) and scope of load forecasting (high level
load estimates, loads requested on Power Supply Request Form, loads approved by DSO),
shall be managed in accordance with the Grid Code and DSO Standards.
9.4
Power Supply Request Forms
All requests for a new power supply connection within the NEOM region will require a web
Power Supply Request (PSR) application via Energy Demand Portal, to be completed and
approved by the associated sector head prior to assessment by DSO/TSO. This is detailed
out in APPENDIX V.
The requestor shall complete all fields in the form and provide additional supporting
documents including a location map showing clear site boundaries, metering location,
phasing of the load and load schedules, that clearly details disturbing loads i.e., all
equipment including but not limited to motors, welding units, generators, and any other
disturbing loads within the proposed development. DSO system planning team will make an
assessment of the impact of proposed disturbing loads on the distribution network.
Following initial assessment and depending on the nature and extent of capacity demand,
the application will be processed by DSO planning team as required.
10
Security of Supply and Network Capacity
10.1
Security of Supply
Supply security is usually measured by the resilience of the network to withstand the loss of
any of the network elements. Where only one element is removed from service, the
condition is known as first circuit outage (N-1 condition). This indicates the number (N) of
elements removed from service. It is most often used when describing the unexpected loss
of a main network element due to failure of that element – such as a cable fault.
Another part of supply security is the speed at which the faulty element can be restored to
service. So, in the case of a simple cable fault occurring on a radial network, the fault would
result in loss of supplies to all downstream customers. The loss of supply would exist until
the cable fault had been replaced or (should an alternative circuit be available) network
reconfiguration implemented.
A continuous electricity supply can be provided if the network was to be operated in parallel
(sometimes known as a ‘mesh’ network). This arrangement is, however, more complex to
protect and may increase fault levels to an unacceptable values.
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It should be noted that a duplicate supply does not guarantee no loss of supply. In the
unlikely event of a second unexpected loss of another network element on the same section
of network, then the customer will experience an interruption of supply.
When determining security of supply for a network, it is normal to firstly asecertain the size
of the ‘group’ that would be affected by a particular fault. In other words, the groups of
customers and the demand associated with them. The DSO should identify the demand
groups within its network – and then carry out a security of supply assessment should be
carried out in accordance with Table 6 which sets the normal levels of security required for
MV networks.
There will be numerous demand groups in a DSO network and lower voltage demand
groups will combine to form larger demand groups, as illustrated in Figure 4.
Security of Supply Standards, as mentioned in Table 6, do not apply to a single customer
for all voltage levels.
Demand Class C
>12 MVA &
MVA
MVSS
T1
33/13.8 kV
30/40 MVA
T2
33/13.8 kV
30/40 MVA
13.8 kV
MV Loop 1
MV Loop 2
DSS 1
1 MVA
Demand
Class A
2MVA
DSS 2
1MVA
Demand
Class A
2MVA
Demand Class B
>2 MVA &
MVA
DSS 7
DSS 6
Demand Class A
MVA
Demand Class A
MVA
DSS 3
2 MVA
DSS 4
0.5 MVA
DSS 5
Figure 4: Typical demand groups (section of network) in a network
NOTE 1: Dashed’ lines indicate a section of network and hence a demand group.
NOTE 2: The demand group for 33 kV outgoing feeder shall be treated the same as the 13.8 kV
outgoing feeder.
When estimating the maximum demand of the group i.e. the Group Demand, DSO should,
where necessary, take into consideration (but not be limited to) the following: the Latent
Demand due to Generation, and the Latent Demand due to DSR.
When carrying out a security assessment for a group, consideration should be given to the
following:
•
The time of the year and day that the maximum demand occurs.
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•
The capacity rating of the network equipment (transformer, cables, switchgear) in
the group
a. Network equipment should not be loaded to a point where it would suffer
unacceptable loss of life during the Group Demand peak.
b. Nertwork equipment capacity rating will be based on the appropriate continuous
rating or cyclic rating (short-term or long-term), taking into account the relevant
environmental conditions and the expected demand profile.
c. For First Circuit Outages, the network equipment capacity shall be based on the
rating corresponding to when the Group Demand occurs.
d. For Second Circuit Outages, the network equipment capacity shall be based on
the rating corresponding with the time when a pre-arranged First Circuit Outage
is likely.
•
The availability and capacity rating of MV circuits i.e. circuits interconnecting to
adjacent groups.
•
The contribution to capacity from Generation in the group
•
The contribution to capacity from DSR in the group
Saudi Electricity Regulatory Authority (SERA) stipulates the minimum demand to be
restored within defined periods of time in different outage scenarios. For guidance on
achieving the prescirbed secuirty of supply, SERA Security of Supply Standards shall
always be referred to.
NOTE: The repair time for different demand groups is more onerous than one required by
the WERA Security of Supply Standards.
Each demand class of supply refers to ranges of Group Demand. The demand class of
supply are defined in MW but due regard should be paid to power factor when assessing
plant capabilities. Table 6 provides an overview of the normal level of security of supply and
should be read in conjunction with the notes in the sections that follow. Table 6 provides an
overview of the normal level of security of supply and should be read in conjunction with the
notes in the sections that follow.
The DSO shall undertake an annual review of all Groups which are Class C or above, to
ascertain adherance to Table 6.
Table 6: Security of Supply for MV groups (in accordance with NEOM Grid NESSS)
Demand
Class
A
Demand Class
boundaries
Low MW
>0
First Circuit
Outage
Second Circuit Outage
(N-2 condition)
High MW
(N-1 Condition)
≤2
Restore in repair time:
Total load group
demand
None
Retore within 2 hours:
B
>2
≤ 12
Total load group
Demand minus 2MW
in 2hrs AND
On return of first circuit:
Maintenance Period Demand
for the Load Group.
Restore group
demand in repair time
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C
> 12
≤ 60
Restore Immediately
Immediately:1/3 of
(auto reclose): Group Maintenance Period Demand
demand
for the Load Group
NOTE 1: Load groups in Demand Class A are likely to be associated with DSS or groups of LV
feeders.
NOTE 2: Load groups in Demand Class B are likely to be associated with groups of MV feeders. For
the loss of a single circuit, an alternative supply should be available.
NOTE 3: Load groups in Demand Class C are likely to be associated with groups of MVSS or groups
of MV feeders. Class C supplies will normally be supplied by at least two normally closed circuits or
one circuit, with automation in place to switch to an alternative circuit if required.
10.1.1 Cost Benefit Analysis
The DSO may derogate from the requirements of Table 6 by means of a cost benefit
analysis. The CBA should primarily be based on the rate of return principle (discount rate),
and should also consider:
•
Network losses and the economic value of those losses; and
•
The cost of supply interruptions to customers.
Expected Energy Not Supplied (EENS) is expressed in MWh over a specific period (e.g. a
year). Using the concept of EENS, it is possible to monetize the shortfall in system capacity
where Value of Lost Load (VoLL) has also been calculated since the EENS can then be
multiplied by VoLL. Hence, a change in EENS rising from remedial actions may be
assessed based on:
10.2
•
VoLL= $50,000 / MWh; different values of VoLL can be used where deemed
appropriate by DSO
•
VoLL impact assessed for an appropriate period of time, relevant for the CBA
Customers Resiliency
The Security of Supply requirements apply to demand groups. However, individual
consumers may require specific security requirements, which can be achieved for
consumers connected to the DSO MV distribution network by selecting one of the standard
connection arrangements. The standard connection arrangement for different types of
power supply arrangements for MV customers is detailed in APPENDIX III. The network
resilience on the LV network has a dependency on the MV network; hence, careful
consideration is required for the network configuration of the MV network for the LV network
design.
10.3
Guaranteed Standards
The following requiredments in accordance with SERA Electricity Guaranteed Standards
shall apply to the MV network
•
Duration for restoring the electrical supply after it is interrupted (6th guaranteed
standard)
•
In the event that the customer’s electrical supply is disconnected, the DSO must
restore the electrical service with resonable means within 6 hours from the time the
electrical service was cut off.
•
Number of electical service outages (7th guaranteed standard)
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•
10.4
The DSO must ensure that the electical service to a customer(s) is not subject to
more than 2 supply interruptions per calendar year, if each interruption is more than
2 hours long.
MV Network Capacity
10.4.1 General
The MV network shall be designed to operate without intervention for a period of 25 years,
considering Distribution Future Energy Scenarios (DFES) such that the network has the
capacity to accommodate future demand and generation growth.
The MV network minimum capacity requirements shall be determined by the requirements
for security of supply in accordance with Table 6. In the infancy of the MV network, it is
preferable to select equipment with a headroom (spare capacity) of 20% on continuous
ratings. Notwithstanding this preference, the following principles are mandatory when
assessing the rating of MV equipment:
a) MV equipment (MV cables, MV switchgear and power transformers) shall not be
overloaded under normal network conditions (N Condition).
b) For abnormal conditions during first faults/outages (first circuit outage condition),
power transformers shall not be overloaded more than 150% of their continuous
rating for operational scenarios. To achieve this, transformers shall have cyclic, and
emergency ratings as specified in the DSO specification, NEOM-NDS-SPC-009 and
cables shall have cyclic ratings as specified in the DSO specification, NEOM-NDSSPC-001. All MV switchgear shall be continuously rated to match the 120%
requirement.
If MV equipment does not conform with item b), the network shall be re-designed or
reinforced.
In addition to items a) and b), the MV network shall accommodate an allocation of at least
20% of its capacity to generation.
NOTE: DSS transformers (e.g. 13.8/0.4 kV) shall be planned to operate with headroom in
accordance with LV Network Development Standard, NEOM-NDS-EMR-006.
10.4.2 MV Firm Capacity Determination
The firm capacity for a substation or group is the capacity that is secure under a first
outage/fault condition. This shall only include the capacity that is immediately available after
the event without requiring manual intervention. The capacity can be provided by the
network assets, the distributed generation security contribution, and the demand response
(DSR) contracted with NEOM ENOWA.
The single transformer MVSS shall not be established due to the risk that there is no other
way to provide power via upstream supply or the load pick capability from the downstream
MV feeder.
For two and three transformer sites, the capacity headroom required at the network
planning stage must follow the 20% and 10% principle. So, for system intact conditions shall
be:
•
40% of a single transformer continuous rating, at two transformer sites as shown in
Figure 5.
•
60% of a single transformer continuous rating, at three transformer sites as shown
in Figure 6.
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The headroom may be relaxed at the detailed design stage subject to the customer
projected demand profile being established and confirmed to be within the switchgear
continuous rating (see 13.2) and transformer continuous and long/short term ratings (see
13.1).
NOTE: A three-transformer site should only be considered if the demand and security of
supply requirements cannot be satisfied by a two-transformer site.
Firm Capacity: 30 MVA
Firm Capacity: 30 MVA
33 kV
33 kV
Headroom
60%
0MVA
24 MVA
15 MVA
15 MVA
Headroom
Headroom
0%
Headroom
60%
30 MVA
33/13.8 kV
30 MVA
33/13.8 kV
30 MVA
33/13.8 kV
40%
80%
30 MVA
33/13.8 kV
40%
Utilisation
Utilisation
Utilisation
13.8 kV
Utilisation
13.8 kV
0MVA
15 MVA
12 MVA
12 MVA
12 MVA
System Intact (N condition)
12 MVA
First Circuit Outage (N-1 condition)
Figure 5: Firm supply (2xCircuits) for a two-transformer substation
Firm Capacity: 60MVA
33kV
Headroom
40%
30 MVA
33/13.8 kV
60%
18 MVA
18 MVA
18 MVA
Headroom
Headroom
40%
30 MVA
33/13.8 kV
60%
Utilisation
Utilisation
0MVA
0MVA
40%
30 MVA
33/13.8 kV
60%
Utilisation
13.8kV
18 MVA
18 MVA
18 MVA
System Intact (N condition)
Firm Capacity: 60MVA
33kV
90%
Headroom
10%
30 MVA
33/13.8 kV
90%
Utilisation
Utilisation
8 MVA
16 MVA
0MVA
30 MVA
33/13.8 kV
27 MVA
27 MVA
Headroom
10%
Headroom
30 MVA
33/13.8 kV
Utilisation
13.8kV
18 MVA
18 MVA
18 MVA
First Circuit Outage (N-1 condition)
Figure 6: Firm supply (3xCircuits) for a three-transformer substation
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11
MV System Configuration
11.1
General
All new MV networks within the NEOM region shall be designed to be fully underground.
The DSO MV system shall comprise MV switchboard (excluding the primary transformer
circuit-breaker), MV feeders from PSS and all downstream network up to DSS (the
transformer incoming MV transformer circuit-breaker at the PSS will form the demarcation
boundary between TSO and DSO, in accordance with Figure 1).
The network configurations in the following clauses are for guidance purposes. The
selection of the optimum network configuration shall be determined by the System Planners
at the time of network development.
11.2
PSS, MVSS and MVSW
11.2.1
PSS
A Primary Substation (PSS) normally consists of two or more 132/MV transformers.
PSS with two transformers will normally be operated in parallel. PSS with three or more
transformers will operate such that no more than two transformers will run in parallel. The
off-parallel may be achieved by an open MV bus-section or an open incomer. It would be
possible to switch the site at low load periods so 1 transformer is switched out and the 3rd
switched into parallel – for maintenance/inspection etc. In the event of a fault on a
transformer, the open bus-section or incomer would close on auto-changeover. Primary and
secondary side protection on each transformer would need to be set accordingly high and
some form of overload protection via winding temperature measurement provided in case
the 3rd transformer fails to auto-changeover. The transformer hot-spot temperature will be
continuously monitored for transformer overload, where overload protection shall be
achieved by applying settings to the Winding Temperature Alarm (WTA) and the Winding
Temperature Trip (WTT) relays and also the set points for operating any auxiliary cooling
fans/oil pumps.
11.2.2
MVSS
A Medium Voltage Substation (MVSS) consists of two or more 33/13.8 kV transformers.
Similar to the PSS, the MVSS may operate with two transformers or three transformers. The
running arrangement for the 3rd transformer does not follow the same principle for the PSS,
i.e., all three transformers shall run parallel.
A typical example of an MVSS (two or three transformers) is depicted in APPENDIX II.
The size of the transformers for a PSS or MVSS will be dictated by the Group Demand and
the Security of Supply required in accordance with Table 6.
MVSS sites shall be designed with sufficient space to accommodate transformers for load
expansion and associated MV switchgear. This requirement may be relaxed for specific
projects with agreement from the Head of Grid Planning & Development.
11.2.3 MVSW
A Medium Voltage Switching Station (MVSW) is a switching point on the 33 kV or 13.8 kV
network, as depicted in Figure 1. There are likely three situations in which an MVSW is
required:
a) Mid-point break on an MV radial feeder
When establishing an MV network in a rural location with a lengthy distribution network, it is
important to carefully assess if mid-point switching is necessary to keep the network's
reliability at a level that is acceptable. Subject to review on a case-by-case basis, a midpoint
Internal
Internal
switching station shall be required to ensure that the restoration of the network can be
carried out within an acceptable timeframe.
Operational consideration must be given to the customer restoration in the event of
unplanned outages, particularly for customers fed from a radial supply (single circuit
security), where the loss of supply remains for a longer period if the faults cannot be located
swiftly due to circuit length, or the cable route is challenging. Hence, customers with a radial
supply (single circuit security) located in challenging terrain shall be provided with a
midpoint switching where the circuit length is in excess of 10 km.
b) Interconnection between PSS or MVSS sites
In areas of extremely high density where the power requirement per square meter is
extremely high, the interconnection of adjacent PSS or MVSS sites, if feasible, should be
considered to improve system security and reliability. Any interconnection between the PSS
or MVSS sites must comply with the network capacity and protection requirements.
11.3
Standard MV Feeders
Section 7.2 covers several MV feeder configuration but the the standard MV feeder
arragnement shall be interconnected radial i.e. an open point between adjacent MV feeders,
and utilise RMUs as shown in APPENDIX I. The standard MV feeder shall have N-1
resiliency, such that the system maintains reliable power supplies and supply can be
restored for both planned and unplanned events.
MV feeders are ring circuits that will be operated as radial circuits with a normally open point
selected for ease of operational access and to minimize the number of customer
interruptions and customer minutes lost, while taking account of the need to minimize the
system losses and optimize the voltage regulation.
Table 7 provides the maximum loading of different types of MV feeder as follows:
Table 7: Maximum loading of different types of feeders
Feeder Type
Maximum
loading
with
relation to de-rated capacity
Remarks
Radial Feeder
100%
For network feeders supplying one or
multiple network DSS, reinforcement will be
triggered if the cyclic loading exceeds the
capacity of the circuit rating.
Single loop
50%
The MV circuit shall not be overloaded for
the first circuit outage condition.
Multi loop
66%
The MV circuit shall not be overloaded for
the first circuit outage condition.
NOTE: For all credible first circuit outage conditions, depending upon the type of MV feeder, single or
multi-part MV switching shall be used to restore the supplies until the planned or unplanned work is
completed.
11.3.1
Remote Control and Automation
Remote control on MV circuits shall be applied to all MV switching points to maintain and
improve the operational performance and asset utilization of the network and help to meet
the CI and CML targets. The application of remote control shall
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•
reduce the time to carry out MV switching in both planned and unplanned outage
scenarios, and
•
facilitate reconfiguration of the MV network quickly following a fault, thus reducing
the time to restore customer supplies.
Remote control of MV switching points can be achieved by the installation of remotely
controlled actuators on all ground-mounted switchgear that includes both RMU and Circuit
Breaker used on the MV network. The practical application of these requirements is
highlighted in Figures 10 and 11 of Appendix 1.
The deployment of network automation on MV feeders will increase the resiliency of our LV
customers for MV faults; this reconfigures the network to swiftly restore power supply to our
customers. Automation is achieved by an algorithm that is part of the module named
“Automated Power Restoration System” (also referred to as Fault Location, Isolation, and
Service Restoration (FLISR)) within the Advanced Distribution Management System
(ADMS). The technology allows radial and lightly meshed circuits with different feeder
topologies to be automatically and optimally restored when a fault is detected. The
sequence of operations for a MV feeder with network automation is as follows:
•
When a fault occurs on the network, APRS/FLISR uses telemetered fault
detection/location devices to locate the network section containing the fault.
•
It then analyzes the faulted circuit and its neighboring circuits to determine the size
of the outage and spare capacity on potential donor circuits. Next, the APRS/FLISR
isolates the faulted section and restores power supply upstream and downstream of
the isolated section.
Network automation and monitoring shall be used on 13.8 kV feeders only to automatically
reconfigure one or more MV feeders. But the application of network automation on 33 kV
feeder is limited due to protection scheme applied on the RMUs. The network automation
restriction on the 33 kV circuit can be relaxed only once the protection issues are
addressed.
With APRS/FLISR, restorations typically occur within a minute or less of a fault being
detected, depending on the utility’s communication infrastructure and the size of the MV
network. MV automation switching studies will be required to enable load transfer options
for each MV feeder of a MVSS. MV remote control automation at normal open point and
dedicated sites for load transfer will be required.
NOTE: Sites with Pad Mounted or Small Power Prefabricated substations (i.e., substations
with capacity of <= 315 kVA) do not provide remote control capability, and hence, they
cannot be included for network automation. These shall not be used as normally open
points.
11.3.2
Network Open Points
The supply restoration on the network is achieved by isolating the fault and moving the
network open points around. The most desirable location for a normally open point in any
ring feeder is to have equal loading on the individual circuits for a single loop. To achieve
maximum load transfer capability between MVSS, the location of the normally open point
should be such that each loop originates from a separate MVSS wherever possible, but this
may not be the case in every circumstance, especially where MVSS are distant apart. In
that situation,
NOTE: When normally open points are planned to be moved with circuits having more than one
protection zone, consideration shall be given to protection settings with respect to the configured
circuit.
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The selection of the MV open point on the network shall be driven by the following priorities:
11.4
•
The demand on an MV feeder shall not exceed 12 MVA under normal conditions in
accordance with Table 6.
•
The rating of the MV cable shall not be overloaded for the first circuit outage
condition as per Table 7.
•
Normally open points are applicable to MV switching points where remote control is
available.
•
For adjacent MV feeders, the open point shall generally be at a strategic location
where adequate load share as per the MV feeder types (i.e., single loop or multi
loop type) can be obtained between the MV loops.
•
Adjacent MV feeders should be suitably rated to support the combined demand of
both feeders. Network characteristics (voltage level) shall not be compromised
during the abnormal running of the open point.
•
The load transfer to the neighboring MVSS from the adjacent MV feeder should not
overload the MVSS.
•
Refer to Section 7.2 for a typical MV feeder arrangement.
MV Connections
The connection arrangement for large customers is mainly driven by the load and level of
supply security i.e., resilience required. The MV customers may be connected to an existing
MV feeder or provided with a dedicated MV feeder(s). The standard connection
arrangements for MV customers shown in APPENDIX III should meet the demand
requirements of the majority of MV customers.
NOTE: The point of supply associated with dedicated connections would normally be
located at the customer site – however this can also be located at the PSS/MVSS/MVSW
circuit-breaker such as for independent customers operating private networks.
11.5
MV Feeder Restoration
For radial MV feeders, the RMU switchgear shall incorporate motorised actuators to
open/close the switch by remote command. In addition, a restoration logic system (e.g.
SCADA based, or RTU based) may be utilised to allow timely restoration of customers in
the event of cable fault. The principles of the restoration logic should the example
demonstrated by Figure 7.
As shown in Figure 7, a fault occurs between DSS1 and DSS2 – this trips the circuit-breaker
at the PSS/MVSS for MV feeder 1. Fault passage indicators at each DSS shall inform the
location of the fault i.e. for the example, only a fault passage indicator at DSS1 operates.
The sequence of restoration is:
•
Switch at DSS1 opens towards faulted section
•
MV Feeder 1 CB closes to restore DSS1
•
Switch at DSS2 opens towards fault section
•
Normally open point at DSS3 closes to restore DSS3 and DSS2.
The above sequence would typically take a maximum of 1 minute, thus satisfying resilience
category 2 requirements.
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MVSS
13.8 kV
MV Loop 1
MV Loop 2
2
DSS 1
DSS 5
1
Fault
3
DSS 2
DSSS 4
4
DSS 3
Figure 7: Restoration sequence for MV feeder following first circuit outage condition
11.6
Customer Connection Co-ordination
The design of customer connections shall be made in a way that the network hosting
capacity shall be made available at HV to MV substation in coordination with TSO planning
team and physical space shall be reserved to install additional equipment, to meet future
customer requirements (refer APPENDIX III). This is a particular concern at HV to MV
substations where there is limited physical space to install additional circuit breakers. In
such situations, dedicated circuit breakers should not be used to provide a new connection
if their use would restrict the obligation to provide connection to future agreed customers.
This will reduce any unutilized electrical capacity due to the lack of physical space to install
further circuit breakers or other equipment. This situation must be prevented by coordination
at the design stage.
At an HV to MV substation where the MV switchboard cannot be extended, an MVSW may
be installed close to the HV to MV substation to effectively create additional connection
points for MV circuits. The creation of the MVSW should not compromise the use of land for
any future replacement of substation plant. The specification of switchgear shall take into
consideration:
•
The number of additional MV circuits required,
•
Possibility of the MVSS extension in the future, and
•
The protection requirements of the circuits
When the MV network is to be modified including diversions, this document may be utilized
to improve the network with a view to optimize investment for an efficient and economical
MV system.
When the MV network is considered for reinforcement, specific attention shall be paid to the
following:
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11.7
•
Review the Company future energy scenarious such as load forecast and future
distributed generation connections.
•
Requested, and agreed demand load or distributed generation load in associated
Neom region.
•
Demand load estimates as documented by the load forecast team of ENOWA.
Metering Arrangements and Specifications
The metering locations associated with all MV customers shall either be outgoing terminals
of MV RMU or circuit-breaker at customer site, or outgoing terminals of PSS/MVSS/SWSS
circuit-breaker. This metering location for the MV connection type is provided in the
APPENDIX III, and an approval is required from the GRID DSO after the fnial design
submission. All metering circuit-breakers shall be owned by ENOWA DSO and should be
capable of bi-directional power flows.
The ratings of current and voltage transformers should be adequate to align with customer
energy requirements. All other metering specifications shall comply with NEOM-DSO-EMR003 and NEOM-NDS-SPC-005 .
11.8
Interfaces with Connected Parties
Interface with customer shall comply with connection offer terms & conditions and all other
NEOM Standards including statutory requirements. Further guidance on planning the
interface to the system can be reached with the Operational Grid Planning & Development
department.
At interface points, compatibility of plant ratings shall be ensured by the customer.
12
DISTRIBUTED ENERGY RESOURCES AND MICROGRIDS
The Distributed Energy Resources (DERs) and microgrids practice applies to
•
ac microgrids that are normally grid-connected
•
Distributed energy resources (DERs), such as renewable energy sources (RES),
dispatchable energy sources, and energy storage systems (ESS)
The integration of DERs within MV networks shall be justified through feasibility studies and
proper technoeconomic evaluations. Also, it shall not lead to any undesirable disturbances
to MV system operation, such as protection coordination, power quality, and response to
contingencies. Like conventional networks, DERs shall be able to coordinate and manage
facilities capable of an autonomous and seamless transition from grid-connected to islanded
mode and vice versa. Unless being part of a microgrid, the DER shall have an effective antiislanding mechanism according to the standard IEEE 1547.
DERs can be interfaced at various voltage levels. Based on the voltage level, different
capacities are permitted as per the IEEE Standard 2030.9 requirements listed in the Table 8
below. DERs and Microgrids at the MV level shall be interfaced with the network through
transformers and adequately rated switchgears and cables. The installation shall permit bidirectional power flows between the two systems, including ancillary services.
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Table 8: DERs integration voltage level in accordance with their power capacities
Voltage Level
Installed capacity
Power exchange at PCC
(kV)
(MW)
(MW)
33
≤ 100
≤ 20
22
≤ 50
≤ 10
13.8
≤ 20
≤6
LV
≤2
≤ 0.5
Energy storage and dispatchable sources connected at 13.8 kV and above shall have
capabilities to support grid forming capabilities, voltage support and black start capabilities.
The DERs connected to the MV network shall support normal operation within the voltage
and frequency ranges specified in this document. Furthermore, these DERs shall provide
the fault ride through requirements and voltage/frequency support specified in ENOWA
GRID code.
DER with a power rating higher than 2 MVA shall support operation in the power factor
range of -0.85 to +0.85. provision of reactive power support shall be based on the V-Q
curve defined in the ENOWA GRID code or upon receiving command from upstream
controllers.
The microgrid protection system shall be designed to enable effective operation not only
during normal operation, but also during transition phases between various operating
modes. Conventional protection usually applied at distribution networks is insufficient when
considering systems with distributed energy resources such as microgrids. For protection
coordination, detailed studies of the behavior of these DERs during various types of faults
shall be carried out in coordination with the System Engineering Team to determine the
proper settings of various protection relays. A report that details the protection system
response considering the impact of the installed DERs, any associated challenges, and the
suggested actions shall be provided. There can be certain cases where multiple setting
groups for a protection scheme are required depending on whether a specific set of DERs
are operational or not.
Also, the DERs shall not contribute current harmonics of more than 5% Total Harmonic
Distribution (THD).
In case the earthing connecting point is in the grid side, when the microgrid switch to
islanded mode, another earthing point shall be connected within the microgrid. The earth
fault protection system shall be managed accordingly. Moreover, analysis of temporary
overvoltage due to phase to neutral faults shall be carried out in the microgrid.
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13
STANDARD PLANT
Standardization of electrical equipment for use on the MV system will help manage
emergency replacement and minimize the network risks. Standardization will help to
optimize the number of products and benefit overal asset management (condition
assessment, maintenance, operation, spares management).
This section defines the preferred standard suite of switchgear, transformer, and circuits.
The main purpose is to reduce the number of arrangements to balance between, risk, cost,
and performance throughout NEOM regions.
13.1
Transformers
13.1.1
General
Power Transformers shall conform to the requirements of NEOM-NDS-SPC-009, unless
otherwise stipulated in this document.
NEOM-NDS-SPC-009 specifcation is based on IEC 60076 series, in particular the loading of
power transformer is based on IEC 60076-7 methodolgy.
The ambient design temperature for power transformers for their continous rating, in
accordance NEOM-NDS-SPC-009, is 50°C.
The tapping range for power transformers is +10% to -15% at 1.25% steps.
The default vector group for transformers is Dyn1.Depending upon site requirements, this
may change, and alternatively, Dyn11 may be specified.
13.1.2
Loading Limits
Power transformers shall be assigned the following ratings:
13.1.3
•
Normal – this is 100% of the continous ‘nameplate’ forced cooling rating of the
transformer at the design temperature.
•
Long-term emergency – this is the 100+Y% of the continous ‘nameplate’ forced
cooling rating which shall be available for 120 minutes. Before and after the 120minute period, it should be confirmed that load is no greater than 80% of the
continuous rating. The upper limit for short-term emergency cyclic rating should be
150%. Variations of these limits may be acceptable if this is established in
accordance with IEC 60076-7 i.e. fluid temperature calculations for given load
profile and ambient conditions.
MVSS Standard Power Transformer Ratings
The MVSS power transformer standard votlage ratio shall be 33/13.8 kV. The MVSS
substation shall be equipped with transformer in accordance with NEOM-NDS-SPC-009.
NOTE: See Section for voltage ratios which may be deployed in high load density areas.
The MVSS transformers shall have nominal design impedance on principal tap as listed on
the Table 9 below.
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Table 9: Typical Transformer Impedance for 33/13.8 kV transformer
Secondary
Voltage
Name Plate
Rating
Maximum
Forced Cooling
Rating
Typical
Impedance
Typical
Impedance
(MVA)
(% on Machine
Base)
(% on 100 MVA
Base)
20/30
30
10
33.33
30/40
40
13
32.5
35/40/50
50
17
34
40/50/60
60
20
33.33
(kV)
13.8
The standard power 33/13.8 kV transformer ratings are as summarised in Table 10 below.
Future demand and/or generation that the transformer may supply should be considered
when determining the transformer rating to be utilized.
Table 10: 33/13.8 kV Power Transformer Standard Ratings
Name Plate
Rating (MVA)
Type of Rating
20/30
30/40
35/40/50
Loading limit (MVA)
KNAN
KNAF
KDAN
KDAF
Nameplate / Continuous Rating
20
30
-
-
Long-term emergency
30
45
-
-
Nameplate / Continuous Rating
30
40
-
-
Long-term emergency
45
60
-
-
Nameplate /Continuous Rating
35
-
40
50
Long-term emergency
52.5
60
60
(Note 2)
NOTE 1: Refer to Section 13.1.4 for power transformers for high load density areas.
NOTE 2: The emergency rating of the 35/40/50 MVA transformer shall be limited to 60 MVA based on
the busbar rating of 2500 A.
13.1.4
PSS Standard Power Transformers Ratings
In high load density areas and after economic analysis, a PSS may be utilised with the
following standard voltage ratios:
•
132/13.8 kV,
•
Double wound transformer i.e., 132/13.8/13.8 kV, and
•
Dual ratio transformer i.e. 132/33/13.8 kV.
NOTE: 132 kV voltage will require close coordination with the transmission planning team in
addition to DSO team.
The standard rating for 132 kV/MV power transformers may be:
•
50/67 MVA, and
•
80/100 MVA.
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NOTE: A further check needs to be evaluated at the conceptual design stage if the
proposed requirement can bet met.
13.1.5
Auxiliary Transformers for Medium Voltage substations
The technical details of the auxiliary transformer shall be in accordance with NEOM-NDSSPC-008. Every power transformer shall be equipped with an auxiliary transformer and shall
normally have a rating of 315 kVA or 500 kVA based on the substation auxiliary loads. At
sites with more than one NEOM owned 33 kV transformer, the LV supplies shall be
duplicated. The preferred method of achieving this is to provide 13.8 kV auxiliary
transformers/breakers on each side of the busbar. It is not necessary to provide an
alternative LV supply from the surrounding network infrastructure at a dual transformer
substation as, for the loss of one transformer, supplies shall be maintained by the remaining
transformer. For single transformer substations, an alternative LV supply shall be provided
from the surrounding network so that it is possible to support substation auxiliary demand
for loss of the main power transformer.
NOTE 1: Currently, there are no plans as such to establish a MVSS with a single
transformer. Hence, an alternative supply from the neighbouring network required for the
loss of the main single transformer is not applicable and not in the scope.
NOTE 2: For a MV customer fed from a ring circuit (witchalternative supply) or a radial
supply, LV supply shall be provided from the distribution substation from the neighbouring
networks so that it is possible to support substation auxiliary demand for loss of uptream
power transformer.
13.1.6
DC Auxiliary Supply Systems
DC Auxiliary Supply Systems for a MVSS and DSS shall be in accordance with NEOMNDS-SPC-165 which details ENOWA’s technical requirement for 24 V, 48 V and 110 V
standby auxiliary D.C. supplies. The auxiliary D.C. supplies will be used for the operation of
switch tripping, protection tripping and other ancillary apparatus within MVSS and DSS. The
Backup Period shall be:
13.2
•
10 hours for a 33/13.8 kV MVSS.
•
5 hours for MV switching substation.
•
3 hours for a 13.8/0.4 kV or 33/0.4 kV DSS.
MV Switchgear
There are three predominant types of MV switchgear to be used:
•
MV Switchboard – normally located at a transformer substation (PSS or MVSS), but
may also be located at a customer site or at a network interconnection point
•
MV RMU – normally located along a MV feeder at a DSS
•
MV MRMU (metered RMU) – normally located along a MV feeder at a Customer
POC and
•
MV Switching Station (MVSW) panel - normally located on a mesh MV feeder, or on
a radial MV feeder acting as a mid-point break, or to facilitate a customer MV POC.
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MV Switchboard
MV
MVSW
MVSW
MV MRMU
MV RMU
Figure 8: Typical MV switchgear types
It shall be noted that selection of MV voltage level shall be based on the consideration of the
load as well as the cost justification.
MV switchgear shall be operated up to 90% of its short-circuit rating during normal network
conditions.
MV switchgear continuous rating shall be suitable for normal and abnormal network
conditions, i.e., MV switchgear shall not operate above its continuous rating at any given
time.
13.2.1
33 kV and 13.8 kV Switchgear
MV switchgear including those used for PSS, MVSS and MVSW, shall be metal enclosed
modular, fixed pattern, gas-insulated in accordance with NEOM-NDS-SPC-019 and NEOMNDS-SPC-024. The standard voltage and short-circuit ratings of MV switchboards is
outlined in Section 6.7.
Table 11: MV Switchgear continuous current ratings
Type of Ground
Mounted
Substation
Switchgear
Busbar
Continuous
Rating (A)
Switchgear
Continuous
Rating (A)
132/33 kV PSS
33 kV Bus Section CB
2500
2500
132/33 kV PSS
33kV Outgoing Feeder CB
2500
33 kV STSW
33 kV Incoming CB
630 or 1250
630 or 1250
33 kV STSW
33 kV Bus Section CB
630 or 1250
630 or 1250
33 kV STSW
33 kV Outgoing Feeder CB
630
630
1250
1250
33/13.8 kV MVSS
33 kV Incoming Feeder CB
1250
1250
33/13.8 kV MVSS
33 kV Transformer CB
1250
1250
33/13.8 kV MVSS
33 kV Bus Section CB
1250
1250
33/13.8 kV MVSS
13.8 kV Transformer CB
20003 or 25004
20003 or 25004
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Type of Ground
Mounted
Substation
Switchgear
Busbar
Continuous
Rating (A)
Switchgear
Continuous
Rating (A)
33/13.8 kV MVSS
13.8 kV Bus Section CB
20003 or 25004
20003 or 25004
33/13.8 kV MVSS
13.8 kV Outgoing Feeder CB
20003 or 25004
630
13.8 kV STSW
13.8 kV Incoming CB
630
630
13.8 kV STSW
13.8 kV Bus Section CB
630
630
13.8 kV STSW
13.8 kV Outgoing Feeder CB
630
200 or 630
33/0.4 kV DSS
33kV Feeder Switch
630
630
33/0.4 kV DSS
33kV Transformer CB
630
200
13.8/0.4 kV DSS
13.8kV Feeder Switch
630
630
13.8/0.4 kV DSS
33kV Transformer CB
630
200
NOTE 1: The outgoing feeder of 132/33 kV substation shall be rated at 630 A where a 132/33 kV
primary substation and 380/132 kV BSP substation are adjacent to each other.
NOTE 2: The outgoing feeder of 132/33 kV substation shall be rated at 1250 A where a 132/33 kV
primary substation is fed from a remote 380/132 kV BSP substation.
NOTE 3: The switchgear rating applies to 20/30 MVA transformer.
NOTE 4: The switchgear rating applies to 30/40 MVA, and 35/40/50 MVA transformer.
13.2.2
33 kV and 13.8 kV Ring Main Unit
The 33 kV and 13.8 kV networks include distribution substations which comprise a ring main
unit (RMU) supplying an MV/0.4 kV transformer or an LV customer. It shall be noted that the
MV voltage level shall be based on the consideration of load as well as cost justifications.
The configuration of RMUs shall be part of radial MV feeders in accordane with Clause
11.3. RMU switches shall incorporate remote operation to satisfy requirements of Clause
11.5.
Table 12: MV RMU rated voltage and short-circuit ratings
System Voltage
(kV)
RMU maximum
rated voltage
(kV)
Rated Shortcircuit
withstand
current –
BREAK
Rated Shortcircuit
withstand
current - MAKE
Rated Shortcircuit
withstand
duration
(kA)
(sec)
54
54
3
3
(kA)
33
13.8
36
17.5
20
20
NOTE: DC time constant for RMU circuit breaker assumed as 45 ms unless otherwise
specified/modelled.
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13.3
Cable Circuits
13.3.1
General
MV cables shall conform to NEOM-NDS-SPC-001, including cable type, size, and conductor
size.
It is preferable to use standard cable sizes for the MV network; the following cables types,
are preferable and have proven economic advantages over other cable types and suit the
majority of connection and load arrangements provided the required circuit rating is met
under site-specific service and installation conditions.
•
33 kV cable shall be 3-core 400 mm2 Al or 3-core 240 mm2 CU
•
13.8 kV cable shall be 3-core 500 mm2 Al
However, when it is unreasonable or impractical (e.g. where installtion requires tight
bending radii) to use the above 3-core cables, an economic justification and load losses
study will be required by the System Planner to justify switching from 3-core to 1-core.
Copper conductor XLPE insulated MV 1-core-cable is available in larger sizes (400 mm2,
500 mm2, 630 mm2, 800 mm2, and 1000 mm2) and shall be used where the 3-core cables
would have an insufficient rating or excessive impedance, for example, to provide supplies
to individual customers with a large MV demand and/or generation. If the cable installation
is less than 1.2 km, a single length of 1-core cables can be considered to avoid multiple
cable joints due to the cable drum length, provided that this is approved by the Head of Grid
Planning & Development. The use of these cables shall be restricted to special
circumstances, and not used in general network situations. An assessment of network
losses should be undertaken in these situations. Care should be taken to co-ordinate the
cable rating with the switchgear rating.
Inside a MVSS and/or PSS, where MV cables are terminated into a CB, 1-core cables shall
be used to allow ease of installation and multiple cables per phase. If 3-core cables are
installed on the network that consists of joints, the last joint position shall be inside the
substation compound comprising of a trifurcating joint which will be installed to joint onto a
1-core cable to allow for terminating into the switchgear,
While sizing of the cable for the MV system, consideration shall be given to minimizing
system losses and maintaining sufficient capacity for the future load growth. This implies
that a cable with the largest cross-sectional area that can be reasonably justified shall be
used. For 1-core cables, the standard installation configuration is trefoil formation. However,
flat or flat-spaced formations may be employed if technically justifiable.
The use of cable ducts shall be on a case-by-case basis.
13.3.2
Cable ratings
Cable ratings shall be based on Manufacturer/Supplier datasheets for the cable type, size,
service and installation conditions criteria as defined in NEOM-SPC-001, XLPE Insulated
Power Cables for Rated Voltages from 13.8 kV to 33 kV.
NOTE: Consideration may be given to using a cable rating calculation tool/software to
determine a bespoke rating and consequently identify any de-rating of cables associated
with the anticipated site installation conditions, for example due to proximity to any existing
or future cables, installation on a bridge/road or exposure to solar heating.
Installing MV cables in trenches (liad direct or in ducts), troughs, conduits, duct banks and
backfills, culverts, tunnels, sea bed requires careful planning as numerous factors need to
be accounted for, such as cable corridors, number of cable layers, proximity to other cables,
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depth of burial, and thermal resistivity of the backfill and native soil. Cable installation
minimum requirements for MV cable shall conform to the requirements of NEOM-NDS-STD202, unless otherwise stipulated in this document. The cable type and environment criteria
for DSO cables must adhere to NEOM-NDS-SPC-001.
Based on the criteria mentioned in NEOM-NDS-SPC-001, the applicable cable ratings for
standard cable sizes are shown in Table 13, Table 14 and Table 15 (ratings determined by
DSO cable supplier1). The appropriate correction (derating) factors for temperature,
installation conditions, and grouping, extracted from the manufacturer/supplier catalogue,
shall be used, where applicable, to derate the tabulated current rating in the
manufacturer/supplier datasheet for site-specific service and installation conditions that may
differ from the standard one defined by NEOM-NDS-SPC-001 standard.
For cables laid in close proximity to other loaded circuits where runs are less than 12 m in
length and the congestion is not excessive, the effect of de-rating can be ignored. Where
more than 4 circuits are in the same trench, the circuit configuration and spacing shall be
simulated in CYMCAP. The System Planner or the Contractor shall validate their design
proposal using the recommended software and a detailed report must be submitted for
approval to ENOWA DSO before work commences.
For cables laid direct that contain a continuous ducted section of less than 12 m 2 in length,
the effect of derating can be ignored. However, where there are more than two 12 m ducted
sections in any 100 m length a cable de-rating must be applied.
100m
< 12m
100m
< 12m
< 10m
< 12m
Figure 9: Examples where do duct de-rating is required
The above criteria does not apply to Horizontal Directional Drill (HDD) installations, as the
MV cable will be installed at a depth greater than the standard depth defined in NEOMNDS-STD-202. For burial depths that are greater than 3 meters and/or HDD installations,
ENOWA DSO recommended propriety software program ‘CYMCAP’ shall be used to
simulate the proposed greater burial depth to establish the de-rating of the cable. During the
parametric study using CYMCAP software, the effect on current rating of the following
parameters shall be studied as follows:
For cables in air
For buried cables
o conductor size,
o enclosing in duct, duct size, duct
material if applicable
o conductor material,
o phase separation,
1
2
Refer to ‘Bahara Current Ratings Jan 24_Std Cable Sizes v1_Issued’
The 12 m is based on the road crossing of a single carriage way (2x3.65 m) and a pedestrian foot path (2x2 m) on both sides of the road.
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o separation between groups of cables in
air
o multiple buried circuits,
o soil ambient temperature,
o sheath bonding arrangement,
o soil thermal resistivity,
o ambient air temperature, and
o backfill thermal resistivity,
o exposure to direct solar radiation
o backfill construction,
o soil dry-out,
o standing voltage,
o 1- core sheath loss factor, and
o multi-core sheath loss factor
Cables shall be selected on their continous rating based on the maximum demand expected
for the circuit. In accordance with NEOM-NEG-EMR-002, DBD Part 2, the load limit for
cables is 120% of their continuous rating. The 120% load limits shall only be applied in the
event of a long-term cyclic i.e. 2 hours. Cables from different manufacturers will have
slightly different characteristics; however, they should all be within the tolerances of the
NEOM cable specification NEOM-SPC-001, and therefore the current rating in the Table 13
below shall be utilized at the design stage.
NOTE: Cyclic rating for the cables in the air cannot be applied because the cables installed
in the air reach their maximum operating temperature with load variations due to the air’s
low thermal capacity. Therefore, the peak load should never surpass the continuous rating,
unlike buried cables, which have a relatively high peak load rating factor.
The System Planner is responsible for providing all voltage drop and cable ampacity
calculations supporting the final installed cable.
Table 13: Standard MV cable ratings (Unarmored cable)
Protection
Ducted Rating
Rating with
STR of
2 K.m/W
Rating with
STR of
2 K.m/W
Air Indoor Rating
13.8
500
Al
3
XLPE CWS
375
8.9
319
7.6
496
11.8
33
240
Cu
3
XLPE CWS
329
18.7
280
16.0
411
23.4
33
400
Al
3
XLPE CWS
332
18.9
282
16.1
427
24.3
kV
Sheath
No.
Laid Direct
Rating
Material
Insulation
Construction
mm2
Voltage
Conductor
Amps
MVA
Amps
MVA
Amps
MVA
Table 14: Standard MV cable ratings (Armored Cable)
Protection
Ducted Rating
Rating with
STR of
2 K.m/W
Rating with
STR of
2 K.m/W
Air Indoor Rating
13.8
500
Al
3
XLPE CWS SWA
342
8.2
291
7.0
444
10.6
33
240
Cu
3
XLPE CWS SWA
311
17.8
265
15.1
394
22.5
33
400
Al
3
XLPE CWS SWA
312
17.8
265
15.1
406
23.1
kV
Sheath
No.
Laid Direct
Rating
Material
Insulation
Construction
mm2
CWS stand for
copper wire screen
Voltage
Conductor
Amps
MVA
Amps
MVA
Amps
MVA
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NOTE 1: The cable rating for a single cable in the cable trench is based on NEOM installation
conditions in line with NEOM-NDS-STD-202. Comprehensive ratings for all ENOWA DSO approved
cables can be found in NEOM-NDS-STD-221.
NOTE 2: In locations where the effect of STR value is higher than 2 K.m/W, refer to NEOM-NDS-SPC001 to apply an appropriate derating factor or replace the soil around the cable with a stabilized
backfill.
NOTE 3: Emergency rating is based on 120% of continuous rating in accordance with NEOM-NEGEMR-002, DBD Part 2, unless otherwise specified by the DSO Planning Engineer. Emergency rating
shall be used for operational scenarios where cable can be loaded up to 120% of a continuous rating
with cable derating included if applicable for a duration no longer than 3 hours, followed by a reduction
in demand equal to or below 80% for a duration of 21 hours.
Table 15: Typical MV subsea cable ratings (Armored Cable)
Construction
3
Protection
Cu
Sheath
400
Insulation
No.
33
Material
kV
mm2
Voltage
Conductor
TR-
CWS SWA
Laid Direct
Rating 1.0 m
below seabed
(single circuit in
trench)
Rating with
STR of
1.0 K.m/W
Laid Direct
Rating 1.0 m
below seabed
(2 Cables with
7.5 m
separation)
Rating with
STR of
1.0 K.m/W
HDD Rating 25 m
below seawall
(single circuit)
Rating with
STR of
1.5 K.m/W
Amps
MVA
Amps
MVA
Amps
MVA
544
31.1
542
30.9
324
18.5
XLPE
NOTE 1: The rating of both single and 2 x cable installation is based on buried depth of 1m below
seabed, temperature is 25°C, soil thermal resistivity of 1.0K∙m/W. The minimum separation of a 2cable installation shall be a minimum of 7.5 m.
NOTE 2: The rating of a single cable installed in HDD tube at a depth of 25m below seawall,
temperature is 25°C, soil thermal resistivity of 1.5K∙m/W (Water Filled HDD tube).
NOTE 3: The ratings in Table 15 are typical ratings but are subject to change depending on the
installation depths.
The de-rating factors in Table 16 shall be applied where multiple cables of different circuits
are in proximity i.e. on the same tray or in the same trench. Detailed analysis utilizing
approved cable rating software may be required for more complex installations.
Table 16: Cable derating factors for multiple cable installation as per NEOM-NDS-STD-221
Number of
installation
cables
in
same
Derating factor
2 cable circuits
3 cable circuits
4 cable circuits
Multi-core cable circuits touching
in ground (laid direct or ducted)
0.73
0.60
0.54
Multi-core cable circuits touching
in air
0.89
0.87
-
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13.3.3
Transformer Standard Cable Tails
The cable tails used for connecting MVSS transformers to the switchgear on the 33 kV and
13.8 kV sides shall be unarmoured 1-core copper cables. The type of cable size and their
associated ratings for different MVA rated MVSS transformer are provided in
Table 17: Standard cable sizes for transformer tails
Transformer
Size
Min. Cable Continuous Rating
(120%) Required (NOTE 1)
Cable required for Transformer
HV or LV side tails per phase (NOTE 2)
MVA
33 kV
(Amps)
13.8 kV
(Amps)
MVA
33 kV
13.8 kV
20/30
630
1506
36
1c x 400 mm 2 Cu
1c x 630mm 2 Cu
(1 cable per phase)
(2 cable per phase)
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(1 cable per phase)
(3 cable per phase)
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(2 cable per phase)
(4 cable per phase)
30/40
35/40/50
840
1050
2008
2510
48
60
(Note 3)
40/50/60
1260
3012
72
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(Note 4)
(Note 3)
(2 cable per phase)
(4 cable per phase)
(Note 4)
NOTE 1: Required cable continuous rating (120%) is based on the long-term cyclic rating of the
transformer which is also set to a limit of 120% (see 13.1.2).
NOTE 2: The transformer tails are expected to be installed in air indoors. In accordance with Clause
13.3.2, it is generally accepted that burial or ducts up to 15 m long may be used without derating 15
m.
NOTE 3: The 13.8 kV fixed pattern switchgear without forced cooling is limited to 2500 A. Hence, the
ratings of the 35/40/50 MVA and 40/50/60 MVA transformers are limited to 60 MVA.
NOTE 4: The transformer 13.8 kV tails are adequately rated to meet the 60 MVA rating imposed by
the 2500 A switchgear.
, where the stated rating is for cables laid in the air as this tends to be the most common
installation method for transformer tails installed between the switchgear and the
transformer. If the cable type and installation method for transformer tails are different, then
each cable installation will require an individual assessment, which may result in the
derating of the individual cable.
Table 17: Standard cable sizes for transformer tails
Transformer
Size
Min. Cable Continuous Rating
(120%) Required (NOTE 1)
Cable required for Transformer
HV or LV side tails per phase (NOTE 2)
MVA
33 kV
(Amps)
13.8 kV
(Amps)
MVA
33 kV
13.8 kV
20/30
630
1506
36
1c x 400 mm 2 Cu
1c x 630mm 2 Cu
(1 cable per phase)
(2 cable per phase)
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(1 cable per phase)
(3 cable per phase)
30/40
840
2008
48
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35/40/50
1050
2510
60
(Note 3)
40/50/60
1260
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(2 cable per phase)
(4 cable per phase)
3012
72
1c x 630mm 2 Cu
1c x 630mm 2 Cu
(Note 4)
(Note 3)
(2 cable per phase)
(4 cable per phase)
(Note 4)
NOTE 1: Required cable continuous rating (120%) is based on the long-term cyclic rating of the
transformer which is also set to a limit of 120% (see 13.1.2).
NOTE 2: The transformer tails are expected to be installed in air indoors. In accordance with Clause
13.3.2, it is generally accepted that burial or ducts up to 15 m long may be used without derating 15
m.
NOTE 3: The 13.8 kV fixed pattern switchgear without forced cooling is limited to 2500 A. Hence, the
ratings of the 35/40/50 MVA and 40/50/60 MVA transformers are limited to 60 MVA.
NOTE 4: The transformer 13.8 kV tails are adequately rated to meet the 60 MVA rating imposed by
the 2500 A switchgear.
13.3.4
Long Cables Between Switching Points
Where the development of power supply to customers in a remote location is being
considered, such connections shall be carefully considered. Depending on how long such
cables are, there can be issues associated with the capability of switchgear to cater for the
capacitive charging currents3 when the cable is energized and the ability to carry out fault
location and pressure testing using standard test equipment. In addition, this charging
current can also affect the performance of protection systems that use differential and
directional relays.
NOTE: For long-distance lines where fault diagnosis or inspection may be challenging
because of the cable route, a switching substation may need to be placed strategically for
operational needs.
The capacitive nature of cable also leads to the generation of capacitive ‘vars’ that will
return to the source substation. For small lengths, this may not be an issue, whereas for
long cables or cables operating at MV level, the reactive power generated could become
large and can lead to the Ferranti effect in cables where the receiving side voltage is outside
the statutory voltage limits. In such cases, to comply with the voltage limits at both the
sending and receiving ends, the over voltage effect on cable shall be minimized by using
line reactors to inject inductive vars, which will cancel capacitive vars that the cable
generates with a capacitance.
NOTE: The problem associated with the overvoltage as a result of the combination of high
system capacitance due to the long length of cables and a lightly loaded network can be
resolved by installing the shunt reactor or STATCOM at the source substation busbars.
13.3.5
Bonding of Cable Screens
The metallic sheath of the cable is bonded to earth to reduce electric force and thermal
effects. The most suitable in terms of functional, safe, and cost-effective sheath bonding
arrangement for their MV cable systems projects shall be considered. Single-point bonding,
3
Refer to the cable data sheet for charging current.
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solid bonding, and cross-bonding methods are used for grounding metallic sheaths
according to the IEEE 575-1988 standard.
Solid bonding is a simple and low-cost solution, but there is a limitation due to the induced
circulating currents (also sheath’s voltage) losses and eddy current losses into the sheaths,
which may cause additional heating, which will de-rate the cable system and result in larger
cable sizes. Hence, solidly bonded systems shall be used for 1-core and 3-core cables,
installed in trefoil, up to 10 km in length without further design to ensure that the maximum
induced standing sheath voltage is kept below 65 V (usually at the mid-point of the circuit),
and the circulating currents are below 50 A.
Cross-bonded systems may be used on long MV cable circuits, where circulating currents
have been calculated to exceed 50 A.
Single-point bonding will only be used on short lengths (less than 1 km) of 1-core cable
within a substation. This will ensure that the normal standing sheath voltage does not
exceed 65 V under normal running conditions. An alternative scheme that can be applied to
long line lengths is multiple single-point bonding, in which the three cable sheaths are
solidly bonded and grounded to an earth continuity conductor (ECC) at one end of a section
and connected to ground through sheath voltage limiters (SVL) at the other end. This
process is repeated at multiple locations along a route.
13.3.6
Bespoke and Real time Thermal Ratings
Where cost-effective, it may be appropriate to carry out a bespoke thermal rating study
using soil thermal resistivity measurements, ambient temperature, burial depth, and method
of installation for cables. Using such data and modelling it is possible to calculate circuit
specific ratings which may release latent thermal headroom.
13.3.7
Coordination of Current Rating
The distribution system is normally developed with co-ordinated ratings for the major items
of electricity network. Coordination is still the preferred approach to develop and maintain an
efficient, co-ordinated, and economical system of electricity supply for foreseeable future of
the NEOM regions.
It is important to cater for seasonal loads imposed due to peak summer and inclusion of
climate change factor. Compatibility of network component rating for cyclic and emergency
ratings shall be verified by use of approved software.
13.4
Fibre Optic Cable
To mitigate the risk of high induced voltages or earth potential rise, the fiber optic cables
shall be free of any metallic components. The fiber optic cable shall be circular in cross
section and free from pinholes, joints, and other defects. The cable shall be adequately
designed and shall meet the requirements of the NEOM-NDS-SPC-011.
Development of the MV system generally provides an opportunity for substantial sections of
telecommunications cables to be installed between selected locations. Consequently, when
MV underground cables are to be installed or replaced, the opportunity shall be taken to
review the initial and likely future telecommunication cable requirements. Provision of cable
ducts and fiber circuits shall be implemented for current and future telecommunications
requirements. At least one 96 core fiber optic cable as specified in the NEOM Technical
Specification for Fiber Optic Cables and NEOM design basis document shall be installed
with each MV cable. In some situations, for example when the LV distribution board is
located at the different location to the MV switchgear, at least one 96 core fiber optic cable
shall be installed with each LV cable from MV switchgear location to LV distribution board.
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13.5
MV System Protection
Protection of the MV systems shall be in accordance with the Distribution System Design
Standard (DSDS) document. The protection scheme on the MV network primarily depends
upon the network topology. Principles of primary (main) and backup protection must be
followed while designing the NEOM Electricity Network. There should be enough
redundancy included such that the loss of one piece of protection won't restrict the amount
of plants available. If requirements are not covered in the DSDS document, proposed
designs shall be agreed upon with the Head of Grid Planning & Development.
When network is proposed, it is necessary to conduct a thorough transient system and
protection study during the early design phase in order to establish an appropriate value for
the critical fault clearance time and allow the final MV network topology to be verified prior to
design finalization.
The primary rating of CTs and VTs used for protection purposes shall be co-ordinated with
the capability of the associated primary plant.
Due to the time grading of overcurrent and earth fault protection in a distribution ring
(interconnected radial network), the 200 ms fault clearance time is difficult to achieve with a
33 kV Ring Main Unit, and hence protection discrimination may not be achieved which leads
to extension of the fault zone. Therefore, enhanced protection needs to be implemented to
meet this requirement.
The directional overcurrent protection applied to the Low Voltage side of power transformers
shall be set to operate in a maximum time of 500 ms, with a target of achieving the fault
clearance in 200 ms if possible.
13.5.1
33kV Protection System
Two levels of protection equipment, main and backup, shall be provided to ensure that no
single failure of a protection device shall result in a failure to clear a fault from the primary
system.
Each protection system shall discriminate between faults within its protection zone and
initiate the opening of only those circuit breakers required to isolate the faulted plant from
the primary system.
The protection sensitivity shall be capable of detecting earth faults including a fault
resistance of up to 100 ohms.
The main protection which initiates fault clearance by a switching device shall operate in
less than 100 ms. This is to achieve a total fault clearance time from fault inception to arc
extinction of 200 ms.
On ENOWA Distribution feeder circuits, the target for the maximum clearance time of the
backup protection that initiates fault clearance by a switching device shall be 750
milliseconds. Under certain circumstances using overcurrent protections with a standard
inverse characteristic this may not be possible to achieve, e.g., persistent faults on the LV
side of the transformer. In these instances, an alternative-operating characteristic for the
protection shall be considered in order to meet the above requirement.
13.5.2
13.8kV Protection System
All plant will be protected against phase and earth faults. In general, 13.8kV plant and
feeder will be protection by time graded overcurrent and earth fault protection. Protection
systems shall co-ordinate with downstream and upstream protection devices, through the
application of appropriate settings, whilst achieving required sensitivity and operating time to
limit the disruption of supplies in the event of a system fault.
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The total fault clearance time for protections on radial networks shall where practicable not
exceed 1 s for a multi-phase or single phase to earth fault.
In some cases where the feeder required to run interconnected, or when the feeder demand
is high enough (i.e., more than 8MVA) to prevent the overcurrent protection setting to
achieve the required sensitivity, discriminative protection that will disconnect only faulty
system elements for all likely faults (I.e., line differential protection) shall be implemented.
13.5.3
Short-term Parallel Generation Protection
A customer may wish to install standby generation for the entire facility or critical loads only
to improve network resilience on their end in the event of a loss of utility supply. This
necessitates the testing of the standby generation in parallel with the DSO network to
maintain the continuity of supply during changeover and to facilitate for testing and
maintenance works, but this will be limited by the duration and testing regime as the
customer standby generator will exceed the contracted export capacity and have an impact
on the distribution network (i.e., voltage and fault level).
For a short-term parallel operation, the following parameters need to be taken into
consideration as follows: protection requirements, connection with the earth, fault level,
voltage rise/step voltage change, and out-of-phase capabilities.
If the total period of parallel operation is less than 5 minutes in any given month and no
more frequently than once a week, and is for generation plant testing purposes only, the
requirements for interface protection may be relaxed, provided that the supply to other
customers is not compromised.
The protection requirement for infrequent short-term parallel requires only under/over
voltage and under/over frequency protection.
An automatic electrical interlock shall be implemented to ensure that the parallel between
the generator and DSO system is disconnected after a maximum of 5 minutes in any month.
13.5.4
Parallel Generation Protection
If the distributed generation is to operate in parallel with the public distribution system for
more than 5 minutes in any given month, full generation interface protection (such as but
not limited to under/over-voltage protection, under/over-frequency protection, Loss of Mains
(LOM) protection etc.) shall be required; the total generation capacity and type of generation
technology at the point of connection, the system voltage at the point of connection, and the
agreed capacity will determine the protection requirements.
ENOWA DSO requires interface protection at the generation site to mitigate the potential
risks to the NEOM distribution network. Any generator connected to the distribution network
shall be disconnected from the distribution network during the LOM event. It is the
generation owner’s responsibility to provide Loss of Mains protection for their generation.
Note that it’s ENOWA DSO’s obligation to ensure the generation network is adequately
protected before energization is made.
For customer feeders at 33 kV and 13.8 kV that consist of generation, customer interface
protection shall be installed at Point of Supply (PoS) to provide both backup overcurrent and
backup LOM protection. The following functions shall be provided as the minimum
requirement of customer interface protection: under/over-voltage protection, under/overfrequency protection, Loss of Mains (LOM) protection etc. Additional protection may be
required subject to assessment of the connection.
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13.6
MV System Analogue Measurement
SCADA facilities shall be provided at MV substations. Protection and control facilities shall
be used to provide analogue measurement to monitor and manage power flow on the MV
system in both real-time and planning timescales. Following analogue measurement shall
be provided on all MV circuit breakers at an MV substation as minimum:
•
•
•
•
•
Red-Yellow, Yellow-Blue, and Bue-Red Voltage
Red, Yellow and Blue Current
Apparent Power, Real Power and Reactive Power
Power Factor
Frequency
The above analogue measurement shall be made available via the SCADA system of the
DSO. Direction of real and reactive power flows in the forward and reverse directions shall
be provided.
14
System Studies and Modelling
Network modelling and analysis tools with high quality, integrated data help to ensure that
networks are operated within thermal, voltage, fault level, and other constraints. NEOM
uses DIgSILENT PowerFactory and CYMCAP software tools to build and analyze network
models at the design stage and operation planning stage. To ensure that the network can
cope with credible running arrangements, System Intact (normal running conditions), First
Circuit Outage (FCO) and Second Circuit Outage (SCO) conditions are assessed. The
network must conform to a number of standards and criteria, some of which are license
requirements, including
14.1
•
Grid Code
•
Security of Supply Standards
•
Power Quality Standards
•
Railway Grid Connection Engineering Recommendations
System Studies
In accordance with NEOM-NEG-EMR-002, power system studies shall include but not be
limited to the following:
•
steady state load flow analysis: shall be performed to verify network operation
under various network contingencies and various load/generation balance
conditions. The results of load-flow studies are assessed to confirm that circuits are
not overloaded, and voltages are within acceptable limits.
•
short circuit analysis: shall be performed to identify the maximum available fault
current which is essential for sizing switchgear and selection of protective devices.
•
transient stability studies: shall be performed to analyze the system response to
forced or planned outages such as loss of generation, loss of load, and fault
clearance followed by the tripping of a network element (transformer, circuit), etc.
•
protection coordination and discrimination study,
•
power quality analysis (harmonics analysis, voltage fluctuations including flicker):
shall be performed to assess the impact of power swings (voltage fluctuation), nonlinear loads/power electronic devices (harmonic contributions).
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The design calculation shall include but not limited to demand estimation, equipment sizing
calculations, and cable temperature rise calculations and design.
14.2
System Model
Electrical power system analysis software shall be used for the design of all new
connections, asset replacement, system reinforcement, and modifications to the existing MV
system. Electrical models shall be created using single line diagram, schematic drawing and
equipment library, which provide a graphical representation of an electrical network with or
without a map background. Network analysis shall be carried out to specify the optimal size
of an electrical equipment.
An accurate representation of the DSO network is required to plan, analyze, and develop a
robust distribution system that will cater to the present and future energy needs of NEOM,
involving 100% renewable generation and the deployment of low carbon technologies. This
will require DSO planning team to undertake various studies to identify optimal options in
terms of voltage levels, network topologies, protection requirements and distributed energy
resources (DER) integration, etc.
An approved network model, referrred to as ‘Master’ model and realised in Digsilent
PowerFactory, shall be use to perform power system analysis for ENOWA networks. The
DSO planning team will be responsible to undertaking power systems analysis on a regular
basis, particularly during new connections/network extensions, to investigate any observed
abnormalities in the system and suggest effective remedies. In addition, approved/delivered
projects will be validated for inclusion within the master model to ensure compliance with
standards and grid codes.
15
System Reinforcement and Replacement
15.1
Reinforcement
Future reinforcement of the MV network may be required due to demand growth or new
demand or generation connections applications. However, gap analysis between demand
growth and maximum demand must be driven from network software. This should be
substantiated by information on circuit loading obtained from the SEC historical load
database, which is populated with data from the SEC SCADA system and half-hourly
metering data. Network reinforcement can be anything from minor protection changes up to
major upgrades of the network.
15.2
Replacement
The asset replacement strategy must be part of the initial design and it should be submitted
as part of the overall design. The spare capacity is strategically allocated (e.g., through the
use of spare ducts or the allocation of minimum 20% headroom) on the MV feeder and DSS
to avoid the overloading of the asset at the initial stage of the network design and increase
the utilisation of the asset throughout its life. The intervention to replace the present asset
and install a new one will be made in the event that an asset undergoes considerable
degradation, damage that cannot be economically repaired, or network restrictions
necessitate an increase in headroom capacity. Installation routes and corridors must be
designed for one level up the size of transformer for 33 kV voltage level.
15.3
Performance Criteria
Care must be taken to visualize and detail the installation strategy to achieve maximum
network performance in terms of cost and system losses along with future proofing.
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16
Plant location and routing circuits
Both the technical and physical aspects shall be considered for the optimal location of the
substation and the proposed underground cable route. The substation and the cables shall
be installed within the public highway subject to compliance with the requirements of NEOM
Authority, and relevant consents from the General Authority for Roads need to be obtained.
DSO should follow Public or Adoptable Highway land thereby limiting the land rights
required for substation locations and cable routes. Where infrastructure installation is
permitted entirely within the Highway, DSO can rely upon its Statutory Authority to access,
inspect, and maintain and where it is not possible, it may be necessary to take land rights
for future access, inspection, maintenance, etc.
If a substation is required to be established at the customer site, then a land transfer4 or the
lease or the customer to include and seek LUP approval for the agreed substation plot
within their site plans for the substation site shall be required to enable them to operate and
maintain a substation. Ventilation, monitoring systems, parking, and vehicular access rights
from the substation to the nearest Public Highway should also be considered. In addition to
this, the DSO owned incoming and outgoing cables from a substation shall have a cable
easement in place for all the circuits, which provides a legal framework that allows DSO to
use designated spaces in each property for cable infrastructure, ensuring coverage and
service delivery even if it’s on private property.
If the shared ownership, substation lease, and cable easement cannot be obtained, then the
point of supply, including the metering infrastructure, shall be at the interfacing boundary of
the customer. In such cases, it is the customer’s responsibility to operate and maintain the
downstream asset.
16.1
Location of substation
All substations shall be placed as near as practicable to the load centre. The System
Planner must consider the following criteria when specifying or agreeing the location of a
substation and where appropriate, should follow best practices for substation installation
“Noise” and “Electromagnetic Fields”. Whether a substation will cause a noise problem is
dependent to a large extent on the existing background noise levels in the locality. For
general guidance, the average background levels must be restricted to 30 dB in residential
area. It will not be acceptable if the transformer noise level exceeds the measured
background noise level by 5 dB (A) or more. If the transformer noise level is 10 dB (A)
below the background levels, then it will be acceptable.
During the design and installation of new substations, attention must be paid to the future
maintenance, renewal and disposal needs of the substation.
All substations and their associated housings shall be installed and arranged for flood and
fire mitigation.
16.2
Routing of Underground Cables
The proposed cable route can be adopted using standard Land Use Permit (LUP) process
approval if not incorporated and approved in the master plans. The cable shall be laid
parallel to the roads but on soft verge wherever possible outside the highway maintenance
area (or LUP) to avoid future road closures. Location of other utilities (e.g., railways,
information and communication technology (i.e., fibre optic cable and communication),
4
A land ownership transfer provides the adopting network with ownership of the land as opposed to a lease, which enables them to occupy
the land for a period of years (e.g., 99 years).
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water mains, gas mains, sewer) along the proposed cable routes shall also be taken into
consderation.
The installation of distribution power ables shall be done in accordance with best practice as
established by NEOM-NDS-STD-202, which shall be followed when installing distribution
power cables. This will include the trench design, excavation of trenches, trench
preparation, installation of ducts, installation of safety features and warning signs, laying
and pulling in of cables, back filling of trenches, re-making of ground, and recording of cable
positions.
Routes shall ideally be simple and direct, with the minimum of cross-over, particularly in the
open trenchwork of substations. Where practical and economic, cables shall be laid on a
route that is separate from other cables supplying or providing security to a given group of
customers. Opportunities shall be taken to use common excavation with new LV cables.
Cable routes shall be accessible by vehicle and preferably be on a public highway where
NEOM has Land Use Permit (LUP) rights.
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APPENDIX I: MV Network Configuration
The section provides an overview of the MV NEOM underground cable network arrangement from a
network planning perspective and does not cover design principles for customer connection schemes.
For customer connection schemes, refer to APPENDIX III.
Figure 10 below provides the overview of 13.8 kV underground cable network arrangement.
Feeder Configuration
Ring circuit on MVSS, from one side of
the bus section circuit breaker to the
other if the neighboring MV feeder
from neigbouring MVSS is not nearby.
Normally Open Point
Radial interconnector between MVSS,
ideally with the normally open switch
(refer section )
GM Substation
DSS capacity will
vary between 500 to
2000 kVA.
Feeder Configuration
Ring circuit from one
MVSS to the other
Security of Supply Standards
Each MV feeder with a switched
alternative supply shall not exceed
12 MVA demand to meet the
requirement of Demand Class B.
Single-loop arrangement (refer to section 6.2.1.1)
NOP
MV
MV
Single-loop arrangement
(refer to section 6.2.1.2)
NOP
Multi-loop arrangement
(refer to section 7.2.2 )
Substation A
Substation B
Remote Control
Every switching point including
NOP shall have a remote
controlled installed. NOP shall be
strategically located.
Restriction
Tee-off on the first leg of
the MV feeder shall not
be permitted.
Restriction
Ground mounted
substation shall be
looped unless single
customer requests
single circuit security
Radial Tee
Maximum one tee between remote
controlled switching points. Existing
teed substation shall be looped-in
where economic.
Security of Supply Standard
Each tee shall not exceed
2MVA capacity to meet the
requirement of Demand
Class A.
Restriction
Only one radial fed Pad-mounted
Substation permitted between two
switching points. Pad-mounted
transformer shall only be deployed
for 13.8 kV system
Figure 10: 13.8 kV underground cable configuration
Internal
Restriction
Extensible switchgear shall
be used for a 4 way kit.
4way RMU shall not be
permitted.
Internal
Figure 11 below provides an overview of 33 kV underground cable network arrangement.
Feeder Configuration
Ring circuit on MVSS, from one
side of the bus section circuit
breaker to the other if the
neighboring MV feeder from
neigbouring MVSS is not nearby.
GM Substation
Larger DSS capacity will vary
between 500 to 2000 kVA where
as smaller DSS also called as Small
Power Substation (SPSS) will vary
between 100 to 315 kVA.
Normally Open Point
Radial interconnector
between MVSS, ideally
with the normally open
switch (refer section
10.3.2)
Feeder Configuration
Ring circuit from one
MVSS to the other
Security of Supply Standards
Each MV feeder with a switched
alternative supply shall not exceed
12 MVA demand to meet the
requirement of Demand Class B.
Single-loop arrangement (refer to section 6.2.1.1)
NOP
33kV
Single-loop arrangement
(refer to section 6.2.1.2)
33 kV
Restriction
Network Automation
scheme such as
FLISR/APRS cannot
be implemented on
33kV feeder.
NOP
Single-loop arrangement
(refer to section 6.2.1.2)
Substation A
Substation B
Remote Control
Every switching point including
NOP shall have a remote
controlled installed. NOP shall be
strategically located.
Restriction
Tee-off on the 33 kV
feeder shall not be
permitted.
Restriction
Ground mounted
substation shall be
always be looped.
Restriction
33 kV network development will
primary depend upon the ability
to meet the fault clearance time
and fault location.
Restriction
Multi-loop feeder shall not
be permitted for 33kV
networks.
Restriction
Pad-mounted Substation
comprising MV fuses shall
not be permitted for 33kV
system.
Figure 11: 33 kV underground cable configuration
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APPENDIX II: Typical Substation Diagram
To establish a MV network for a development, the transformer, switchgear, and associated plant items are adequately rated to meet the required firm capacity of an
MVSS. This section provides a simplified substation diagram to meet a firm capacity of
•
30 MVA with the use of two transformer,
•
40 MVA with the use of two transformer,
•
50 MVA with the use of two transformer, and
•
60 MVA with the use of three transformers.
NOTE: A cost-benefit analysis must be used to support the decision to use three transformers rather than two in order to achieve the necessary firm capacity.
Internal
Internal
30 MVA Firm Capacity
Incomer 1 Incomer 2
2
Incomer 3 Incomer 4
2
1c 400mm Cu XLPE
(1 cable per phase)
1c 400mm Cu XLPE
(1 cable per phase)
1250 A
Space
(Future)
1250 A
1250 A
33 kV (31.5 kA / 3 Sec)
1250 A
1250 A
1c 400mm2 Cu XLPE
(1 cable per phase)
Spare
1c 400mm2 Cu XLPE
(1 cable per phase)
1c 400mm Cu XLPE
(1 cable per phase)
1250 A
1250 A
Space
(Future)
2
OLTC
+10% to -15%
1.25% step size
1250 A
1c 400mm2 Cu XLPE
(1 cable per phase)
Space
(Future)
Spare
Space
(Future)
OLTC
+10% to -15%
1.25% step size
Transformer 1
20/30 MVA
33/13.8 kV
Dyn1
Transformer 2
20/30 MVA
33/13.8 kV
Dyn1
NER
Ω
600A
NER
Ω
600A
1c 630mm2 Cu XLPE
( 2 cable per phase)
1c 630mm2 Cu XLPE
( 2 cable per phase)
2000 A
2000 A
2000 A
13.8 kV (25 kA / 3 Sec)
630 A
Space
(Future)
Space
(Future)
Spare
630 A
Spare
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
Capacitor
Aux Tx 1
Bank
630 A
Aux Tx 2
Figure 12: Example of two transformer MVSS with a 30 MVA firm capacity
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630 A
Capacitor
Bank
630 A
Spare
630 A
Spare
Space
(Future)
Space
(Future)
Internal
40 MVA Firm Capacity
Incomer 1 Incomer 2
2
Incomer 3 Incomer 4
2
1c 630mm Cu XLPE
(1 cable per phase)
1c 630mm Cu XLPE
(1 cable per phase)
1250 A
Space
(Future)
1250 A
1250 A
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
33 kV (31.5 kA / 3 Sec)
1250 A
1250 A
Spare
1c 630mm2 Cu XLPE
(1 cable per phase)
1c 630mm Cu XLPE
(1 cable per phase)
1250 A
1250 A
Space
(Future)
2
OLTC
+10% to -15%
1.25% step size
1250 A
1c 630mm2 Cu XLPE
(1 cable per phase)
Spare
Space
(Future)
Space
(Future)
OLTC
+10% to -15%
1.25% step size
Transformer 1
30/40 MVA
33/13.8 kV
Dyn1
Transformer 2
30/40 MVA
33/13.8 kV
Dyn1
NER
Ω
600A
NER
Ω
600A
1c 630mm2 Cu XLPE
(3 cable per phase)
1c 630mm2 Cu XLPE
(3 cable per phase)
2500 A
2500 A
2500 A
13.8 kV (25 kA / 3 Sec)
630 A
Space
(Future)
Space
(Future)
Spare
630 A
Spare
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
Capacitor
Aux Tx 1
Bank
630 A
630 A
Aux Tx 2
Figure 13: Example of two transformer MVSS with a 40 MVA firm capacity
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630 A
Capacitor
Bank
630 A
Spare
Spare
Space
(Future)
Space
(Future)
Internal
50 MVA Firm Capacity
Incomer 1 Incomer 2 Incomer 3
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
1250 A
Space
(Future)
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
1250 A
1250 A
33 kV (31.5 kA / 3 Sec)
1250 A
1250 A
1c 630mm2 Cu XLPE
(2 cable per phase)
Spare
Incomer 6
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
1250 A
Space
(Future)
Incomer 4 Incomer 5
1c 630mm2 Cu XLPE
(1 cable per phase)
OLTC
+10% to -15%
1.25% step size
1250 A
1c 630mm2 Cu XLPE
(2 cable per phase)
Spare
Space
(Future)
Space
(Future)
630 A
630 A
OLTC
+10% to -15%
1.25% step size
Transformer 1
35/40/50 MVA
33/13.8 kV
Dyn1
Transformer 2
35/40/50 MVA
33/13.8 kV
Dyn1
NER
Ω
600A
NER
Ω
600A
1c 630mm2 Cu XLPE
(4 cable per phase)
1c 630mm2 Cu XLPE
(4 cable per phase)
2500 A
2500 A
2500 A
13.8 kV (25 kA / 3 Sec)
630 A
Space
(Future)
Space
(Future)
Space
(Future)
Spare
630 A
Spare
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
630 A
Capacitor
Aux Tx 1
Bank
630 A
Aux Tx 2
Figure 14: Example of two transformer MVSS with a 50 MVA firm capacity
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630 A
Capacitor
Bank
630 A
Spare
Spare
Space
(Future)
Space
(Future)
Space
(Future)
Internal
60 MVA Firm Capacity
Incomer 1
Incomer 2
1250 A
1250 A
Space
(Future)
Space
(Future)
Spare
Incomer 3
1c 630mm2 Cu XLPE
(1 cable per phase)
1c 630mm2 Cu XLPE
(1 cable per phase)
Incomer 4
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
1250 A
1250 A
1250 A
1250 A
1c 400mm2 Cu
(1 cable per phase)
1250 A
Space
(Future)
Space
(Future)
Space
(Future)
Spare
Spare
630 A
Capacitor
Aux Tx 1
Bank
630 A
630 A
630 A
33 kV (31.5 kA/ 3 Sec)
630 A
1c 400mm2 Cu
(1 cable per phase)
Spare
630 A
630 A
630 A
630 A
630 A
2000 A
2000 A
630 A
630 A
630 A
Capacitor
Bank
630 A
630 A
13.8 kV (25 kA/ 3 Sec)
630 A
Spare
Figure 15: Example of three transformer MVSS with a 60 MVA firm capacity
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Space
(Future)
1c 630mm2 Cu XLPE
(2 cable per phase)
2000 A
630 A
Space
(Future)
NER
Ω 600A
NER
Ω 600A
2000 A
Spare
OLTC
+10% to -15%
1.25% step Size
1c 630mm2 Cu XLPE
(2 cable per phase)
630 A
1250 A
Transformer 3
20/30 MVA
33/13.8 kV
Dyn1
NER
Ω 600A
630 A
1250 A
1250 A
Transformer 2
20/30 MVA
33/13.8 kV
Dyn1
1c 630mm2 Cu XLPE
(2 cable per phase)
630 A
1250 A
OLTC
+10% to -15%
1.25% step size
Transformer 1
20/30 MVA
33/13.8 kV
Dyn1
630 A
1250 A
1250 A
1c 630mm2 Cu XLPE
(1 cable per phase)
1c 400mm2 Cu
(1 cable per phase)
Spare
2000 A
Incomer 6
1c 630mm2 Cu XLPE
(1 cable per phase)
1250 A
OLTC
+10% to -15%
1.25% step size
630 A
Incomer 5
1c 630mm2 Cu XLPE
(1 cable per phase)
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630 A
630 A
630 A
630 A
630 A
630 A
Aux Tx 2
630 A
Capacitor
Bank
630 A
Spare
630 A
Spare
Space
(Future)
Space
(Future)
Space
(Future)
Internal
APPENDIX III: MV Standard Connection Arrangement
This section presents a power supply strategy that effectively meets the capacity
requirements of MV customers stated in Section 8.2. Though the NEOM preferred
connection arrangements are set out in this policy document, a connection can, subject to
engineering and financial considerations, be made to meet any special requirements of the
customer. The connection capacity for each supply type is associated with the ducted rating
of standard cable sizes, but if higher capacity is required, then a bespoke cable can be
utilized to meet the customer load requirement.
1. Firm Supply Connection
A customer requesting reliable power supply for critical loads shall require firm supply,
which shall be achieved using parallel feeders originating from the separate bus section of
the same substation or from a separate substation wherever possible. The parallel feeder
system is commonly used in large-scale electrical distribution systems like industrial and
critical infrastructure like hospitals, data centers, airports, and commercial buildings,
providing reliable and efficient power to many end-users while minimizing the risk of
planned outages and faults.
Parallel MV feeders are required to maintain a continuous supply in the event of a first
circuit outage. A firm supply to the customer improves reliability and efficiency by
distributing the load evenly, reducing the risk of overloading and voltage drops. In the event
of planned or unplanned outages on one feeder, the load can be transferred to the other
feeder, thus ensuring an uninterrupted power supply.
A firm MV switching station comprises three or more panels of extensible ground-mounted
switchgear configured to enable two or more circuits from the MVSS, equipped with suitable
protection, to operate in parallel such that supplies to the MV substation will be maintained
for an outage on one of the two circuits from the source substation. Such a configuration
improves the security of supply to the ENOWA interface substation, and the customers
supplied from it when compared to a simple radial system. It is important to note that the
customer load for both systems intact (N condition) and system non-intact (N-1 condition)
should not exceed the agreed firm capacity of the site.
1.1
Connection Arrangement 1.1: Firm Connections for individual customer
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
This arrangement in Figure 16 provides a firm connection to an individual Customer’s
premises as there are two points of supply and an outage of one of the ENOWA metering
circuit breakers or feeders would not interrupt the supply to the other Point of Supply.
MV
MV Loop 1
MV Loop 2
DSO owned
cable
DSO owned
cable
ENOWA SWST
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer SS (Typical SS)
MV
Figure 16: Connection Arrangement 1.1
Internal
Internal
NOTE: Though the simplified diagram in Figure 16 represents a single circuit breaker for each cable
circuit within the ENOWA switching station, a two-panel circuit breaker shall be required for each
cable circuit for incoming and outgoing cable. The incoming cable CB shall have no protection,
whereas the outgoing cable CB shall have both protection and metering installed.
1.2
Connection Arrangement 1.2: Firm Connections for individual customer
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
The arrangement in Figure 17 arrangement is comparable to Figure 16, but it takes into
consideration the space constraint. If the customer requires a continuous, firm connection
from two discrete MV feeders from the MV busbar but there is not sufficient space for the
customer intake switchboard, then this connection can be made in exceptional
circumstances. A different level of protection is necessary when the cable loop travels
outside the building, but it is not necessary when the cable loop is inside the same building
between the metering CB and the customer's busbar end box.
In the above-mentioned exceptional circumstances, where it is agreed that a Point of Supply
can be provided at the ENOWA substation, arrangement 1.2 can be used such that the
customer owns the metering circuit breaker and the outgoing circuits. In this arrangement,
the protection is in the ENOWA owned Point of Supply circuit breakers. The customer
interface protection wall box shall be situated in the ENOWA building, from where multicore
cable will run to the customer room for the control of the metering circuit breaker. The
customer shall ensure that space is available to accommodate any interface equipment
within their switchgear located in their substation.
NOTE: The customer substation in Figure 17 is shown on a high level and will be designed
as per customer requirements.
MV
MV Loop 1
MV Loop 2
DSO owned
cable
DSO owned
cable
ENOWA SWST
MV
Point of Supply
Metering CB
P Protection CTs
M Metering CTs
Customer owned
cable
Customer owned
cable
MV Customer SS (Typical SS)
Figure 17: Connection Arrangement 1.2
1.3
Connection Arrangement 1.3: Firm Connections for individual customer
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
In exceptional cases, where the customer site is adjacent to the MVSS with no publicly
adopted highway, it is possible to provide the arrangement shown in Figure 18. This means
that a separate ENOWA switching substation may not be necessary. This arrangement
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provides a continuous, firm connection to an individual customer located in the vicinity of the
MVSS, where the MVSS circuit breaker serves as a Point of Supply.
In this arrangement, the protection is in the ENOWA-owned Point of Supply circuit breakers.
However, the customer must ensure that there is enough space available to accommodate
any interface equipment within their switchgear located in their substation.
MV
MV Loop 1
MV Loop 2
P
M
Metering CB
Protection CTs
Metering CTs
Customer
owned cable
Customer
owned cable
MV Customer SS (Typical SS)
MV
Figure 18: Connection Arrangement 1.3
1.4
Connection Arrangement 1.4: Dedicated connection from a MVSS
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
MV
MV Loop 1
MV Loop 2
DSO owned cable
(feeders are equipped
with unit protection)
DSO owned cable
(feeders are equipped
with unit protection)
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer
Customer
owned cable
Figure 19: Connection Arrangement 1.4
The arrangement in Figure 19 is an alternative to providing the customer with one of
Arrangement 1.1-1.3, provided that the customer substation is adjacent to the ENOWA
interfacing substation. Since the ENOWA substation and customer substation will be close
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to each other, the risk associated with the fault on the customer MV cable will be very low;
the outgoing customer MV cable will be a short piece of length of not more than 10m. It is
expected that the ENOWA substation will be situated at the customer boundary, and the
customer MV cable will be within the customer premises and not on the public highway.
Even though there is only one Point of Supply on the outgoing customer MV cable, this
connection arrangement can still be categorized as a firm supply given the likelihood of
customer MV cable failure and the supply arrangement to the customer via parallel feeders.
Unit protection on the incoming MV feeders will be required so that they can be run in
parallel, but this requires an extensible three-panel switchboard rather than an RMU. This
would provide continuity of supply in the event of a failure of one of the two feeders. The
capacity available on both the normal and switched alternative network feeders shall be
sufficient for supplying the full load requirements of the customer.
2. Switched-firm supply connection
A customer requesting supply for non-critical loads may require switched-firm supply using
an interconnected ring but radially open (often referred to as a switched alternative supply)
with normal open points. Both network automation and supervised remote control/switching
shall be implemented to speed up the restoration process and reduce the customer
interruption duration. However, the customer will experience a very short service
interruption due to the outage. The interconnected radial system is similar to the loop feeder
system in that it has multiple interconnected feeders.
2.1 Connection Arrangement 2.1: Connection to an existing MV loop with one RMU
Connection Capacity: Load ≤ 4 MVA at 13.8kV, Load ≤ 8.7 MVA at 13.8kV
A substation with a single RMU shall be the preferred arrangement as shown in Figure 20.
that provides a loop-in, loop-out arrangement; however, the capacity will be dependent on
the capacity available on that network. The capacity shall be constrained by either the rating
of the RMU circuit breaker or the network capacity, whichever is smaller.
MV
MV Loop 1
MV Loop 2
DSS 1
DSS 5
DSS 2
DSS 4
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer
Customer
owned cable
Figure 20: Connection Arrangement 2.1
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2.2 Connection Arrangement 2.2: Dedicated connection from a MVSS
Connection Capacity: Load ≤ 4 MVA at 13.8kV, Load ≤ 8.7 MVA at 13.8kV
The arrangement in Figure 21 and Figure 22 is for a bulk customer and provides a costeffective, switched-firm connection with the use of an RMU, but this would result in an
interruption of the MV supply for any outages on MV Loop 1. The supplies to the substation
can be restored by switching the alternative incoming MV feeder in the event of a failure of
one of the incoming feeders; however, there will be a supply outage for the customer for a
small period during the switching and restoration period. The capacity on both the switched
alternative network feeder and the regular network feeder must be adequate to meet the
customer’s entire load requirements.
MV
MV
MV Loop 1
MV Loop 1
DSO owned cable
DSO owned cable
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer
(Typical SS)
Customer
owned cable
Figure 21: Connection Arrangement 2.2 (option 1)
MV
MV Loop 1
MV Loop 2
DSO owned
cable
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer
Customer
owned cable
Figure 22: Connection Arrangement 2.2 (option 2)
As mentioned in 7.2.1 for MV feeder configuration, the switched alternative MV Loop feeder
should be prioritized to be fed from a different source substation, as shown in Figure 21. In
the event that it is not feasible to feed MV Loop 2 from a different source substation, then
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MV Loop 2 can be fed from the same source substation but from a different bus section of
the same source substation, as shown in Figure 22.
3. Non-firm supply connection
A customer may seek to accept a single circuit connection to reduce initial costs and accept
the outage risks due to planned maintenance or faults; if the circuit is subject to a fault, the
connection will be unavailable for a repair time. This shall be achieved by using a single MV
feeder without an alternative supply (often referred to as a radial feeder system). It consists
of a single feeder originating from the substation and delivering power to the end users.
Though it is the simplest and most cost-effective distribution feeder system, it has its own
limitations. Since it has only one path for power to flow from the substation to the end users,
it is vulnerable to power outages if there is a fault or outage along the MV feeder.
NOTE: There may be instances where power is required to be supplied in rural areas, either
for small residential load or for a public infrastructure such as water pumps, streetlights,
warning signs, illuminated traffic signs, illuminated boards, speed monitoring cameras, and
electric vehicle charging infrastructure. These supplies, if classed as non-critical supplies
depending upon their location remote from the source, can be provided with a radial supply.
3.1 Customer Connection Arrangement 3.1: Non-firm connection to a radial MV feeder
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
This connection arrangement (refer to Figure 23) allows multiple substations to be established
on the MV feeder for customers who are willing to accept lower resilience, provided that the
Security of Supply Standards are met before this supply is offered to any new customer. The
maximum connection capacity that can be provided to a customer depends upon the existing
demand, provided that the group demand of 12 MVA is not exceeded.
NOTE: For an MV feeder with multiple DSS, the demand group shall not exceed 12 MVA to comply
with Security of Supply demand class B.
MV Loop 1
DSS 1
DSS 2
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer A
(Typical SS)
Customer
owned cable
Figure 23: Connection Arrangement 3.1
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3.2 Customer Connection Arrangement 3.1: Non-firm connection to a radial MV feeder
Connection Capacity: Load ≤ 8 MVA at 13.8kV or Load ≤ 17.4 MVA at 33kV
If there is only one dedicated customer B to be supplied (refer to Figure 24), then the capacity
limitation associated with the Security of Supply Standard can be relaxed, and there is no
requirement to comply with the Security of Supply Standard.
NOTE: The security of supply Standards is not applicable to individual end customers (it applies to
group demand).
MV
MV Loop 1
ENOWA DSS
Metering CB
P Protection CTs
M Metering CTs
Point of Supply
MV Customer B
(Typical SS)
Customer
owned cable
Figure 24: Connection Arrangement 3.2
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APPENDIX IV: MV Demand Estimation Methodology
In the absence of network SCADA data (the demand for each DSS, MV feeder, and MVSS),
the MV customer demand or demand at the MV level shall be estimated using Coincident
Demand Load (CDL), which is also referred to as Coincident Peak Load. It is the maximum
sum of demand imposed by a customer or a group of customers over a time interval and
measures how each customer or group of customers contributes to the overall peak
demand of a system. The methodology for MV demand estimation as per the SEC
Distribution Planning Standard is described below.
Step 1: Determine the coincident demand load as follows:
The coincident demand load in kVA for the group of all units of the customer building is as
follows:
𝑁
𝐶𝐷𝐿 = (∑ 𝐶𝐿𝑖 × 𝐷𝐹𝑖 ) × 𝐶𝐹(𝑁) … … … … (𝑖)
𝑖=1
Where:
𝑁
Number of individual units required for the customer's building,
𝐶𝐿
Connected load in (kVA) for the individual unit number,
𝐷𝐹
Demand factor,
CDL
Coincident demand load, and
𝐶𝐹
Coincident factor
To determine the coincident demand load for each customer, the total connected load for
each individual unit in the customer building, including the number of individual kWh meters
(N), needs to be known. The other parameters, such as the Demand Factor and the
Coincident Factor, will be based on the type of facility and the number of energy meters,
respectively.
NOTE: For a group of (𝑁) units in the customer's building where all of them have the same
CL and the same DF, the equation to calculate the Coincident Demand Load (CDL) for this
group could be simplified as follows:
𝐶𝐷𝐿 = 𝑁 × 𝐶𝐿 × 𝐷𝐹 × 𝐶𝐹(𝑁) … … … (𝑖𝑖)
NOTE: For a group of (𝑁) units in the customer's building where any one of them has a
different connected load, the equation to calculate the Coincident Demand Load (CDL) for
this group of kWh meters will be as follows:
𝑁−1
𝐶𝐷𝐿 = [𝐶𝐿𝐿𝑎𝑟𝑔𝑒𝑠𝑡 𝑈𝑛𝑖𝑡 × 𝐷𝐹𝐿𝑎𝑟𝑔𝑒𝑠𝑡 𝑈𝑛𝑖𝑡 ] + [(∑ 𝐶𝐿𝑖 × 𝐷𝐹𝑖 ) × 𝐶𝐹(𝑁 − 1)] … … … (𝑖𝑖𝑖)
𝑖=1
Step 2: Calculate the Total Coincident Demand Load (TCDL) for the Development
Project or Plot Plan as follows:
Calculate the CDL according to the steps described below for MV connections for
customers’ buildings designed to be supplied by a private substation or by MV RMU.
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𝑁
𝑇𝐶𝐷𝐿 𝑇𝑜𝑡𝑎𝑙 = ∑ 𝐶𝐿𝑖 × 𝐶𝐹 𝑠𝑢𝑏𝑠𝑡𝑎𝑡𝑖𝑜𝑛𝑠 × 𝐶𝐹 𝑀𝑉 𝑓𝑒𝑒𝑑𝑒𝑟𝑠 … … … (𝑖𝑣)
𝑖=1
Where:
𝑁
Number of all substations which is designed to supply all plots/buildings
within the Development Project / Plot Plan
T𝐶𝐷𝐿
Total Coincident Demand Load in (kVA) for the individual substation
𝐶𝐹s𝑢𝑏𝑠𝑡𝑎𝑡𝑖𝑜𝑛𝑠
Coincident Factor between substations = 0.9 (refer Table 5)
𝐶𝐹𝑀𝑉 fee𝑑𝑒𝑟𝑠
Coincident Factor between MV Feeders = 0.9 (refer Table 5)
Based on the coincident demand load of the customer, a suitable customer connection
arrangement that meets the capacity requirement of the customer will be provided to the
customer.
Example: Calculate the MVSS substation load for two MV network loops
The coincident loads for the several DSS connected on the two MV loops out of a MVSS
are as follows: CDLDSS1 = 0.8 MVA, CDLDSS2 = 1.2 MVA, CDLDSS3 = 1 MVA, CDLDSS4 = 1.6
MVA, CDLDSS5 = 0.9 MVA
MVSS
13.8 kV
MV Loop 1
MV Loop 2
DSS 1
800 kVA
DSS 5
900 kVA
DSS 2
1.2 MVA
DSSS 4
1.6MVA
DSS 3
1 MVA
Figure 25: MV demand calculation example
In the case of multiple distribution substations on the same MV ring, the coincident factor is
applicable. In a similar fashion, when multiple MV rings are connected to a MVSS, a further
coincident factor is applicable. The total network demand on MVSS will be the sum of
individual MV ring demands after the application of coincident factors. By way of example,
for Figure 25 which indicates the design demand for each DSS:
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Method 1
Total demand load MVSS level can be calculated using the equation (iv)
TCDLTotal = (0.8x0.9x0.9) + (1.2x0.9x0.9) + (1x0.9x0.9)+ (0.9x0.9x0.9) + (1.6x0.9x0.9) = 4.46 MVA
Method 2
Total demand load for MV Loop 1 (feederl level),
TCDL Loop 1 = (0.8x0.9) + (1.2x0.9) + (1x0.9) = 2.7 MVA
Total coincident demand load for MV Loop 2,
TCDL Loop2 = (0.9x0.9) + (1.6x0.9) = 2.25 MVA
Total demand load at MVSS level,
TCDLTotal = (2.7x0.9) + (2.25x0.9) = 4.46 MVA
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APPENDIX V: Power Request Application
ENOWA requires stakeholders to submit power information regarding their assets (from
concept to operation) so that ENOWA may plan their generation and grid infrastructure
assets. To capture these power requirements, ENOWA collects this data in a Power
Request Form. The aim of this process is to formalize data collection, provide clearer data
requirements to our stakeholders, and pave the way for a more formalized relationship with
the NEOM regions and sectors. There are two steps: the first is to get the customer power
demand information via the Energy Demand Template, and secondly, the submitted
information by the customer needs to be pushed into the Energy Demand Portal by an
NEOM employee once the stakeholder’s asset has either reached NEOM Stage Gate 2D or
3 years prior to expected power on, whichever is earliest.
Step 1: The customer is required to fill out the Energy Demand Template provided by
NEOM, which outlines the required energy demand information and tools to aid in demand
estimation. The information captured within the template is listed below at a high level (not
exhaustive):
•
type of the service (new connection, update to an existing power request),
•
asset details (location and plot details),
•
nature of the asset (temporary or permanent connection, type of load, NEOM stage
gate),
•
type of connection required (preferred voltage, installed capacity, peak load, power
factor, annual energy demand, gross floor area),
•
type of supply required (firm, Switched firm and non-firm)
•
level of network resilience (category 1 (secure for first circuit outage), category 2
(switched alternative supply) and category 3 (single circuit conneciton)) required by
the customer, and
•
detailed load breakdown and load profiles, with supporting calculations.
The template also has a calculator, which provides the option for stakeholders with assets in
the early stages to use a GFA-based calculator tool to estimate their annual energy
demand. Assets in more advanced stages of the NEOM stage gate will be required to
complete their own calculations to support their assets.
Step 2: If a Power Request form is required, the stakeholder will submit this information via
the Energy Demand Portal, here: Energy Demand Portal (neom.com).
With the completion of those two steps mentioned above, we will endevor to ensure
electricity can be provided on time to our customers as part of an integrated energy system
compromising multiple assets, many of which have long lead times. However, each asset
will undergo an assessment to ensure that the requirements are realistic and accurate
before responding to the stakeholder with a proposed connection solution (grid/ off-grid,
demand provided as requested/ suggested variation to demand, or start date).
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