jamaica electric sector utility sector distribution code

jamaica electric sector utility sector distribution code
JAMAICA ELECTRIC SECTOR UTILITY SECTOR
DISTRIBUTION CODE
DISCLAIMER
This is a draft document and is a work in progress. The document is in the process of preparation and
editing and as such Table of Contents, page numbering, appendixes, glossary will be added or modified
as appropriate based on stakeholders review comments.
This draft document is for review only by the OUR and Stakeholders. It should not be relied upon by any
other party or parties or used for any other purpose.
The Office of Utilities Regulation (OUR) accepts no responsibility for the consequences of this document
being relied upon by any other party, or used for any other purpose, or containing any error or
omission which is due to an error or omission in data supplied to us by other parties.
The data, conclusions and recommendations will remain draft until the documents have gone through the
review process and is approved by the legally authorized entities
DC 1
SCOPE
DC 1.1.1
This Distribution Code sets out the procedures and principles governing the System
Operators relationship with all Users of the System Operator s Distribution System.
DC 1.1.2
The Distribution Code shall be complied with by the System Operator and existing and
potential Embedded Generators and Users connected to or seeking to connect to the
System.
DC 2
GENERAL REQUIREMENTS
DC 2.1.1
This Distribution Code contains the procedures to provide an adequate, safe and efficient
service to all parts of Jamaica, taking into account a wide range of operational
circumstances. It is however necessary to recognise that the Distribution Code can not
address every possible situation. Where such unforeseen situations occur the System
Operator shall act as a reasonable and prudent operator in the pursuance of any or a
combination of the following General Requirements. To protect the safety of the public
and employees
a.
b.
c.
d.
e.
f.
The need to preserve the integrity of the System
To prevent damage to the System.
Compliance with conditions under its Licence
Compliance with the Act
Compliance with the Transmission Code
Compliance with the Generation Code
DC 2.1.2
Users shall provide such reasonable co-operation and assistance as the Grid Operator
reasonably request in pursuance of the General Requirements.
DC 3
LONG TERM DISTRIBUTION NETWORK PLANNING
DC 3.1
Purpose and Scope
DC 3.1.1
The purpose of this chapter of the Distribution Code is to:
a.
Specify the responsibilities of the , Users and Generators with respect to the
planning of the Distribution System;
b.
Specify the technical studies and planning procedures to ensure that the System is
planned in compliance with statutory requirements;
c.
Specify the planning data required to be supplied by Users and
Generators to the and by the to Users and
Generators to enable the System to be planned to meet statutory requirements.
DC 3.1.2 The scope of this chapter covers:
a.
System Operator
b.
System Users;
c.
Embedded Generators and
d.
Generators
DC 3.2
Distribution Planning Responsibilities
DC 3.2.1
The is responsible for Distribution System planning including:
a.
Analysing the impact of changes to an existing Users Systems;
b.
Analysing the impact of the connection of new Users Systems;
c.
Analysing the impact of new generation connections;
d.
Analysing the impact of the connection of Rural Electrification Projects;
e.
Planning the network to meet forecast demand and forecast generation capacities;
and
f.
DC 3.2.2
Identifying and correcting areas of non-conformance with planning criteria related to
Voltage Drop, System Capacity, Fault Level, System Loss and Power Quality.
To address areas of non-conformance, reinforcement, extension, protection modification
and power quality improvement, works may be required at or on:
a.
the Connection Point between the Users System and the s System,
b.
the Distribution System remote from User Connection Points and
c.
the Transmission System remote from User Connection Points
DC 3.2.3
The Users and Generators are responsible for provision of information to support the
requirements of the and to operate their Systems in accordance with the data provided.
DC 3.3
Planning Process
DC 3.3.1
The shall follow a planning process divided into major activities as follows:
a.
Identification of the need for expansion or modification of the Distribution System;
b.
Formulation of alternative options to meet this need;
c.
Study of these options to ensure compliance with agreed technical limits and
justifiable reliability and quality of supply standards;
d.
Costing of these options and determination of the preferred option on the basis of
procedures consistent with Prudent Utility Practice ;
e.
Approval of the preferred option in line with JPS Financial Authorisation Levels and
initiation of execution.
DC 3.4
Planning Timescales
DC 3.4.1
The planning process above should operate on an annual planning cycle. The cycle
commences with the gathering of information for the demand forecasting process in DPC
3.2.2 at the beginning of Q3 (year n) and completes with the production of the Generation
Least Cost Expansion Plan at the end of Q2 (year n+1) followed by the Distribution
Expansion Plan a month later.
DC 3.4.2
Connection related planning studies will be undertaken outside the above process, but new
load information will be used to inform the demand forecasts. The timescales required to
undertake the new connection studies necessary to plan the System vary depending on the
driver for the studies and the ability to obtain consented routes.
DC 3.4.3
For smaller connections the planning timescales are set and agreed with the OUR. These
are included in the Distribution Connection Code section of this Distribution Code.
DC 4
Planning Principles
DC 4.1
Planning Criteria
DC 4.1.1
Planning criteria are based on the requirement to comply with statutory requirements.
Where no statutory requirements exist the criteria are based on international practices
which would be expected of a reasonable and prudent.
DC 4.1.2
The overriding principle in the planning of the System is the compliance with the licence
requirement for the to “provide an adequate, safe and efficient service based on modern
standards”.
DC 4.1.3
The effective planning of the Distribution System requires consideration of a broad range
of factors that can affect the network. These factors are identified in Appendix A to this
Distribution Planning Code which serves as a representation of the broad scope of any
System planning activity.
DC 4.2
Voltage Criteria
DC 4.2.1
The System shall be designed to ensure that under normal and planned contingency
conditions, voltages at all Connection points and buses are to be within:
a.
± 5% of nominal voltage under normal conditions
b.
±6% of nominal Voltage under planned contingency conditions
DC 4.3
Load Power Factor
DC 4.3.1
The System will be planned for a normal load power factor of 0.95.
DC 4.4
Security of Supply
DC 3.4.1
Jamaica does not have a prescriptive reliability standard that covers the Distribution
System planning in terms of maximum restoration times for different load groups
under different contingency considerations. This does not mean that security of
supply is disregarded in the planning of the Distribution system. The Service Area
Concept as described in DC 3.5 will be used to set a base n-1 contingency level on a
geographic basis and as a general planning guidance the overall network should be
designed to ensure that 98% of customers affected by faults can be restored within
24 hours as assessed on an annual basis.
DC 4.5
The Service Area Concept
DC 4.5.1
The Distribution System has developed using predominantly radial HV feeders teed off of
open ring Systems close to the Transmission System substations.
DC 4.5.2
The design criteria utilises a concept of Service Areas. Which are a network of substations
and feeders defined by any subset of the following parameters:
a.
Geography;
b.
Feeder Connectivity;
c.
Customer Type;
d.
Serviceability of Load (Transformer Capacity, Acceptable Voltage);
e.
Cost of Service Delivery.
DC 4.5.3
The Service Areas will be defined by the.
DC 4.5.4
In practical application the definition of Service Areas describes a section of (usually
interconnected) Distribution System supplied from one or more HV busbars. A Service Area
is not necessarily a load centre, however, situations may arise where this is the case.
DC 4.5.5
The Service Area should be able to sustain itself under normal conditions, and during any
single contingency event (i.e. loss of transformer, feeder, recloser etc).
DC 4.5.6
The objectives of the Service Area concept are as follows:
a.
Ensure reliable service under normal and N-1 contingency conditions.
b.
Localize impact of N-1 contingency.
c.
Ensure restoration of supply to customers after contingency in accordance with the
Overall Standards.
DC 4.5.7
d.
Ensure structured approach to expansion of the distribution network.
e.
Maximise utilization of distribution plant and assets by feeder load management.
f.
Group homogenous customers to facilitate delivery of special service needs.
g.
Ensure network safety and security.
Service Area design criteria are as below:
a.
Substation MVA capacity should be sufficient to satisfy load demand and to sustain a
N-1 contingency situation;
b.
Service voltages for all feeders should be the same;
c.
Where economically feasible, each Service Area should have at least two (2) 3-phase
interconnection points to adjacent Service Areas;
d.
Each feeder in Service Area must have at least one (1) 3-phase connection to a feeder
supplied by another transformer;
e.
Feeder loadings must be maintained to sustain 100% load transfers within the Service
Area after any contingency event;
f.
DC 4.5.8
Service Area must be returned to normalcy after contingency.
Investment triggers for reinforcement expenditure to support the Service areas are as
below:
a.
Violations of design criteria requirements for Service Area;
b.
Alternatives for load transfers do not exist;
c.
Transformer loading exceed 105% of thermal rating under N-1 contingency conditions;
d.
Overhead line exceed 100% of thermal rating under normal or contingency conditions;
Violations of service voltage criteria under normal or N-1 conditions.
DC 5
PLANNING STUDIES
DC 5.1
DC 4.1.1
General
The will undertake distribution planning studies as required to:
a.
Determine the connection requirements for any Users System, submitted in
accordance with the connection application process, including any reinforcement,
protection or power quality improvement requirements;
b.
Determine the connection requirements for any Generators System, submitted in
accordance with the connection application process, including any reinforcement,
protection or power quality improvement requirements;
c.
Prepare the Distribution Least Cost Expansion Plan which is prepared as required by
the OUR.
DC 5.2
Demand Forecasts
DC 5.2.1
Demand forecast are required to enable the network to be developed in a coordinated and
economic manner. A consumption forecast using an econometric regression methodology
is considered suitable for this. This forecast of unit consumption is then to be developed
into a peak demand forecast for each substation which will inform the studies outlined
further in this section.
DC 5.2.2
The overall process for development of the demand forecast at substation level is as below.
This should be undertaken on an annual basis in line with the planning timescales in DC
2.4.1.
DC 5.3
LOAD FLOW STUDIES
DC 5.3.1
The will undertake load flow studies using appropriate modelling tools.
DC 5.3.2
Load flows will be modelled at peak feeder loads, based on the feeder metering data or
SCADA data where metering data is not available, with forecasts at a feeder level based on
regression analysis and forecast forward for an appropriate period to ensure that all
network components are operating within their design parameters for the forecast period.
DC 5.3.3
Load flows will model the contingency scenarios planned for in the network design and will
be undertaken to ensure that all network components are operating within their design
parameters for all plausible scenarios of supply network reconfiguration. Short term and
emergency ratings of plant may be used if it is considered that the timescale for restoration
to normal operation will align with the manufacturers guidance on such ratings, or other
parameters as determined by the .
DC 5.4
Voltage Drop Studies
DC 5.4.1
The will undertake voltage drop studies to determine the voltages at all connection points
using appropriate modelling tools. Such studies will be used to determine the impact of any
load connection, generation connection, System extension or reinforcement.
DC 5.4.2
The planning of Voltage regulation will be in accordance with the principles in Engineering
Standard ES-1300 section 1.2.3. These principles recommend that voltage regulation
planning takes into account 5 year load growth forecasts and includes the use of:
a. Tap changers to maintain busbars at constant voltage;
b. Line Drop Compensation;
c. In line voltage regulators; or
d. Capacitors (fixed capacitor banks should be sized on present requirements rather than
growth forecasts to avoid over voltage).
DC 5.4.3
The Distribution System will be planned with voltage controlled level bars on the secondary
sides of the 69/24kV, 69/13.8kV and 69/12kV sides of the relevant transformers using
automatic tap changers.
DC 5.4.4
Capacitors may be used to provide voltage improvement on the distribution network. Their
use will be in accordance with Engineering Standard ES-1300 section 1.2.3.1. which
provides guidance in the following applications:
a. Reducing the lagging component of circuit current;
b. Increasing the voltage level at the load;
c. Improving voltage regulation, if the capacitors are properly switched;
d. Reducing I2R power loss and I2X kVAr loss in the system because of reduction in current;
e. Increasing power factor of source generators;
f.
Decreasing kVA loading on source generators and circuits to relieve overloads and
reduce demand.
DC 5.4.5
Suitable control Systems will be employed where required to ensure that excess voltages
are not experienced at connection points during periods of light load or abnormal running
conditions.
DC 5.4.6
Voltage regulators may be used to provide level bars or fixed voltage increases at
intermediate points on the Distribution network. Their use will be in accordance with
Engineering Standard ES-1300 section 1.2.3.2. which covers the rating, determination of
optimum location, requirements for bypassing, control settings and economic evaluation
of regulators and recommends the determining of size and location after fixed capacitor
bank sizes and locations have been determined.
DC 5.4.7
Voltage drops will be modelled at peak feeder loads based on the feeder metering data, or
SCADA data where metering data is not available, to ensure that the design voltage at the
customer connection points meet the voltage requirements of this code.
DC 5.4.8
Voltage drops will be modelled for the contingency scenarios planned for in the network
design and will be undertaken to ensure that the design voltage at customer connection
points meets the voltage requirements of this code for all plausible scenarios of supply
network reconfiguration.
DC 5.4.9
Any extension or connection to the s Distribution System shall be designed in such away
that it does not adversely affect the voltage control employed on the Distribution System.
Information on the voltage regulation and control arrangements will be made available by
the if requested by the User.
DC 5.5
Short Circuit Studies
DC 5.5.1
The will undertake fault level studies at all switching points on the network where fault
interrupting devices are located. The studies will determine the 3 phase and single phase
to ground short circuit levels. Studies will be carried out for the Maximum Plant and
Minimum Plant conditions.
DC 5.5.2
The System should normally be designed to ensure that the short-circuit fault current does
not exceed 80% of the declared manufacturers ratings of all switches, fuses, circuit breakers
and other protective devices in terms of both Breaking Capacity and Making Capacity.
DC 5.5.3
Where it is identified that the design Breaking Capacity or Making Capacity is likely to be
exceeded, the non-compliance should be documented and the plant subject to appropriate
operational restrictions until compliance is achieved.
DC 5.5.4
The and User will exchange information on fault infeed levels at
Connection Points. This shall include:
DC 5.5.5
a.
The maximum and minimum three-phase and line to ground fault in feeds; and
b.
The X/R ratio under short circuit conditions.
Unless the agrees otherwise it is not acceptable for a User or Embedded Generator to
limit fault current infeed to the s Distribution System through the use of protection and
associated Equipment if the failure of that protection and associated Equipment could
cause the s Distribution System to operate outside its short circuit rating.
DC 5.6
System Loss Studies
DC 5.6.1
System loss studies shall be performed to quantify the losses in the Distribution System and
determine optimum System open points to provide an acceptable balance between
reduced losses and System reliability.
DC 5.6.2
Where investment in the System is required, lower loss solutions, in terms of plant and
System configuration should be evaluated as part of the alternative solutions and
appropriate allowances made in the economic appraisal for any benefit arising from the
adoption of such solutions.
DC 5.7
Reliability
DC 5.7.1
System reliability studies shall be carried out to determine the theoretical levels of SAIDI
and SAIFI for the System using average fault rates for System components. These studies
will be used to determine optimum System configurations when undertaking any
connection, extension to or reinforcement of the distribution System.
DC 5.7.2
SAIDI and SAIFI have the definitions as described in IEEE Standard 1366-1998.
DC 5.7.3
SAIDI – The System Average Interruption Duration Index is the average outage duration for
each customer served. It is measured in units of time, minutes or hours, and is calculated
as:
DC 5.7.4
SAIFI - The System Average Interruption Frequency Index is the average number of
interruptions that a customer would experience. It is measured in units of interruptions per
customer, usually over the course of a year, and is calculated as:
DC 5.8
Economic Criteria to be Adopted for Least Cost Expansion Planning
DC 5.8.1
The planning studies described in this section may require solutions to be developed to
address any non-conformances found. It is usual that several alternative solutions will be
determined. The will use recognised methods of financial investment appraisal to ensure
that the option chosen represents the most efficient investment over the life of the assets.
DC 5.8.2
Unless other methods are agreed with OUR, the will utilise a Discounted Cash Flow method
to decide between alternative projects. The appraisal will normally cover a 40 year
investment period unless the nature of the assets to be installed requires an alternative
period.
DC 5.8.3
The Discount Rate used will be 12% or other values as agreed between the and the OUR
from time to time.
DC 5.8.4
For each comparable viable solution the investment appraisals will require financial
benefits to be determined for:
a.
Reduction in Losses;
b.
Improvements in Safety;
c.
Improvements in Quality of Supply; and
d.
Costs of maintenance.
DC 5.8.5
The methodology for determining a-d above shall be documented by the and applied in a
consistent manner.
DC 5.9
System Grounding
DC 5.9.1
System grounding will be in accordance with the Systems Grounding Regulations in
Engineering Standard ES-1300 section 2.7.
DC 5.9.2
System Grounding will be designed to the following key principles:
a.
To protect life from danger or electric shock, and property from damage.
b.
To limit the voltage upon a circuit when exposed to higher voltages than that for which
the circuit is designed.
c.
In general to limit AC circuit voltages to Ground to 150V or less on circuits supplying
interior wiring Systems; and
d.
To limit the voltage on a circuit which might otherwise occur through exposure to
lightning.
DC 6
STANDARD PLANNING DATA
DC 6.1
Energy and Demand Forecast
DC 6.1.1
Where the considers it necessary, the User shall provide the with its Energy and Demand
forecasts at each Connection Point for the five succeeding years.
DC 6.1.2
This forecast data, for the first year will include monthly Energy and Demand forecasts,
while the remaining four years will include only annual forecasts.
DC 6.1.3
The Users shall provide the net and gross values of Energy and Demand forecast. The net
values will be less any deductions to reflect the output of Customer Generating Plant.
DC 6.1.4
The following factors shall be taken into account by the and Users when forecasting
demand:
a.
Historical Demand Data;
b.
Demand Trends;
c.
Customer Self Generating Plant Schedules; and
d.
Demand Transfers.
DC 6.2
Distribution System Data
DC 6.2.1
The shall have available all the data relevant to the Distribution System itself. This network
data includes the following:
DC 6.2.2
Transformers (Including Voltage Regulators) - The primary input data for transformers
includes MVA rating, primary and secondary winding voltages, windings connection,
sequence impedances, X/R ratio, tap ranges, tap settings, emergency ratings.
DC 6.2.3
Distribution Lines -The primary input data required among other things are line voltage,
conductor type, type of construction, thermal ratings, emergency rating, sequence
impedances.
DC 6.2.4
Embedded Generators - Generators are modelled by their real and reactive power
capabilities for steady state analysis. For dynamic analysis more detailed mathematical
models are required for generators, exciters and governor control Systems. The generators
are represented by their mathematical model which includes the synchronous, transient
and sub transient reactance and inertia constants. The excitation and governor control
Systems are modelled by their type 1 excitation and type 10 general-purpose governor
control model respectively.
DC 6.2.5
Other Parameters - In order to develop a reliability data bank outage rates and durations
for all major equipment are also necessary.
DC 6.3
User System Data
DC 6.3.1
For Low Voltage connected Users the following data will be required by the
DC 6.3.2
a.
Maximum power requirement (kVA or kW)
b.
Type and number of significant load items (Cookers, Showers, Motors, Welders etc)
For Users Connected at High Voltage the following data will be provided to the .
a.
Connected Load including type and control arrangements
b.
Maximum demand
For Fluctuating and Cyclical Loads:
c.
The rate of change of demand
d.
The switching Interval
e.
The magnitude of the largest step change
DC 7
EMBEDDED GENERATORS
DC 7.1
General
DC 7.1.1
Embedded Generators can have a significant effect on the s Distribution System and as a
result its Users. To enable the to assess the impact that the Embedded Generator will have
on the System they will be required to provide the information outlined in DC 7.2.2.
DC 7.1.2
Embedded Generators shall comply with the Distributed Generation Interconnection
Technical Guidelines
DC 7.2
Provision of Information
DC 7.2.1
The will use information provided to in the planning of the Distribution System and the
assessment of connection requirements in terms of the voltage level to which the
connection should be made and any other requirements to enable the connection of the
generator.
DC 7.2.2
All Generators shall provide the following information below:
Data Description
Units
Terminal Volts
kV
Rated kVA
kVA
Rated kVAr
kVAr
Maximum generation
kW
Reactive Power required
kVAr
Type of Generator
Text
Type of Prime Mover
Text
Annual Operating Regime
Text
Fault Level contribution
MVA
Method of Voltage Control
Text
Generator Step-up Transformer Details
Text
Rated Capacity
MVA
Voltage Ratio
Text
Impedance
% on specified base
Data Description
Terminal Volts
Rated kVA
Rated kVAr
Maximum generation
Reactive Power required
Type of Generator
Type of Prime Mover
Units
kV
kVA
kVAr
kW
kVAr
Text
Text
Annual Operating Regime
Fault Level contribution
Method of Voltage Control
Generator Step-up Transformer Details
Rated Capacity
Voltage Ratio
Impedance
DC 7.2.3
Text
MVA
Text
Text
MVA
Text
% on specified base
For all Embedded Generators at a single site equal to or greater than 3MW in aggregate:
Data Description
Rated MW at Registered Capacity for individual units and
the Power Station
Rated MW at Minimum Generation for individual units in
the Power Station
Auxiliary Active Power demand for individual units and
the Power Station at Registered Capacity
Auxiliary Reactive Power demand for individual units and
the Power Station at Registered Capacity
Auxiliary Active Power demand for individual units and
the Power Station under Minimum Generation
Auxiliary Reactive Power demand for individual units and
the Power Station under Minimum Generation
Individual Generator Information
Rating
Generator MW/MVAr Capability Chart
Total Inertia Constant of Prime Mover and Generator
Stator Resistance
Direct axis synchronous, transient and sub-transient
reactance
Quadrature axis synchronous, transient and subtransient reactance
Direct axis synchronous, transient and sub-transient time
constants
Quadrature axis synchronous, transient and subtransient time constants
Units
MW
MW
MW
MVAr
MW
MVAr
MVA
Text
MWsec/MVA
% on specified base
% on specified base
% on specified base
secs
secs
Draft Distribution Code-OUR_CARCEP_Rev02
DC 7.2.4
Under certain circumstances more or less detailed information than that specified
above may be required. Additional data requirements are outlined in the
Distribution Connections Code and Distribution Data Registration Code of this
Distribution Code.
DC 8
MAINTENANCE STANDARDS
DC 8.1.1
All Plant and Apparatus on the System shall be operated and maintained in
accordance with original equipment manufacturers (OEM) recommendations and
Prudent Utility Practice and in a manner that shall not pose a threat to the safety of
employees or the public.
DC 8.1.2
The System Operator shall establish a Distribution System Maintenance Policy which
shall be reviewed and approved by the OUR.
DC 8.1.3
The System Operator shall maintain maintenance records relating to its maintenance
of Plant and Apparatus.
DC 9
COMPETENCY OF STAFF
DC 9.1.1
The System Operator shall have in place training polices that serve to ensure that
persons operating, maintaining, testing and controlling the System Operator
Transmission and Distribution Systems are competent for the tasks to be undertaken.
The policies shall include refresher training at appropriate intervals to maintain the
currency of the training.
DC 9.1.2
All persons operating, maintaining, testing and controlling the System Operator
Transmission and Distribution Systems, shall have received appropriate training to
ensure competency for the tasks that they shall be undertaking and refresher training
at appropriate intervals to maintain the currency of the training.
The System Operator shall maintain records of training given and issue certificates
indicating the areas of competency of the persons trained.
DC 9.2
Requirement for inspection
DC 9.2.1
All Plant and Apparatus that shall form part of the Distribution System shall only
become part of the Distribution System following inspection and approval by the
Government Electrical Inspectorate.
DC 6.0
DISTRIBUTION CONNECTION
DC 6.1
Introduction
DC 6.1.1
General
18
Draft Distribution Code-OUR_CARCEP_Rev02
This Section of the Distribution Code specify the normal method of connection to the
Distribution System and the minimum technical, design and operational criteria which
must be complied with by any User or prospective User.
DC 10.1.2
For the purpose of the Distribution Connection User refers to both Embedded
Generators and Customers connected to the Distribution System.
DC 10.1.3
In addition, details specific to each User s connection may be set out in a separate
Connection/Interconnection Agreement or in some cases a Power Purchase
Agreement. The connection conditions set out in this Code are complementary to
these Agreements.
DC 10.1.4
All interconnection costs and responsibility shall normally be borne by the User
connected to the Distribution System unless specified otherwise by an
Interconnection Agreement or policy or as dictated by the OUR.
DC 10.1.5
The JPS Line Extension Policy provides for the process and commercial aspects of
managing User connections to the System. This Distribution Connection Code does
not serve to cover the commercial arrangements for the payments, deposits or
refunds for connections.
DC 10.2
Objective
DC 10.2.1
The objective of the Distribution Connection is to ensure that by specifying minimum
technical, design and operational criteria the basic rules for connection to the
Distribution System shall enable JPS in its capacity as System Operator to comply with
its statutory and Licence obligations.
DC 10.2.2
Distribution Connection applies to the following: JPS in its capacity as Distribution
System operator at the Connection Points to the Distribution System;
a. Customers directly connected to the Distribution System, and
b. Generators connected to the Distribution System (Embedded Generators).
DC 11.0
METHOD OF CONNECTION
DC 11.1
General
DC 11.1.1
The System Operator in consultation with the User shall determine the optimum
connection method on the basis of several technical and economic factors including:
a.
b.
c.
d.
e.
f.
Geographical considerations including proximity to the Distribution System;
Maximum Demand to be supplied;
Generating Facility MW capacity;
Supply voltage;
Reliability considerations;
Standby or auxiliary power requirements;
19
Draft Distribution Code-OUR_CARCEP_Rev02
g. Substation configuration; and
h. Costs.
DC 11.1.2
The studies to be undertaken to determine the works required to facilitate a
connection are those outlined in the Distribution Planning Code and serve to ensure
that for any new connection the proposed customer(s) and all existing Customers
receive a supply within the statutory parameters.
DC 11.1.3
Multiple Connections Points shall not be provided to Connection Sites.
DC 11.1.4
No interconnection of the Systems from two different Connection Points shall be
allowed unless specifically detailed in the Connection Agreements and appropriate
safeguards put in place.
DC 11.1.5
It should be noted that it shall not be technically or economically practicable to
achieve uniformity of the method of connection. In all cases, Prudent Utility Practice
shall influence the method adopted.
DC 11.1.6
The provisions relating to connection to the Distribution System are contained in the
Connection Agreement with a User and include provisions relating to both the
submission of information and reports relating to compliance with the relevant
Connection Conditions for that User, Safety Rules, commissioning and periodic testing
programmes, Operation Diagrams, approval to connect, any Power Purchase
Agreement and the Terms and Conditions of Service.
DC 11.2
Connections at Low Voltage
DC 11.2.1
For low voltage connections, supply shall be provided at:
a.
b.
c.
d.
DC 11.2.2
Single phase 110V;
Single Phase110/220V; or,
Three phase 220V Delta
Three Phase 415/240V Star dependant on User requirements and
availability in the location required.
The information required for low voltage connections shall be a minimum of:
a.
b.
c.
d.
e.
Customer name, address and contact details
Location of proposed connection.
Type of connection (Residential, Commercial, Industrial)
Capacity required (if not known then type of use appliances etc)
Identification of any large motors or welders.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 11.2.3
Normal connections shall be provided by up to three single phase pole
mounted transformers appropriately connected. Transformer ratings and
connections shall be in accordance with Engineering Standard ES-1300-2.8.
DC 11.2.4
Connections may be provided by ground mounted three phase pad mount
transformers where specific User requests are made.
DC 11.2.5
The normal method of low voltage supply will utilise overhead lines. The
connection will be a single connection of the appropriate number of phases.
No alternative is normally provided. Underground cables may be used in the
central business area or due to specific User request. The charging policy
outlined in the JPS Standard Terms and Conditions of Service approved by the
OUR shall apply to requests for non-standard connection.
DC 11.2.6
The connection will be made to an appropriate point on the customer premises
approved by the Government Electrical Inspector. The customer may be
required to provide for the connection from this Connection Point to the
Metering Point.
DC 11.2.7
The Metering Points shall be accommodated in metering facilities provided by
the Customer. These metering facilities shall comply fully with the
requirements of Engineering Bulletin No. TSD 007/3 Metering Facility Policy
and the Standard Terms and Conditions of Service.
DC 11.2.8
The distance between the Connection Point and the Metering Point should be
minimized. It is also desirable that any such connection between the Connection Point
and the Metering Point is secured to prevent unauthorised access.
DC 11.3
Connection at Medium Voltage (MV)
DC 11.3.1
For connections given at MV level, then prior to the Completion Date under the
Connection Agreement, the following, (as applicable) may be requested to be
supplied by the User to the System Operator:
a. Updated Planning Code data with any estimated values assumed for planning
purposes confirmed or, where practical, replaced by validated actual values
and by updated estimates for the future and by updated forecasts for items
such as Demand;
b. Details of the Protection arrangements and settings including
c. Protection and Control single line diagrams;
d. Copies of all Safety Rules and Local Safety Instructions applicable at Users
Sites which shall be used at the System Operator/User interface;
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Draft Distribution Code-OUR_CARCEP_Rev02
e. Information to enable the System Operator to prepare Site Responsibility
Schedules on the basis of the provisions set out in Appendix A;
f. An Operation Diagram for all MV Apparatus on the User side of the
Connection Point;
g. The proposed name of the User Site (which shall not be the same as, or
confusingly similar to, the name of any JPS Site or of any other User Site);
h. A list of Safety Co-ordinators;
i. A list of the telephone numbers for Joint System Incidents at which senior
management representatives nominated for the purpose can be contacted
and confirmation that they are fully authorised to make binding decisions on
behalf of the User;
j. A list of managers who have been duly authorised to sign Site Responsibility
Schedules on behalf of the User; and
k. Information to enable System Operator to prepare Site Common Drawings.
DC 11.3.2
Such connections shall normally be overhead and provided from a radial feeder. The
connection shall not normally be designed to provide a switched alternative supply
for faults on the Distribution System that supplies the Customer. The Service Area
concept is used as outlined in the Planning Code to determine appropriate network
configuration and any reinforcement required to enable the connection to be
accommodated onto the System. The connection shall be designed to comply with
the Guaranteed and Overall Standards of restoration.
DC 11.3.3
Alternative supply arrangements may be requested based on either switched
alternative, (Manual or Automatic) or parallel circuit supply. These may be provided
at the discretion of the System Operator based on technical considerations. The
appropriate charging policy in force at the time shall apply to requests for non
standard connection.
DC 11.3.4
In some cases (for example Subdivisions) a single connection to a premise shall be
made and multiple Metering Points shall be installed to meter individual Customers.
In these cases meters shall only be installed to provide supplies to electrically isolated
User Systems.
DC 11.4
Connection of Generators
DC 11.4.1
Generator connections shall comply with the requirements of the Generation Code.
DC 11.4.2
In accordance with the Generation Code, Generators with a rated capacity of 10MW
or below may be connected to the Distribution System where technical conditions
allow. The design of connections between any Embedded Generating Unit and the
Distribution System shall be as set out in the Generation Code. The design of
connections between the Distribution System and Customers shall be consistent with
the Licence.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 11.4.3
The voltage of connection shall be at the discretion of the System Operator and based
on the relevant studies as described in the Planning Code.
DC 11.4.4
The connection of generators to the Distribution System shall be consistent with the
OUR Document Ele 2005/08.1 Guidelines for the addition of Generating Capacity to
the Public Electricity Supply System (2006) and the JPS Guide to the Interconnection
of Distributed Generation documents as amended from time to time.
DC 11.4.5
Embedded Generation Units shall be required, as a minimum, to meet following
performance standards:
a. Sustained Operation at any Load within the loading limits and within the
System frequency range 49.5 Hz to 50.5 Hz,;
b. Emergency Operation at any Load within the loading limits within the System
frequency range 48.0 Hz to 52.5 Hz during exceptional conditions;
c. Maintain normal rated output at the voltages specified in DC 2.2.1.
d. Sustained Operation at the rated Power Factor set out in the Interconnection
Agreement.
DC 11.4.6
Embedded Generation Units shall not normally be required to have Black Start
facilities.
DC 11.4.7
Embedded Generation units shall not normally be permitted or required to generate
when the part of the Distribution System to which they are connected is disconnected
from the Transmission System. Any such permission or requirement shall be detailed
in the Interconnection Agreement along with detailed requirements for the voltage
and frequency control.
DC 11.5
Variable Renewable Power Plant (VRPP)
Although this code is for all Variable Renewable Plants, the code addresses in greater
detail Wind and Photovoltaic technical aspects, which were prevalent at the time of
writing this code. The code will be updated as needed to address concerns of other
technologies.
Voltage Relay Requirements
Table DC 3.2.1 Voltage relay requirements
Voltage Condition (% of Vnominal)
V < 50%
50% < V < 88%
110% < V < 120%
V > 120 %
23
Maximum Time to
Disconnect
0.16 sec (8 cycles)
2 secs (100 cycles)
1 sec (50 cycles)
0.16 sec (8 cycles)
Draft Distribution Code-OUR_CARCEP_Rev02
DC 11.6
Frequency Criteria
DC 11.6.1
Maintain frequency within the limit of 50 Hz ± 0.2 Hz, with a deadband of 30 mHz.
Outside of this range the VRPP is required to trip off the JPS Distribution network.
DC 11.6.2
Power Factor
The VRPP facility shall be capable of operating in the power factor range of 0.9
lagging to 0.95 leading. Power factor correction techniques may be required.
DC 11.6.3
Voltage Flicker
Voltage Flicker is the rapid change in voltage that distorts or interferes with the
normal sinusoidal voltage waveform of the Distribution Network. Such
interference is a product of a relatively large current inrush when Apparatus, such
as a large motor, is suddenly switched on, or resulting from the sudden increased
Demand from for example welding equipment.
The current inrush acting over the Network impedance results in a voltage dip (sudden
fall) and/or voltage swell (sudden rise), therefore the Voltage Flicker, as well as when
the Apparatus concerned is off-loaded. VRPPs are not allowed to introduce significant
Voltage Flicker on the Distribution Network as measured at the Point of
Interconnection. In setting and analysing Voltage Flicker limits, the appropriate
standards should be applied.
DC 11.6.4
VRPP Harmonic Distortion
Harmonics are waveforms that distort the fundamental 50 Hz wave. The limits,
assessment, planning, testing and measurement for harmonic distortion levels are
well defined and be found in a number of internationally accepted standards such
as the IEEE 1547, its IEC equivalent and other internationally accepted standards.
If harmonics that exceed above listed standards result from the operation of the
VRPPs electrical equipment which are verified by testing, the VRPP system shall
be disconnected until the harmonics are mitigated by the VRPP in accordance with
the above listed standards.
In the situation where current harmonic measurements are required, the current
harmonic limits shall be derived from the harmonic voltage limits in accordance
with the appropriate standards.
Additionally, and in instances where several VRPPs are located in the vicinity of each
other, the total harmonic contribution shall not exceed the above requirements.
DC 11.6.5
VRPP Phase Imbalance & Negative Sequence Handling
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Draft Distribution Code-OUR_CARCEP_Rev02
The negative sequence current control would enable the reduction or even total
elimination of the negative sequence short circuit current in many modern wind
turbines/solar inverters. During unbalanced faults, e.g. line-to-line fault, full
negative sequence current suppression control would lead to a line-to-line short
circuit current in the range of the current of the loads connected to the grid or even
to zero under no load conditions. The conventional protection devices would thus
have difficulty to sense and clear the fault.
In order to overcome this problem, VRPP are to be required to inject a certain level
of inductive negative sequence short circuit current proportional to the negative
sequence voltage. This will result not only in higher short circuit current but also in
the reduction of the negative sequence voltage and thus better phase voltage
symmetry.
Under normal operation, the maximum negative phase sequence component of the
phase voltage of the power system should remain below 1%. A control measures can
be implemented to support this requirement, while adhering to the relevant
standards, should be applied.
DC 11.6.6
VRPP Anti-Islanding Requirements
Under no conditions is the VRPP permitted to be in an islanded situation with any
part of the Distribution System. Islanding occurs when part of the Distribution System,
to which the VRPP is connected, during emergency conditions, becomes detached
from the rest of the Distribution System as described in ANSI/IEEE Std. 1547-2003. In
order to eliminate this risk, the following shall be implemented:
1.
The VRPP must be capable of tripping off line in accordance with JPS, upon loss of
main power (LoM) from the grid. It is the responsibility of the VRPP to incorporate the
most appropriate technique or combination of techniques to detect a loss of main
power event in its protection systems to achieve disconnection of the VRPP from the
Distribution System. This will be based on knowledge of the VRPP, site and network
load conditions.
2.
If no facilities exist for the subsequent re-synchronization with the rest of the
Distribution System then the VRPP shall under JPS instruction ensure that the VRPP is
disconnected for re-synchronization.
DC 11.6.7
VRPP Data Requirements& Studies
In addition to the studies outlined in DC 4 above and due to the intermittent nature
of the VRPP, additional power system studies as outline below but not limited to
should be done:




Voltage Flicker
Harmonic Analysis
Phase Imbalance
Feeder Stability
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 12
DC 12.1
POWER QUALITY STANDARDS
Power Quality
DC 12.1.1
For the purpose of this Article, Power Quality shall be defined as the quality of the
voltage, including its frequency and the resulting current that is measured in the
Distribution System during normal conditions. The standards applicable to Power
Quality are set out in the System Operator s Power Quality Policy and System
Operation Policy No 2 Operational Standards of Security of Supply which shall be
approved by the OUR and amended from time-to-time.
DC 12.1.2
A Power Quality problem exists when at least one of the following conditions is
present and significantly affects the normal Operation of the System:
a.
b.
c.
d.
e.
f.
The System Frequency has deviated from the nominal value of 50 – 0.2Hz;
Voltage magnitudes are outside their allowable range of variation;
Harmonic Frequencies are present in the System;
The magnitude of the phase voltages are unbalanced;
The phase displacement between the voltages is not equal to 120 degrees;
Voltage Fluctuations cause Flicker that is outside the allowable Flicker
Severity limits; or
g. High-frequency Over-voltages are present in the Distribution System.
DC 12.2
Frequency Variations
DC 12.2.1
The frequency of the Distribution System shall be consistent with JPS System
Operation Policy No.2 and have a normal frequency of 50Hz – 0.2Hz and shall be
controlled within the limits of 49.5 and 50.5 Hz.
DC 12.2.2
Under some conditions the system frequency could rise to 52.5 Hz or fall to 48.0 Hz
and shall be taken into account in the design of Plant and Apparatus.
DC 12.3
Power Factor
DC 12.3.1
The User shall maintain power factor at the Connection Point to the Distribution
System consistent with JPS Standard Terms and Conditions of Service as amended
from time to time.
DC 12.3.2
The System Operator shall correct Reactive Power Demand on feeders and
substations to a level that will economically reduce technical losses and maintain a
minimum power factor of 0.95 lagging on the Distribution System.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 12.4
Voltage Variations
DC 12.4.1
The voltage on the 24 kV, 13.8kV and 12 kV parts of the Distribution System at each
Connection Site with a User shall normally remain within –5% of the nominal value.
DC 12.4.2
The voltage on the lower voltage side of transformers at Connection Sites with Users
shall be consistent with the JPS Standard Terms and Conditions of Service as amended
from time to time.
DC 12.5
Voltage Waveform Quality
DC 12.5.1
All Plant and Apparatus connected to the Distribution System, and that part of the
Distribution System at each Connection Site, should be capable of withstanding
distortions of the voltage waveform in respect of harmonic content and phase
unbalance as outlined in the System Operator Power Quality Policy.
DC 12.6
Exceptional Conditions
DC 12.6.1
Some events such as system faults which involve the Transmission System or a
generating plant or faults that lead to loss of more than one generating set in the
System or where a Significant Incident has occurred or during constrained operating
conditions such as light load conditions and shortage of Active/Reactive Power, can
result in variations outside the normal power quality standards as outlined in section
DC 12 and its subsections. During these events, the System Operator shall be relieved
of its obligation to comply with the System conditions referenced in the
aforementioned.
DC 13.0
PLANT AND APPARATUS RELATING TO CONNECTION SITES
DC 13.1
General Requirements
DC 13.1.1
All Plant and Apparatus relating to the Users/System Operator at the
Connection Point, shall be compliant with the following requirements in DC 13.0 and
its subsections.
DC 13.2
Substation Plant and Apparatus
DC 13.2.1
All circuit breakers, switch disconnectors, Earthing Devices, power
transformers,
Voltage Transformers, reactors, Current Transformers, surge
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Draft Distribution Code-OUR_CARCEP_Rev02
arresters, bushings, neutral Equipment, capacitors, line traps, coupling devices, external
insulation and
insulation co-ordination at the User/JPS Connection Point shall be
constructed, installed and tested in accordance with the current edition at the time of
construction of the following codes and standards, or their international equivalents and
Prudent
Utility Practice:
ACI
American Concrete Institute
ANSI
American National Standards Institute
ASCE
American Society for Civil Engineers
ASME
American Society for Mechanical Engineers
ASNT
American Society for Non-Destructive Testing
ASTM
American Society for Testing Materials
AWS
American Welding Society
BSJ
Bureau of Standards Jamaica
IEC
International Electro-technical Commission
IEEE
Institute of Electrical and Electronic Engineers
ISO
International Organization for Standardization
NBCJ
National Building Code of Jamaica
NEC
National Electric Code
NEMA
National Electric Manufacturers Association
NEPA
Natural Environmental and Planning Agency (Jamaica)
NESC
National Electric Safety Code
NETA
National Electric Testing Association
NFPA
National Fire Protection Association
OSHA
Occupational Safety and Health Administration
SSPC
Steel Structures Painting Council
UL
Underwriters Laboratory
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 13.2.2
DC 13.3
Plant and Apparatus shall be designed, manufactured and tested in premises certified
in accordance with the quality assurance requirements of ISO 9001 or equivalent.
Generator Connection Points
DC 13.3.1
The requirements for the design of Connection Points between Generators and the
System Operator are set out in the Generation Code. For information the following
sections are extracted from the Generation Code, minor wording modification have
been made to refer to Distribution connections.
DC 13.3.2
The Generation Code states that the voltage level at which the Generating
Unit(s) are connected to the Transmission or Distribution System shall be dependent on
but not
limited to the size and number of units and the other factors that determine
the Connection Point. Subject to other technical considerations, Generating Units with a
Rated Capacity of 10 MW or above shall be connected to the Transmission System at
69 kV or 138 kV. Generating Units with a Rated Capacity of below 10 MW may be
connected to either the Transmission System at 69 kV or 138 kV or the primary
Distribution System at 24 kV or less. The chosen method of connection shall be
determined by the System Operator on the grounds of system security, stability and
safety.
DC 13.3.3
All Substations shall have the capability to disconnect or separate, from the
Distribution System, any line and/or Generating Unit which is interconnected to the
Substation.
DC 13.3.4
The Generation Code states that the method of connection of Generating Unit(s) shall
be determined on the basis of several technical and economic factors which include:
a.
b.
c.
d.
e.
f.
g.
Proximity to System Grid;
Generating Unit MW rating or Generating Facility MW capacity;
Supply voltage;
Reliability considerations;
Auxiliary power supply;
Substation configuration; and
Costs.
It should be noted that it will not be technically or economically practicable to achieve
uniformity of the method of connection. In all cases however, Prudent Utility Practice
shall influence the method adopted.
DC 13.4
DC 13.4.1
Interconnection Connection Points to Transmission System
The Distribution System connection to the Transmission System shall comply
with section TC 4.4 o the Transmission Connection code.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 13.5
Protection Requirements
DC 13.5.1
The protective Systems to be applied to Generating Units are set out in the
Generation Code and shall, as a minimum, have protection against the following
incidents unless specifically agreed with the System Operator:
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k.
l.
m.
n.
o.
Loss of excitation;
Under excitation;
Unbalanced load Operation;
Stator phase faults and earth faults;
Reverse power protection;
Main Generating Unit Step Up transformer phase and earth faults, HV and LV;
Station service transformer phase and earth faults, HV and LV;
Transformer tank sudden pressure;
Backup protection in the event that external phase and earth faults are not
cleared by remote protection System;
Backup protection in the event of circuit breaker failure to operate;
Generating Unit over and under frequency;
Generator over speed;
Stator over temperature;
Rotor over temperature; and
Restricted earth fault;
DC 13.5.2
All protection Systems and settings shall be in accordance with the System
Operators
protection policy as contained in the document JPS Protective Relaying
Philosophy & Practices .
DC 13.5.3
Protection of the Distribution System and Customers directly supplied from the
Distribution System shall be designed, coordinated and tested to achieve the desired
level of speed, sensitivity and discrimination to isolate the affected parts of the
System while ensuring that the section isolated does not include parts of the System
not directly affected by the fault, as far as possible in accordance with Prudent Utility
Practice, and maintaining supplies to the remainder of the System within design
parameters.
DC 13.5.4
The System Operator shall be solely responsible for the protection of the
Distribution System. Users and Embedded Generators shall be solely responsible for the
protection of the User Systems on their side of the Connection Point.
DC 13.5.5
be
DC 13.5.6
Users shall design their protection System to ensure that no other User shall
affected for faults on their System.
The reliability of the protection scheme to initiate the successful tripping of
the Circuit
Breakers that are associated with the faulty Equipment shall be consistent
with Prudent Utility Practice.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 13.5.7
The System Operator may require specific Users to provide other protection
schemes, designed and developed to minimize the risk and/or impact of
disturbances on the
Grid.
DC 13.5.8
Where as part of the Connection Agreement, a User is required to provide
Demand disconnection as part of the System Operators under frequency
management process that includes the automatic disconnection of
substations and feeders then the relays shall comply with the requirements
of Appendix B.
DC 14
SITE RELATED CONDITIONS
DC 14.1
General
DC 14.1.1
In the absence of agreement between the parties to the contrary, construction,
commissioning, control, operation and maintenance responsibilities follow
ownership.
DC 14.2
Responsibilities for Safety
DC 14.2.1
Before connection to the Distribution System at the MV level the System Operator
and the User shall enter into a written agreement as to the Safety Rules to be used for
work on Plant and/or Apparatus at the Connection Point
DC 14.3
Site Responsibility Schedules
DC 14.3.1
In order to inform site operational staff and the System Operator s Control Engineers
of agreed responsibilities for Plant and/or Apparatus at the Operational Interface at
the MV level, a Site Responsibility Schedule shall be produced for System Operator
and Users with whom they interface.
DC 14.3.2
The format, principles and basic procedure to be used in the preparation of Site
Responsibility Schedules are set down in Appendix A. These documents should be
incorporated into the Connection (Interconnection) Agreements.
DC 14.4
Operation Diagrams
DC 14.4.1
An Operation Diagram shall be prepared for each Connection Site at which a
Connection Point is at the MV level in accordance with Appendix C. Users shall provide
Operation Diagrams of their Apparatus to the System Operator in a suitable form as
specified by the System Operator.
DC 14.4.2
The Operation Diagram shall include all MV Apparatus and the connections to all
external circuits and incorporate numbering, nomenclature and labelling, as set out
in the Operations Code. At those Connection Sites where SF6 gas-insulated metal
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Draft Distribution Code-OUR_CARCEP_Rev02
enclosed switchgear and/or other SF6 gas-insulated MV Apparatus is installed, those
items must be depicted within an area delineated by a chain dotted line which
intersects SF6 gas-zone boundaries. The nomenclature used shall conform to that
used on the relevant Connection Site and circuit.
DC 14.4.3
The Operation Diagram (and the list of technical details) is intended to provide an
accurate record of the layout and circuit interconnections, ratings and numbering and
nomenclature of MV Apparatus and related Plant.
DC 14.5
SF6 Gas Zone Diagrams
DC 14.5.1
An SF6 Gas Zone Diagram shall be prepared for each Connection Site at which a
Connection Point exists where SF6 gas-insulated switchgear and/or other SF6 gasinsulated MV Apparatus is utilised. This is to ensure that responsibility for the SF6 gas
is documented and is particularly important as the chamber containing the insulating
medium can extend beyond the Connection Point. They shall use, where appropriate
the graphical symbols shown in Appendix C. The nomenclature used shall conform
with that used in the relevant Connection Site and circuit.
DC 14.6
Preparation of Operation and SF6 Gas Zone Diagrams
DC 14.6.1
Each party shall provide to the other party an Operation Diagram and details of the
SF6 Gas Zones on its side of the Connection Point. The party owning the Connection
Site is then responsible for the preparation of a composite Operation Diagram and
SF6 Gas Zone diagrams for the site.
DC 14.7
Changes to Operation and SF6 Gas Zone Diagrams
DC 14.7.1
When either party has decided that it wishes to install new MV Apparatus or it wishes
to change the existing numbering or nomenclature of its MV Apparatus at a
Connection Point it shall one month prior to the installation or change, send to the
other party a revised Operation Diagram of that Site, incorporating the new MV
Apparatus to be installed and its numbering and nomenclature or the changes, as the
case may be.
DC 14.8
Validity
DC 14.8.1
The composite Operation Diagram prepared by System Operator or the User shall be
the definitive Operation Diagram for all operational and planning activities associated
with the Connection Site. If a Dispute arises as to the accuracy of the composite
Operation Diagram, a meeting shall be held at the Connection Site, as soon as
reasonably practicable, between the System Operator and the User, to endeavour to
resolve the matters in Dispute.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 14.9
Site Common Drawings
DC 14.9.1
Site Common Drawings shall be prepared for each Connection Site which is connected
at the MV level and shall include Connection Site layout drawings, electrical layout
drawings, common Protection/control drawings and common services drawings.
DC 14.9.2
In the case of a User Connection Site, the System Operator shall prepare and submit
to the User, Site Common Drawings for the System Operator side of the Connection
Point
in accordance with the requirements of the Connection Agreement.
DC 14.9.3
The User shall then prepare, produce and distribute, using the information submitted
by the System Operator, Site Common Drawings for the complete Connection Site in
accordance with the requirements of the Connection Agreement.
DC 14.9.4
In the case of a System Operator Site, the User shall prepare and submit to the Grid
Operator Site Common Drawings for the User side of the Connection Point in
accordance with the requirements of the Connection Agreement.
DC 14.9.5
The System Operator shall then prepare, produce and distribute, using the
information
submitted by the User, Site Common Drawings for the complete
Connection Site in accordance with the requirements of the Connection Agreement.
DC 14.10
DC 14.10.1
Changes to Site Common Drawings
When the System Operator or a User becomes aware that it is necessary to changeany
aspect of the Site Common Drawings at a Connection Site it shall notify the other Party
and amend the common site drawings in accordance with the procedure set out in DC
10.9.
DC 14.10.2
If the change can be dealt with by notifying the other Party in writing of the change
and for each party to amend its copy of the Site Common Drawings then each party
shall so amend.
DC 14.11
Validity of Site Common Drawings
DC 14.11.1
The Site Common Drawings for the complete Connection Site prepared by the User or
the System Operator as the case may be, shall be the definitive Site Common
Drawings for all operational and planning activities associated with the Connection
Site. If a Dispute arises as to the accuracy of the Site Common Drawings, a meeting
shall be held at the site, as soon as reasonably practicable, between the System
Operator and the User, to endeavour to resolve the matters in Dispute.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 14.12
Access
DC 14.10.1
The provisions relating to access to System Operator Sites by Users, and to User Sites
by the System Operator are set out in each Connection Agreement with the System
Operator and each User and/or Standards Terms and Conditions of Service.
DC 14.10.2
In addition to those provisions, where a System Operator Site contains exposed MV
conductors, unaccompanied access shall only be granted to individuals holding an
Authority for Access issued by the System Operator.
DC 14.13
Maintenance Standards
DC 14.13.1
All Plant and Apparatus at the Connection Point shall be operated and maintained in
accordance with Prudent Utility Practice and in a manner that shall not pose a threat
to the safety of any personnel or cause damage to the Plant and Apparatus of the
System Operator or the User.
DC 14.13.2
The User shall maintain a log containing the test results and maintenance records
relating to its Plant and Apparatus at the Connection Point and shall make this log
available when requested by the System Operator.
DC 14.13.3
The System Operator shall maintain a log containing the test results and maintenance
records relating to its Plant and Apparatus at the Connection Point and shall make this
log available when requested by the User.
DC 14.13.4
Either Party shall have the right to inspect the test results and maintenance records
relating to the other Party s Plant and Apparatus at any time.
DCC 11
COMMUNICATIONS AND CONTROL
DC 15.1.1
In order to ensure control of the Distribution System, telecommunications between
User(s) and the System Operator must be established if required by the System
Operator.
DC 15.1.2
Control Telephony is the method by which a Users Responsible Engineer/Operator
and the System Operator s Control Engineers speak to one another for the purposes
of control of the Distribution System in both normal and emergency operating
conditions.
DC 15.1.3
At any Connection Point where the Users telephony Equipment is not capable of
providing the required facilities or is otherwise incompatible with the System
Operators control telephony, the User shall install appropriate telephony Equipment
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Draft Distribution Code-OUR_CARCEP_Rev02
to the specification of the System Operator. Details of, and relating to, the control
telephony required shall be set out in the Connection Agreement.
DC 15.1.4
The System Operator shall provide Supervisory Control And Data Acquisition (SCADA)
outstation interface Equipment. The User shall provide such voltage, current,
frequency, Active Power and Reactive Power measurement outputs and Plant status
indications and alarms to the System Operator SCADA outstation interface
Equipment as required by the System Operator in accordance with the terms of the
Connection Agreement. The manner in which information is required to be presented
to the outstation Equipment is set out in Appendix D.
APPENDIX A
SITE RESPONSIBILITY SCHEDULES
DCC APPENDIX A - SITE RESPONSIBILITY SCHEDULES
At all Connection Sites the following Site Responsibility Schedules shall be drawn up using the proforma attached or with such variations as may be agreed between the System Operator and Users,
and in the absence of agreement the pro-forma attached shall be used: i) Schedule of MV
Apparatus ii) Schedule of Plant, LV Apparatus, services and supplies; iii) Schedule of
telecommunications and measurements Apparatus.
Other than at Generating Unit and Power Station locations, the schedules referred to in (ii) and (iii)
above may be combined.
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Draft Distribution Code-OUR_CARCEP_Rev02
Each Site Responsibility Schedule for a Connection Site shall be prepared by the System Operator in
consultation with other Users at least 2 weeks prior to the Completion Date under the Connection
Agreement for that Connection Site. Each User shall, in accordance with the timing requirements
of the Connection Agreement, provide information to the System Operator to enable it to prepare
the Site Responsibility Schedule.
i.
ii.
iii.
iv.
v.
vi.
vii.
viii.
Each Site Responsibility Schedule shall detail for each item of Plant and Apparatus;
Item of Equipment Using the agreed Numbering and Nomenclature in accordance with DOC
10.
Equipment Owner This identifies the party that owns the Equipment under common law;
Safety Rules This identifies whether the System Operator s or User s Safety Rules shall be
applied to the Equipment.
Operational Procedures This identifies whether System Operator or Users personnel shall be
responsible for Operations on the Equipment. Note that if this is System Operator, it does not
preclude the System Operator from authorising Users personnel from acting on it behalf and
vice versa.
Control Responsibility This identifies whether the System Control used shall be the System
Operators or the Users.
Maintenance Responsibility This identifies whether the System Operator or the User is
responsible for the inspection and maintenance of the Equipment.
vii)
Access and Security This identifies whether the System Operator or the User shall be
responsible for the establishment and maintenance of perimeter fencing and any manned
access security for the protection of the public and to prevent malicious entry. Access to
operational areas of the site shall be restricted to persons duly authorised in accordance with
the prevailing Safety Rules.
The MV Apparatus Site Responsibility Schedule for each Connection Site must include lines and cables
emanating from the Connection Site.
Every page of each Site Responsibility Schedule shall bear the date of issue and the issue number.
When a Site Responsibility Schedule is prepared it shall be sent by System Operator to the Users
involved for confirmation of its accuracy.
The Site Responsibility Schedule shall then be signed on behalf of System Operator by the Manager
responsible for the area in which the Connection Site is situated and on behalf of each User
involved by its Responsible Manager, by way of written confirmation of its accuracy. Once signed,
two copies shall be distributed by System Operator, not less than two weeks prior to its
implementation date, to each User which is a party on the Site
Responsibility Schedule, accompanied by a note indicating the issue number and the date of
implementation.
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Draft Distribution Code-OUR_CARCEP_Rev02
Attachment to Appendix A: PRO FORMA for SITE RESPONSIBILITY SCHEDULE
Item
Equipmen
Safety
o
t
Rule
Owne s
f
r
Equipmen
t
Operational
Control
Maintenance
Access and Comment
Procedure
Responsibilit
Responsibilit
Securit
s
s
y
y
y
Signed on behalf of the System Operator
Date
Signed on behalf of the User
37
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Draft Distribution Code-OUR_CARCEP_Rev02
APPENDIX B
TECHNICAL REQUIREMENTS FOR UNDER FREQUENCY RELAYS
DCC APPENDIX B - TECHNICAL REQUIREMENTS FOR UNDER FREQUENCY RELAYS
The Connection Agreement shall specify the manner in which Demand at the User Site, subject to
Automatic Load Disconnection (separate from the System Operators underfrequency load
shedding scheme), shall be actuated by under-frequency relays.
1) Under Frequency Relays shall have a frequency setting range of 46.0 to 52.0Hz and be suitable
for Operation from a nominal AC input of 63.5, 110 or 240V.
The following general parameters on the requirements of approved Frequency Relays for automatic
installations is given as an indication to the provisions that may be included in a Connection
Agreement:
a.
b.
c.
d.
e.
f.
Frequency settings: 46-52Hz in steps of 0.01Hz;
Measurement period: Within a minimum selectable settings range of 3 to 7 cycles;
Operating time: Between 100 and 160ms dependent on measurement period setting;
Voltage lock-out: 20 to 90% of nominal voltage;
Facility stages: Four stages of frequency Operation;
Output contacts: Two output contacts per stage.
2)
The voltage supply to the Under Frequency Relays shall be derived from the Transmission
System at the supply point concerned so that the frequency of the Under Frequency Relays
input voltage is the same as that of the primary System. This requires either:
a. the use of a secure supply obtained from Voltage Transformers directly associated with the
Transmission System interconnection transformer(s) concerned, the supply being obtained
where necessary via a suitable automatic voltage selection scheme; or
b. the use of the substation 110V phase-to-neutral selected auxiliary supply, provided that this
supply is always derived at the Connection Point concerned and is never derived from a
standby Generator or from another part of the User System.
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Draft Distribution Code-OUR_CARCEP_Rev02
3) The tripping facility should be engineered in accordance with the following reliability
considerations:
a. Dependability: Failure to trip at any one particular Demand shedding point shall not harm the
overall Operation of the scheme. However, many failures would have the effect of reducing
the amount of Demand under low frequency control.
b. Outages: Low frequency Demand shedding schemes shall be engineered such that the amount
of Demand under control is as specified by the System Operator and is not reduced
unacceptably during Equipment outage or maintenance conditions.
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Draft Distribution Code-OUR_CARCEP_Rev02
APPENDIX C
PROCEDURES RELATING TO OPERATION DIAGRAMS
DC xx APPENDIX C - PROCEDURES RELATING TO OPERATION DIAGRAMS
Basic Principles
Where practicable, all the MV Apparatus on any Connection Site shall be shown on one Operation
Diagram. Provided the clarity of the diagram is not impaired, the layout shall represent as closely
as possible the geographical arrangement on the Connection Site.
a.
Where more than one Operation Diagram is unavoidable, duplication of identical information
on more than one Operation Diagram must be avoided.
b. The Operation Diagram must show accurately the current status of the Apparatus, e.g.
whether commissioned or decommissioned. Where decommissioned, the associated
switchbay shall be labelled "spare bay".
c. Provision shall be made on the Operation Diagram for signifying approvals, together with
provision for details of revisions and dates.
Apparatus to be shown on Ownership Diagrams
1. Busbars
2. Circuit Breakers
3. Disconnector (Isolator) and Switch Disconnectors (Switching Isolators)
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Draft Distribution Code-OUR_CARCEP_Rev02
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
17.
18.
19.
20.
21.
22.
23.
24.
25.
26.
27.
28.
29.
30.
Disconnectors (Isolators) - Automatic Facilities
Bypass Facilities
Earthing Switches
Maintenance Earths
Overhead Line Entries
Overhead Line Traps
Cable and Cable Sealing Ends
Generating Unit
Generator Transformers
Generating Unit Step Up Transformers, Station Transformers, including the lower voltage
circuit-breakers
Synchronous Compensators
Static VAR Compensators
Capacitors (including Harmonic Filters)
Series or Shunt Reactors
Grid Transformers
Tertiary Windings
Earthing and Auxiliary Transformers
Three Phase VTs
Single Phase VT & Phase Identity
High Accuracy VT and Phase Identity
Surge Arrestors/Diverters
Neutral Earthing Arrangements on MV Plant
Fault Throwing Devices
Quadrature Boosters
Arc Suppression Coils
Current Transformers (where separate Plant items)
Wall Bushings
Use of Approved Graphical Symbols
All graphical symbols to be used in Operation Diagrams shall be approved by the System Operator.
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Draft Distribution Code-OUR_CARCEP_Rev02
APPENDIX D
SCADA INTERFACING
DCxxx APPENDIX D - SCADA INTERFACING
This Appendix sets out the technical requirements for connections to the System Operator s
Supervisory Control and Data Acquisition System outstation in terms of electrical characteristics.
GENERAL REQUIREMENTS
In all cases signals shall be arranged such that the level of electrical interference does not exceed
those defined in IEC 870-2-1: "Telecontrol Equipment and Systems - Operating Conditions - Power
Supply and Electromagnetic Compatibility" a nd IEC870-3: "Telecontrol Equipment and Systems Specification for Interfaces (Electrical Characteristics)".
Digital Inputs
Digital inputs cover both single and double points for connection to digital input modules on the
System Operators outstation Equipment. The Equipment contacts shall be free of potential,
whereas the input circuitry of the outstation are common to the negative 48 volt potential.
Single Points
Single point inputs must be used for alarms and where single contact indications are available. The
off (contact open or 0) state is considered to be the normal state and the on (contact closed or 1)
state the alarm condition.
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Draft Distribution Code-OUR_CARCEP_Rev02
Double Points
Double points are used to indicate primary Plant states by the use of complementary inputs for eac h
Plant item. Only the "10" and "01" states are considered valid with the "00" and "11" states
considered invalid. The "10" state is considered to be the normal or closed state.
Energy Meter Inputs
Energy meter input pulses for connection to pulse counting input modules on the System Operator s
outstation Equipment must operate for a minimum of 100ms to indicate a predetermined flow of
MWh or MVArh. The contact must open again for a minimum of 100ms. The normal state of the
input must be open.
Analogue Inputs
Analogue inputs for connection to analogue input modules on the System Operator s outstation
Equipment must all be electrically isolated with a two wire connection required. Signals shall be
in the form of 4-20mA (or other range to be agreed between the User and the System Operator)
for both unidirectional and bi-directional measured values. Signal converters shall be provided as
necessary to produce the correct input signals.
Command Outputs
All command outputs for connection to command output modules on the System Operator s
outstation Equipment switch both the 0 volts and -48 volts for a period of 2.5 seconds at a
maximum current of 1 amp. All outputs shall electrically isolated with a two wire connection to
control interposing relays on the Plant to be operated.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 16
NUMBERING AND NOMENCLATURE
DC 16.1
Introduction
DC 16.1.1
Distribution Code Section 16 ( DC 16 ) sets out the responsibilities and procedures for
notifying the relevant owners of the numbering and nomenclature of Apparatus at
Connection Points.
DC 16.1.2
The numbering and nomenclature of Apparatus shall be included in the Operation
Diagram prepared for each site having an Ownership Boundary.
DC 16.2
Objectives
DC 16.2.1
The prime objective embodied in DC 16 is to ensure that at any site where there is an
Ownership Boundary every item of Apparatus has numbering and/or nomenclature
that has been mutually agreed and notified between the owners concerned to ensure,
so far as is reasonably practicable the safe and effective Operation of the Systems
involved and to reduce the risk of error.
DC 16.3
Procedure
DC 16.3.1
New Apparatus
When the System Operator or a User intends to install Apparatus on a site having an
Ownership Boundary the proposed numbering and/or nomenclature to be adopted
for the Apparatus must be notified to the other owners. The notification shall be
made in writing to the relevant owners and shall consist of an Operation Diagram
incorporating the proposed Apparatus to be installed and its proposed numbering
and/or nomenclature. The notification shall be made to the relevant owners at least
three months prior to the proposed installation of the Apparatus.
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Draft Distribution Code-OUR_CARCEP_Rev02
The relevant owners shall respond in writing within one month of the receipt of the
notification confirming both receipt and whether the proposed numbering and/or
nomenclature is acceptable or, if not, what would be acceptable.
In the event that agreement cannot be reached between the System Operator, and
the other owners, the System Operator, acting reasonably, shall have the right to
determine the numbering and nomenclature to be applied at that site.
DC 16.3.2
Existing Apparatus
The System Operator and/or every User shall supply the other Party on request with
details of the numbering and nomenclature of Apparatus on sites having an
Ownership Boundary. The System Operator and every User shall be responsible for
the provision and erection of clear and unambiguous labelling showing the numbering
and nomenclature of its Apparatus on sites having an Ownership Boundary.
DC 16.3.3
Changes to existing Apparatus
Where the System Operator or a User needs or wishes to change the existing
numbering and/or nomenclature of any of its Apparatus on any site having an
Ownership Boundary, the provisions of DC 16 shall apply with any amendments
necessary to reflect that only a change is being made.
Where any Party changes the numbering and/or nomenclature of its Apparatus, which
is the subject of DC 16, that party shall be responsible for the provision and
erection of clear and unambiguous labelling.
DC 17
SPECIAL SYSTEM TESTS
DC 17.1
Introduction
DC 17.1.1
Distribution Code Section (DC 17 ) sets out the responsibilities and procedures
for arranging and carrying out Special System Tests which have or may have
an effect on the System Operators Distribution System or Users Systems.
Special System Tests are those tests which involve either simulated or the
controlled application of irregular, unusual or extreme conditions on the
System or any part of the System, but which do not include commissioning or
re-commissioning test or any other tests of a minor nature.
DC 17.2
Objective
DC 17.2.1
The objectives of DC 17 are to:
a. ensure that the procedures for arranging and carrying out Special System
Tests are such that, so far as practicable, Special System Tests do not threaten
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Draft Distribution Code-OUR_CARCEP_Rev02
the safety of personnel or the general public and cause minimum threat to
the security of supplies, the integrity of Plant or Apparatus and are not
detrimental to the System Operator and Users; and
b. set out procedures to be followed for establishing and reporting Special
System Tests.
DC 17.3
Procedure
DC 17.3.1
General
If the System Test proposed by the System Operator or the User connected to
the Distribution System will or may have an effect on the Transmission System
then the provisions of DC 17 and the Transmission Code shall apply.
Special System Tests which have a minimal effect on the Distribution System or
Systems of other Users shall not be subject to this procedure; minimal effect will
be taken to mean variations in voltage, frequency and waveform distortion of a value
not greater than those figures which are defined in the Distribution Planning and
Connection Section of the Codes.
DC 17.3.2
Proposal Notice
When the System Operator or a User intends to undertake a System Test which
willhave or may have an effect on the System or other User s Systems normally
notice shall be provided twelve (12) months in advance of the proposed System Test,
or as otherwise agreed by the System Operator, by the person proposing the System
Test (the Test Proposer ) to the System Operator and to those Users who may be
affected by such a System Test.
The proposal shall be in writing and shall contain details of the nature and purpose
of the proposed System Test and shall indicate the extent and situation of the Plant
or Apparatus involved.
If the information set out in the proposal notice is considered insufficient by the
recipient they shall contact the Test Proposer with a written request for further
information which shall be supplied as soon as reasonably practicable. The System
Operator shall not be required to do anything under DC 17 until it is satisfied with the
details supplied in the proposal or pursuant to a request for further information.
If the System Operator wishes to undertake a System Test the System Operator shall
be deemed to have received a proposal of that System Test.
DC 17.3.3
Preliminary notice and establishment of Test Panel
the System Operator shall have overall co-ordination of the System Test, using the
information supplied to it under DOC11 and shall identify in its reasonable estimation,
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Draft Distribution Code-OUR_CARCEP_Rev02
which Users other than the Test Proposer, may be affected by the proposed System
Test.
DC 17.3.4
Test Panel
A Test Co-ordinator, who shall be a suitably qualified person, shall be recommended
by the Test Proposer and approved by the System Operator with the agreement of
the Users which the System Operator has identified may be affected and shall act as
Chairman of the Test Panel (the Test Panel ).
All Users identified under DC 17 shall be given in writing, by the Test Coordinator, a
preliminary notice of the proposed System Test. The preliminary notice shall
contain:
a. the Test Co-ordinator s name and nominating company;
b. the details of the nature and purpose of the proposed System Test, the extent
and situation of the Plant or Apparatus involved and the Users identified by
the System Operator;
c. an invitation to each identified User to nominate a suitably qualified person
to be a member of the Test Panel for the proposed System Test.
The preliminary notices shall be sent within one month of the receipt of the
proposal notice or the receipt of any further information requested.
As soon as possible after the expiry of this one month period all relevant Users and
the Test Proposer shall be notified by the Test Co-ordinator of the composition of the
Test Panel.
A meeting of the Test Panel shall take place as soon as possible after the relevant
Users and the Test Proposer have been notified of the composition of the Test Panel.
The Test Panel shall consider:
a. the details of the nature and purpose of the proposed System Test and other matters
set out in the proposal notice;
b. the economic, operational and risk implications of the proposed
System Test;
a. the possibility of combining the proposed System Test with any other tests and with
Plant and/or Apparatus outages which arise pursuant to the operational planning
requirements of the System Operator and Users; and
b. implications of the proposed System Test on the Scheduling and Dispatch of
Generating Plant, insofar as it is able to do so.
Users identified under DC 17 and the System Operator, whether or not they are
represented on the Test Panel, shall be obliged to supply that Test Panel upon written
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Draft Distribution Code-OUR_CARCEP_Rev02
request with such details as the Test Panel reasonably requires in order to consider the
proposed System Test.
The Test Panel shall be convened by the Test Co-ordinator when it is necessary to
conduct its business, subject to the oversight of the System Operator.
DC 17.3.5
Proposal report
Within two months of the first meeting the Test Panel shall submit a report, which in
this DC 17 shall be called a proposal report, which shall contain:
a. proposals for carrying out the System Test (including the manner in which the System
Test is to be monitored);
b. an allocation of costs (including un-anticipated costs) between the affected Parties,
(the general principle being that the Test Proposer shall bear the costs); and
c. such other matters as the Test Panel consider appropriate.
The proposals report may include requirements for indemnities to be given in respect
of claims and losses arising from the System Test. All System Test procedures must
comply with all applicable legislation.
If the Test Panel is unable to agree unanimously on any decision in preparing its
proposal report the proposed System Test shall not take place and the Test Panel
shall be dissolved.
The proposal report shall be submitted to all those who received a Preliminary notice.
Within fourteen days of receipt of the proposal report, each recipient shall respond
to the Test Co-ordinator with its approval of the proposal report or its reason for
non-approval.
In the event of non-approval by one or more recipients, the Test Panel shall as soon
as practicable meet in order to determine whether the proposed System Test can be
modified to meet the objection or objections.
If the proposed System Test cannot be so modified then the System Test shall not take
place and the Test Panel shall be dissolved.
If the proposed System Test can be so modified the Test Panel shall as soon as
practicable, and in any event within one month of meeting to discuss the responses
to the proposal report, submit a revised proposal report.
In the event of non-approval of the revised proposal report by one or more recipients,
the System Test shall not take place and the Test Panel shall be dissolved.
DC 17.3.6
Final test programme
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Draft Distribution Code-OUR_CARCEP_Rev02
If the proposal report (or, as the case may be, the revised proposal report) is
approved by all recipients, the proposed System Test can proceed and at least one
month prior to the date of the proposed System Test, the Test Panel shall submit to
the System Operator and all recipients of the proposal notice a programme which
in this DC 17 shall be called a final test programme stating any switching sequence
and proposed timings, a list of those staff involved in the carrying out of the System
Test (including those responsible for site safety) and such other matters as the Test
Panel deem appropriate.
The final test programme shall bind all recipients to act in accordance with the
provisions contained in the programme in relation to the proposed System Test.
Any problems with the proposed System Test which arise or are anticipated after the
issue of the final test programme and prior to the day of the proposed System Test
must be notified to the Test Co-ordinator as soon as possible in writing If the Test
Co-ordinator decides that these anticipated problems merit an amendment to or
postponement of the System Test he shall notify any party involved in the System Test
accordingly.
If on the day of the proposed System Test operating conditions on the System are
such that any party involved in the proposed System Test wishes to delay or cancel
the start or continuance of the System Test, they shall immediately inform the Test
Co-ordinator of this decision and the reasons for it. The Test Co-ordinator shall then
postpone or cancel, as the case may be, the System
Test and shall if possible, agree with all parties involved in the proposed System Test
another suitable time and date or if he cannot reach such agreement, shall
reconvene the Test Panel as soon as practicable which shall endeavour to arrange
another suitable time and date and the relevant provisions of DC 17 shall apply.
DC 17.3.7
Final report
At the conclusion of the System Test, the Test Proposer shall be responsible for
preparing a written report (the final report ) of the System Test for submission to
other members of the Test Panel.
The final report shall include a description of the Plant and/or Apparatus, tested and
of the System Test carried out, together with the results, conclusions and
recommendations.
The final report shall not be distributed to any party which is not represented on the
Test Panel unless the Test Panel having considered the confidentiality issues, shall
have unanimously approved such distribution.
When the final report has been submitted under the Test Panel shall be dissolved.
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DC 18
DISTRIBUTION METERING
DC 18.1
Purpose
DC 18.1.1
To establish the requirements for metering the Active and Reactive Energy and
Demand input to and/or output from the Distribution System.
DC 18.1.2
To ensure appropriate procedures for metering reading; and
DC 18.1.3
To ensure that procedures are in place to manage disputed readings.
DC 18.2
Scope
DC 18.2.1
This Chapter applies to:
a. The System Operator
b. Users
c. Embedded Generators
DC 15.
METERING REQUIREMENTS EMBEDDED GENERATORS
DC 19.1
Overall Accuracy
DC 19.1.1
The overall accuracy of Generator metering is to be designed to give a tolerance of
+/- 0.5% on an ongoing basis.
DC 19.2
Relevant Metering Policies, Standards and Specifications
DC 19.2.1
Both Primary and Backup Metering systems shall be installed to accumulate the
outputs and/or inputs at the High Voltage side bushing of the Generating Unit step up
transformer.
DC 19.2.2
The System Operator shall own and maintain the Primary Metering System while the
Generator shall own and maintain the Backup Metering System.
DC 19.2.3
Each meter shall have its own Current Transformer (CT) and Voltage Transformer (VT)
and necessary independent Systems to function effectively.
DC 19.2.4
Instrument transformers shall conform to ANSI Standards C12.11 and C57.14 Class
03 and shall have sufficient capacity to handle the attached Equipment. The ANSI
standards refer to the physical characteristics of meters and the procedures and
practices related to type and pattern approval. The detailed use of these standards in
the testing of meters are set out in the OUR document Meter Testing Administrative
Protocol which is attached at Appendix B.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 19.2.5
The Current Transformers secondary winding used for metering purposes shall supply
only the metering Equipment and associated Systems.
Notwithstanding the foregoing each Current Transformer may have other secondary
windings that may be used for purposes other than metering.
DC 19.2.6
Voltage Transformers’ secondary windings may be used for metering and other
purposes provided that the total loading does not exceed one half burden of the
rating of the transformer.
DC 19.3
Parameters for Meter Reading
DC 19.3.1
The Generator shall provide and install appropriate Equipment and shall make a
continuous recording on appropriate magnetic media or equivalent of the Net Energy
Output of the Generating Unit(s).
DC 19.3.2
The parameters to be metered shall be subject to the Interconnection Agreement
between the Generator and the System Operator, and may consist of but are not
limited to any or all of the following parameters:
a.
b.
c.
d.
e.
f.
g.
h.
Active Energy (Wh) OUT;
Active Energy (Wh) IN;
Reactive Energy (VARh) First Quadrant;
Reactive Energy (VARh) Fourth Quadrant;
Active Power Demand (W) OUT;
Active Power Demand (W) IN;
Reactive Power Demand (VAR) First Quadrant; and
Reactive Power Demand (VAR) Fourth Quadrant.
All units shall be expressed at appropriate multiples determined by the maximum
expected Demand.
DC 19.4
Frequency of Meter Reading
DC 19.4.1
The Demand Interval shall be fifteen (15) minutes and shall be set to start at the
beginning of the hour. Demand shall be calculated by averaging the respective
parameters over the stated Demand Interval.
DC 19.5
Generators <100kW
DC 19.5.1
For small Generators with a rated capacity below 100kW the full generator metering
requirements above may be reduced. These generators shall be permitted to be
metered using separate import and export meters. DC 19.5.2 The metering
requirements for such connection shall have the specification and accuracy as defined
in Section DC 20.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 19.6
Metering Responsibility (Embedded Generators)
DC 19.6.1
It is the responsibility of Embedded Generators to cooperate with the System
Operator in the execution of all its responsibilities under this code.
DC 19.6.2
The costs for installation and replacement of meters shall be outlined in the Generator
s Power Purchase Agreement or Standard Offer Contract.
DC 20.
METERING REQUIREMENTS - USERS
DC 20.1
Overall Accuracy
DC 20.1.1
The overall accuracy of the metering for revenue purposes is to be designed to give a
tolerance of +/- 1% when tested in the laboratory and +/- 2 when tested in the field.
DC 20.2
Relevant Metering Policies, Standards and Specifications
DC 20.2.1
The meters, and associated installations, used on the System Operator s Distribution
System shall comply with the following documents which are identified as Distribution
Code Technical Specifications in DGC10.6 or issued by the OUR:
a. JPS Engineering Instruction 4.7
b. OUR Document ELE 2005/07 Electricity Meter Testing in Jamaica - Protocol on
Administrative and Testing Procedures and
c. Meter Facilities Policy as set out in JPS Engineering Bulletin TSD 007/3
DC 20.2.2
The meters shall be designed, constructed and operated to comply with the latest
revision of the relevant ANSI standards or international equivalents in particular:
a. ANSI C12.1 2008 The Electric Meters code for Electricity Metering;
b. ANSI C12:10 2004 Physical aspects of watt-hour meters - safety standard; and
c. ANSI C12:20 2002 Electricity meters 0.2 and 0.5 accuracy Classes.
DC 20.3
Requirement for Metering
DC 20.3.1
All Exit Points and Entry Points to the Distribution System shall have appropriate
metering in accordance with this Distribution Metering Code.
DC 20.4
Metering Responsibility (Users)
DC 20.4.1
It is the responsibility of the System Operator to ensure that all Exit Points and Entry
Points are metered in accordance with this code.
DC 20.4.2
It is the responsibility of Users to cooperate with the System Operator in the execution
of all its responsibilities under this code.
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DC 20.4.3
The costs for installation and replacement of meters shall be outlined in the User s
Connection Agreement and/or the Standard Terms and Conditions of Service.
DC 21.0
METERING EQUIPMENT
DC 21.1.1
The metering Equipment shall consist of :
Revenue Meters;
a. Current and Voltage Transformers where applicable;
b. All interconnecting cables, wires and associated devices, seals and protection;
and
c. All Equipment associated with Advanced Metering Infrastructure.
DC 21.2
Revenue Meters
DC 21.2.1
The revenue meter shall have the appropriate rating for the connection requirements
to be supplied and shall conform to the terms of the Connection Agreement between
the System Operator and User/Generator.
DC 21.2.2
Meters shall have an accuracy in accordance with ANSI class 0.5 or international
equivalent.
DC 21.2.3
At the System Operator s discretion Advanced Metering Infrastructure may be
installed at some customers sites. This metering infrastructure enables two way
communication with the metering Systems. These devices shall comply with the
specifications in DC 16.2.2. The accuracy shall be equivalent to ANSI Class 0.5.
DC 21.2.4
The relevant metered parameters, as required by the System Operator for billing
purposes, shall be stored cumulatively on the meter and shall be able to be accessed
by the UserGenerator.
DC 21.2.5
Where required these parameters may include any or all of the following depending
on the connection and the tariff schedule:
a.
b.
c.
d.
e.
f.
g.
KW Hours (delivered and received);
KVAr Hours (delivered and received);
KVA Hours (delivered and received);
Ampere Squared Hours
Volt Squared Hours
Maximum Demand (15 minute period)
Power Factor
The above parameters shall be measurable over intervals from 1 minute to 60
minutes.
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DC 21.3
Voltage Transformers
DC 21.3.1
All Voltage Transformers shall comply with IEC Standards or their equivalents and
shall have and accuracy class of 0.5.
DC 21.3.2
The burden in each phase of the Voltage Transformer shall not exceed the specified
burden of the said Voltage Transformer.
DC 21.4
Current Transformers
DC 21.4.1
All Current Transformers shall comply with IEC Standards or their equivalents and
shall have and accuracy class of 0.5.
DC 21.4.2
The burden in each phase of the Current Transformer shall not exceed the specified
burden specification of the said Current Transformer.
DC 22.
METERING POINTS
DC 22.1
Whole Current Metering
DC 22.1.1
The Metering Point should be as close as possible to the Connection Point.
DC 22.2
CT Metering
DC 22.2.1
The Metering Point shall be at the position of the Current Transformers used for the
metering system. This should be designed to be as close as possible to the Connection
Point.
DC 22.2.2
Current Transformers should be installed in a separate chamber and must be before
the main switch (on the line side). They shall be housed in suitable metal enclosures,
and be able to be secured.
DC 22.2.3
Where the Connection Point is declared on the outgoing side of a High voltage circuit
breaker the metering Current Transformers may be accommodated in that circuit
breaker unit.
DC 22.2.4
Where appropriate the Metering Point should be at the same voltage as the
Connection Point. Where the Metering Point is at a lower voltage than the Connection
Point then appropriate loss factors should be calculated to ensure any additional loss
is appropriately accounted for.
54
Draft Distribution Code-OUR_CARCEP_Rev02
DC 23.
METER READING AND COLLECTION SYSTEMS
DC 23.1
Meter Reading and Recording Responsibility
DC 23.1.1
It is the responsibility of the System Operator to ensure that meters are read in
accordance with the requirements of overall standard EOS7 in the System Operators
Licence.
DC 23.1.2
Meter reading and recording shall be undertaken by a suitable authorised
representative of the System Operator.
DC 23.1.3
It is the responsibility of Users and Embedded Generators to cooperate with the
System Operator in the execution of its responsibilities under this code.
DC 23.1.4
The User shall be provided with access to its billing and consumption records on
request.
DC 24
APPROVAL OF METERS
DC.24.1
Only meters that have received pattern approval from the Bureau of Standards,
Jamaica (BSJ) in accordance with the OUR Document ELE 2005/07 Electricity Meter
Testing in Jamaica - Protocol on Administrative and Testing Procedures, may be used
on the System Operators Distribution System.
DC 25
CALIBRATION AND SEALING
DC 25.1
Calibration
DC 25.1.1
All meters (new meters and repaired meters) rated above 12kVA shall be calibrated
and the tolerance adjusted to ensure that it measures as close to zero tolerance as
possible prior to field installation.
DC 25.1.2
All meters rated above 12kVA shall be recalibrated every 10 years where unless they
have a manufacturers guaranteed calibration period in which case this period shall be
used.
DC 25.1.3
All meters rated at 12kVA and below shall comply with the requirements of
acceptance testing in OUR Document ELE 2005/07 Electricity Meter Testing in Jamaica
- Protocol on Administrative and Testing Procedures, prior to field installation.
DC 25.1.4
All laboratory calibration shall be undertaken in laboratories accredited by the Bureau
of Standards, Jamaica (BSJ).
55
Draft Distribution Code-OUR_CARCEP_Rev02
DC 25.2
Traceability
DC 25.2.1
The kilowatt hour standard used to calibrate electricity meters shall be traceable to
the Systeme Internationale (SI) at the Bureau Internationale des Pois et Measures.
This extends to the calibration of Equipment used to calibrate meters.
DC 25.3
Sealing
DC 25.3.1
All meters shall be constructed to enable the meter unit to be sealed to prevent
unauthorised access or interference with the Operation of the meter or the input
terminals of the meter.
DC 25.3.2
All meters shall be sealed to prevent unauthorised access or interference with the
Operation of the meter or the input terminals of the meter.
DC 25.3.3
Seals applied after calibration shall be marked with the date that recalibration is
required.
DC 25.3.4
All seals shall include marks that identify the authorised person that sealed the meter.
DC 26
METERING DISPUTES
DC 26.1
Meter Accuracy Check
DC 26.1.1
A User/Embedded Generator has a right to request a meter accuracy check when they
consider that the meter may be reading incorrectly in accordance with the meter
testing protocol.
DC 26.1.2
Should a User/Embedded Generator request more than one accuracy check in a single
calendar year then the System Operator may charge for these additional check should
the accuracy be within +/-2%.
DC 26.2
Resolution of Disputes
If the metering system is found to be inaccurate by more than the allowable error
and the System Operator and the Generator/User fail to agree upon an estimate for
the correct reading within a reasonable time (as specified in the relevant Power
Purchase Agreement or Connection Agreement or Standard Offer Contract) of the
Dispute being raised, then the matter may be referred for arbitration by either party
in accordance within the relevant specified agreements.
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 23
INSPECTION AND TESTING
DC 27.1
Maintenance Policy
DC 27.1.1
The System Operator shall put in place and implement a policy for the inspection and
testing and recalibration of all metering Equipment. This policy shall be in accordance
with the procedures set out in DC 16.2 above.
DC 27.2
Maintenance Records
DC 27.2.1
The System Operator shall keep all test results, maintenance programme records and
sealing records for a period of at least 5 years.
DC 27.3
Generator Metering
DC 27.3.1
The System Operator and Generator shall abide by the conditions of the Generation
Code that details the maintenance procedures to be applied in the case of Generator
meters. The Generation Code includes provisions on the use of back-up meters when
metering inaccuracies are suspected and on the resolution of metering Disputes.
DC 28
DISTRIBUTION DATA REGISTRATION CODE
DC 28.1
General
DC 28.1.1
The Data Registration Code ( DRC ) sets out a unified listing of all data required by the
System Operator from Users and by Users from the System Operator.
DC 28.1.2
Where there is any inconsistency in the data requirements under any particular
section of the Distribution Code and the Data Registration Code the provisions of the
particular Chapter of the Distribution Code shall prevail.
DC 28.1.3
The Code under which any item of data is required specifies the procedures and
timing for the supply of data, for routine updating and for recording temporary or
permanent changes to data.
DC 28.1.4
The DRC also lists data required to be provided by Generators under the Generation
Code. This data is provided for
DC 28.2
Objective
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 28.2.1
The objective of the DRC is to:
a. List and collate all the data to be provided by each category of User to the
System Operator under the Distribution Code;
b. List all data to be provided by the System Operator to each category of User
under the Distribution Code; and
c. List all data to be provided by Generators to the System Operator and by the
System Operator to Generators under the terms of the Generation Code.
DC 28.3
Scope
DC 28.3.1
The Users to which the DR Section of this Code applies are:
a. Generators under the terms of the Generation Code;
b. JPS in its role as System Operator; and
c. Users connected directly to the Distribution System.
DC 29
DATA CATEGORIES AND STAGES IN REGISTRATION
DC 29.1
General
DC 29.1.1
Within the DRC each item of data is allocated to three categories.
a. System Planning Data as required by the Planning and Connection Section of
the Distribution Code;
b. Generation Planning Data as required by the Generation Code;
c. Operational Data as required by the Operations Code. This section also
includes data required from Generators in accordance with the Scheduling
and Dispatch provisions of the Generation Code.
DC 30.
PROCEDURES AND RESPONSIBILITIES
DC 30.1
Responsibility for Submission and Updating of Data
DC 30.1.1 I
In accordance with the provisions of the various Chapters of the Distribution Code,
each User must submit data as summarised, listed and collated in the attached
Schedules.
DC 30.2
Methods of Submitting Data
DC 30.2.1
The data must be submitted to the System Operator. The name of the person at the
User who is submitting each Schedule of data must be included.
DC 30.2.2
The data may be submitted via a computer link if such a data link exists between a
User and the System Operator or utilising a data transfer media, such as floppy
diskette, magnetic tape, CD ROM etc after obtaining the prior written consent from
the System Operator.
DC 30.3
Changes to Users Data
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Draft Distribution Code-OUR_CARCEP_Rev02
DC 30.3.1
The User must notify the System Operator of any change to data which is already
submitted and registered with the System Operator in accordance with each Chapter of
the Distribution Code.
DC 30.4
Data not supplied
DC 30.4.1
If a User fails to supply data when required by any Chapter of the Distribution
Code, the System Operator shall estimate such data if and when, in the view of the
Grid Operator, it is necessary to do so.
DC 30.4.2
If the System Operator fails to supply data when required by any Chapter of the
Distribution Code, the User to whom that data ought to have been supplied, shall
estimate such data if and when, in the view of that User, it is necessary to do so.
DC 30.4.3
Such estimates shall, in each case be based upon data supplied previously for the
same Plant or Apparatus or upon corresponding data for similar Plant and/or
Apparatus or upon such other information as the System Operator or that User, as
the case may be, deems appropriate.
DC 30.4.4
The System Operator shall advise a User in writing of any estimated data it
intends to use relating directly to that User Plant and/or Apparatus in the event of
data not being supplied.
DC 30.4.5
The User shall advise the System Operator in writing of any estimated data it intends
to use in the event of data not being supplied.
Schedule
Data Type
Description
I
User System Data
II
Load Characteristics
III
Demand profiles and
Active Energy
User
Code Section
JPS
Procedure
Electrical parameters relating JPS
to Plant and Apparatus
connected to the
Distribution System
DC 7.1
DC 7.2
DC 7.3
EI 3.1
SOPP 4
SOPP 7
SOPP 9
The estimated parameters of JPS
loads in respect of, for
example,
harmonic
content,
frequency
response.
JPS
Total Demand and Active
Energy taken from the
Distribution System
DPC 1.2 DPC 3
59
DPC 1.2
DPC 3
DC 7.1
DOC 2.3
GSDC 3.5.1
Draft Distribution Code-OUR_CARCEP_Rev02
IV
Connection Point
V
Demand Control
Information related to
Demand, and a summary of
Embedded
Generators
and Customer generation
connected to the
Connection Point.
Information related to
Demand Control
JPS
User
JPS
DPC 1.2
DPC 3
DPC 4.1
DPC 4.2
DPC 4.3
DPC 5
DOC 5
GSDC 3.5.1
EI 1.6
SOPP 11
User
VI
Fault Infeed
Information on Short Circuit JPS
contribution to the
User
Distribution System.
GEN
DPC 1.2
DPC 3.5
Key to Users
GEN
Generator
Abbreviations used in all Schedules:
DPC
:
Distribution Planning Code
DCC
:
Distribution Connections Code
DOC
:
Distribution Operations Code
TOC
:
Transmission Operations Code
GCC
:
Generation Connections Code
GSDC
:
Generation Scheduling and Dispatch Code
GMPC :
Generation Maintenance Planning Code
GLSC
:
Generation Load Shedding Code
EI :
JPS Engineering Instructions
SOPP
:
JPS System Operation Policies and Procedures
NOTE: In the Schedules Data Category refers to the Code Sections and/or JPS Instructions/Procedures.
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Draft Distribution Code-OUR_CARCEP_Rev02
Schedule I Users System Data
The data in this Schedule I is required from all Users with appropriate Demand at the discretion of the
System Operator.
Data Description
Units
Code
JPS
Section
Instruction/
Procedure
Operation Line Diagram
Single Line Diagram showing all existing and proposed
Equipment and Apparatus and Connections together with
Equipment rating
Drawing
DC 7.3
Site Responsibility Schedules
Schedule
DCC 5.3
Safety Coordinators
Text
DOC 7.3
Reactive Compensation Equipment
For all reactive compensation Equipment connected to the
User System at [12kV] and above, other than Power
Factor correction Equipment associated directly with a
Customer Plant, the following details
Type of Equipment (e.g. fixed or variable)
Text
Capacitive rating
MVAr
Inductive rating
MVAr
Operating range
MVAr
Details of any automatic control logic to enable operating
characteristics to be determined
Text and/or
Diagrams
Point of Connection to the User System in terms of electrical
location and System voltage
Text
Switchgear
For all switchgear (i.e. circuit breakers, switch disconnectors
and isolators) on all circuits Directly Connected to the
Connection Point including those at
Production Facilities
Rated voltage
kV
Operating voltage
kV
Rated short-circuit breaking current
Single phase
Three phase
kA kA
Rated load breaking current
Single phase
Three phase
kA kA
61
SOPP 9
DC 7.3
SOPP 4
SOPP 7
DC 7.3
SOPP 7
Draft Distribution Code-OUR_CARCEP_Rev02
Rated peak short-circuit making current
Single phase
Three phase
kA kA
User Connecting System data: Circuit Parameters for all circuits
Data Description
Units
DC 7.3
SOPP 7
Code
Section
JPS
DC 7.3
SOPP 7
EI 3.1
DC 7.3
SOPP 7
Instruction/
Procedure
For all Systems at [12] kV and above Connecting User System to
the Distribution System, the following details
are required relating to that Connection Point Rated
voltage
kV
Operating voltage
kV
Positive phase sequence
Resistance
Reactance
Susceptance
% on 100
% on 100
% on 100
Zero phase sequence
Resistance
Reactance
Susceptance
% on 100
% on 100
% on 100
Interconnecting transformers
For transformers between the Distribution System and
the User System, the following data is required:
Rated Power
Rated Voltage Ratio
(i.e. primary/secondary/tertiary)
Winding arrangement
Vector group
MVA
Positive sequence resistance
@ maximum tap
@ minimum tap
@ nominal tap
% on MVA
% on MVA
% on MVA
Positive sequence reactance
@ maximum tap
@ minimum tap
@ nominal tap
% on MVA
% on MVA
% on MVA
Zero phase sequence reactance
% on MVA
Tap changer type
Tap changer range
Tap changer step size
On/Off
Impedance value (if not directly earthed)
MV Motor Drives
62
Draft Distribution Code-OUR_CARCEP_Rev02
Following details are required for each MV motor drive
connected to the User System Rated VA
MVA
Rated Active Power
MW
Full Load Current
kA
Means of starting
Text
Starting Current
kA
Data Description
Units
Code
Section
JPS
Instruction/
Procedure
Motor torque/speed characteristics
Drive torque/speed characteristics
Motor plus drive inertia constant
User Protection Data
Following details relates only to protection Equipment which
can trip, inter-trip or close any Connection Point circuit
breaker or any System Operator circuit breaker A full
description including estimated settings, for all relays and
Protection Systems installed or to be installed on the User
System
DC 7.3
SOPP 7
DC 7.3
SOPP 7
Text
A full description of any auto-reclose facilities installed on the Text
User System, including type and time delays
The most probable fault clearance time for electrical faults on ms
any part of the User System Directly Connected to the
Distribution System
Transient Over-Voltage Assessment Data
When requested by JPS, each User is required to submit data
with respect to the Connection Site as follows
(undertaking insulation co-ordination studies) Busbar
layout, including dimensions and geometry together with
electrical parameters of any associated Current
Transformers, Voltage Transformers, wall bushings, and
support insulators
Diagram
Physical and electrical parameters of lines, cables, transformers, Text
reactors and shunt compensator Equipment Connected at
that busbar or by lines or cables to the busbar (for the
purpose of calculating surge impedances)
Specification details of connected directly or by lines and cables Text
to the busbar including basic insulation levels
Characteristics of over-voltage protection at the busbar and at Text
the termination of lines and cables connected at the busbar
63
‘
Draft Distribution Code-OUR_CARCEP_Rev02
Schedule II Load Characteristics
The following information is required from each User with appropriate Demand ,at the discretion of
the System Operator, regarding existing and future connections for each Connection Point.
Data Description
Units
Data for Future Years
YR
0
1. Details of individual loads which have fluctuating,
pulsing or other characteristics significantly
different from the typical range of Domestic,
Commercial or Industrial loads supplied
MW/kV
MVAr/kV
MW/Hz
MVAr/Hz
3. Phase unbalance imposed on the Distribution
System o Maximum
%
o Average
YR YR
2 3
DPC 4.3
2. Sensitivity of Demand to variations in voltage and
frequency on the Distribution System at the
peak Connection Point Demand (Active Power)
o Voltage sensitivity
o Frequency sensitivity
YR
1
Data
category
%
4. Maximum harmonic content imposed on the
%
Distribution System
5. Details of loads which may cause Demand
fluctuations greater than [1 MW] at a
Connection Point
64
Draft Distribution Code-OUR_CARCEP_Rev02
III.
Demand Profiles and Active Energy
Data
The following information is required from each Users with appropriate Demand, at the discretion of the
System Operator.
Data Description
FY0
FY1
FY2
Update
Time
Forecast daily Demand profiles in respect of each 1. Day of User maximum Demand
(MW) at Annual MD Conditions
User System (summated over all
[End
2. Day of peak Distribution System January]
Connection Points )
Demand (MW) at Annual MD
Conditions
3. Day of minimum Distribution
System Demand (MW) at Average
Conditions
(Delete as appropriate)
65
Data
Category
DPC 4.1
DC 7.3
DOC 2.3
GSDC
3.5.1
Draft Distribution Code-OUR_CARCEP_Rev02
0000 : 0100
0100 : 0200
0200 : 0300
0300 : 0400
0400 : 0500
0500 : 0600
0600 : 0700
0700 : 0800
0800 : 0900
1000 : 1100
1100 : 1200
1200 : 1300
1300 : 1400
1400 : 1500
1500 : 1600
1600 : 1700
1700 : 1800
1800 : 1900
1900 : 2000
2000 : 2100
2100 : 2200
2200 : 2300 2300 : 2400
Data Description
FY0
FY1
FY2
Update
Time
Data
Category
Data Description
YR 0
YR 1
YR 2
Update
Data
Time
Category
[End
Sept]
DPC 4.1 DC
7.3
The annual MWh requirements for each User System (summated over all Connection
Points for the Distribution System) at Average Conditions:
66
Draft Distribution Code-OUR_CARCEP_Rev02
1. Domestic
2. Agricultural
3. Commercial
4. Industrial
5. Parish
6. Public Lighting
7. [Any other identifiable categories of
Generator]
8. User System losses
Applicable only Users with Embedded Generator s
[End
Sept]
DPC 4.1.3
DPC 5
DC 7.4
1. Total Demand (MW) on its System
2. Active Energy (MWh) requirement on its
System
3. Active Energy from Embedded Generation
IV.
Connection Point Data
The following information is required from each User with appropriate Demand, at the discretion of the
System Operator.
Data Description
Units
YR 0
YR 1
67
YR 2
Update Data
TimeCategory
Draft Distribution Code-OUR_CARCEP_Rev02
Forecast Demand and Power Factor related to each Connection Point
[End
DPC 4.1
Sept]
DPC 4.3
1. Annual peak hour User MW
Demand at Annual MD pf
Conditions
2. User Demand at Distribution
System peak hour Demand pf
at Annual MD Conditions
[End
DPC 4.1
Sept]
DPC 4.3
MW
3. User Demand at minimum MW
Distribution System pf
[End
DPC 4.1
Sept]
DPC 4.3
hour
Demand at Average
Conditions
Demand Transfer Capability
[End
Sept]
Where a User Demand or group of
Demands may be fed by alternative
Connection Point(s) , the following
details should be provided:
DPC 4.1
DPC 4.3
1. Name of the alternative
Connection Point(s)
2. Demand transferred
MW
MVAr
3. Transfer arrangement
(e.g. manual or automatic)
4. Time to effect transfer
V.
hrs
Demand Control
Data
The following information is required from the System Operator or Embedded Customer
68
Draft Distribution Code-OUR_CARCEP_Rev02
Data Description
Units
Time
Covered
Update Time
Data
Category
Programming Phase: applicable to the System Operator and Embedded Generator
Demand Control which may result in a Demand
change of [1] MW or more on an hourly and
Connection Point basis
1. Demand profile
2. Duration of proposed Demand Control
DOC 5.3
EI 1.6
SOPP 11
MW
Weeks
1 to 8
10:00
Friday
hrs
Weeks
1 to 8
10:00
Friday
GSDC
3.5.1
Control Phase: applicable to Distribution System Operator and Non-Embedded Generator
1. Demand Control which may result in a Demand Mw
change of 1 MW or more averaged over any hour
on any Connection Supply Point which is planned
after 10:00 hours
Now to
Days
2. Any changes to planned Demand Control notified hrs
to the System Operator prior to 10:00 hours
Now to
Days
7
DOC 5
Immediate
7
Immediate
Post Control Phase
Demand reduction achieved on previous calendar day
of 1 MW or more averaged over any Connection
Point, on an hourly and Connection
Point basis
1. Active Power profiles
DOC 5
MW
Previous Day
Previous Day
2. Duration
VI.
hrs
10:00
Daily
10:00
Daily
Fault Infeed Data
The following information is required from each User who is connected to the Distribution
69
Draft Distribution Code-OUR_CARCEP_Rev02
System via a Connection Point where the User System contains Embedded Generating
Unit(s) and/or motor loads. The data is required for the three following years
Data Description
Units
Update Time
Data Category
Short Circuit Infeed to Distribution System from User System at a Connection Point
Name of Connection Point: ____________________________
1. Symmetrical three-phase short circuit current
infeed:
[end Sept]
DPC 3.5
o At instant of fault
o
kA
After sub-transient fault current kA
contribution has substantially decayed
2. Zero sequence source impedance values as seen
from the Connection Point consistent with the
maximum infeed above:
o Resistance (R)
o Reactance (X)
3. Positive sequence X/R ratio at instant of fault
VII.
% on 100
% on 100
User Outages Data
Data Description
Timescale
Update Time
Covered
Year 1
Generators and Non-Embedded Generator provide
Details of Apparatus owned by them other than
Generating Units at each Connection Point
System Operator informs Users of aspects that may affect Year 1
their Systems
Users inform System Operator if not in agreement with Year 1
aspects as notified
70
[end Sept]
Data Category
Draft Distribution Code-OUR_CARCEP_Rev02
Data Description
Units
Update
Data Category
Time
Individual Generating Unit Demand
Demand supplied through unit transformer when
Generating Unit is at Rated MW output
MW
MVAr
Generating Unit Performance and Parameters
General
1. Details of point of connection to the Distribution System of the Text
Generating Unit in terms of geographical and electrical
location and System voltage, including a Single Line Diagram
As required
GCC 1.2.4
2. Type of Generating Unit (e.g. Steam Turbine Unit, Gas Turbine Text
Unit, Cogeneration Unit, wind, etc)
3. Registered Capacity
4. Distribution System Constrained Capacity
Generating Units only)
MW
(for Embedded MW
5. Rated Active Power
MW
6. Minimum Generation
MW
7. Rated Apparent Power
GCC 1.2.4
MVA
System Operator issues final Transmission System outage Year 1
plan with advice on Operational Effects on User
Systems
[end Oct]
Week 8
As occurring
ahead
to
year
end
Transmission Code is referenced as the final outage plan rests with Transmission.
Embedded Generator and Users to inform Grid
Operator of changes to outages previously requested
VIII.
Generator Planning Parameters Data
Generating Facility Name: _____________________________________
71
DOC 3.3
DOC 3.3
Draft Distribution Code-OUR_CARCEP_Rev02
The following details are required from each Generating Facility with a rated capacity greater than
[100kW] directly connected, or to be directly connected, to the Distribution System The data shall be
supplied for the following 3 years.
Data Description
Units
Update Time
Generating Facility Demand
Demand associated with the Generating Facility supplied through the
Distribution System or via a Generator s own System in addition to
Demand supplied through unit transformer
1. Maximum Demand that could occur
[end Sept]
MW
MVAr
2. Demand at the time of peak Distribution System Demand
MW
MVAr
3. Demand at the time of minimum Distribution System Demand
MW
MVAr
The data in the following table shall be supplied for each Generating Unit
72
Data
Category
Draft Distribution Code-OUR_CARCEP_Rev02
Data Description
Units
Update
Time
8. Rated terminal voltage
kV
9. Generator Performance Chart at stator terminals
Chart
10. Net Dependable Power Capacity (on a monthly basis)
MW
11. Short circuit ratio
12. Turbo-Generator inertia constant (alternator plus prime MW/MVA
mover)
13. Rated field current at Rated MW and MVAr output and at A
rated terminal voltage
14. Field current open circuit saturation curve as derived
from appropriate manufacture s test certificate o 120%
rated terminal voltage
A
o 110% rated terminal voltage
A
o 100% rated terminal voltage
A
73
Data Category
Draft Distribution Code-OUR_CARCEP_Rev02
o 90% rated terminal voltage
A
o 80% rated terminal voltage
A
o 70% rated terminal voltage
A
o 60% rated terminal voltage
A
o 50% rated terminal voltage
A
Impedances
GCC 1.2.4
1. Direct axis synchronous reactance
% on MVA
2. Direct axis transient reactance
% on MVA
3. Direct axis sub-transient reactance
% on MVA
4. Quadrature axis synchronous reactance
% on MVA
5. Quadrature axis sub-transient reactance
% on MVA
6. Stator leakage reactance
% on MVA
7. Armature winding direct-current resistance
% on MVA
Time Constants
GCC 1.2.4
1. Direct axis short-circuit transient time constant
secs
2. Direct axis short-circuit sub-transient time constant
s
3. Quadrature axis short-circuit sub-transient time constant
s
4. Stator time constant
s
Data Description
Units
Update
Data Category
Time
Generator Transformer
GCC 1.2.4
1. Rated Apparent Power
MVA
74
Draft Distribution Code-OUR_CARCEP_Rev02
2. Rated voltage ratio
3. Winding arrangement
4. Vector group
5. Positive sequence resistance
o @ maximum tap
% on MVA
o @ minimum tap
% on MVA
o @ nominal tap
% on MVA
6. Positive sequence reactance o @
maximum tap
% on MVA
o @ minimum tap
% on MVA
o @ nominal tap
% on MVA
7. Zero phase sequence reactance
% on MVA
8. Tap changer range
±%
9. Tap changer step size
%
10. Tap changer type (i.e. on-load or off-load)
On/Off
Excitation Control System Parameters
GCC 1.2.4
1. Exciter category (e.g. rotating or static)
Text
2. Details of Excitation System described in block diagram showing Diagram
transfer functions of individual elements (including Power
System Stabiliser if fitted)
3. Rated field voltage
V
4. Generator no-load field voltage
V
5. Excitation System on-load positive ceiling voltage
V
6. Excitation System no-load negative ceiling voltage
V
7. Power System Stabiliser fitted?
Yes/No
8. Details of over excitation limiter described in block diagram
showing transfer functions of individual elements
Diagram
Diagram
9. Details of under excitation limiter described in block diagram
showing transfer functions of individual elements
75
Draft Distribution Code-OUR_CARCEP_Rev02
Data Description
Units
Update
Data Category
Time
Governor Parameters (All Generating Units)
GCC 1.2.4
Governor System block diagram showing transfer function of Diagram
individual elements
Prime Mover Parameters
GCC 1.2.4
Prime mover System block diagram showing transfer function of Diagram
individual elements and controllers
Generator Flexibility Performance
GCC 1.2.4
Details required with respect to Generators
1. Rate of loading following a weekend shut-down (Generator and MW/Min
Generating Facility)
2. Rate of loading following an overnight shut-down (Generator MW/Min
and Generating Facility)
3. Block load following Synchronising
MW
4. Rate of De-loading from Rated MW
MW/Min
5. Regulating range
MW
6. Load rejection capability while still Synchronised and able to MW
supply Load
IX.
Generator Operational Planning Data
Generator Facility Name: ____________________________________________
The following details are required from each Generator in respect of each Generating Unit with a rated
capacity greater than [100kW].
Data Description
Units
Data Category Generating Unit and Generating
Facility Data
76
Draft Distribution Code-OUR_CARCEP_Rev02
U1 U2
Steam Turbine Generating Units
U3
U4
U5
U6
GF
GSDC 3.2
1. Minimum notice required to synchronise under
following conditions:
o Hot start
Min
o Warm start
Min
o Cold start
Min
2.
Minimum time between synchronising
different Generating Units at a Generating
Facility
Min
3.
Minimum block
synchronising
Load
requirement
on MW
4. Maximum Generating Unit loading rates
from synchronising under following
conditions: o Hot start
Min
o Warm start
Min
o Cold start
Min
5. Maximum Generating Unit de-loading rate
6.
MW/Min
Minimum
interval
between
desynchronising and synchronising a
Generating Unit (off-load time)
Min
Gas Turbine Generating Units
GSDC 3.2
SOPP 7
1. Minimum notice required to synchronise
Min
2.
Minimum time between synchronising
different Generating Units at a Generating
Facility
3.
Minimum block
synchronising
Data Description
Load
requirement
Min
on MW
Units
Data Category Generating Unit and Generating
Facility Data
U1 U2
77
U3
U4
U5
U6
GF
Draft Distribution Code-OUR_CARCEP_Rev02
4. Maximum Generating Unit loading rates from
synchronising for
o Fast start
Min
o Slow start
Min
5. Maximum Generating Unit de-loading rate
6.
MW/Min
Minimum
interval
between
desynchronising and synchronising a
Generating Unit
X.
Scheduling and Dispatch
Min
Data
Generating Facility Name: _____________________________________
The following details are required from each Generator in respect of each Generating Unit with a rated
capacity greater than [100kW].
Data Description
Units
Data Category
Generating Unit, and Generating
Facility Data
U1 U2
Generating Unit Availability Notice
1. Generating Unit Availability o
Power Capacity
o Start time
GSDC 3.2
GSDC 3.5.1
GMPC 5.1
SOPP 7
MW
date/time
2. Generating Unit unavailability
o Start time
date/time
o End time
date/time
3. Generating Unit initial conditions
o Time required for Notice to hrs
Synchronise
o Time required for start-up
hrs
78
U3 U4
U5
U6
GF
Draft Distribution Code-OUR_CARCEP_Rev02
4. Maximum Generation increase in output
MW
above declared Availability
5. Any changes to Primary Response and
Secondary Response characteristics
Scheduling and Dispatch Parameters
GSDC 3.2
GSDC 3.5.1
GMPC 5.1
1. Generating Unit inflexibility o
Description
Text
o Start date
date/time
o End date
date/time
o Active Power
MW
Data Description
Units
Data Category
Generating Unit, and Generating
Facility Data
U1 U2
2. Generating Unit synchronising intervals
Hot time interval
hrs
Off-load time interval
hrs
3. Station Generating Unit desynchronising hrs
intervals
4. Generating Unit basic data
Minimum Generation
MW
Minimum shutdown time
hrs
5. Generating Unit two shifting limitation
6. Generating Unit minimum on time
hrs
7. Generating Unit Synchronising Generation MW
8. Generating Unit Synchronising groups
9. Generating Unit
breakpoints
run-up
rates
with MW/min
10. Generating Unit run-down rates with MW/min
breakpoints
79
U3 U4
U5
U6
GF
Draft Distribution Code-OUR_CARCEP_Rev02
11. Generating Unit loading rates covering MW/min
the range from Minimum Generation to
Maximum Output
12. Generating Unit de-loading rates covering MW/min
the range from Maximum Output to
Minimum Generation
Generating Unit Merit Order Data(*) o
Fuel data o Heat Rate data
GSDC 3.2.2
(*)NOTE: Fuel data to be updated at the beginning of each month
to be updated following twice yearly tests
XI.
Heat Rate data
Generator Outages Data
Generating Facility Name: _______________________________________________
The following details are required from each Generator in respect of each Generating Unit with a rated
capacity greater than 1MW.
Data Description
Units
Time
Update
Covered Time
Data Category
Provisional Outage Programme
DOC 3.3
TOC3.3
1. Generating Units concerned
ID
2. Active Power not available as a result of Outage
MW
3. Remaining Active Power of the Facility
MW
4. Duration of Outage
Weeks
80
Year
[End Oct]
2 to 3
Year
2 to 3
[End Oct]
Year
2 to 3
Year
2 to 3
[End Oct]
[End Oct]
GSDC 3.5.1
GMPC 5.1
EI 1.11
SOPP 19
Draft Distribution Code-OUR_CARCEP_Rev02
5. Start date and time or a range of start dates and timesDate hrs
Year
2 to 3
[End Oct]
System Operator issues Provisional Outage Programme to
Users
Agreement on Provisional Outage Programme
Text
Year
2 to 3
Year
2 to 3
[End
Sept]
[End Oct]
Final Outage Programme
1. Generating Units concerned
ID
Year 1
[End
Oct]
2. Active Power not available as a result of Outage
MW
Year 1
[End
Oct]
3. Remaining Active Power of the Plant
MW
Year 1
[End
Oct]
4. Duration of Outage
Weeks
Year 1
[End
Oct]
Data Description
Units
Time
Update
Covered
Time
5. Start date and time or a range of start dates and timesDate hrs
Year 1
System Operator issues draft Final Outage Programme
to Users
Year 1
System Operator issues Final Outage Programme to
Text
Users
Year 1
81
[End Oct]
[End
Sept]
[End Oct]
TOC 3.3
DOC 3.3
GSDC 3.5.1
GMPC 5.1
SOPP 19
Data Category
Draft Distribution Code-OUR_CARCEP_Rev02
Short Term Planned Maintenance Outage
1. Generating Units concerned
ID
Year 0
5
Days
before
2. Active Power not available as a result of Outage
MW
Year 0
5
Days
before
3. Remaining Active Power of the Facility
MW
Year 0
5
Days
before
Year 0
5
Days
before
Year 0
5
Days
before
4. Duration of Outage
Weeks
5. Start date and time or a range of start dates andDate hrs
times
82
GSDC 3.5.1
GMPC 5.1.3
SOPP 19
Draft Distribution Code-OUR_CARCEP_Rev02
XII.
System Operator Information to Users
The System Operator shall provide, where appropriate for the Demand, Users and prospective Users, with
appropriate connection capacities, the following data related to the Distribution System.
Code
Description
DCC 5.4
Operation Diagram
DCC 5.3
Site Responsibility Schedules
DOC 2.3
Demand
The System Operator shall notify each User no later than the [end of October] of each
calendar year, for the current calendar year and for each of the following 3 calendar
years
1. The date and time of annual peak of Distribution System Demand at Annual Maximum
Demand Conditions
2. The date and time of annual minimum Distribution System Demand at Average
Conditions
DPC 4.2
Distribution System Data including
Network Topology and ratings of principal items of Equipment
Positive, negative and zero sequence data of lines, cables, transformers etc
Generating Unit electrical and mechanical parameters
Relay d protection data
83
Draft Distribution Code-OUR_CARCEP_Rev02
DPC 4.2
The following Network Data as an equivalent voltage source at the voltage of the
Connection Point to the User System
Symmetrical three-phase short circuit current infeed at the instant of fault from the
Distribution System
Symmetrical three-phase short circuit current from the Distribution System after the
sub-transient fault current contribution has substantially decayed
Zero sequence source resistance and reactance values at the Connection Point,
consistent with the maximum infeed below
Pre-fault voltage magnitude at which the maximum fault currents were calculated
Positive sequence X/R ratio at the instant of fault
Appropriate
interconnection transformer data
DOC 7.3
Code
Names of Safety Co-ordinators
Description
Outage Programmes
DOC 3.4
Provisional Outage programme showing the Generating Units expected to be withdrawn
from service during each week of Years 2 and 3 for Planned Outages
DOC 3.5
Draft Final Outage programme showing the Generating Units expected to be withdrawn
from service during each week of Year 1 for Planned Outages
Demand Estimates and Operating Margin
Synchronising and Desynchronising times of Embedded Generating Units to the
Distribution System Operator
Special Actions that may be required of Users
84
Draft Distribution Code-OUR_CARCEP_Rev02
GSDC 3.2.3
Merit Order to be notified to Generators at the start of each month
GSDC 3.5.1
System Operator to provide daily schedule of expected availability and generation
dispatch at 15:00hours each day for the following day and at 15:00hours on Friday for
the following three (3) days
XIII.
Metering Data
Data Description
Responsible Party
Connection and Metering Point reference details for both Delivery
Point and Actual Metering Point
Data communication details when communication Systems are used
Data validation and substitution processes agreed between affected
parties
85
Data Category
EI 4.7
Draft Distribution Code-OUR_CARCEP_Rev02
86
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