Mauritius National Grid CodeDistribution CodeVersion December 2022

CONTENTS

DC 1 OBJECTIVE AND SCOPE

The objective of the Distribution Code is to establish the rules, procedures, requirement and standards that govern the operation, maintenance and development of the Distribution System to ensure an efficient, co-ordinated and economical system for electricity distribution. It also sets out procedures and requirements for the Distribution Licensee's and all Users of the Distribution System.
The Distribution Licensee and existing and potential Users connected to or seeking to connect to the Distribution System shall comply with the relevant sections of the Distribution Code, including Distributed Generators and Customers.
Users connected to the Distribution System shall comply with the Distribution Code.
The Interconnection Boundary of the Transmission and Distribution Systems shall be as defined in Section TC 1.1 of the Transmission Code.

DC 2 GENERAL REQUIREMENTS

This Distribution Code contains the procedures to provide an adequate, safe and efficient electricity distribution service to all parts of Mauritius, taking into account a wide range of Normal and Contingency Conditions. It is however necessary to recognize that the Distribution Code cannot address every possible situation. Where such unforeseen situations occur the Distribution Licensee 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:
  • the need to preserve the integrity of the System;
  • to prevent damage to the System;
  • compliance with conditions under its License;
  • compliance with the Electricity Act 2005 and its amendment;
  • compliance with the Distribution Code.
Users shall provide such reasonable co-operation and assistance as the System Operator reasonably request in pursuance of the general requirements in this Section DC 2

DC 3 DISTRIBUTION SYSTEM PLANNING

DC 3.1 Purpose and Scope

The Distribution Licensee with the Single Buyer will be responsible for planning the development of the Distribution System.
The Authority will provide the System Operator with policy guidelines from the Ministry for the development of the system such as policy objectives regarding the use of primary energy sources for generating electricity, future technologies, etc.
The Single Buyer will also develop procedures for development of an Integrated Resource Plan, engaging key electricity sector stakeholders in a collaborative process.
The objective of the long-term Integrated Resource Planning (IRP) is to define the development (upgrading and expansion) of the Transmission and Distribution Systems as well as the indicative incorporation of new generation resources based on policy guidelines provided by the Ministry, in order to guarantee the quality and reliability of electricity supply for the nation and the economic players.
The Distribution Licensee and the Transmission Licensee, as it corresponds, shall be responsible for the implementation of the upgrading and expansion of the Transmission and Distribution Systems as defined in the IRP.
The Single Buyer shall elaborate the long-term IRP according to the procedures and information requirements established in section SOC 1 of the System Operations Code.
The System Operator is also responsible for the short-term planning (Operation Planning) as required by section SOC 2 of the System Operations Code.
The IRP horizon analysis shall be 10 years and the plan shall be updated yearly with the most recent updated information available such as policy guidelines, load forecasts, expected commercial operational date of key ongoing projects, fuel prices, new generation technologies and prices, etc.
In the elaboration of the IRP, the Single Buyer shall specifically consider the location of renewable and other generation sources.
This section DC 2 specifies the following criteria, processes and information that will be used by the Single Buyer in the fulfilment of its planning duties:
  • Distribution System Planning Criteria
  • Planning Studies, and
  • Data Requirements

DC 3.2 Distribution System Planning Criteria

DC 3.2.1 Principles

The Distribution System planning criteria shall be based on the requirement to comply with statutory requirements in DC 3.2. Where no statutory requirements exist, the criteria shall be based on Prudent Utility Practice and relevant international standards.
The overriding principle in the planning process of the Distribution System is the responsibility of the Distribution Licensee to "maintain any installation, apparatus or premises relating to his license in such condition as to enable it to provide safe, adequate and efficient electricity service", as set forth in the Act.

DC 3.2.2 Planning Criteria

The Distribution Licensee and Single Buyer shall adopt the following criteria to perform the Distribution System planning:
  • The Distribution System shall be designed in such a manner that all spur lines with load above 100 Amperes and 22 kV feeders have a back-up supply from the System.
  • The number of switching operations shall be kept to a minimum so as to enable fast restoration of supply.
  • The feeder's loading under Normal Conditions shall be limited to 50% of conductor nominal current rating.
  • The voltage limit shall be within statutorily prescribed limits under Normal Conditions. Voltage regulation at the nominal value of 230 V for single-phase supply and 400 V for three-phase supply shall be within ±6% at the Interconnection Boundary.
  • The closed busbar configuration at 22 kV in the Distribution System Substations, where required, shall satisfy the N-1 Security Criterion. This requires operating the tap changers on parallel transformers in the master-slave configuration in order to ensure that all tapping is carried out in unison.

DC 3.2.3 Voltage Criteria

The Distribution System shall be designed to ensure that under Normal and Contingency Conditions, voltages at all Interconnection Boundaries and buses are within the following ranges:
  • between +6% and -6% of nominal voltage under Normal Conditions at MV busbars;
  • between +6% and -6% of nominal voltage under Normal Conditions at LV busbars;
  • between +10 and-10% of nominal voltage under Contingency Conditions at LV and MV busbars.

DC 3.2.4 Load Power Factor

The Distribution System shall be planned for a Demand load consumption with Power Factor between 0. 90 leading to 0.90 lagging under Normal Conditions.

DC 3.3 Studies for Interconnection

DC 3.3.1 General

The Distribution Licensee in collaboration with the Single Buyer and the System Operator, if required, shall undertake Distribution System interconnection studies whenever required to:
  • Determine particular interconnection requirements for any Users' System, submitted in accordance with the interconnection application process, including any reinforcement, Protection or Power Quality improvement requirements; and
  • Determine the interconnection requirements for any Generating Station, submitted in accordance with the interconnection application process, including any reinforcement, Protection or Power Quality improvement requirements.
All technical data required for the interconnection studies to the Distribution System (as well as other information) shall be provided by the applicant to the Distribution Licensee, who will flow the information to the Single Buyer, if needed. The Distribution Licensee shall coordinate, as needed, with the System Operator and the Single Buyer for the provision of additional data required to carry out the interconnection studies. The Distribution Licensee shall contact the Large Customer directly for additional technical information related to his request for interconnection.
The Distribution Licensee shall coordinate with the System Operator specific requirements for the interconnection of large loads to the MV system (e.g. protection studies and specifications), and require its assistance in the elaboration of some studies. However, the Distribution Licensee should remain ultimately responsible for the execution of the studies and for the coordination and communication with the applicant.
All information exchange among licensees shall be properly recorded.

DC 3.3.2 Demand Forecasts

The Distribution Licensee and the Single Buyer shall be responsible for the elaboration of the load forecasts.
The Distribution System expansion plan shall be mainly guided by inputs from a Spatial Load Forecast, the construction of new substations and requests of connection of Customers to the MV network.
The load forecast methodology shall also consider the increasing number of connected Distributed Generation projects.
The Spatial Load Forecast shall be supported by the Geographical Information System of the whole Grid.
The Geographical Information System shall store virtual information relating to the physical aspects of the transmission and distribution networks. It shall permit the viewing, understanding, questioning, interpreting and visualizing of data in many ways that reveal relationships, patterns and trends in the form of maps, reports and charts. These capabilities of the Geographical Information System shall assist in load forecasting and transmission and distribution planning activities
System planning simulation software shall use the outputs of the proposed Geographical Information System so as to enable the conduct of detailed technical studies of the Distribution System. It is expected that the Geographical Information System shall support other activities of the Distribution and Transmission Licensees such as asset management.
The Geographical Information System shall support the development of a consumption forecast using an econometric regression methodology. This forecast of unit consumption is then to be developed into a peak demand forecast for each substation which shall inform the planning studies.

DC 3.3.3 Load Flow Studies

The Distribution Licensee in collaboration with the Single Buyer and/or System Operator, if required, shall undertake load flow studies using appropriate Models.
Load flows shall be analysed at least for peak and minimum feeder loads, based on the feeder metering data or SCADA data where metering data is not available calculated from the 30-minute averages. The calculation of the forecasts at a feeder level shall be 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.
Load flows shall model the contingency scenarios planned for in the network design and shall 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 shall align with the manufacturers' guidance on such ratings, or other parameters as determined by the Distribution Licensee.

DC 3.3.4 Voltage Regulation Studies

The Distribution Licensee in collaboration with the Single Buyer and/or System Operator, if required, shall undertake voltage regulation studies to determine the voltages at all Interconnection Boundaries using appropriate modelling tools and verify the compliance with the limits in DC 3.2.3. Such studies shall be used to determine the impact of any Demand or Generation interconnection, System expansion or reinforcement.
The planning of the Distribution System voltage regulation shall take into account 5 years Demand forecasts and include the use of:
  • power transformer tap changers to maintain bus bars at within acceptable ranges;
  • voltage regulation of Distributed Generators and Energy Storage Units;
  • capacitors (fixed capacitor banks should be sized on present requirements rather than growth forecasts to avoid over voltage); or
  • upgrade of conductor size
The Distribution System shall be planned considering voltage control on the secondary sides of the 66/22kV transformers using tap changers.
Capacitors may be used to provide voltage improvement on the Distribution System in the following cases:
  • reducing the lagging component of circuit current;
  • increasing the voltage level at the load;
  • improving voltage regulation, if the capacitors are properly switched;
  • reducing Active Power and Reactive Power losses in the system because of reduction in current;
Suitable Equipment and procedures shall be employed where required to ensure that excessively high voltages are not experienced at Interconnection Boundaries during periods of light load or abnormal operating conditions, or due to the active power injection of Distributed Generators.
Voltage drops shall be assessed at peak feeder Demand based on the 15-minute average of the feeder metering data, or SCADA data where metering data is not available, to ensure that the design voltage at the User Interconnection Boundary meets the voltage requirements set forth in DC 3.2.3.
The voltage profiles shall be assessed for planned Contingency Conditions and shall be such that the design voltage at User's Interconnection Boundaries meets the voltage requirements of this Distribution Code for all plausible Distribution System configurations.
Any extension or interconnection to the Distribution System shall be designed in such a way that it does not adversely affect the voltage control employed on the Distribution System.

DC 3.3.5 Short Circuit Studies

The Distribution Licensee in collaboration with the Single Buyer and/or System Operator, if required, shall undertake fault current level studies at all switching points on the Distribution System where fault interrupting devices are located. The studies shall determine the three phase and single phase to ground short circuit levels for the most stringent conditions.
The Distribution System shall be designed to ensure that the short-circuit fault current shall be limited to the declared manufacturers' ratings of all switches, fuses, circuit breakers and other Protection devices in terms of both Breaking Capacity and Making Capacity.
Where it is identified that the design Breaking Capacity or Making Capacity is likely to be exceeded, the non-compliance shall be documented and the plant shall be subject to appropriate operational restrictions until compliance is achieved.
The Distribution Licensee and Users, including Distributed Generators, will exchange information on fault infeed levels at Interconnection Boundaries. This shall include:
  • the maximum and minimum three-phase and line to ground fault infeeds; and
  • the X/R ratio under short circuit conditions.
Unless the Distribution Licensee agrees otherwise, it is not acceptable for a User or Distributed Generator to limit the fault current infeed at the Interconnection Boundary through the use of Protection and associated Equipment if the failure of that protection and associated Equipment could cause the Distribution System to operate outside its short circuit rating.

DC 3.3.6 System Losses Studies

System losses studies shall be performed to quantify the Active Power losses in the Distribution System and determine optimum Distribution System open points to provide an acceptable balance between reduced losses and Distribution System reliability.
Where investment in the Distribution System is required, lower loss solutions, in terms of plant and Distribution System configuration shall 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 3.3.7 Reliability Studies

Reliability studies shall be carried out by the Distribution Licensee to determine the theoretical levels of System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) for the Distribution System using average fault rates for the Distribution System components. These studies shall be used to determine optimum Distribution System configurations when undertaking any interconnection, extension to or reinforcement of the Distribution System.
The SAIDI and SAIFI indices are defined as follows according to the IEEE Standard 1366-2012:
The SAIDI is the average outage duration for each customer served. It is measured in units of time, minutes or hours, and is calculated as:
Sum of customer minutes of interruption
SAIDI = Total number of customers served
The SAIFI 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:
Sum of total number of customers interrupted
SAIFI = Number of customers served
The SAIDI and SAIFI indices shall be reported to the Authority. The reporting and computation methodology of the SAIFI and SAIDI shall be approved by the Authority.

DC 3.3.8 System Earthing

System Earthing shall be designed in accordance with the Distribution System Construction Manual and the relevant regulations, and with the following purposes:
  • To protect life from danger or electric shock, and property from damage.
  • To limit the voltage upon a circuit when exposed to higher voltages than that for which the circuit is designed.
  • To limit the voltage on a circuit which might otherwise occur through exposure to lightning.

DC 3.4 Standard Planning Data

DC 3.4.1 Energy and Demand Forecast

Where the Distribution Licensee considers it necessary for the purpose of interconnection studies, the User connected at MV shall provide the Distribution Licensee with its Energy and Demand forecasts at each Interconnection Boundary at least for the five succeeding years.
This forecast data, for the first year shall include monthly Energy and Demand forecasts, while the remaining two years shall include only annual forecasts.
The Users shall provide the net and gross values of energy and Demand forecast. The net values shall be less the output of the User Distributed Generation, if applicable.
The following factors shall be taken into account by the Distribution Licensee and Users when forecasting demand:
  • Historical Demand Data;
  • Demand trends;
  • Customer's own Generation Schedules, if applicable; and
  • Demand transfer capability where the same Demand can be supplied from alternate User interconnection points.
  • Proposed new activities
Energy and Active Power Demand forecasts of Users connected at Low Voltage shall be produced by the Distribution Licensee.

DC 3.4.2 Distribution System Data

The Distribution Licensee shall make available to the Single Buyer and the System Operator all the data relevant to the Distribution System. This network data shall include at least the following:
  • Transformers - The primary input data for transformers includes MVA rating, primary and secondary winding voltages, windings interconnection, sequence impedances, X/R ratio, tap ranges, tap settings, emergency ratings.
  • Electric Lines or Electrical Conductors -The primary input data required among other things are rated line voltage, conductor type, and type of construction, thermal ratings, emergency rating, and sequence impedances.
  • Distributed Generating Units shall be modelled by their Active Power and Reactive Power capabilities for steady state analyses. For dynamic analysis more detailed Models are required for the Generating Units and their controls, that allow to represent the dynamic behaviour of the Generating Station to large changes in the System voltage and frequency. The DGS shall be represented using the information specified in DC 4.6.1.
  • Other parameters - In order to develop a Grid reliability data base outage rates and durations for all major Equipment are also required.

DC 3.4.3 User System Data

For Users connected at Low Voltage the following data shall be provided to the Distribution Licensee;
  • Maximum power requirement (kVA or kW)
  • Type and number of significant load items (cookers, showers, motors, and welders, electric vehicle, etc.)
For Users connected at Medium Voltage the following data shall be provided to the Distribution Licensee;
a) All types of loads
  • Maximum Active Power requirements.
  • Maximum and minimum Reactive Power requirement.
  • Type of load and control arrangements (e.g. type of motor start, controlled rectifier or large motor drives).
  • Maximum load on each phase.
  • Maximum harmonic currents that may be imposed on the Distribution System.
  • Details of cyclic load variations or fluctuating loads (as below).
Users connected to the MV network having Electrical Facilities undergoing two or more phases of development, shall provide the information above for each phase of development.
b) Disturbing Loads
Comprehensive schedule of installed new Equipment including details of Disturbing Loads.
These are loads which have the potential to introduce harmonics, flicker or unbalance to the System. This could adversely affect the supply quality to other Customers. Disturbing Loads could be non-linear loads, power converters/regulators and loads with a widely fluctuating Demand. The type of load information required for motive power loads, welding Equipment, harmonic producing or non-linear loads and generating Equipment can be obtained from the Distribution Licensee on request.
In the case of compensating Equipment associated with Disturbing Loads, details and mode of Operation to be provided so as to ensure compliance with emission limits specified in DC 6.
c) Fluctuating Loads
Details of cyclic variation, and where applicable the duty cycle, of Active Power (and Reactive Power if appropriate), in particular:
  • The rates of change of Active Power and Reactive Power, both increasing and decreasing;
  • The shortest repetitive time interval between fluctuations in Active Power and Reactive Power; and
  • The magnitude of the largest step changes in Active Power and Reactive Power, both increasing and decreasing
In some cases, more detailed information may be required to permit a full assessment of the effect of the User's load on the Distribution System. Such information may include an indication of the pattern of load build-up schedule and a proposed Commissioning programme. This information shall be specifically requested by the Distribution Licensee when necessary and shall be provided by the User within a reasonable time.

DC 4 DISTRIBUTED GENERATION

DC 4.1 Introduction

Section DC 4 of the Distribution Code is applicable to all existing or prospective Distributed Generators, all of which are connected to the LV or MV Distribution System. Requirements apply to all Generating Stations, including Synchronous and Asynchronous Generating Stations and Power Park Stations unless otherwise more specifically defined in this Distribution Code. Customers with Stand-by Generating Units who are connected to the Distribution System shall also comply with clause DC 4.13.
In addition to meeting the requirements of DC 4, Distributed Generators shall also comply with the requirements all relevant sections of the National Grid Code.
The Distributed Generator shall initiate discussions at a sufficiently early stage in design to allow the Distribution Licensee to examine the impact of the Generating Unit(s) on the Distribution System.
The Distribution Licensee shall be responsible for all the aspects related to the Distributed Generators interconnections to the Distribution System, including the information exchange and connection process with the users, the elaboration and maintenance of the DG Grid Code, technical design specifications, safety requirements, monitoring of standards compliance and elaboration of studies needed to authorize the interconnection. The Distribution Licensee, may request assistance of the System Operator and / or Single Buyer when studying DG interconnections that may have an impact in the Distribution Network, including dynamic performance studies of DG generation. The requirements for telecommunications and control of DG generation shall be defined by the System Operator.
The Distribution Licensee may refuse permission for the connection of a Distributed Generating Unit to the Distribution System or require the revision of the design, technical parameters or nominal capacity of the Distributed Generation Unit, or impose certain restrictions in order to ensure the security and quality of supply standards as specified in DC 3.2. In such instances, the Distribution Licensee shall provide sufficient supporting information to justify the refusal or the required revisions. The Authority shall be informed before any refusal notice is given to a Distributed Generator that requested an Interconnection to the MV or LV Distribution System

DC 4.2 Distributed Generation Interconnection

DC 4.2.1 SSDG and MSDG Grid Codes

The Distribution Licensee shall produce a document (DG Grid Code) for each category of Distributed Generation containing:
  • Procedural aspects: the detailed procedures to be followed by the Generator, the Distribution Licensee, the System Operator and other parties in order to connect the Distributed Generator to the grid, starting from the submission of the application to the Distribution Licensee to the signature of the Connection Agreement, ESPA, or PPA. and subsequent Proclamation by the President of the Republic as the case may be; and,
  • Technical aspects: all the safety, design, construction, testing, commissioning, and administrative requirements for the connection of the Distributed Generators to the Distribution System.
The DG Grid Code as applicable for each category of Distributed Generation shall be approved by the Authority.

DC 4.2.2 DG Grid Code Technical aspects

The purpose of the technical aspects of the DG Grid Code is to provide guidance on the connection of a Distributed Generating Station to the Distribution System. It is intended to address all aspects of the connection process from standards of functionality to site commissioning, such that Users, Equipment manufacturers and Generators shall be aware of the requirements of the Distribution Licensee and the System Operator before the Distributed Generating Station shall be accepted for connection to the Distribution System.
The technical aspects of the DG Grid Code shall:
  • include requirements for the Distributed Generation installations that shall be compatible (equal or better) with those set out in the corresponding sections of this DG Grid Code.
  • be aimed at facilitating the connection of a Distributed Generator whilst maintaining the integrity of the Distribution System, both in terms of safety and supply quality. It shall cover all Distributing Generating Stations within the scope of Section DC 4, irrespective of the type of Plant and Apparatus used to convert any primary energy source into electrical energy.
The technical aspects of the DG Grid Code shall at least contain the following:
  • Safety, Isolation and Switching Requirements
    • Rules for working on Low Voltage (LV) grid based on Occupational Safety and Health Act 2005.
    • Safety Concerns
    • Labelling and information to be displayed on Electrical Facilities
    • Information plate
  • Standards, guidelines and norms applicable to the components and materials of the Electrical Facilities and the design of Distributed Generating Stations.
  • Certification of installation and compliance with the Distribution Code and the standards, norms and guidelines in item b) above.
  • Detailed construction and design specifications for MSDG 2 and MSDG 3, including:
    • Switchgear arrangement
    • Interconnection Facility Description
    • Interconnection Transformer Specifications
    • Mineral insulating oil for transformers
    • Typical HV switchgear panel and protection guidelines
    • Protection Specifications
    • Communication Requirement
    • Typical 22kV switchgear room layout

DC 4.2.3 Generator's responsibility

Distributed Generators shall comply with the corresponding DG Grid Code in Section DC 4.2.1 and the corresponding License.

DC 4.3 Determination of significance

A Distributed Generating Station shall comply with the requirements on the basis of the voltage level of their connection point and their maximum capacity according to the categories set out in the following paragraph.
The Distributed Generating Station within the following categories shall be considered as significant:
  • Small-Scale Distributed Generator (SSDG): Distributed Generating Station connected to the 230 single - phase/400 V three-phase Distribution System and has a maximum Registered Capacity of 50 kW;
  • Medium-Scale Distributed Generator 1 (MSDG 1): Distributed Generating Station with Registered Capacity greater than 50 kW but not exceeding 500 kW and connected to the 22 kV Distribution System through a dedicated transformer;
  • Medium-Scale Distributed Generator 2 (MSDG 2): Distributed Generating Station with Registered Capacity greater than 500 kW but not exceeding 4 MW and connected to the 22 kV Distribution System through a MV switchgear panel (MV metering) and a step-up interconnection transformer;
  • Medium-Scale Distributed Generator 3 (MSDG 3): Distributed Generating Station with Registered Capacity greater than 4MW but not exceeding 10MW and connected through a dedicated 22kV line to the 22 kV section of the Transmission System;
A Generating Station with Registered Capacity greater than 4MW but not exceeding 10MW and connected through a dedicated line to the 22 kV section of the Transmission System shall comply with the requirements of the Distribution Code applicable to MSDG 3.
Notwithstanding the above general categories, the Distribution Licensee may authorize after a complete technical evaluation, a DG generator between 50 kW and 500 kW to connect to the 22kV Distribution System through MV switchgear without the need of a dedicated transformer. In these cases, the MSDG 2 is applicable
A typical Interconnection layout for MSDG 1 is provided in DC 21.4.1. Typical medium voltage switchgear panel and protection drawings for MSDG 2 and 3 are presented in DC 21.4.2 for Generating Stations using both synchronous and induction machines and inverter-based generation. A typical connection diagram of a MSDG 3 scheme via a dedicated feeder line is shown in DC 21.4.2.

DC 4.4 Connection Capacity

DC 4.4.1 Feasibility

The feasibility to connect a Distributed Generating Station to the Distribution System shall be confirmed by a study to determine the impact of the interconnection of the Grid, which shall be conducted by the Distribution Licensee in collaboration with the System Operator, if required, on a case-to-case basis.
The possibility of interconnecting a Variable Renewable Generating Station to the Distribution System shall be subject to the maximum amount of variable renewable energy-based power generation that can be accommodated in the Distribution System while maintaining the Total System's stability and security.

DC 4.4.2 Connection studies

  • Connection of SSDG: Applications shall be allocated to the relevant feeder and distribution transformer where the Distributed Generator shall be connected. During the analysis stage, if the maximum allowed capacity is found to have been already attained for the feeder or transformer, the applications shall not be entertained unless the Distributed Generator opts for a Network Review.
  • Connection of MSDG1, MSDG2 and MSDG3: If any works in the distribution network are necessary, the Distribution Licensee and the Single Buyer shall determine what Grid modifications (reinforcements or extensions) are required, if any, to connect the DGS by conducting the necessary studies. The description of the required Grid modifications shall be communicated to the Distributed Generator, detailing who shall be the Party (Single Buyer and Distribution Licensee, or the Distributed Generator) responsible for execution of each of the works and who shall be the Party (Single Buyer and Distribution Licensee, or the Distributed Generator) responsible for payment of each of the works, subject to approval of the Authority.

DC 4.4.3 Capacity allocation

Capacity allocation to feeders for Distributed Generators (SSDG, MSDG 1 and MSDG 2) shall be done according to the rules and procedures as approved by the Authority and to provisions of the Connection Agreement

DC 4.5 Specific Rules for Distributed Generators

The integrity of the Distribution System and the security and quality of supply to existing Users shall not fall below standard as a result of the Distributed Generators operating in parallel (synchronized) with the Distribution System. Conditions for Operation shall guarantee the safety of:
  • Members of general public
  • Personnel
  • Distribution Equipment
Supply quality to other Customers shall not fall below standard as a result of the presence or Operation of the Distributed Generating Units.
Where a Distributed Generating Unit is to be installed as per the Electricity Act and its amendments in a premise with the possibility of Parallel Operation, the Distribution Licensee shall inspect the Distributed Generating Station Electrical Facilities to ensure that the requirements of the National Grid Code are met. The Distribution Licensee may require a demonstration by Operation of the Distributed Generator. Parallel Operation of the DG shall be allowed only if authorized by the Distribution Licensee and the System Operator as per prevailing scheme and policy.

DC 4.6 Provision of Information

DC 4.6.1 Information required from Generators

Distributed Generators shall provide to the Distribution Licensee and the Single Buyer Licensee, via the forms defined by the Distribution Licensee, information on the Distributed Generating Station and the proposed interface arrangements between the Distributed Generating Station and the Distribution System.
The details of information required shall vary depending on the type and size of the Distributed Generating Unit and the characteristics of the Interconnection Boundary. This information shall be provided by the Distributed Generator at the reasonable request of the Distribution Licensee.
The Distribution Licensee and Single Buyer shall use the information provided by the Distributed Generator to produce a Model of the DGS to determine a technically acceptable method of connection. If the Distribution Licensee and/or Single Buyer reasonably concludes that the nature of the proposed connection or changes to an existing connection requires more detailed analysis then further information than that specified in this Section DC 4.6.1 may be required.
The information required by the Distribution Licensee and Single Buyer before entering into an agreement to connect any Distributed Generating Station to the Distribution System is specified below.

DC 4.6.1.1 Distributed Generating Station Data

  • User System Data Schedule in DC 20.1
  • Fault Infeed Data Schedule in DC 20.2
  • Terminal Voltage (kV)
  • Rated kVA
  • Rated kW
  • P-Q Capability Diagram.
  • Type of Generating Station – synchronous, asynchronous, etc.
  • Type of primary energy resource;
  • Anticipated operating regime of generation e.g. continuous, intermittent, peak shaving;
  • Method of voltage control
  • Distributed Generating Unit transformer resistance, reactance, MVA rating, tap changer arrangement, vector group, Earthing;
  • Requirements for standby supplies
  • For Synchronous and Asynchronous Generating Units:
    • Inertia Constant in MW sec/MVA (whole derive train)
    • Stator resistance
    • Direct Axis Reactance: Sub-transient, Transient and Synchronous
    • Time Constants: Sub-transient, Transient and Synchronous
    • Zero Sequence Resistance and Reactance
    • Negative Sequence Resistance and Reactance

DC 4.6.1.2 Interface Arrangements

  • The means of synchronization between the Distribution Licensee and the User;
  • Details of the earthing system of the Distributed Generating Station;
  • The means of connection and disconnection which are to be employed; and
  • Precautions to be taken to ensure the continuance of safe conditions if any earthed neutral point of the Distributed Generators' system becomes disconnected from earth.

DC 4.6.2 Additional information required from MSDG 2 and MSDG 3

Additional information may be required from Distributed Generators with Registered Capacity larger than 2 MW and connected to the 22kV Distribution System. This may include:
  • Single line diagram of the Distributed Generating Station and the Interconnection Site.
  • Models of the Distributed Generating Units in the form of transfer function block diagram including parameters and nonlinearities of:
    • Distributed Generating Units in Synchronous and Asynchronous Distributed Generating Stations: AC machine, the excitation system, automatic voltage regulator and power plant controller; and prime mover and speed governor.
    • Distributed Generating Units in Power Park Stations: Generating Unit Model including Active and Reactive Power controls, LVRT and HVRT capability, limiters and any relevant controller influencing the interactions of the Distributed Generating Unit with the Grid.
The dynamic Models shall be provided in the digital format required by the power system simulation software used by the System Operator and Single Buyer. They must not require a simulation time step of less than 5 ms. Details of the software version shall be provided by the System Operator and/or Single Buyer upon request.
  • Harmonic current emissions for individual harmonics up to the 50th order.
  • Steady state capability
    • Registered Capacity and Minimum Load of each Distributed Generating Unit and Distributed Generating Station in MW.
    • Distributed Generating Unit and Power Station Auxiliaries' Active and Reactive Power Demand, at Registered Capacity and under Minimum Load.
  • Positive and zero sequence parameters and rated capabilities of power transformers, lines, cables, reactors, capacitors and other relevant Equipment connected between the terminals of the Distributed Generating Unit and the Interconnection Boundary.
In normal circumstances the information specified above shall enable the Distribution Licensee with the support of the System Operator and/or Single Buyer, if needed, to assess the connection requirements. Occasionally additional information may be required. In such circumstances, the information shall be made available by the Distributed Generator, at the reasonable request of the Distribution Licensee.

DC 4.6.3 Information Provided by the Distribution Licensee

Where a Distributed Generating Station is intended for Parallel Operation with the Distribution System at least the following additional information shall be provided by the Distribution Licensee to the Distributed Generator:
  • Settings of the Protection relays of the feeder on which the Distributed Generation is to be connected, and of any other relay with which coordination is required
  • Equipment, cabling, switchgear, metering requirements
  • Distributed Generator's Substation site and building requirements (dimensions, access, planning permission, Earthing, lighting, air conditioning and heating among others)

DC 4.7 Technical Requirements

DC 4.7.1 Design

DC 4.7.1.1 Connection Arrangements

The DGS shall be connected to the System as follows:
  • A SSDG shall be connected to the 230/400 V Distribution System
  • A MSDG 1 shall be connected to the 22 kV Distribution System. Whenever possible, the connection shall be through a dedicated 22/0.415 kV transformer.
  • A MSDG 2 or MSDG 3 shall be connected to the 22 kV Distribution System through a 22kV switchgear panel (MV metering) and a step-up interconnection transformer

DC 4.7.1.2 Interconnection transformer

The MSDG 1, MSDG 2, and MSDG 3 interconnection transformer shall be of vector group Dyn11 (Delta on the Grid side and star on the DGS side). The delta winding on the Distribution System side ensures that:
  • The performance and sensitivity of the earth fault protection scheme at the Distribution System substation are not affected;
  • Triple harmonics from the Distributed Generating Station do no reach the Distribution System; and
  • The MSDG is provided some isolation from voltage sags due to single-line-to-ground faults, allowing it to better ride through voltage sags.
Alternative transformer vector groups may be used subject to the Distribution Licensee approval.
Detailed specifications of the interconnection transformer (when applicable) and switchgear shall be given by the Distribution Licensee in the corresponding DG Grid Code. The transformers and 22kV switchgear shall be approved by the Distribution Licensee prior to ordering.

DC 4.7.1.3 Earthing

When a DGS is operating in parallel with the Distribution System, there shall be no direct connection between the AC generator stator winding (or pole of the primary energy source in the case of a PV array or Fuel Cells) and the Distribution System's earth terminal.
The stator winding of an AC Generating Unit of a SSDG directly connected to the LV Distribution System without step-up transformer must not be earthed.
A DC source or DC Generating Unit could be earthed provided that the inverter separates the AC and DC sides by at least the equivalent of a safety isolating transformer. In such case, consideration shall then be given to the avoidance of corrosion on the DC side.
A TT earthing system is adopted in the Distribution system. The neutral and earth conductors must be kept separate throughout the installation, with the final earth terminal connected to a local earth electrode.
  • SSDG: Earthing shall be according to IEC 60364-5-55. For systems capable of operating in isolated generation, protection by automatic disconnection of supply shall not rely upon the connection to the earthed point of the utility supply system.
  • MSDG 1: Earthing shall be according to IEC 60364-5-54. For systems capable of operating in isolated generation, the neutral point of the AC generator must not be earthed during Parallel Operation with the Distribution System. When the Distributed Generating Station operates in isolation, the Distributed Generating Unit neutral-to-earth connection must be closed. The operation of the neutral-to-earth connection shall be carried out by an inter-locking system. The busbar system shall be equipped with visible lockable Earthing Device.
  • MSDG 2 and MSDG 3: Earthing systems shall be designed, installed, tested and maintained according to BS 7354 (Code of Practice for Design of high voltage open terminal stations) and BS 7430 (Code of Practice for Protective Earthing of electrical installations). Steps must be taken to prevent the appearance of hazardous step and touch potential when earth faults occur on the 22kV Grid.
In all applicable Electrical Facilities, the 22 kV earth electrodes and Low Voltage earth electrodes shall be adequately separated to prevent dangerous earth potentials being transferred to the Low Voltage Grid.
Warning notice that: "CONDUCTORS MAY REMAIN LIVE WHEN ISOLATOR IS OPEN" shall be conspicuously displayed at the installation.

DC 4.7.1.4 Electromagnetic Emission and Immunity

The DGS shall comply with the requirements of IEC 61000.

DC 4.7.1.5 Surge Withstand Capability

The Interconnection Facilities shall have a surge withstand capability, both oscillatory and fast transient, in accordance with IEC 62305-3, the test levels of 1.5 kV. The design of control systems shall meet or exceed the surge withstand capability requirements of IEEE Standard C37.90.

DC 4.7.2 Distributed Generating Station Performance Requirements

  • Distributed Generators subject to Dispatch shall comply with the relevant sections of the Generation Code;
  • Protection associated with a Distributed Generating Station shall be required to co-ordinate with the Distribution System Protection settings and shall not be changed without agreement from the Distribution Licensee.
  • Each Distributed Generating Unit shall, as a minimum, operate continuously at normal rated output at the System frequencies in the range of 49.25Hz to 50.75Hz (50 Hz ±1.5%).
  • Each Distributed Generating Unit shall, as a minimum, remain synchronized to the Distribution System during a Rate of Change of Frequency of values up to and including plus or minus 2.5 Hz per second measured as a rolling average over 500 ms, and adjust the loss of mains protection according to the values in Table 3 of Section DC 4.8.6.
  • Each Distributed Generating Unit shall, as a minimum, remain synchronized to the Distribution System at normal rated output at Distribution System voltages within the ranges specified for Normal Conditions in DC 3.2.3.
  • After a single Contingency or under System Emergency conditions, frequency and voltage may go out of normal limits but still inside operational acceptable values. In those cases, the Distributed Generating Station shall comply with the following:
    • SSDG may disconnect from the Distribution System for Distribution System voltages outside the range specified in DC 4.7.2.g).
    • MSDG 1, MSDG 2, and MSDG 3 must be able to operate within the range specified for Contingency Conditions in DC 3.2.3.
  • The DGS Electrical Facilities shall be able to withstand the following fault levels at the Interconnection Boundary during at least 1 s, unless otherwise instructed by the System Operator or Distribution License
  • Each Distributed Generating Unit shall have the Reactive Power capability specified in Table 2 measured at the Point of Delivery for Grid voltages within the range for Normal Conditions defined in DC 3.2.3.
The resulting Reactive Power requirement at Registered Capacity shall be available from 20% of the Registered Capacity.

DC 4.8 Protection Requirements

DC 4.8.1 Scope

The Protection requirements set forth in this section are mandatory for all DGSs, irrespective of the Generation technology used.

DC 4.8.2 General Requirements

The coordination and selectivity of the Protection system must be safeguarded even with the connection of new Distributed Generation to the Distribution System. To satisfy this condition, the Distributed Generator shall install the Protection Equipment listed in DC 4.8 and the settings of those Protections shall be proposed by the Distributed Generator and accepted by the Distribution Licensee.
In case of short circuits in the DGS side, the DGS shall adjust its Protections in such a way that they shall avoid unnecessary trips in the Distribution System side of the Interconnection Boundary and at the same time avoid that the incident propagates to the rest of the Distribution or Transmission Systems.
In case of incidents originated outside the DGS Electrical Facilities, such as short circuits in the Distribution System, abnormal voltage or frequency excursions, the Distributed Generating Station shall give priority to the Grid Protections to solve the incident and act accordingly with the coordination and selectivity principles of the Protection system.
The Protection system shall provide protection against fault occurring on both the Distribution System and the DGS Electrical Facilities. The Protection system shall provide protection against short circuit, earth faults and overloading conditions and also prevent the Islanding of the part of the Distribution System to which it is connected.
In addition, the Distributed Generator must provide any additional Protection functions necessary to adequately protect all equipment and personnel. The settings of the additional Protection systems shall be appropriately defined so as to prevent unnecessary trips during remote disturbances that affect the voltage and frequency of the Distribution or Transmission Systems. Any modifications in the Protection settings carried out by the Distributed Generator shall be communicated to and accepted by the Distribution Licensee.

DC 4.8.3 Availability of Protection

The Distributed Generator shall ensure that all its Electrical Facilities are protected and that all elements of the Protection, including associated inter-tripping, are operational at all times. Unavailability of the Protection shall require the Distributed Generating Station to be taken out of service.
The DGS shall be protected against
  • Overload.
  • Short circuit within the DGS Electrical Facilities.
  • Earth faults in the close vicinity of the DGS Electrical Facilities.
  • Overcurrent.
  • Abnormal voltages (Table 3 below)
  • Abnormal frequencies (Table 3 below)
  • Lightning.
  • Loss of mains including Rate of Change of Frequency (ROCOF) and/or voltage vector shift Protection.

DC 4.8.4 DC Functions of Protection Apparatus

All Protection apparatus functions shall operate down to a level of 50% of the nominal DC supply voltage of the DC system, or the system must be able to safely disconnect and shutdown when operation conditions are outside the nominal operating DC voltage specified in the DC system specifications.

DC 4.8.5 Protection Flagging, Indications and Alarms

All Protection devices supplied to satisfy the Distribution Licensee requirements shall be equipped with operation indicators. Such indicators shall be sufficient to enable the determination of which devices caused a particular trip.
Any failure of the Distributed Generating Station's tripping supplies, Protection apparatus and Circuit Breaker trip coils shall be supervised within the Distributed Generator's installation, and the Distributed Generator shall be responsible for prompt action to be taken to remedy such failure.

DC 4.8.6 Trip settings

Distributed Generating Units shall not supply power to the Distribution System after the formation of a Power Island. The DGS may only be operated during such outages to supply its own load (isolated generation) with a visibly open tie to the Distribution System. The DG shall be disconnected from the Distribution System within 0.5 seconds of the formation of a Power Island as shown for the loss of mains Protection in Table 3.
The trip settings must comply with the values stated in Table 3. These trip settings are indicative and may be subject to change upon request of the Distribution Licensee for the safe interconnection to the Grid.
NOTES:
  • Voltage and frequency are referenced to the terminals of the Generating Unit
  • If the DG can generate higher voltage than the U> trip setting, the U>> overvoltage setting is also required.

DC 4.8.7 Re-connection

Following a Protection initiated disconnection, the DGS shall remain disconnected from the Grid until the voltage and frequency at the Interconnection Boundary has remained within the limits for Normal Conditions for at least 3 minutes.
Automatic reconnection is only allowed when disconnection was due to operating parameters being outside the ranges stated in DC 4.7.2.h), not if disconnection was caused by any Apparatus within the DGS installation failing to work or operate correctly.

DC 4.8.8 Synchronizing AC generators

The Distributed Generator shall provide and install automatic synchronizing Equipment. A Synchronism-Check Relay shall be provided on all generator circuit breakers and any other circuit breakers, that are capable of connecting the DGS plant to the Distribution System. Synchronism-Check Relay Interlocks shall be provided.

DC 4.9 Additional Protection requirements for MSDG 2 and MSDG3

DC 4.9.1 Inter-tripping Protection for DGS of Registered Capacity equal to or greater than 1 MW

The inter-tripping scheme is to be designed and pre-wired, subject to the requirement of the System Operator or Distribution Licensee, such that tripping of the interconnecting feeder circuit breaker in the Distribution System 22 kV Substation results in the tripping of the CB1 in DC 21.4.2. The tripping of the Distribution System 22 kV Circuit Breaker shall be a tripping due to Protection relay action at the Distribution System 22 kV Substation level. Manual opening and tripping due to Protection relay of CB1 in DC 21.4.2 shall not cause tripping of corresponding Circuit Breaker at the Distribution System 22 kV Substation. However, the above scheme shall be wired but disabled initially for Registered Capacity up to 4MW only. The communication scheme shall be set as per section DC 4.17.

DC 4.9.1.1 Inter-tripping requirements for solar PV Distributed Generating Stations

The following indicative tripping scheme shall be implemented for MSDG installations employing solar PV systems:
(1) During the day, upon tripping of the 22 kV Circuit Breaker at the respective Distribution Licensee substation on fault, System Control Engineer or designated representative shall open CB1 in DC 21.4.2 remotely. CB1 in DC 21.4.2 intertrips CB2 and all other outgoing circuit breakers. Upon supply restoration, the System Control Engineer or designated representative shall reclose CB1 in DC 21.4.2 remotely and liaise with the contact person at the MSDG site to reclose CB2 in DC 21.4.2 locally.
(2) During the night, upon tripping of the 22 kV circuit breaker at the respective Distribution Licensee Substation on fault, the System Control Engineer or designated representative shall not open CB1 as there is no PV generation at night, and hence no-fault contribution due to the PV installation.
(3) In case of abnormal setup (MSDG shifted to another feeder), the System Control Engineer or its designated representative shall adopt the same philosophy as above.

DC 4.9.2 Protection against relay malfunction

The watchdog function of the protection relay protection must issue an alarm in case there is a malfunction.
For DGS of Registered Capacity greater than 1000 kW, this alarm signal, if required by the System Operator or Distribution Licensee, shall be transmitted to the interconnecting Distribution System Substation via the fibre optic channel or wireless communication.

DC 4.9.3 Protection Settings: Grading and Discrimination

For DGS of Registered Capacity above 500 kW, the Distributed Generator shall submit to the Distribution Licensee appropriate settings for grading and discrimination of the interconnecting Protection (22 kV Circuit Breaker at the Distribution System side of the Interconnection Boundary) with the upstream Distribution System Substation Protection.
The Distributed Generator shall also submit to the Distribution Licensee the Fault current contribution (both single phase to earth and three phase) from the Distributed Generating Station to faults on the Distribution System. The Distribution Licensee shall provide the relevant Grid information to the Generator for the purpose of the Protection study.

DC 4.9.4 Additional Protection and Safety requirements

In addition to mandatory safety interlocks as per IEC 62271‑200, for metal-enclosed MV switchgear, appropriate interlocking mechanism shall be incorporated between the Circuit Breakers on the Distribution System and DGS side as a measure of protection against an incorrect sequence of manoeuvres by operating personnel. This interlocking mechanism shall prevent the possibility of mechanically closing the CB1 in DC 21.4.2 onto a live busbar on the User side via a mechanical or electrical interlocking system between CB1 in DC 21.4.2 and the Distributed Generating Unit transformer Circuit Breaker (CB2 in DC 21.4.2) and any other outgoing circuit breakers.
The Distribution Licensee may request additional interlocking and Protection systems for safety reasons. The Distributed Generator shall demonstrate the incorporation of the above safety interlocking mechanism both at design and Commissioning stages.
In case the DGS contains synchronous and/or induction machines, additional measures listed below are required:
  • A dead-bus/live-line Synchronism- Check Relay shall be provided to prevent remote/electrical closure of Interconnection Circuit Breaker (CB1 in DC 21.4.2) as long as the DGS-side 22 kV busbar is energized.
  • A Synchronism-Check Relay shall be provided on all Distributed Generating Station circuit breakers and any other circuit breakers (including Low Voltage Circuit Breakers), unless interlocked, that are capable of connecting the DGS to the Distribution System.

DC 4.10 Black Start Capability

Distributed Generators shall notify the System Operator and the Distribution Licensee if its Generating Station has a Black Start Capability (ability to restart the Generating Unit in the absence of incoming power from the Grid), unless the Distributed Generator has previously notified the System Operator accordingly under the Generation Code.

DC 4.11 Power Quality

The DG Electrical Facilities shall not cause excessive voltage excursions nor cause the voltage to drop below or rise above the range maintained by the System Operator.
A DGS shall not produce excessive distortion to the sinusoidal voltage or current waves, and shall comply with DC 6.

DC 4.12 Testing and Commissioning

DC 4.12.1 General requirements

The Distributed Generator shall perform the testing and pre-commissioning phases of the DGS as per relevant standards norms. The Distributed Generator shall provide the Distribution Licensee with a Testing and Pre-commissioning program, approved by the Distribution Licensee if reasonable in the circumstances, to allow Testing and Pre-commissioning to be coordinated.
The Distributed Generator shall keep written records of test results and Protection settings. The Distributed Generator shall regularly maintain the Protection systems in accordance with good electrical industry practice.
The Distribution Licensee has the right to require the Distribution Generator to perform tests on ad-hoc basis for purposes such as ascertaining level of Harmonic Distortion, voltage rise, Protection operation in the context of System changes, Fault investigation and Protection changes. The Distribution Licensee shall be assisted by the System Operator during the tests.

DC 4.12.2 Specific Requirements for SSDG and MSDG 1

Testing and Pre-Commissioning of the SSDG and MSDG 1 Electrical Facilities shall be performed by an Installer.

DC 4.12.3 Specific Requirements for MSDG 2 and MSDG 3

DC 4.12.3.1 Testing and Pre-Commissioning

For Greenfield project the Distributed Generator shall submit appropriate testing and pre-commissioning procedures and plans as per applicable standard for the DGS Electrical Facilities to the Distribution Licensee for approval at least 3 (three) months prior to the scheduled Commercial Operation Date. Testing and Pre-Commissioning of the facility shall be performed by the Distributed Generator under the supervision of a Registered Professional Engineers (for MSDG 2) or Independent Engineers (for MSDG 3) in their relevant fields.
The Registered Professional Engineers or Independent Engineers, as the case may be, shall certify the test and results and confirm that the installation complies with the National Grid Code requirements. It is the responsibility of the Distributed Generator to ensure that all required tests are performed to ensure compliance with Section DC 4.
a) Testing Phase
At least the following tests shall be performed on:
1) All Distributed Generating Units
  • i. Functional Test;
  • ii. Insulation resistance testing; and
  • iii. Performance verifications;
  • iv. 6-hour test run with the Distributed Generating Unit connected to the Grid
  • v. Verification of the settings of all the Protection relays/systems;
  • vi. Checking/proving of all safety Equipment;
  • vii. Voltage phasing checks between the Distributed Generating Unit and the Substation to which it is connected, and the Grid;
  • viii. Proving of all inter-tripping circuits between the Distributed Generating Unit and the Distribution System Equipment.
  • ix. Earthing test at the Distributed Generating Station switchyard;
2) Solar photovoltaic Generating Stations only
  • i. Earthing continuity of array frame to earth and connection to main earthing terminal
  • ii. Polarity of each module string
  • iii. PV string Open-Circuit Voltage (Voc) Test;
  • iv. PV Short Circuit current (Isc) Test;
  • v. PV array insulation Test;
  • vi. Operational Test PV string current;
  • vii. Functional Test;
  • viii. Insulation resistance testing; and
  • ix. Performance verifications;
3) Wind Distributed Generating Stations only:
  • i. Demonstration of Distributed Generating Unit vibration level below acceptable level.
  • ii. Test of trip function when Distributed Generating Unit is generating and grid loss occur
  • iii. Test of over speed trip of each Distributed Generating Unit
  • iv. Test of yaw drives
  • v. Functional test
  • vi. Performance verification
4) Thermal and hydro Distributed Generating Stations only:
  • i. Automatic Voltage Regulator (AVR) setting and adjusting in both stand-still condition and with the Distributed Generating Unit running at full speed no load condition;
  • ii. Governor Control System checks, including a 10% (or the percentage as specified by the manufacturer) over-speed test;
b) Pre-Commissioning Phase
The Pre-Commissioning tests shall be performed in the presence of the Distribution Licensee with the assistance of the System Operator. The Distribution Licensee has the right to request the Distributed Generator to perform additional tests which Distribution Licensee may find necessary to ensure integrity of the Distribution System.
Pre-Commissioning shall be performed for Active Power levels of at least 20% of the Registered Capacity, where applicable. The pre-commissioning of the electrical system shall include at least the following:
  • i. Demonstration of satisfactory operation of power measurement equipment
  • ii. Functional tests of Protection relays and verification of settings
  • iii. Demonstration of satisfactory operation of internal reticulation, and step-up transformer
  • iv. Pressure tests on 22 kV switchgear
  • v. Reactive Power Capability.
  • vi. Power Quality Test as per IEC 61400-21
  • vii. Anti-islanding Protection test
  • viii. Test of the facility to withstand a step load change

DC 4.12.3.2 Power Quality

After satisfactory testing and pre-commissioning of the DGS and submission of the Certificate of Installation, the Distribution Licensee with assistance of the System Operator shall perform tests to ensure that the DGS is compliant with the Power Quality requirements set forth in Section DC 4.11 of this Distribution Code.

DC 4.12.4 Certification

DC 4.12.4.1 Certificate of Installation

An Installer (for SSDG and MSDG 1) or Registered Professional Engineer (for MSDG 2 and MSDG 3 of Registered Capacity up to 4MW) or Independent Engineer (for MSDG 3 of Registered Capacity above 4MW), as the case may be, shall inspect and test the installation for compliance with existing requirements and standards and report the results to the Distribution Licensee.
The Distributed Generator shall then submit to the Distribution Licensee a Certificate of Installation duly filled and signed by the Installer, Registered Professional Engineer or the Independent Engineer as the case may be.

DC 4.12.4.2 Certificate of Compliance of MSDG 1, MSDG 2 and MSDG 3

In case of compliance of an MSDG 1, MSDG 2, and MSDG 3 to the requirements of the Distribution Code after performing the tests in DC 4.12.3.2, the Distribution Licensee shall then issue a Certificate of Compliance to the Distributed Generator confirming that the installation:
  • a) complies with the requirements of this Distribution Code, and
  • b) has been found to be fit for connection to the Distribution System.

DC 4.13 Standby Generating Units

Parallel Operation with the Distribution System shall not be permitted for Standby Generating Units unless there is a specific agreement with the System Operator or Distribution Licensee for Parallel Operation. If the System Operator authorizes or requires the Parallel Operation of a Stand-by Generating Unit with the Distribution System, the Stand-by Generating Unit shall comply with all the requirements for Distributed Generators set forth in the Distribution Code and other relevant parts of the National Grid Code. Customers with Stand-by Generating Units shall ensure that any part of the installation supplied by the Stand-by Generating Unit has first been disconnected from the Distribution System and remains disconnected while the Stand-by Generating Unit is connected to the User’s System. Methods of changeover and interlocking shall meet these requirements. Warning signs must be affixed at the LV and MV poles, pillars, transformers where a Standby Generating Unit is connected.\n
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DC 4.14 Compliance with the Distribution Code

In case of non-compliance with any of the technical provisions of this Distribution Code, the Distribution Licensee shall inform the Distributed Generator in writing of the discrepancies.
The Distributed Generator shall have the following times to rectify the discrepancies:
  • 1. 60 days for SSDG
  • 2. 90 days for MSDG 1, MSDG 2 and MSDG 3
Failing to do that, the Distribution Licensee shall be entitled to disconnect the Distributed Generator. The Distribution Licensee shall be entitled to disconnect the DGS without prior notification if the installation conditions are harmful or creates unavoidable risks for the safety.
The Distribution Licensee shall not be responsible for any damage if such disconnection requires the disconnection of other loads associated or connected to the same connection as the DGS. Reconnection of the DGS shall require that the Distribution Licensee certifies that the installation complies with this Distribution Code.

DC 4.15 Additional Requirements for MSDG 2 and MSDG 3

The requirements of DC 4.15 shall be met by all MSDG 2 and MSDG 3.

DC 4.15.1 Uninterruptible Power Supply

The Distributed Generating Station shall have a secured AC auxiliary source of supply protected by surge and lightning devices. An online uninterruptible power supply (UPS) is required and it shall have adequate capacity to ensure that the protection, measurement, control and communication systems operate without interruption for a minimum duration of at least 3 hours after loss of Distribution System power supply.
The Distributed Generator shall submit the calculations in the determination of the sizing of the UPS. In the event of loss of the secured auxiliary supply, all the Distributed Generator's 22 kV Circuit Breakers shall be tripped until remedial actions are taken.
The UPS system shall be installed on the Distributed Generator side and be maintained accordingly by the Distributed Generator. The UPS shall be equipped with a bypass switch/system that shall allow continuous operation during maintenance on the UPS.
In Distributed Generating Stations of Registered Capacity equal to or greater than 1 MW, all Equipment used for the transmission of signals and commands (PLC, modem, router, etc.) between the Distributed Generating Stations and the Distribution Licensee's control system shall be supplied from a separate UPS than the one stated in the previous paragraph. All associated requirements shall also be applicable to this separate UPS.

DC 4.15.2 Indication, Alarms and Instrumentation

The alarm and trip facilities on DGS side of the Interconnection Boundary shall have local indication and, for DGS with Registered Capacity equal to or greater than 1 MW, an additional set of potential-free contacts for onward transmission of the alarm/trip signals to the Distribution System Substation.
The following panel instrumentation and other fittings are required in addition to other standard Equipment required or implied for the type of panel and scheme functionality:
  • a. Transducer fed voltmeter, ammeter, MW, MVAr, indicating import and export, and appropriate test blocks for current and voltage circuits.
  • b. Suitable test facilities shall be provided for the secondary injection of current/relay testing and for any other tests as reasonably required by the Distribution Licensee.
External indicator lamps, for DGS of Registered Capacity greater than 200kW, shall be installed to indicate parallel operation of the DGS with Distribution System. A lighted red lamp shall indicate Parallel Operation while a lighted green lamp shall indicate isolated operation.
All required equipment for the above shall be procured, installed, tested, commissioned and maintained by the Distributed Generator.

DC 4.15.3 Generation Schedule

DGS connected to the MV system with Registered Capacity greater than 2 MW shall submit a Distributed Generation forecast to the Distribution Licensee and the System Operator. This forecast shall be in accordance to the requirements of section SOC 4.2.4 of the System Operations Code.
This requirement can be withdrawn/redefined if so agreed between the System Operator and the Distributed Generator in each particular case.

DC 4.15.4 Preventive and corrective maintenance

The provisions of DC 4.15.4 apply to DGS with Registered Capacity greater than 1 MW.

DC 4.15.4.1 Generator Maintenance

A DGS with Registered Capacity greater than 1 MW connected to the MV network shall submit its preventive maintenance plan to the System Operator for its approval every year for the following year, in the dates required by the System Operator and any modification thereof as per the requirements established in section SOC 4.3 of the System Operations Code.

DC 4.15.4.2 Network maintenance

The Distribution Licensee shall communicate its maintenance plans to the System Operator and the DGSs connected to the MV network on the same terms that apply to all Users of the Distribution System.
The Distribution Licensee shall communicate its maintenance plans by mail, or any other agreed channel, to DGs connected to the MV network at least one week before the planned maintenance action takes place.
Maintenance works or any faults occurring on the feeder to which the MSDG is connected may prevent the Distributed Generator from exporting. No compensation shall apply for any loss of generation due to preventive and corrective maintenance in the Distribution System network.

DC 4.15.5 Distributed Generating Station Performance Requirements

DC 4.15.5.1 Fault Ride Through Requirements

The DGS shall remain connected to the Distribution System for System voltage dips on any or all phases, where the Distribution System voltage measured at the Point of Delivery remains above the blue line in the voltage duration profile in Figure 1 for Synchronous and Asynchronous Generating Stations, and above the blue line in the voltage duration profile in Figure 2 for Power Park Stations.
In addition to remaining connected to the Distribution System, the DGS shall have the technical capability to provide the following:
  • a. During a Distribution System voltage dip, the DGS shall provide Active Power in proportion to retained voltage and maximise reactive current to the Distribution System, within the technological and design limitations of the DGS and without exceeding its design limits. The maximisation of reactive current shall continue until the Distribution System voltage recovers within the range for Normal Conditions.
  • b. A different LVRT curve for the DGS may be required by when duly justified by the Distribution Licensee to ensure the System reliability and security. In such case, the LVRT curve shall be coordinated with the settings of the Under-Voltage Relays in Table 3 to ensure grid support during fault conditions.

DC 4.15.5.2 Frequency Response

In case of frequency deviations in the Distribution System, the DGS shall be designed to be capable to provide power-frequency response in order to contribute to the stabilization of the frequency.
A DGS of Registered Capacity greater or equal to 1 MW shall be able to provide a frequency response as displayed in Figure 3 below. The Distributed Generating Units of a DGS, excluding Electricity Storage Units, shall be able to provide at least the Active Power output response to frequency changes displayed in Figure 3.
Figure 3: Frequency response requirements for MSDG 2 and MSDG 3.
When System Frequency is above 50.5 Hz, a DGS shall reduce its power output as per Figure 3 and the output power is only allowed to increase again as soon as the frequency is back at 50.5Hz or below.
All DGSs shall disconnect within 0.5 seconds from the System in case the System's frequency is above 52Hz or below 47Hz, according to the Protection settings specified in Section DC 4.8.6.

DC 4.15.5.3 Reactive Power Control

A DGS of Registered Capacity equal to or greater than 1 MW shall be equipped with Reactive Power control functions capable of controlling the Reactive Power supplied by the DGS at the Interconnection Boundary.
The Reactive Power control functions shall be mutually exclusive, which means that only one of the two functions mentioned below can be activated at a time:
  • a) Power Factor Control
  • b) Reactive Power Control
If required by the Distribution Licensee on a case by case basis, a voltage control mode may also be required. The operating modes and the operating set point shall be determined by the Distribution Licensee and shall not be changed by the Distributed Generator unless instructed by the Distribution Licensee.

DC 4.15.5.4 Ramp Rate Limits

A DGS of Registered Capacity equal to or greater than 1 MW shall have a maximum ramp rate (up and down) equal to the DGS Registered Capacity (MW) divided by 5 for 1-minute ramps under Normal Conditions.
The limit for positive ramps only applies during start-up and for negative ramps only apply during shut down of the DGS. The ramp rate settings shall be approved by the System Operator prior to testing and commissioning of the system on the network.
For any subsequent change, a minimum of two weeks' notice shall be given. Implementation by the Distributed Generator shall be done within two weeks of formal request and approved by the Distribution Licensee.

DC 4.16 Installer

A DGS shall be installed by an Installer in accordance with the instructions issued by the manufacturer.
In designing a connection for a DGS, the Installer must consider at least the following aspects:
  • a. the maximum demand (and the Distributed Generating Unit output);
  • b. the type of Earthing arrangement;
  • c. the nature of the supply;
  • d. external influences;
  • e. compatibility, maintainability and accessibility;
  • f. Protection against electric shock;
  • g. Protection against thermal effects;
  • h. Protection against overcurrent;
  • i. isolation and switching;
  • j. selection and installation issues.
The Installer must affix a label clearly indicating the next scheduled maintenance of the installations and inform the Distribution Licensee, who shall add the information to a DGS register.
The Installer must be skilled in the field of DGS Electrical Facilities and possess an approved certificate.

DC 4.17 Communication Requirements for MSDG 2 and MSDG 3

DC 4.17.1 Communication system setup

An MSDG 2 with Registered Capacity greater than or equal to 1 MW or MSDG 3 shall install communication Equipment for secured transfer of operating data and Protection and control signals via:
  • a. Fibre optics cable as per DG INTERCONNECTION REQUIREMENTS for DGS of Registered Capacity equal to or greater than 1 MW.
  • b. 4G/LTE (using VPN) or Microwave link or any other communication system acceptable to the System Operator as back-up communication channel for DGS of Registered Capacity equal to or greater than 1MW;
In those cases where the installation of fibre optic cable is not feasible or advisable because of high risk of damaging cane fire below the cable and there is no alternative routing for the fibre optic cable at a reasonable cost, the communication can be based only on the 4G/LTE (using VPN) and Microwave link, subject to approval by the Distribution Licensee for each particular case.
The Distributed Generator shall bear the cost for the installation of the communication system from the DGS to the corresponding Substation and shall install, test, commission and maintain the system (this includes equipment in the Distribution System side of the Interconnection Boundary and in the corresponding 66 kV-to-22 kV Substation).
At the 66kV-to-22kV substation, the Distributed Generator shall install a cabin, with access from outside the Substation boundary, to install its communication equipment. The cabin shall be termite proof and cross ventilated.
A LV supply (230 V ± 6%) shall be provided by the Distribution Licensee in the 66 kV-to-22 kV Substation subsequent to application for supply and payment of relevant fees by the Distributed Generator. However, given that this LV supply may be subject to unavoidable voltage disturbances and variations, the Distributed Generator shall ensure that all appropriate measures have been catered on his side for the protection of his communication system which may be sensitive to such power quality issues.
In addition, the Distributed Generator shall be responsible for the maintenance of the communication equipment at the Distribution Licensee Substation. The Distribution Licensee's liability shall be up to the LV supply and shall not bear any liability for damage in the Distributed Generator's communication Equipment.
Relevant information for the operation of the System shall be transmitted in real time to the System Control Centre through the RTU (remote terminal unit) available at the Distribution System Substation.

DC 4.17.2 Communication Equipment

The Distributed Generator shall install a communication Equipment having the following features: i. One-way communication from the Transmission Substation (66kV-to-22kV Substation) to the DGS of 22kV Circuit Breaker status (open/close); ii. One–way communication from the DGS to the Transmission System Substation (66kV-to-22kV Substation) of: a. Interconnection, transformer and generator Circuit Breakers Status (open/close) b. Alarms (list of warnings/alarms shall be determined at discussion stage with the Distribution Licensee): 1. Protection Operated 2. Protection relay not healthy 3. SF6 Alarm (if available) 4. UPS Alarms 5. Door Alarm (Switchgear room door on CEB side) 6. Inter-tripping signal 7. Remote/Local signal (Circuit Breaker CEB (CB1)) 8. Other Alarms (grouped) c. MW, MVAr (at the Point of Delivery) d. Voltage level of the DGS 22kV busbar (any line-to-line voltage) e. Current (at the Point of Delivery) (any phase current) iii. Remote control Equipment shall be provided only for DGS with Registered Capacity 1MW and above: a. Load Break Switch OPEN CTRL command for each incomer (if available). b. Load Break Switch CLOSE CTRL command for each incomer (if available). c. Distribution Licensee Circuit Breaker (CB1 in DC 21.4.2) OPEN CTRL command. d. Distribution Licensee Circuit Breaker (CB1 in DC 21.4.2) CLOSE CTRL command. iv. Optical Fibre The Optical fibre shall connect the DGS and the 22kV feeder’s Substation on which the DGS is Interconnected. The Distributed Generator shall bear the cost of the procurement, installation and commissioning of the fibre optic link. v. Wireless Communications Where wireless communications are used, either as main or backup communication channel or as replacement of the fibre optic channel wherever authorized, it shall comply with any requirements approved by the Distribution Licensee and in particular with the following minimum characteristics: a. Use the latest 3G/4G/LTE or newer communication technologies for the bands of frequency used in the Republic of Mauritius; b. Use Microwave link as main channel and the latest 3G/4G/LTE as backup channel. Should any of the channel fail, switching to the other channel shall be seamless. In addition, SLA of 4 hours (Service Level Agreement) between the Distributed Generator and the Service Provider shall be applicable on the communication equipment to cater for their failure and link loss. The Distributed Generator shall provide a copy of the SLA to the Distribution Licensee. c. Alternatively, communication equipment/Gateway/Router having dual SIM slot capability and using latest 3G/4G/LTE can be used. This shall allow to remove carrier dependency and swapping network operators seamlessly if the primary run into trouble. SLA of 4 hours (Service Level Agreement) between the Distributed Generator and the Service Provider shall be applicable on the communication equipment to cater for their failure and link loss. The Distributed Generator shall provide a copy of the SLA to the Distribution Licensee. d. Furthermore, all channels using 3G/4G/LTE technology shall deployed and configured in VPN tunnel mode (virtual private network) for increased end-to-end security. e. Be equipped with at least two routers, each capable of accommodating two SIM cards from different network operators and automatic switching between operators in case of unsuccessful transmission. The two routers shall be set up as one main and one hot standby router. This setup shall ensure redundancy both at the level of equipment and Service Provider. f. Be capable of transmitting data at a rate of at least 85 kbps downloading and 42 kbps uploading. g. Have a configuration interface protected by password; h. Be capable of using VPN tunnels using, at least, technology Open VPN; and i. Be equipped with support auto recovery mechanism.

DC 5 DISTRIBUTION SYSTEM INTERCONNECTION

DC 5.1 Introduction

This section of the Distribution Code specifies the normal method of interconnection to the Distribution System and the minimum technical, design and operational criteria which must be complied with by any User or prospective User. For the purpose of this section of the Distribution Code, User refers to both Distributed Generators and Customers connected to the Distribution System. In addition, details specific to each User’s interconnection may be set out in a separate IA, ESPA, CA or PPA. The interconnection conditions set out in these agreements are complementary to this Distribution Code. All interconnection costs and responsibility shall normally be borne by the User connected to the Distribution System unless otherwise specified by an IA, ESPA, CA or PPA or policy or as dictated by the Authority.

DC 5.2 Objective

The objective of this section of the Distribution Code is to ensure that by specifying minimum technical, design and operational criteria the basic rules for interconnection to the Distribution System shall enable the Licensee in its capacity as the Distribution Licensee to comply with its statutory and License obligations.

DC 5.3 Scope

DC 5 Applies to the following: a. Distribution Licensee at the Interconnection Boundaries; b. Customers directly connected to the Distribution System, and c. Distributed Generators.

DC 5.4 Method of Interconnection

DC 5.4.1 Interconnections at Low Voltage

For Low Voltage interconnections, supply shall be provided at: a. single phase 230 V; or b. three phase 400 V The information required for Low Voltage interconnections shall be a minimum of: a. Customer name, address and contact details; b. Location of proposed interconnection; c. Type of interconnection (Residential, Commercial, Industrial and others); d. Capacity required (if not known then type of use appliances etc.); e. Identification of any large motors or welders. The interconnection shall be made to an appropriate Interconnection Boundary on the User premises.

DC 5.4.2 Interconnection at Medium Voltage

The following information, (as applicable) shall be supplied by the User to the Distribution Licensee for interconnections at Medium Voltage, prior to the first energization of a User system: a. Updated 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 Protection and control single line diagrams; c. Copies of all Safety Rules and Local Safety Procedures applicable at Users’ Sites which shall be used at the interface between the System Operator and the User; d. Information to enable the Distribution Licensee to prepare Site Responsibility Schedules according to the provisions set out in DC 21.1; e. An Operation Diagram for all MV Apparatus on the User side of the Interconnection Boundary; f. The proposed name of the User Site (which shall not be the same as, or confusingly similar to, the name of any Licensee Site or of any other User Site); g. A list of Safety Coordinators; h. 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 authorized to make binding decisions on behalf of the User; i. A list of managers who have been duly authorized to sign Site Responsibility Schedules on behalf of the User; and j. Information to enable System Operator to prepare the Site Common Drawings.

DC 5.5 Interconnection of Distributed Generators

Generator Interconnections to the Distribution System shall comply with the relevant requirements of the Generation Code and Section DC 4 of the Distribution Code. The operator of a Distributed Generating Station shall operate and maintain the Distributed Generating Units in such a manner so as not to adversely affect the Distribution System and other Users, including but not limited to adverse effects voltage level or voltage waveform, power factor and frequency or produce adverse levels of voltage flicker and/or Harmonic Distortion.

DC 6 POWER QUALITY STANDARDS

DC 6.1 General provisions

All Users connected to the Distribution System shall maintain the voltage waveform quality at the Interconnection Boundary within the limits specified in this section.

DC 6.2 Harmonic Voltage and Current Distortion

DC 6.2.1 Harmonic Voltage Distortion

The Distribution Licensee shall limit line-to-neutral voltage harmonics below the values recommended in the IEEE Standard 519 for the Interconnection Boundaries of all Users, and summarized in Table 4. Table 4: Voltage distortion limits for the Distribution System as per IEEE Std. 519-2014. All values in Table 4 should be in percent of the rated power frequency voltage at the Interconnection Boundary.

DC 6.2.2 Harmonic Current Distortion

Users connected to the Distribution System shall ensure that their harmonic current emissions at the Interconnection Boundary do not exceed the limits recommended in the IEEE Standard 519. The harmonic currents at the Interconnection Boundary of Users of the Distribution System should comply with IEEE Std. 519-2014 for the lowest ratio of the short-circuit current available at the Interconnection Boundary, to the maximum fundamental load current. The key requirements of this clause are summarized below: (a) The Total Harmonic Current Distortion (THD) or Total Demand Distortion (TDD) shall be less than 5% of the fundamental frequency current at rated current output. (b) Each individual harmonic shall be limited to the percentages listed in which are expressed in percentage of the fundamental frequency current at rated current output. (c) Even harmonics in these ranges shall be <25% of the odd harmonic limits listed. Table 5: Current distortion limits for the Distribution System as per IEEE Std. 519-2014.

DC 6.3 Voltage Fluctuations

DC 6.3.1 Voltage Flicker

Users shall take responsibility for limiting voltage flicker caused by their Electrical Facilities to remain within the maximum values at the Interconnection Boundary specified in the IEC TR 61000-3-7 for Users connected at Medium Voltage, and in parts 3 and 11 of IEC TR 61000-3 for Users connected at Low Voltage.

DC 6.3.2 Voltage Changes

Users shall ensure that the disturbance levels introduced by their Electrical Facilities do not promote voltage changes at the Interconnection Boundary above the following values under Normal Conditions: a) Voltage fluctuation limit for step changes which may occur repetitively should not exceed ± 1% around the nominal voltage under Normal Conditions b) Voltage Fluctuation limit for occasional fluctuations other than step changes and infrequent planned switching events or outages should not exceed ±3% around the nominal voltage. c) Voltage step changes caused by the connection to and disconnection from the Distribution System of a Distributed Generating Station or a Customer shall not exceed ±6% for unplanned outages such as Faults. Where induction generators are used in a Distributed Generating Station, as in fixed speed wind turbines, they shall be fitted with soft starters to limit inrush currents to a maximum of 110 % the normal rated current. This reduces the magnitude of the step voltage changes which occur on starting.

DC 6.4 Phase Unbalance

The weekly 95 percentile of Phase (Voltage) Unbalance, calculated in accordance with IEC61000-4-30 and IEC61000-3-13, on the Distribution System shall be less than or equal to 1.3% unless abnormal conditions prevail. The Phase Unbalance is calculated from the ratio of root mean square (rms) of negative phase sequence voltage to rms of positive phase sequence voltage, based on 10-minute average values, in accordance with IEC 61000-4-30.

DC 6.5 Exceptional Conditions

DC 6.5.1 Limitation of DC Injection

A Customer or Distributed Generator should not inject a DC current greater than the 0.25 % of the rated AC output current per phase. A Customer or Distributed Generator connected to the LV Distribution System should not inject a DC current greater than the largest value of 20 mA and 0.25% of the rated AC output current per phase.

DC 6.5.2 Voltage and Current Unbalance

The total voltage unbalance in the Grid shall be smaller than 2%, where the unbalance, Uunbalance, is defined as the maximum deviation from the average of the three-phase voltages, Ua, Ub and Uc, divided by average of the three-phase voltages. = max{,,}−(,,) × 100%. (,,) The contribution to the level of unbalance of the voltage at the Interconnection Boundary of a Distributed Generating Station shall be less than or equal to 1.3 %. When considering three phase units, the contribution to the voltage unbalance can be described as or where .

DC 7 ELECTRICAL FACILITIES RELATED TO INTERCONNECTION SITES

DC 7.1 General Requirements

All Electrical Facilities related to the Users/Licensee at the Interconnection Boundary, shall be compliant with the requirements in DC 7 and its subsections.

DC 7.2 Substation Electrical Facilities

All circuit breakers, switch disconnectors, earthing devices, power transformers, voltage transformers, reactors, current transformers, surge arresters, bushings, neutral equipment, capacitors, line traps, coupling devices, external insulation and insulation co-ordination at the User/Licensee Interconnection Site shall be constructed, installed and tested in accordance with the technical standards specified by the Distribution Licensee, and Prudent Utility Practice. Plant and Apparatus shall be designed, manufactured and tested in premises certified in accordance with the quality assurance requirements of ISO 9001 or equivalent.

DC 7.3 Interconnection Boundaries

DC 7.3.1 Low Voltage and Medium Voltage Users Interconnection Boundaries

For LV and MV supplies, the Distribution Licensee’s responsibility extends up to the User's Interconnection Boundary which is normally: a) In major LV and MV installations (CT/PT connected): at the main fuses or Circuit Breaker of the Distribution Licensee. b) In LV premises (single and three phase direct-connected supply): at the outgoing terminals of the Distribution Licensee’s Meter. The Distribution Licensee shall develop an Installation Manual for LV customers. This manual shall comply with the requirements of the Distribution Grid Code and shall be approved by the Authority.

DC 7.3.2 Generator Interconnection Boundaries

The requirements for the design of Interconnection Boundaries between the Distributed Generators and the System Operator are set out in Section DC 4..

DC 7.3.3 Interconnection Boundaries to Transmission System

The Distribution System interconnection to the Transmission System shall comply with the relevant provisions of the Transmission Code.

DC 7.4 Protection Requirements

All Protection Systems and settings shall be in accordance with the Distribution Licensee Protection Policy. The Protection Systems to be applied to Distributed Generating Units shall also comply with DC 4.8 and DC 4.9. 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. The Distribution Licensee shall be solely responsible for the Protection of the Distribution System. Users and Distributed Generators shall be solely responsible for the protection of the User Systems on their side of the Interconnection Boundary. Users shall design their Protection System to ensure that no other User shall be affected for faults on their Plant and Apparatus. 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. The Distribution Licensee and/or 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 System. Where as part of the IA, ESPA, CA or PPA, a User is required to provide Demand disconnection as part of the System Operators’ under frequency management process that includes the automatic disconnection of Demand then the relays shall comply with the Technical Requirements for Under Frequency Relays set forth in the Transmission Code.

DC 8 SITE RELATED CONDITIONS

DC 8.1 General

Responsibility for construction, commissioning, control, operation and maintenance responsibilities for the Electrical Facilities shall be according to the ownership of each facility, unless an agreement between the Parties specifies differently.

DC 8.2 Responsibilities for Safety

The Distribution Licensee and all the Distribution System Users shall comply with the relevant Electricity Regulations. Before interconnection to the Distribution System at the MV level the Distribution Licensee 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 Interconnection Boundary as specified in the Safety Coordination section SOC 15 of the System Operations Code.

DC 8.3 Site Responsibility Schedules

In order to inform site operational staff and the System Operator’s System Control Engineers of agreed responsibilities for Plant and/or Apparatus at the Interconnection Site at the MV level, a Site Responsibility Schedule shall be produced for System Operator and Users with whom they interface. The format, principles and basic procedure to be used in the preparation of Site Responsibility Schedules are set down in DC 21.1. These documents shall be included in the IA, ESPA, CA or PPA.

DC 8.4 Diagrams and Drawings

DC 8.4.1 Project Drawings

Project Drawings of a Distributed Generator shall be reviewed by an Installer for SSDG and MSDG 1 and Registered Professional Engineer for MSDG 2 or MSDG 3 with Registered Capacity up to 4MW and Independent Engineer for MSDG 3 with Registered Capacity above 4MW., while Project Drawings of other Users shall be reviewed directly by the Distribution Licensee and the System Operator. In respect of User’s obligations relating to the drawings of a Project, the following shall apply: (a) The User shall prepare and submit, with reasonable promptness and in such sequence as is consistent with the Project Completion Schedule set forth in the IA, ESPA, CA or PPA, 3 (three) copies each of all drawings to the Installer, Registered Professional Engineer Independent Engineer or Distribution Licensee and System Operator, as the case may be, for review; (b) By submitting the drawings for review to the Installer, Registered Professional Engineer , Independent Engineer or Distribution Licensee and System Operator, as the case may be, the User shall be deemed to have represented that it has determined and verified that the design and engineering, including field construction criteria related thereto, are in conformity with the National Grid Code and IA, ESPA, CA or PPA; (c) Within 15 (fifteen) days of the receipt of the Project Drawings, the Installer, Registered Professional Engineer Independent Engineer or Distribution Licensee and System Operator, as the case may be, shall review the User’s Drawings and convey its observations to the User with particular reference to their conformity or otherwise with the Distribution Code and IA, ESPA, CA or PPA. The User shall not be obliged to await the observations of the Installer, Registered Professional Engineer Independent Engineer or Distribution Licensee and System Operator, as the case may be, on the drawings submitted pursuant hereto beyond the said 15 (fifteen) days period and may begin construction works at its own discretion and risk; (d) If the aforesaid observations of the Installer, Registered Professional Engineer, Independent Engineer or Distribution Licensee and System Operator, as the case may be, indicate that the drawings are not in conformity with the Distribution Code and IA, ESPA, CA or PPA, such Drawings shall be revised by the User and resubmitted to the Installer, Registered Professional Engineer Independent Engineer or Distribution Licensee and System Operator, as the case may be, for review. The Installer, Registered Professional Engineer, Independent Engineer or Distribution Licensee and System Operator, as the case may be, shall give its observations, if any, within 7 (seven) days of receipt of the revised drawings; (e) No review and/or observation of the Installer, Registered Professional Engineer, Independent Engineer or Distribution Licensee and System Operator, as the case may be, and/or its failure to review and/or convey its observations on any drawings shall relieve User of its obligations and liabilities under the Distribution Code in any manner nor shall the Installer, Registered Professional Engineer, Independent Engineer or Distribution Licensee and System Operator, as the case may be, be liable for the same in any manner; (f) Without prejudice to the foregoing provisions of this Section DC 8.4.1, the User shall submit to the Distribution Licensee and System Operator for review and comments, its Project drawings relating to the User Interconnection Electrical Facilities, Protection and control Apparatus and the Distribution Electrical Facilities, and the Distribution Licensee and System Operator shall have the right but not the obligation to undertake such review and provide its comments, if any, within 30 (thirty) days of the receipt of such drawings. The provisions of this Section DC 8.4.1 shall apply mutatis mutandis to the review and comments hereunder; and (g) Within 90 (ninety) days of the Commercial Operation Date, the User shall furnish to the Distribution Licensee and System Operator a complete set of as-built drawings, in 2 (two) hard copies and electronic version in pdf format or in such other medium as may be acceptable to the Distribution Licensee and System Operator, reflecting the User’s as Plant and Apparatus actually designed, engineered and constructed, including an as-built survey illustrating the layout of the Plant and setback lines, if any, of the buildings and structures forming part of the Project Assets.

DC 8.4.2 Operation Diagrams

An Operation Diagram shall be prepared by the User for each Interconnection Site at which an Interconnection Boundary exists in accordance with DC 21.2. 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 Section DC 15.. The nomenclature used shall conform to that used on the relevant Interconnection Site and circuit. 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 8.4.2.1 Validity of Operation Diagrams

The composite Operation Diagram prepared by the User shall be the definitive Operation Diagram for all operational and planning activities associated with the Interconnection Site. If a dispute arises as to the accuracy of the composite Operation Diagram, a meeting shall be held at the Interconnection Site, as soon as reasonably practicable, between System Operator and the User, to endeavour to resolve the matters in dispute.

DC 8.4.3 Site Common Drawings

DC 8.4.3.1 General
Site Common Drawings shall be prepared for each Interconnection Site and shall include Interconnection Site layout drawings, electrical layout drawings, common protection/control drawings and common services drawings. The User shall prepare and submit to the Distribution Licensee Site Common Drawings for the User side of the Interconnection Boundary. The Distribution Licensee shall then prepare, produce and distribute, using the information submitted by the User, Site Common Drawings for the complete Interconnection Site. The System Operator shall receive a copy of the finalized Site Common Drawings for the Interconnection Site.
DC 8.4.3.2 Changes to Site Common Drawings
When the Distribution Licensee or a User becomes aware that it is necessary to change any aspect of the Site Common Drawings at an Interconnection Site it shall notify the other Party and amend the Common Site Drawings in accordance with the procedure set out in sub-section DC 8.4.3.
DC 8.4.3.3 Validity of Site Common Drawings
The Site Common Drawings for the complete Interconnection Site prepared by the Distribution Licensee, shall be the definitive Site Common Drawings for all operational and planning activities associated with the Interconnection 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 Distribution Licensee and the User, to endeavour to resolve the matters in dispute.

DC 8.4.4 Distribution System Drawings

The Distribution Licensee shall produce schematic drawings of the whole Distribution System. It shall be the responsibility of the Distribution Licensee to ensure that all its drawings and schematics are up to date e. Active Power Demand (W) OUT; f. Active Power Demand (W) IN; g. Reactive Power Demand (VAR) First Quadrant; h. Reactive Power Demand (VAR) Fourth Quadrant.; and i. Total Harmonic Distortion All units shall be expressed at appropriate multiples determined by the maximum expected Demand.

DC 8.5 Access

The provisions relating to access to Distribution Licensee Sites by Users, and to User Sites by the System Operator or Distribution Licensee shall be set out in each IA, ESPA, CA or PPA with the System Operator and each User. Access shall be subject to the approval and conditions of the System Operator, Distribution Licensee or User. Request shall be detailed and made 3 business days in advance for the System Operator, Distribution Licensee or User to make necessary arrangements.

DC 9 COMMUNICATIONS AND CONTROL

For the purpose of this section, the term User refers to Distributed Generators and Customers connected to the MV Distribution System. 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. Control telephony is the method by which a User’s and System Operator’s Operations Engineers or delegated representatives speak to one another for the purposes of control of the Distribution System in both normal and emergency situations. At any Interconnection Boundary 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 to the specification of the System Operator. Details of the control telephony required shall be set out in the IA, ESPA, CA or PPA. The System Operator shall provide a SCADA outstation interface Equipment. The User shall provide 4-20 mA signals of voltage, current, frequency, Active Power and Reactive Power measurement outputs and Plant Circuit Breaker positions and alarms to the System Operator SCADA outstation interface Equipment as required by the System Operator. The manner in which information is required to be presented to the outstation Equipment is set out in Section DC 21.3 (DC APPENDIX C: SCADA INTERFACING). Power supply for the communication on the Distribution Licensee side of the Interconnection Boundary shall be metered and billed based on the applicable tariff.

DC 10 TESTING AND MONITORING

DC 10.1 Introduction

To ensure that the Distribution System is operated efficiently and within the License conditions and to meet statutory actions, the Distribution Licensee with the support of the System Operator shall organize and carry out testing and/or monitoring of the effect of Users’ Electrical Facilities on the Distribution System. The testing and/or monitoring procedures shall be developed to demonstrate compliance to all applicable requirements specified in this Distribution Code and any other applicable code or standard approved by the Authority, as applicable. More extensive Special System Tests are outlined in Section DC 16.

DC 10.2 Objective

The objective of DC 10 is to specify the requirement to test and/or monitor the Distribution System to ensure that Users are not operating outside the technical parameters required by the Distribution Code and other relevant parts of the National Grid Code.

DC 10.3 Procedure related to quality of supply

The System Operator shall from time to time determine the need to test and/or monitor the quality of supply at various points of the Distribution System. The requirement for specific testing and/or monitoring may be initiated by the receipt of complaints as to the quality of supply on the Distribution System. In certain situations, the System Operator may require the testing and/or monitoring to take place at the Point of Delivery of a User from the Distribution System. Where testing and/or monitoring is required at the Interconnection Boundary, the System Operator shall advise the involved User and shall make available the results of such tests to the User. These tests shall be performed by the System Operator at the System Operator’s cost. Where the results of such tests show that the User is operating outside the technical parameters specified in the Distribution Code or other relevant part of the National Grid Code, the User shall be informed accordingly. Where the User requests the System Operator to perform a retest, the retest shall be carried out at the User’s cost and witnessed by a User representative. A User shown to be operating outside the limits specified in the Distribution Code or other relevant part of the National Grid Code shall rectify the situation or disconnect the Apparatus causing the problem from its Electrical Facilities connected to the Distribution System immediately or within such time as is agreed with the System Operator. Continued failure to rectify the situation may result in the User being disconnected from the Distribution System either as a breach of the Distribution Code, other relevant part of the National Grid Code or other statutory requirement, where appropriate. The User may conduct test(s) on the User’s side of the Interconnection Boundary at the User’s cost; however, the System Operator shall be notified prior to such test(s).

DC 10.4 Procedure Related to Interconnection Boundary Parameters

The System Operator from time to time shall monitor the effect of the User on the Distribution System. The monitoring shall normally be related to the amount of Active Power and Reactive Power transferred across the Interconnection Boundary. Where the User is exporting to or importing Active Power and Reactive Power from the Distribution System in excess of the levels set forth in the IA, ESPA, CA or PPA the System Operator shall inform the User and where appropriate demonstrate the results of such monitoring. The User may request technical information on the method of monitoring and, if necessary, request another method reasonably acceptable to the System Operator. Where the User requires Active Power and Reactive Power in excess of the physical capacity of the Interconnection Boundary, the User shall restrict power transfers to those specified in the IA, ESPA, CA or PPA until a modified IA, ESPA, CA or PPA has been applied and physically established. All costs to increase the physical capacity of the Interconnection Boundary shall be the responsibility of the User.

DC 11 DEMAND CONTROL (DISTRIBUTION SYSTEM USERS)

DC 11.1 Introduction

The System Operator shall establish the requirements for the Users and Customers of the Distribution System, in certain circumstances, to permit reductions in total Demand in the event of insufficient Generation being available to meet total Demand or to avoid disconnection of Customers and Users or in the event of breakdown and/or overloading on any part of the Transmission and/or Distribution Systems. The Demand Control procedures ensure that hardship to Users and Customers is minimized and that in so far as is practicable, all parties affected are treated equitably. The System Operator and Users shall comply with the requirements established in section SOC 9 of the System Operations Code.

DC 12 OPERATIONAL COMMUNICATION

DC 12.1 Objective

The System Operator and Users shall exchange information so that the implications of an Operation and/or Incident can be considered and the possible risks arising from them can be assessed and appropriate actions taken by the relevant parties in order to maintain the integrity of the Total System and the Users’ Plant and Apparatus. For the purposed of this section, Users mean the Distribution Licensee and any user connected to the Distribution System. The System Operator and Users shall comply with the requirements established in section SOC 11 of the System Operations Code.

DC 13 MAINTENANCE STANDARDS

All Plant and Apparatus on the System 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 employees or the public. The System Operator shall establish a Distribution System Maintenance Policy which shall be reviewed and approved by the Authority. The Distribution Licensee shall coordinate with the System Operator the scheduled maintenance of MV facilities in the Distribution System. The System Operator, the Distribution Licensee and any User connected to the Distribution System shall comply with the requirements established in section SOC 12 of the System Operations Code.

DC 14 SWITCHING INSTRUCTIONS FOR MEDIUM VOLTAGE EQUIPMENT

Medium Voltage switching shall only be carried out with the permission of the System Control Engineer or its designated representatives except under System Emergency. Persons required to carry out Medium Voltage switching must be specifically certified and authorized by the System Operator to carry out such switching. The System Operator shall comply with the requirements and procedures in section SOC 7 of the System Operation Code.

DC 15 NUMBERING AND NOMENCLATURE

DC 15.1 Introduction

This section sets out the responsibilities and procedures for notifying the relevant owners of the numbering and nomenclature of Apparatus at Interconnection Boundaries. The numbering and nomenclature of Apparatus shall be included in the Operation Diagram prepared for each Interconnection Site.

DC 15.2 Objectives

The prime objective embodied in section DC 15 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 15.3 Procedure

DC 15.3.1 New Apparatus

When the System Operator or a User intends to install Apparatus on an Interconnection Site, the proposed numbering and/or nomenclature to be adopted for the Apparatus must be notified by the System Operator to the User or User to the System Operator as the case may be. 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 at least three months prior to the proposed installation of the Apparatus. The System Operator or User as the case may be 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 User, the System Operator, acting reasonably, shall have the right to determine the numbering and nomenclature to be applied at that site.

DC 15.3.2 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 Interconnection Sites. 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 Interconnection Boundary.

DC 15.3.3 Changes to existing Apparatus

Where the Distribution Licensee or a User needs or wishes to change the existing numbering and/or nomenclature of any of its Apparatus on any Interconnection Site, the provisions of DC 15 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 15, that party shall be responsible for the provision and erection of clear and unambiguous labelling.

DC 16 SPECIAL SYSTEM TESTS

DC 16.1 Introduction

This section of the Distribution Code sets out the responsibilities and procedures for arranging and carrying out Special System Tests which have or may have an effect on the 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. If the Special System Test proposed by the System Operator, Distribution Licensee or the User connected to the Distribution System shall or may have an Operational Effect on the Transmission System then the provisions of the Transmission Code shall apply. Special System Tests which have a minimal Operational Effect on the Distribution System or Systems of other Users shall not be subject to this procedure. Minimal Operational Effect shall be taken to mean variations in voltage, frequency and waveform distortion of a value not greater than the figures defined in the Planning and Interconnection sections of the Distribution Code. The Distribution Licensee with the support of the System Operator shall organize and carry out the Special System Tests.

DC 16.2 Objective

The objectives of section DC 16 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 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 Distribution System and Users; and b. set out procedures to be followed for establishing and reporting Special System Tests.

DC 16.3 Procedure

DC 16.3.1 Proposal Notice

When a User intends to undertake a Special System Test which shall have or may have an Operational Effect on the System or other User’s Systems, notice shall be provided one (1) month in advance of the proposed System Test, or as otherwise agreed by the Distribution Licensee, by the person proposing the System Test (the Test Proposer) to the Distribution Licensee and to those Users who may be affected by such a System Test. When the Distribution Licensee intends to undertake a Special System Test which shall have or may have an Operational Effect on the System or other User’s Systems, notice shall be provided one (1) month in advance of the proposed System Test to the Transmission Licensee, or as otherwise agreed, 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, the recipient shall contact the Test Proposer with a written request for further information which shall be supplied as soon as reasonably practicable. The recipient of the proposal notice shall not be required to do anything under DC 16 until it is satisfied with the details supplied in the proposal or pursuant to a request for further information.

DC 16.3.2 Preliminary Notice and Establishment of Test Committee

The System Operator shall have overall co-ordination of the System Test, using the information supplied to it under Section DC 16 and shall identify in its reasonable estimation, which Users other than the Test Proposer, may be affected by the proposed System Test.

DC 16.3.3 Test Committee

A Test Coordinator, who shall be a suitably qualified person, shall be appointed by the System Operator and shall act as chairman of the Test Committee. The Distribution Licensee shall convene a Test Committee, for a Special System Test. The number of Test Committee members shall be kept to the minimum number of persons compatible with affected User representation. The System Operator, the Distribution Licensee, the Test Proposer and all directly affected Users shall be represented in the Test Committee. All Users identified under DC 16 shall be given in writing, by the Test Coordinator, a preliminary notice of the proposed System Test. The preliminary notice shall contain: a. 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 Distribution Licensee; b. an invitation to the identified Users to nominate a suitably qualified person to be a member of the Test Committee 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 Coordinator of the composition of the Test Committee. A meeting of the Test Committee shall take place as soon as possible after the relevant Users and the Test Proposer have been notified of the composition of the Test Committee. The Test Committee 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; c. 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 d. implications of the proposed System Test on the scheduling and dispatch of Generating Stations, insofar as it is able to do so. Users identified under section DC 16 and the System Operator, whether or not they are represented on the Test Committee, shall supply the Test Committee upon written request the information the Test Committee reasonably requires in order to consider the proposed System Test. The Test Committee shall be convened by the Test Coordinator when it is necessary to conduct its business, subject to the oversight of the Distribution Licensee in coordination with the System Operator.

DC 16.3.4 Proposal report

Within two months of its first meeting, the Test Committee shall produce a report, which in DC 16 is 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 the costs that cannot be determined in advance of the test) to the Parties involved in the test, the general principle being that the Test Proposer shall bear the costs; and c. such other matters as the Test Committee consider appropriate. The proposal report may include requirements for possible indemnities to be given in respect of claims and losses that may arise from the System Test. All System Test procedures must comply with all applicable legislation. If the Test Committee is unable to agree unanimously on any decision in preparing its proposal report, the proposed System Test shall not take place and the Test Committee shall be dissolved.

DC 16.3.5 Final Test Program

If the 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 Committee shall submit to the Distribution Licensee, System Operator and all recipients of the proposal notice a program which in this section DC 16 shall be called a final test program 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 Committee deem appropriate. The final test program shall bind all recipients to act in accordance with the provisions contained in the program 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 program and prior to the day of the proposed System Test must be notified to the System Operator as soon as possible in writing If the System Operator decides that these anticipated problems merit an amendment to or postponement of the System Test the System Operator 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 System Operator of this decision and the reasons for it. The System Operator 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 the System Operator cannot reach such agreement, shall reconvene the Test Committee as soon as practicable which shall endeavour to arrange another suitable time and date and the relevant provisions of DC 16 shall apply.

DC 16.3.6 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 Committee. 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 Committee unless the Test Committee having considered the confidentiality issues, shall have unanimously approved such distribution. When the final report has been submitted the Test Committee shall be dissolved.

DC 17 DISTRIBUTION METERING

DC 17.1 Purpose and Introduction

This section of the Distribution Code sets out the way in which power and energy flows shall be measured at an operational Interface. This section of the Distribution Code: a. Establishes the requirements for metering the Active and Reactive Energy and Demand input to and/or output from the Distribution System; b. Sets out appropriate procedures for metering reading; and c. Ensures that procedures are in place to manage disputed readings. The Distribution Licensee shall be responsible for the procurement, installation, maintenance, calibration, and testing of meters and metering systems. The Meter Laboratory will provide support to the Distribution Licensee in the calibration and testing of meters and metering systems. The Distribution Licensee shall be responsible for meter reading, billing, collection and customer claims. The Distribution Licensee shall develop detailed metering specifications compliant with the requirements of the Distribution Grid Code

DC 17.2 Scope

This sub-section applies to: a. the Distribution Licensee b. Users c. Distributed Generators

DC 17.3 Metering Requirements Distributed Generators

DC 17.3.1 Overall Accuracy

The required overall accuracy (maximum allowed values) of Distributed Generator metering is to be designed according to the following categories: a. SSDG: 2.0% b. MSDG-1: 2.0% c. MSDG-2: 1.5% d. MSDG-3: 0.5% Existing installations may allow less stringent requirements according to already signed Connection Agreement, ESPA or PPA.

DC 17.3.2 Relevant Metering Policies, Standards, Specifications and Accuracy

Sample testing of meters must be done and certified by CEB Meter Laboratory. The requirements in Table 6 shall apply to all metering systems installed in Distributed Generation facilities. Table 6: Distributed Generation Metering Requirements Instrument transformers shall conform to the standard IEC 61869. The detailed use of these standards in the testing of meters are set out in the document “Meter Testing Protocol for the Electricity Sector in Mauritius” The precise position of the meters shall be set out in the corresponding Connection Agreement, IA, ESPA or PPA between the Single Buyer and the Distributed Generator For MSDG 3 installations, the Distribution Licensee shall inspect the Main Meter, Back-Up Meter and Secondary Meters (as applicable according to Table 6) upon installation and at least once every year thereafter, and shall also check the certification of these meters through an accuracy test at least once every 4 (four) years thereafter or at any time the kWh readings of these meters and the Distributed Generator Back-Up Meter (if applicable) differ by an amount greater than 0.5%. For MSDG 3 installations, the Distributed Generator shall inspect the Distributed Generator Back-Up Meter (as applicable according to Table 6 both upon installation and at least once every year thereafter, and shall also check the certification of these meters through an accuracy test at least once every 4 (four) years thereafter or at any time the kWh readings of this meter and the Distribution Licensee’s meters differ by an amount greater than 0.5%.

DC 17.3.3 Parameters for Meter Reading

The Distributed Generator and the Distribution Licensee shall provide and install appropriate Metering System (according to Table 6) that shall make a continuous recording on appropriate magnetic media or equivalent of the Net Energy Output of the Distributed Generation Facility as well as the production of the Gross Energy Output of the Distributed Generator. The parameters to be metered shall be subject to the Connection Agreement, IA, ESPA or PPA between the Distributed Generator and the Single Buyer, shall be stored cumulatively on the meter, shall be accessible to the Distributed Generator and may consist of but are not limited to any or all of the following parameters: a. Active Energy (Wh) OUT; b. Active Energy (Wh) IN; c. Reactive Energy (VARh) First Quadrant; d. Reactive Energy (VARh) Fourth Quadrant; e. Active Power Demand (W) OUT; f. Active Power Demand (W) IN; g. Reactive Power Demand (VAR) First Quadrant; h. Reactive Power Demand (VAR) Fourth Quadrant.; and i. Total Harmonic Distortion All units shall be expressed at appropriate multiples determined by the maximum expected Demand.

DC 17.3.4 Frequency of Meter Reading

The Demand Interval shall be thirty (30) minutes, or otherwise mentioned in the ESPA, CA, IA or PPA 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 17.3.5 Metering Responsibility (Distributed Generators)

It is the responsibility of Distributed Generators to cooperate with the Distribution Licensee and the Single Buyer in the execution of all its responsibilities under this Code. The costs for installation and replacement of meters shall be outlined in the Connection Agreement, ESPA or PPA.

DC 17.4 Metering Requirements - Users

DC 17.4.1 Overall Accuracy

The overall accuracy of the electromechanically-based metering systems 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 and shall measure the electrical energy delivered to the User from the Distribution System. For whole current meters (single phase supply) the overall accuracy will be ± 1%. For CT connected meters, the overall accuracy will be as follows: a) for LV connected meters: ± 1.5%, and b) for MV connected meters: ± 1%.

DC 17.4.2 Relevant Metering Policies, Standards and Specifications

The meters, and associated installations, used on the Distribution Licensee’s Distribution System shall comply with the following documents: - Meter Testing Protocol for the Electricity Sector in Mauritius â€" document to be developed by URA; - Other applicable policies, engineering instructions and procedures. The meters shall be designed, constructed and operated to comply with the latest revision of the relevant IEC 62053 or international equivalent.

DC 17.4.3 Requirement for Metering

All Interconnection Boundaries to the Distribution System shall have appropriate metering in accordance with this Code.

DC 17.4.4 Metering Responsibility

It is the responsibility of the Distribution Licensee and the Single Buyer to ensure that all Point of Deliveries are metered in accordance with this Code. It is the responsibility of Users to cooperate with the Single Buyer and Distribution Licensee in the execution of all its responsibilities under this Code. The costs for installation and replacement of meters shall be outlined in the IA, ESPA, CA or PPA.

DC 17.5 Metering Equipment - Users

DC 17.5.1 Revenue Meters

The revenue meter shall have the appropriate rating for the interconnection requirements to be supplied and shall conform to the terms of the IA, ESPA, CA or PPA between the Distribution Licensee and the User. User revenue meters shall have an accuracy class 2 or better. At the System Operator’s or Distribution Licensee’s, discretion Advanced Metering Infrastructure may be installed at some Customers sites. This metering infrastructure enables two-way communication with the Metering Systems. The relevant metered parameters, as required by the Distribution Licensee for billing purposes, shall be stored cumulatively on the meter Where required these parameters may include any or all of the following depending on the interconnection and the tariff schedule: a. kW Hours (delivered and received); b. kVAR Hours (delivered and received); c. kVA Hours (delivered and received); d. Maximum Demand (30-minute period or otherwise mentioned in the ESPA, IA, CA or PPA) e. Power Factor The above parameters shall be measurable over intervals from 1 minute to 60 minutes.

DC 17.5.2 Voltage and Current Transformers

For MV connections, all Voltage and Current Transformers shall comply with IEC Standards or their equivalents and shall have an accuracy class 0.5 or better as the case may be. For LV connections, all Voltage and Current Transformers shall comply with IEC Standards or their equivalents and shall have an accuracy class 1.0 or better as the case may be. The burden in each phase of Voltage and Current Transformers shall not exceed the specified burden of the said Transformers.

DC 17.6 Point of Delivery (metering points)

DC 17.6.1 Whole Current Metering

For whole current meters (meters where the electrical current passes through the meter itself), the Point of Delivery should be as close as possible to the Interconnection Boundary.

DC 17.6.2 CT Metering

The Point of Delivery shall be at the position of the Current Transformers (CT) used for the metering System. This should be designed to be as close as possible to the Interconnection Boundary. 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 concrete enclosures unless otherwise agreed with the Distribution Licensee, and be able to be secured. Where the Interconnection Boundary is declared on the outgoing side of a high voltage circuit breaker the metering transformers may be accommodated in that circuit breaker unit. Where appropriate the Metering Point should be at the same voltage as the Interconnection Boundary. Where the Point of Delivery is at a lower voltage than the Interconnection Boundary then appropriate loss factors should be calculated to ensure any additional loss is appropriately accounted for.

DC 17.7 Meter Reading and Collection Systems

DC 17.7.1 Meter Reading and Recording Responsibility

It is the responsibility of the Single buyer to ensure that meters are read in accordance with the requirements of overall standard set out in its License. Meter reading and recording shall be undertaken by a suitable authorized representative of the Single Buyer. It is the responsibility of Users and Distributed Generators to cooperate with the Single Buyer in the execution of its responsibilities under this Code. The User shall be provided with electronic access to its billing and consumption records on request as per the policy of the Single Buyer.

DC 17.7.2 Approval of Meters

Only meters that have received pattern approval from the Mauritius Bureau of Standards (MSB) in accordance with “Electricity Meter Testing in Mauritius - Protocol on Administrative and Testing Proceduresâ€, may be used on the Distribution System, unless indicated otherwise by the Authority.

DC 17.8 Calibration and Sealing

DC 17.8.1 Calibration

All meters should be calibrated at the factory to ensure they comply with published accuracy specifications. The Meter Laboratory will only perform calibration of electro-mechanical meters and accuracy test for electronic meters. Calibration of electronic meters (if required) will be done only at the factory. Electronic meters should be certified by the manufacturer for a guaranteed calibration period over the operational life of the meter. However, in case that a meter experiences an accuracy drift over time due to environmental or other unknown factors, it shall be sent back to the factory for re-calibration and certification. In case a meter has exceeded the guaranteed calibration period given by the manufacturer, it should be sent for accuracy test as soon as practical. In case the accuracy test is not within standard limits, the meter shall be sent for calibration. All laboratory calibration shall be undertaken in laboratories accredited by the Mauritius Accreditation Service (MAURITAS), unless indicated otherwise by the Authority,

DC 17.8.2 Traceability

The kilowatt hour standard used to calibrate electricity meters shall be traceable to a recognized national or international standard.

DC 17.8.3 Sealing

All meters shall be constructed to enable the meter unit to be sealed to prevent unauthorized access or interference with the Operation of the meter or the input terminals of the meter. Seals applied on a meter after calibration shall be marked with the date of recalibration and serial number.

DC 17.9 Metering Disputes

DC 17.9.1 Meter Inaccuracy

If the Metering System is found to be inaccurate by more than the allowable error (as indicated in DC 17.3.1 and DC 17.4.1) and the Single Buyer and the Distributed Generator/User fail to agree upon an estimate for the correct reading within a reasonable time (as specified in the relevant IA, ESPA, CA, PPA ) of the dispute being raised, then the matter may be referred for arbitration by either party in accordance with the relevant specified agreements.

DC 17.9.2 Meter Accuracy Check

A User/Distributed 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 for the Electricity Sector in Mauritius†User/Distributed has to request for an installation of a check meter when they consider that the meter may be reading incorrectly in accordance with the “Meter Testing Protocol for the Electricity Sector in Mauritius†If after adequate period, there is any discrepancy noted between the check meter reading and meter reading, then a User/Distributed Generator has a right to request a meter accuracy check. Should a User/Distributed Generator requests more than one accuracy check in a single calendar year, then the Single Buyer may charge for these additional checks should the accuracy be within ± 2%

DC 17.10 Inspection and Testing

DC 17.10.1 Maintenance Policy

The Distribution Licensee 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 sections DC 17.3.2 and DC 17.4.2.

DC 17.10.2 Maintenance Records

The Distribution Licensee shall keep all test results, maintenance program records and sealing records for a period of at least 5 years.

DC 17.10.3 Generator Metering

The Distribution Licensee and the Distributed Generator shall abide by the conditions of the Distribution Code that details the maintenance procedures to be applied in the case of Distributed Generator meters. The Distribution Code includes provisions on the use of back-up meters when metering inaccuracies are suspected and on the resolution of metering disputes.

DC 18 REQUIREMENTS FOR THE DISTRIBUTION SYSTEM OF RODRIGUES

This section establishes the minimum requirements to ensure an efficient, coordinated and economic development system for electricity distribution in Rodrigues. The Distribution Licensee and the Users of the Distribution System of Rodrigues, including Distributed Generators and Customers shall comply with the requirements laid down in the Distribution Code, except for the sections specified in

DC 18.1 Exemptions from the Distribution Code

a. DC 3.2.2 (Planning Criteria) b. SOC 9.4a (methods of Demand Control â€" System Operations Code)

DC 18.2 Rodrigues Distribution System Planning

DC 18.2.1 Planning criteria

The electric system of the outer island of Rodrigues is a small system comprising a few generators (combustion engines and also renewable energy). Electricity is distributed to the users of the island using a 22 kV system of feeders. In general, the system of Rodrigues shall comply with the requirements of the Distribution Code, however due to its small size and its isolation with the main system in the island of Mauritius, a few exceptions are identified in this section of the Distribution Code for its application to the Rodrigues’ system.

DC 18.2.2 Planning criteria

The Distribution Licensee shall adopt the following criteria to perform the Distribution System planning in Rodrigues: a) Ensure feeders’ and power transformers’ loading under Normal Conditions is limited to 100% nominal rating. b) A margin of at least 10 % of the System Demand shall be maintained for the Spinning Reserve. c) In the event of a Generating Unit Outage, the remaining available Generating Units shall be able to satisfy the System Demand.

DC 18.2.3 Frequency Criteria

The System Operator shall maintain the System frequency in Rodrigues under Normal Conditions within the limit of 50 Hz ± 0.75 Hz. In case of Generation Outage, the System Operator in Rodrigues may resort to the Demand control methods to contain the Frequency outlined in SOC 9.4 and DC 18.4.

DC 18.3 Security of Supply

The System Operator shall use reasonable endeavours to supply from the System all Customers connected to it. This cannot be ensured at all times, since faults, planned Maintenance and new works outages and other circumstances outside System Operator control can cause interruptions. On such occasions, the System Operator shall use reasonable endeavours to restore the supply or connection as soon as practicable but shall be under no liability for any direct or indirect damage or associated loss incurred by the User.

DC 18.4 Demand Control

DC 18.4.1 Shedding of Demand by Automatic Under-Frequency Relays

The System Operator shall use automatic Demand shedding by Under Frequency Relays to address short-term imbalances between the Total System Generation and Demand, following the tripping of Generation beyond the Spinning Reserve value. The Demand of the System which is subject to automatic disconnection by Under Frequency Relays shall be split into discrete MW blocks. The number, location, size and the associated low frequency settings of these blocks shall be determined by the System Operator through dedicated electrical studies to be approved by the Authority. A load shedding table specifying the pre-selected feeders to disconnect at each level shall be computed considering the most stringent conditions, including the tripping of a large Generating Unit at peak time and at minimum load conditions. After 2 activations of the Under-Frequency Relays, if feasible, the feeders on the first 2 levels shall be swapped with the feeders on the lower levels so as not to penalize the same Customers each time.

DC 18.5 Frequency response requirement for MSDG 2 and MSDG 3

MSDG 2 and MSDG 3 in Rodrigues shall comply with the following frequency response requirements: a) Each Generating Station, including Synchronous and Power Park Stations, must be capable of contributing to frequency control by continuous regulation of the Active Power supplied to the System. b) Each Generating Unit or Power Park Station must be fitted with a fast-acting proportional frequency control device (or Governor Control System) and Generating Unit load controller or equivalent control device to provide frequency response under Normal and Contingency Conditions. In the case of a Power Park Station the frequency or speed control device(s) may be on the Power Park Station or on each individual Power Park Generating Unit or be a combination of both. c) The frequency control device (or Governor Control System) in co-ordination with other control devices must control the Generating Unit or Power Park Station Active Power output with stability over the entire operating range of the Generating Unit or Power Park Station. d) The frequency control device (or Governor Control System) must meet the following minimum requirements: i. Where a Generating Unit or Power Park Station becomes isolated from the rest of the Total System but is still supplying Customers, the frequency control device (or Governor Control System) must also be able to control System frequency below 52 Hz unless this causes the Generating Unit or Power Park Station to operate below its Designed Minimum Operating Level when it is possible that it may trip after a time. For the avoidance of doubt the Generating Unit, or Power Park Station is only required to operate within the System frequency range 47 - 52 Hz. ii. The frequency control device (or Governor Control System) must be capable of being set so that it operates with an overall Governor Droop between 4% and 8% for other units. For the avoidance of doubt, in the case of a Power Park Station the Governor Droop shall be applied to each Power Park Generating Unit in service. iii. In the case of all Generating Units or Power Park Station the frequency control device (or Governor Control System) Dead Band should be no greater than 0.05 Hz (for the avoidance of doubt, ±0.025 Hz).

DC 19 DISTRIBUTION DATA REGISTRATION

DC 19.1 Objective

The objective DC 19 is to: a. List all the data to be provided by the Users to the System Operator and Single Buyer under the Distribution Code; b. List all data to be provided by the System Operator and/or Single Buyer to the Users under the Distribution Code; and c. List all data to be provided by Distributed Generators to the System Operator and Single Buyer and by the System Operator and/or Single Buyer to Distributed Generators under the terms of the Distribution Code.

DC 19.2 Scope

The Parties to which the provisions of DC 19 apply are: a. Distributed Generators; b. Distribution Licensee and c. Users connected directly to the Distribution System.

DC 19.3 Data Categories and Stages in Registration

DC 19.3.1 General

Within the Data Registration Requirements each item of data is allocated to three categories. a. System Planning Data as required by the Planning and Interconnection section of the Distribution Code; b. Generation Planning Data as required by the Generation Code; c. Operational Data as required by the System Operator and including the data required from Generators in accordance with the System Operations Code and the Scheduling and Dispatch provisions of the Generation Code.

DC 19.4 Procedures and Responsibilities

DC 19.4.1 Responsibility for Submission and Updating of Data

In accordance with the provisions of the Distribution Code, each User must submit the data summarized in the DC 20. For the purpose of this section, the User refers both to Customers and Distributed Generators, unless otherwise specified.

DC 19.4.2 Methods of Submitting Data

The data must be submitted to the Distribution Licensee, which shall thereafter be shared with the Single Buyer and System Operator. The name of the person at the User who is submitting each schedule of data must be included. The data may be submitted via a computer link if such a data link exists between a User and the Distribution Licensee or utilizing a data transfer media, such as USB drive, CD ROM, cloud technology, etc. after obtaining the prior written consent from the Distribution Licensee.

DC 19.4.3 Changes to Users Data

The User must notify the Distribution Licensee of any change to data which is already submitted and registered with the Distribution Licensee in accordance with each section of the Distribution Code. The Single Buyer and the System Operator shall be informed of any change in User’s data.

DC 19.4.4 Data not supplied

If a User fails to supply data when required by any section of the Distribution Code, the Distribution Licensee shall estimate in collaboration with the System Operator and/or Single Buyer, if required, such data if and when, in the view of the Distribution Licensee, it is necessary to do so. If the Distribution Licensee fails to supply data when required by any section 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. Such estimates shall, in each case be based upon data supplied previously for the same Electrical Facilities or upon corresponding data for similar Electrical Facilities or upon such other information as the Distribution Licensee or Single Buyer or System Operator or that User, as the case may be, deems appropriate. The Distribution Licensee shall advise a User in writing of any estimated data it intends to use relating directly to that User Electrical Facilities in the event of data not being supplied. The User shall advise the Distribution Licensee in writing of any estimated data it intends to use in the event of data not being supplied.

DC 20 DATA SCHEDULES

DC 20.1 User System Data Schedule

DC 20.2 Fault Infeed Data Schedule

The following information is required from each User who is connected to the Distribution System via an Interconnection Boundary where the User System contains Distributed Generating Unit(s) and/or motor loads.

DC 21 APPENDICES

DC 21.1 DC Appendix A: Site Responsibility Schedules

DC 21.1.1 ATTACHMENT TO APPENDIX A: PRO FORMA FOR SITE RESPONSIBILITY SCHEDULE

COMPANY: INTERCONNECTION SITE: Signed on behalf of the System Operator Date ... Signed on behalf of the User.

DC 21.2 DC APPENDIX B: PROCEDURES RELATING TO OPERATION DIAGRAMS

DC 21.2.1 Basic Principles

Where practicable, all the MV Apparatus on any Interconnection 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 Interconnection Site. 1. Where more than one Operation Diagram is unavoidable, duplication of identical information on more than one Operation Diagram must be avoided. 2. The Operation Diagram must show accurately the current status of the Apparatus, e.g. whether commissioned or decommissioned. Where decommissioned, the associated switch bay shall be labelled "spare bay". 3. 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 Operation Diagrams 1. Bus bars 2. Circuit Breakers 3. Disconnector (Isolator) and Switch Disconnectors (Switching Isolators) 4. Disconnectors (Isolators) - Automatic Facilities 5. Bypass Facilities 6. Earthing Switches 7. Maintenance Earths 8. Overhead Line Entries 9. Overhead Line Traps 10. Cable and Cable Sealing Ends 11. Distributed Generating Unit 12. Distributed Generator Transformers 13. Distributed Generating Unit Step Up Transformers, Station Transformers, including the lower voltage circuit-breakers 14. Synchronous Compensators 15. Static VAR Compensators 16. Capacitors (including Harmonic Filters) 17. Series or Shunt Reactors 18. System Transformers 19. Tertiary Windings 20. Earthing and Auxiliary Transformers 21. Three Phase VTs 22. Single Phase VT & Phase Identity 23. High Accuracy VT and Phase Identity 24. Surge Arrestors/Diverters 25. Neutral Earthing Arrangements on MV Plant 26. Arc Suppression Coils 27. Current Transformers (where separate Plant items) 28. Wall Bushings 29. Standby Generators and Automatic Change-over Switch

DC 21.2.2 Use of Approved Graphical Symbols

All graphical symbols to be used in Operation Diagrams shall be approved by the System Operator.

DC 21.3 DC APPENDIX C: SCADA INTERFACING

DC 21.3.1 General requirements

In all cases signals shall be arranged such that the level of electrical interference does not exceed those defined in IEC 60870-2-1: "Telecontrol Equipment and Systems - Operating Conditions â€" Power Supply and Electromagnetic Compatibility" and IEC60870-3: "Telecontrol Equipment and Systems - Specification for Interfaces (Electrical Characteristics)".
DC 21.3.1.1 Digital Inputs
Digital inputs cover both single and double points for connection to digital input modules on the Distribution Licensee’s outstation Equipment. The Equipment contacts shall be free of potential, whereas the input circuitry of the outstation is common to the negative 48-volt potential.
DC 21.3.1.2 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.
DC 21.3.1.3 Double Points
Double points are used to indicate primary Plant states by the use of complementary inputs for each 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.
DC 21.3.1.4 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.
DC 21.3.1.5 Analogue Inputs
Analogue inputs for connection to analogue input modules on the Distribution Licensee’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 Distribution Licensee) for both unidirectional and bi-directional measured values. Signal converters shall be provided as necessary to produce the correct input signals.
DC 21.3.1.6 Command Outputs
All command outputs for connection to command output modules on the Distribution Licensee’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.

DC 21.4 DC Appendix E: Typical interconnection diagrams

DC 21.4.1 Typical MSDG 1 interconnection layout

DC 21.4.2 Typical Medium Voltage Switchgear Panel and Protection Guideline for MSDG 2 and MSDG3

Notes: 1. The above schematic diagrams refer to typical installations. The actual Protection and inter-tripping requirements may vary depending on the particular setup of the Generating Station under consideration. 2. The Distributed Generator is responsible for providing the appropriate Protection for its transformer and internal loads. 3. The inter-trip between Distribution System substation and the Distributed Generating Station is required for Generating Stations of Registered Capacity greater than 1 MW. 4. In case of synchronous and induction machine-based Generating Units: a. A Dead Bus Live Line (DBLL) relay is required to prevent electrical and remote closure of CB1 on an energised busbar. b. A key Interlock shall be provided between CB1 and all the Generating Station outgoing 22 kV Circuit Breakers. This Interlock shall prevent mechanical closure of CB1 as long as any of the Generating Station outgoing 22 kV Circuit Breakers is closed. c. The onus lies on the Distributed Generator to provide the required Synchronism-Check Relay on Circuit Breakers where there exists the possibility of closing the Generating Unit live on the Distribution System.