TRANSMISSION PLANNING AND SECURITY STANDARDS, POWER SUPPLY PLANNING AND SECURITY STANDARDS, TRANSMISSION OPERATING STANDARDS AND POWER SUPPLY OPERATING STANDARDS   –   2003

SECTION – I

GENERAL

 

1.        INTRODUCTION

 

These standards have been framed with reference to Paragraph 17 of the AP Transmission and Bulk Supply Licence.

2.                  APPLICATION

2.1              The Licensee shall plan and operate its Transmission System and shall plan procurement of electricity  and make the same available to Distribution Licensees and EHT consumers and Generators  in conformity with the standards framed hereunder.

2.2              These standards apply to APTRANSCO as Licensee.  The Licensee plans and operates the Transmission System with the standards as the criteria.  However, for maintaining the Transmission Standards it is essential for all entities whose systems are connected to the Transmission system to maintain certain standards and follow certain procedures in their own systems.  It is to be made obligatory that the Generators and DISCOMs to follow such procedures and maintain such standards by incorporating suitable provisions in the Grid Code,  Power Purchase Agreements and Conditions of Supply and Connection Agreement.  Therefore while these standards apply primarily and directly to the Licensee(APTRANSCO) the corresponding standards apply, although indirectly, to the Generators, DISCOMs and to all either entities whose systems are connected to the APTRANSCO’s system.

 

2.3              Not withstanding anything contained in these standards the Licensee shall not infringe or violate any of the provisions of the Indian Electricity Rules 1956.

 

3.                  DEFINITIONS

 

In these standards, unless the context otherwise requires

 

i)                    “Act” means the AP Electricity Reform Act, 1998.

ii)                  “APERC/Commission” means AP Electricity Regulatory Commission constituted under sub-section (1) of Section 3 of                  AP Electricity Reform Act, 1998.

iii)                 “APTRANSCO” means Transmission Corporation of Andhra Pradesh Limited

iv)                “CBIP” means Central Board of Irrigation and Power.

v)                  “CEA” means Central Electricity Authority.

vi)                “EHT” means Extra High Tension.

vii)               “Generator” means an organisation that generates electricity and who is subject to the Grid Code.

viii)             “Grid Code” means the code prepared by the Licensee in accordance with the terms of Condition 18 of the                   Transmission and Bulk Supply Licence, 2000 and approved by the Commission.

ix)                “Grid Code Review Panel/Panel” means a panel set up under Grid Code.

x)                  “H.T” means High Tension.

xi)                “Licensee” means the holder of the AP Transmission and Bulk Supply Licence, 2000.

xii)               “PGCIL” means Power Grid Corporation of India Ltd.

xiii)             “Rules” means the Indian Electricity Rules,

xiv)             “SREB” means Southern Regional Electricity Board.

xv)              “SRLDC” means Southern Regional Load Despatch Centre.

xvi)              SLDC” means State Load Despatch Centre at Hyderabad.

 

SECTION – 2

 

TRANSMISSION PLANNING AND SECURITY STANDARDS

 

1.                  OBJECTIVE

 

Transmission System planning shall be aimed at the system being capable of delivering power from the generating plants and interconnecting points with the systems of neighbouring States, and PGCIL to the load centres i.e., the outgoing terminals of the E.H.T. grid sub-stations, under established criteria, while operating the power system as an integrated whole.

 

2.                  TRANSMISSION PLANNING

 

2.1              Long Term Transmission Planning shall be originated from Load Forecast and Least Cost Generation Expansion Plan of the Licensee for the period under consideration.  Since, the Licensee’s system operates in synchronism with generators and captive power plants inside the State and SREB system all these elements shall be included in the system modelling.  Any interconnection existing with the neighbouring State in radial mode shall not be included in the modelling.

 

2.2              System Modeling

 

2.2.1        Separate system models shall be developed for each year of a Plan period to assess necessary year of commissioning of particular lines, based on the network, obtaining for the year in question, with the generation and load buses properly located.

 

2.2.2   For modeling purposes, the interconnections with SREB at 400 KV and 220 KV voltage levels and HVDC interconnection with EREB & WREB shall be considered.  An appropriate electrical equivalent shall be used to take into account the fault level at those interconnection points.  Since those Buses will be represented as Generator Buses, generation and respective loads connected at these Buses shall be included in the modelling.  Interconnection with the Eastern Regional Grid and the Western Regional Grid shall be modelled as they exist.

The HVDC terminals could operate both as rectifiers and inverters. HVDC terminal in the rectifier mode should be represented as a load and in the inverter mode, it is should be represented as generator. This aspect also is to be taken into consideration.

 

2.3              System Studies

 

2.3.1          The system shall be evolved based on detailed power system studies

which shall include but not confined to;

i)                    Load Flow Studies

ii)                   Short Circuit Studies

iii)                 Transient Stability Studies

iv)                 Loss of load probability studies (LOLP)

 

2.3.2            Computer Programs

The studies shall be carried out by suitable computer aided programmes.

2.3.3             System Data

        The Licensee shall use updated system data, referred to in Transmission Operating Standards, in carrying out system studies.

2.3.4                Active and Reactive Load allocation

      2.3.4.1                          All loads shall be modelled at 220 KV or 132 KV Buses.  The load for each Load Bus is obtained for any year within Plan period from the Load Forecast and a reasonable estimate of transmission losses shall be made to arrive at peak generation. Procedure adopted for determining  the compounded annual growth rate and base year in case of the peak demand of horizon year can be adopted for deriving the minimum demand of the horizon year.   

        2.3.4.2                          MVAR loading at each Bus shall truly reflect the actual MVAR drawn from the system at that particular location by installing / calibrating suitable measuring instruments.  The average power shall be computed by studying the pattern by installing suitable meters temporarily or any other acceptable method.

2.4           Load and generation Despatches

 

2.4.1  Load  Studies shall be carried out for Peak Load and Minimum Load conditions.

2.4.2   Generation

For peak load conditions two generator despatches shall be used i.e., Maximum Hydro Generation and Maximum Thermal Generation.  For the minimum load the ‘must-run’ generation shall be used in conjunction with the most economical thermal generation.  The generation despatch for purpose of carrying out sensitivity studies corresponding to complete closure of a generating station close to a major load centre shall be worked out by increasing generation at other stations to the extent possible keeping in view the maximum likely availability at those stations, cost of power etc.  Transmission constraints will be brought out and addressed.

2.4.3     Studies shall be repeated for Normal and Contingency conditions as specified under security standards prescribed in the A.P. Grid Code and the Indian Electricity Grid Code.

2.5     Planning Criteria

2.5.1      The Central Electricity Authority (CEA) “Manual on Transmission Planning Criteria” shall be adopted with modification as stated below, particularly with reference to steady state voltage limits and security standards for withstanding outages.

2.5.2    Line Loading Limits

The permissible line loading limits shall conform to CEA’s “Manual on Transmission Planning Criteria”.  The over loading and under loading of lines shall be decided accordingly.

2.5.3                                Options for Strengthening of Transmission Network

 

i)                    Addition of new Transmission lines to avoid over loading of existing system (wherever three or more circuits of the same voltage class are envisaged between two sub-stations, the next higher transmission voltage may be considered).

ii)                   Upgradation of the existing transmission lines such as raising height of conductor supports and or switch over to insulated cross-arms to facilitate change over to higher voltage, if the tower designs so permits.

iii)                 Reconductoring of the existing transmission line with higher size of conductors or with AAAC (All Aluminium Alloy Conductor)

The choice shall be based on cost, reliability, right of way requirements, energy losses, down time, etc.

2.5.4     All single circuit lines shall be planned with double circuit towers, wherever technically feasible, to enable future expansion without right of way problems.

2.5.5         Steady State Voltage Limits

The Licensee shall plan its Transmission System so as to maintain the steady voltage within the limits stated below.

                                                           

3.                  SECURITY STANDARDS

3.1              Steady State Stability

The system shall be planned to supply loads during normal conditions and the following contingency conditions without the need for rescheduling of generation and to maintain voltage and line loading criteria.

Outage of one transmission circuit

Outage of one Interconnecting Transformer or

Outage of one generator.

Outage of  a 400 KV  DC (Double Circuit AC)  line in case of evacuation for a generating station of 1000 MW and above located in a difficult terrain like sea coast susceptible  to yearly cyclones(as per clause 6 of CEA’s manual on Transmission Planning). 

(Prior to such contingency, all elements shall be considered to be in service.

After5 years for adopting CEA/IEGC norms: “ One circuit being already out of service in another corridor” will be adopted).

3.2              Transient Stability

3.2.1                             The system shall be designed to maintain synchronism and system integrity (i.e. a condition wherein all generating units continuously operate in synchronism without tripping and getting separated) under the following disturbances:

a)                  The outage of the single largest unit in the SREB system.  (For this condition the APTRANSCO share of spinning reserve shall be considered as 285  MW being 38 % of one 750 MW unit).(as per load generation balance report of SREB). However this is subject to review on change of system conditions.

b)                 A permanent single line to ground (SLG) fault on a 400 KV transmission circuit, single pole opening of the faulted phase (100 m.sec or 5 cycles) with unsuccessful reclosure (dead time 1 sec.) followed by 3 pole opening (100 m.sec) of the faulted line on a 400 KV transmission circuit (subject to note below).

Note:-  In order to facilitate simulation, a 3 phase fault with 5 cycle duration shall be considered for 400 KV circuit fault.  Should the system survive this fault condition, it shall be assumed that system’s stability is established.  Should the simulation not indicate stability, then the single phase shall be simulated and SLG FAULT CRITERIA shall be applied.

c)                  A permanent three phase fault with a duration of 160 m.sec (8 cycles) on a 220 KV or 132 KV Transmission circuit assuming 3-pole opening.

d)                 No stability studies shall be made for radial lines.

4.                  SUBSTATION PLANNING CRITERIA

4.1              The rated rupturing capacity of the Circuit Breaker in any sub-station shall not be less than 125% of the maximum fault level at that sub-station.  (The 25% margin is intended to take care of the increase in short circuit levels as the system grows).  The standard rated breaking current capacity of switch gear at different voltage levels are as follows:

                  Voltage Level                           Breaking Current (KA)
                                   132  KV                          31.5 KA

220 KV                          40    KA

400 KV                          40    KA

4.2              The capacity at any single sub-station at different voltage levels shall not normally exceed.

                  Voltage Level                             Capacity

400 KV                           1000 MVA

220 KV                            320 MVA

132 KV                           150 MVA

 

4.3              Size and number of Interconnecting Transformers (ICT’s) shall be planned in such a way that the outage of any single unit would not normally over load the remaining Interconnecting transformers. Size and number of EHT/H.T transformers shall be planned in such a way that in the event of outage of any single unit the remaining EHT/H.T Transformers would still supply 80% of the load.

4.4              Further, Local Breaker Backup (LBB) protection is to be provided for all 220 KV and 400 KV feeders.

4.5            Reactive Power Compensation

4.5.1                Shunt Capacitors

Reactive compensation shall be provided as far as possible in 132 KV   systems with a view to meet the reactive power requirement of load close to the load points.  In the planning study the shunt capacitors required shall be shown at 132/220 KV Buses.

4.5.2                                Shunt Reactors

Switchable shunt reactors shall be provided at 400 KV sub-stations for controlling voltages within the limits specified.  The step changes shall not cause a voltage variation exceeding 5%.  Suitable Line Reactors (Switchable/Fixed) shall be provided to enable charging of 400 KV lines without exceeding voltage limits specified.

 

SECTION – 3

POWER SUPPLY PLANNING AND SECURITY STANDARDS

1.                  OBJECTIVE

Power Supply Planning is to aim at a least cost planning to serve the demand at a specified level of reliability.

2.                  POWER SUPPLY PLANNING

Long term power supply planning shall be made based on Load Forecasts prepared pursuant to condition 17.12 of the AP Transmission and Bulk Supply Licence.  The Licensee shall abide by conditions of GRIDCODE in formulating its long term load forecasts.  The planning process shall take into account the existing contracted generation capacity, allocation from Central Sector Generation in the base year and evolve the net additional requirement of power over the years during the plan period.  The planning process shall also consider an extended study period of ten years beyond the base period of ten years to smoothen out the “End Effects” due to different types of generation capacity at the end of the base period. While evolving the planning process the capacity addition programmed shall be at the Strategic locations in the Grid subject to system requirement and constraints like fuel availability, load center and evacuation facilities.

3.                  PLANNING CRITERIA

3.1              Peaking Availability

The peaking availability of existing Hydro Electricity Plants and thermal Plants/Private/Joint Venture plants shall be in accordance with data furnished by the respective Generating Companies and also as per Power Purchase Agreements made with respective power stations.  Availability from Central Sector Plants shall be taken as allocated by the Government of India.  For the  new plants, peak availability shall be as per Central Electricity Authority norms.

3.2              Plant Availability

The following outage rates for plants other than Central Sector plant shall be used in the simulation studies.

 [Note: For Central Sector Plants, norms of SREB/CEA shall be adopted]

3.3              Auxiliary Consumption

Auxiliary consumption in plants for the purpose of planning studies shall be as follows:

3.4              Economic Parameters

3.4.1                Reference Year for Costs

The cost estimate shall reflect economic conditions as on 1^st April of the Base Year.  The cost shall increase over time at the rate of general inflation and shall exclude taxes and duties in so far as they are common in the economic evaluation.

3.4.2.               Reference Year for Present Value Analysis

Discounting for calculating cumulative present value cost for each scheme shall be done at an annual rate of 10%.

3.4.3.                              Plant Economic Life

The economic life of Generating plants may be assumed as follows for the planning studies in accordance with Govt. of India notification dt.27.3.1994 made under sub paragraph (a) of Paragraph VI of the VI schedule to the Electricity (Supply) Act, 1948, from time to time.

Plant Type      Life (Years)

Hydro Electric     35

Thermal             25

Gas Turbine       15

3.4.4                                Cost of Unserved Energy

Value of unserved energy (i.e. the loss to the economy if a KWH of energy required by consumers cannot be supplied) shall be considered in the economic analysis for the least cost generation expansion plan.  Suitable pricing for such power outage costs shall be adopted from available studies applicable to AP.

3.5                                      Evaluation of Planning Studies

3.5.1                                Suitable computer aided programmes shall be adopted to arrive at a least cost generation expansion plan.

3.5.2                                The economic evaluation shall be carried out in accordance with the guidelines enumerated below:

i)                    Set out different generation expansion scenario incorporating mixed hydro/thermal expansion, only thermal expansion, mixed base/peak generation expansion, in the context of demand forecast.

           

ii)                   For each scenario, determine through simulation, the timing of new installations during the planning period in order to meet the security standards.

iii)                 Simulate the system operation in order to obtain the average annual energy production from each hydro electric plant and each thermal plant.

iv)                 Compute the cumulative present value cost for the scenario over the planning period incorporating capital costs for new generation and associated transmission, fixed and variable operation and maintenance costs, fuel costs and unserved energy costs.

v)                  Compare the present value cost of each scenario with that of the other to arrive at the least cost scenario.

vi)                 Calculate the Long Run Marginal Cost for the least cost scenario as follows:

(a)                For each year of the plan period determine incremental cost of generation, energy requirement, energy generated, unserved energy, incremental net energy generated, loss of load probability in hours, Unserved Energy %

(b)               Reduce the incremental cost of generation to the Net Present Value.

(c)                Long Run marginal cost in Rs./KWH is:

            Total net present value of incremental cost of generation (Rs.)

=            ---------------------------------------------------------------------------

                           Incremental net energy generation (KWH)

4.            POWER SUPPLY SECURITY STANDARDS

To ensure that the generation reserve is sufficient so that the system can meet the load, even if one or more units are out of service for scheduled maintenance or in the event of non-availability of adequate hydro-electric generation capacity during the dry period, adequate reserve capacity shall be built into the system both for capacity and energy.

4.1              Capacity Reserve Criteria.

Loss of Load Probability (LOLP) of 1% and 0.15% unreserved energy as per CEA standards shall be used for planning models.  This shall mean that for 1% of the year (i.e. upto 3.65 days/year) the power system may experience shortages of generating capacity.

4.2              A contingency reserve margin equal to 5% of the system peak load shall be planned to take care of fluctuations in the availability of Hydro Electric generation during the critical period of February to June of a dry-year, and to account for outages of units, power station equipment, non-availability of Central Sector share in order to maintain security and integrity of the system.

4.3       Energy Reserve Criteria.

“Energy Not reserved” shall be limited to 0.15% of the average annual energy.

SECTION – 4

TRANSMISSION OPERATING STANDARDS

1.                  OBJECTIVE

 

1.1              These standards shall serve as guidelines for the Licensee to operate its Transmission System for providing an efficient, coordinated and economical system of electricity transmission.

2.                  DATA MANAGEMENT

2.1              The Licensee shall acquire, store and manage following data relating to its Transmission System and generating Units of Generators.

i)                    Line data

ii)                  Transformer data including Generation Transformers

iii)                 Bus data including that of Generating Stations

iv)                Generator data (inclusive of Captive Power Plant)

v)                  Demand data for each EHT sub-station

vi)                Real Time Data

vii)               Schedule maintenance plan of generating units.

2.2              Details of data shall be as specified in Annexure – 1.

3.                  LOAD DESPATCH

3.1              The Licensee shall establish a State Load Despatch Centre and run it round the clock for the purposes of

i)                    Daily Generation Scheduling and issuing despatch instructions.

ii)                  Monitoring line MW and MVAR drawals, EHT Bus voltages, Frequency.

iii)                 Monitoring Generation out-put.

iv)                Coordinating restoration process after total or partial blackouts in the Transmission System or Regional System.

4.                  COMMUNICATION

4.1              The Licensee shall establish reliable and efficient point to point voice and data communication links between SLDC, SRLDC, Generating Stations and EHT sub-stations.

4.2              All operational communications/instructions transmitted by SLDC or transmitted to SLDC shall be recorded as evidence of the communications/instructions.

5.                  OUTAGE PLANNING

5.1              The Licensee shall ensure that its plan for outage of circuits/Transformers required for maintenance, construction, modification, diversion etc. does not violate the security standards of transmission system.

a)                 following loss of the largest in-feed, and

b)                 for the loss of Transmission elements such as a single circuit, a cable, an ICT or a DC line, there shall be

i)                    no loss of supply and

ii)                  no part of the transmission system operating out of synchronism (note that these are probably the same as the Planning Standards but may be relaxed, depending on actual circumstances prevailing at the time).

6.                  SYSTEM STUDIES

6.1              The Licensee shall carry out system studies including Load flow, short circuit and Transient stability studies as often as required but at least once in a year.

6.2              The Licensee shall endeavour for optimal use of existing reactive resources and the reactive reserves in the system to meet the steady state voltage limits at all Buses in the Transmission System as set in “Planning and Security Standards for Transmission System”.

6.3              The Licensee shall coordinate the settings of the Relays in the Protection Schemes of its Transmission system with those of the Generators, PGCIL and grid system of neighbouring States at respective points of interconnections.

6.4              As a routine measure, the Licensee shall intimate all users of the Transmission System, the approximate fault level of the Transmission system at each point of interconnection both at EHT Bus and at H.T. Bus.

6.5              The Licensee shall prepare schedule of operation of on-load Taps of load-transformers and interconnecting transformers at each EHT sub-station in the Transmission System under different Generation and load despatches as stipulated in the system studies and enforce its implementation under similar situations obtained in practice.

7.                  DEMAND MANAGEMENT

7.1              The Licensee shall monitor MW/MVAR loading of each EHT line and each interconnecting transformer on real time basis at SLDC.  Similarly, the loadings on each load transformers at EHT sub-station shall be closely monitored during peak load hours.

7.2              If any system component is being over loaded/over heated, the load on the same shall be reduced by following suitable procedure.

8.                  VOLTAGE MANAGEMENT

8.1              The Licensee shall monitor voltage levels at all EHT sub-stations of its Transmission System on real time basis at SLDC.

8.2              Since voltage is affected both by frequency and reactive power flow, system

 voltage shall be regulated by taking all possible measures to regulate system frequency and reactive power flows.

8.3              All local voltage problems shall be addressed by attending to local transformer taps.

8.4              In case of system High Voltage, Licensee shall take following measures:

i)                    Generator plant to increase MVAR absorption subject to stability limit.

ii)                  Switch off capacitors.

iii)                 Switch in bus reactor where provided.

iv)                Switch off one circuit lightly loaded.