AMENDED ELECTRICITY TRANSMISSION GRID
REGULATION
After Public Consultation
April 2015
Amendments are marked in colour (red or green)
PART I
General Provisions
ARTICLE 1 Objective
[Previous Article 1]
(1) The purpose of this Regulation is to determine the procedures and principles
for the standards to be applied in planning and operating the electricity transmission
system in a reliable and low-cost manner and ensuring the system stability and to
determine the conditions for the supply reliability and quality to be applied in order to
supply quality, adequate and low-cost electric energy to the consumers.
ARTICLE 2 Scope
[Previous Article 2; amended for harmonization with ENTSO-E code]
(1) This Regulation covers the liabilities of TEIAS, distribution network
operators when applying or using processes in coordination with TEIAS, the users of
the transmission system and market participants and any other users deemed as
significant according the provisions set forth in the present Regulation, such as those
who are connected to the distribution system but affect the transmission system.
(2) This Regulation also covers the facility design and operation rules the
aforementioned operators should comply with, and the requirements that should be
fulfilled by TEIAS for planning and operating the transmission system considering the
system safety conditions.
(3) Any conflict arising from the implementation of the present Regulation and
other distribution related provisions should be addressed to the Director of TEIAS [and/or
to EMRA] by writing. Accordingly, the Director of TEIAS [ and/or to EMRA] will provide
for clarification within sixty (60) calendar days. Such clarification will be binding for al l
operators in the transmission and distribution system”.
ARTICLE 3 Legal Basis
[Previous Article 3]
(1) This Regulation has been issued in compliance with the provisions of Electricity
Market Law no. 6446 dated 14/03/2013.
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ARTICLE 4 Definitions and Abbreviations
[Previous Article 4]
(1)For the purposes of interpretation and implementation of this Regulation, the
following terms and abbreviations shall bear the following meanings;
a) Emergency: Any case or situation that endangers the system stability and/or
safety within the framework of this Regulation, TEIAS license or other provisions of the
relevant legislation,
b) Emergency notification: Any notification which impose obligations on the legal
persons engaged in generation activities and/or other users in order to protect the
operational safety in case of emergency and which is issued by the NLDC and/or RLDC
using the means of communications such as telephone, fax, pax, or MMS,
c) Island: The independent subsystems of the transmission system that have no
electrical connection with the remaining parts of the transmission system,
ç) Main busbar: The busbar to which the feeders are connected with their own
breakers and disconnectors,
d) Main interconnected system: 400 kV and 154 kV components of the
transmission system, excluding user circuits,
e) Instantaneous demand control: automatic disconnection of the consumption
facilities included in the scope of an ancillary service agreement related to the
instantaneous demand control service in the event that the system frequency decreases to a
frequency level determined by TEIAS with the instantaneous demand control relays,
f) Instantaneous demand control relay: A device that issues trip command to the
breakers for disconnecting the loads of the consumption facilities in order to provide
instantaneous demand control service when the frequency drops below the predetermined
operating values,
g) Supply capacity loss: The decrease in the supply capacity arising in the
electricity generation and transmission system,
ğ) Over-excitation operation: Increasing the excitation voltage of synchronous
compensators and/or generating units when the system excitation voltage decreases below
specified operation values,
h) Disconnector: The equipment that is used in order to connect and disconnect the
no-load electric circuits,
ı) Maximum primary reserve capacity: The maximum change in output power
which may be made within 30 seconds at the latest in the case of a step frequency
deviation of 200 mHz
i) Connection agreement: The agreement which includes the general and special
provisions and which is made for any generation company, distribution company or any
consumer to connect to the transmission system or the distribution system,
j) Connection point: The site or point where a user connects to the system as per the
connection agreements,
k) Connection request: The request of a user to connect its facility to a certain point
on the transmission system,
l) Busbar: The mechanism in which the electric energy at the same voltage is
collected and distributed
m) Busbar coupling: The interconnection of two different busbars at the same
voltage level with a full feeder having a disconnector or breaker only and, when required,
by means of a serial reactor,
n) Standby reserve service: Engaging of a disabled Power Generating Module
which cannot submit its generation capacity through the real-Time market and which
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remains available to be enabled within the engagement time determined by TEIAS by the
System Operator,
o) Supply point: The point on the transmission and/or distribution system where the
customers are supplied electricity,
ö) Block: For combined cycle Power Generating Facilities, more than one gas
turbine and alternator that can load and unload together, including the steam turbine and
alternator fed by these,
p) Regional capacity leasing: Leasing of the capacities of the new Power
Generating Facilities and/or the units added to the existing Power Generating Facilities
through the tenders made by TEIAS in order to ensure maintenance of the system
reliability and meet the regional system needs that may arise due to insufficient capacity,
r) Regional load dispatch center (RLDC): The control center which is engaged in
the operation of a zone, with the boundaries designated, of the electricity interconnected
system of Turkey under TEIAS in a safe, quality and economic manner in terms of
generation, transmission and consumption and which performs/causes to be performed the
coordination of the operating maneuvers in coordination with the NLDC,
s) Transposition: The transposition of the conductors with each other at the points
at the rate of approximately 1/3 and 2/3 of the length of the line in order to be able to
balance the phase impedances of the transmission line,
ş) Multi circuit lines: The lines where more than one line at the same voltage level
is on the same pole,
u) Distribution region: The region defined in the license of a distribution company,
t) Distribution: The transport of electricity through lines of 36 kV and below,
ü) Distribution system: The electricity distribution facilities and grid which are
operated by any distribution company in the distribution zone designated in its license,
v) Distribution system operator: A legal person who is holder of a distribution
license and responsible for operation of the distribution system within the boundaries of
the related distribution region,
y) Distribution company: Any legal entity engaged in electricity distribution in a
designated geographical region,
z) Distribution facility: The plant and equipment which are furnished for the
electricity distribution and the meters which are furnished or taken over by the distribution
company, except for the building entrance and between the meters, from the terminal post
after the point where the transmission facilities and the switchyards belonging to the
generation and consumption facilities connected at the distribution voltage level end to the
building entry points of the consumers connected at the low voltage level,
aa) Fluctuating load: Variable impedance load which lags interrupted current in
different amplitudes and distort the waveform of grid voltage,
bb) Balancing: The actions taken in order to balance the system supply and
demand,
cc) Balancing unit: A generating or consumption plant or a part thereof that may
take part in balancing as defined in the relevant legislation which sets out the balancing
and settlement procedures,
çç) Balancing Power market: An organized wholesale electricity market operated
by the System Operator for trade of reserve capacity obtained through the output power
change that can be made within 15 minutes in order to serve the purpose of real-time
balancing of the supply and demand,
dd) Balancing mechanism: The activities which supplements the bilateral
agreements and which consist of the day-ahead market, day market and real-time
balancing,
ee) Outage: Automatic or manual outage of a part of the facility and/or equipment
due to maintenance, repair or any breakdown,
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ff) Low frequency relay: The equipment that gives ‘opening instruction’ to breakers
for disconnecting the loads of the consumption facilities if the frequency decreases below
pre-specified operation values,
gg) Underexcitation: Decreasing the excitation currents of the synchronous
compensators and/or generating units if the system voltage is over the operating values set
out in this Regulation,
ğğ) Crew chief or supervisor: The personnel who takes or causes to be taken the
necessary safety measures before any work to be carried out on the equipment, conducts
the works to be performed on the equipment, ensures that these measures are removed at
the end of the works and notifies to the relevant departments that the equipment can be put
into the service again,
hh) Power cut: Cutting the power of plant and/or equipment from every direction
via circuit breakers and disconnectors,
ıı) Energy storage systems: The systems which can continuously store the electric
energy at limited capacity by converting it into different forms by means of the
mechanical, hydraulic, electrochemical, chemical, electrical and thermal energy storage
systems, provide the electric energy to the system or draw energy from the system when
required, continually circulate the energy and give rapid reaction,
ii) Energy transmission line (EİH): The facility which consists of the overhead lines
and/or power cables that are used in the High Voltage (HV) energy transmission,
jj) Interconnection: The connection of the national electric system that consists of
the total of the transmission and distribution systems to the electric system that belongs to
another country,
kk) ENTSO-E: Electric Network Transmission System Operators of Europe,
ll) Phase unbalance: Different amplitude and phase angles between phase voltages
at a certain point of power system,
mm) Feeder: Line or cable outlets which transmit energy to the user from a central
busbar,
nn) Flicker: Voltage fluctuations below 50 Hz, which occur because of fluctuations
in load and create discomfort by creating blinks in illumination armatures,
oo) Flicker severity: Level of flicker voltage fluctuations defined and measured in
accordance with the international standards,
öö) Frequency: The number of alternating current cycles in one second in the
system (expressed in Herz),
pp) Real-time balancing: The activities carried out by the System Operator in order
to real-timely balance the active electric energy supply and demand,
rr) Sudden voltage changes: Changes occurred in voltage after a switching
operation and after completion of temporary regime conditions and following the start of
voltage regulators and static VAR compensators and before tap change settings and other
switching operations,
ss) Voltage waveform distortion: Distortion occurred in the sinusoidal form of
voltage,
şş) Voltage regulator: The equipment regulating the terminal voltage of alternators,
tt) Power factor: The ratio of active power to apparent power,
uu) Power quality measuring period: The one-week continuous measuring time
defined in IEC 61000-4-30,
üü) Power system stabilizers: The equipment controlling the synchronous alternator
and turbine to reduce power fluctuations via voltage regulator using excitation level, speed,
frequency, power or combination of those as input variables,
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vv) Day-ahead market: An organized wholesale electricity market established for
the electric energy trades on the basis of settlement period to be delivered in the next day
and operated by the Market Operator,
yy) Safety rules: Rules put in place by TEIAS or users to protect personnel working
on relevant plant and/or equipment from dangerous events that may occur during the
maintenance, repair, and operation of the system,
zz) Harmonic: Each of sinusoidal components occurred in direct multiples of
fundamental frequency component in an alternative current or voltage distorted because of
non-linear loads or generating units, whose voltage waveform is not ideal,
aaa) Harmonic voltage value: The effective value of harmonic components in
distorted vol
bbb) Harmonic content: Distortion leading to difference between the effective
value of the waveform and effective value of the fundamental component and stating the
overall effect of harmonics in the distorted alternative current or voltage wave,tage
waveform,
ccc) Harmonic limits: Harmonic limits on plant and equipment connected to
transmission and distribution system which is determined in international standards and
permitted for voltage and current in certain points on the system,
ççç) Line: The facilities composed of conductors carrying electricity,
ddd) Speed drop: The speed governor setting value (expressed as a percentage) that
specifies the variation ratio of the unit output power according to the deviation ratio at the
system frequency,
eee) Speed governor: The device regulating the turbine speed and/or output power,
fff) Speed governor block diagram: Diagram showing the mathematical transfer
functions of the components forming the speed governor of the unit and control units and
input and output relation between those,
hhh) Speed governor gain value: The ratio of change in terminal signal of speed
governor to entry speed fault signal of speed governor,
ğğğ) Speed governor dead band: Stable condition frequency range, where speed
governor does not intervene to frequency deviation,
hhh) Speed governor time constant: the constant showing the response of speed
governor to a sudden change in the entry,
ııı) IEC: International Electrotechnical Commission,
iii) IEC Standard: Technical specifications and standards published by International
Electrotechnical Commission,
jjj) Internal demand: Total electricity consumption of facility, equipment and other
components of a plant required to be operated under normal operating conditions,
kkk) Bilateral agreements: The trade agreements which are made between the real
and legal persons as subject to the special legal provisions for the sale and purchase of the
electric energy and/or capacity and which are not subject to the approval of the Board,
lll) Transmission: The transport of electricity through lines higher than 36 kV,
mmm) Transmission circuit: The part of the transmission system which remains
between two or more breakers,
nnn) Transmission equipment: The circuit, busbar and switch equipment that
belong to the transmission system,
ooo) Transmission system: Electricity transmission facilities and grid,
ööö) Transmission facility: The facilities from the terminal post after the generation
or consumption facility switchyard to which the generation or consumption facilities are
connected at the voltage level above 36 kV to the connection points of the distribution
facilities including the medium voltage feeders of the transmission switchyards,
5
ppp) Relevant legislation: The laws, regulations, communiqués, circulars and Board
decisions regarding the electricity market and the licenses of the related legal entities,
rrr) Alternator: Electromechanical equipment converting mechanical energy into
electric energy,
sss) Law: Electricity Market Law dated 14/03/2013 and no 6446,
şşş) Stable condition: The state of the system operation values of which is accepted
as constant after termination of temporary regime conditions,
ttt) Breaker: The equipment connecting/disconnecting the electric circuits including
the short circuits,
uuu) Definite day-ahead generation/consumption program (DDGP): The generation
and consumption values which are estimated by a supply/draw unit subject to a settlement
for the next day based on the obligations of the related party responsible for balance and
day-ahead market transactions and reported by the said unit to the System Operator at the
beginning of the real-time market and updated by the said unit according to the day market
transactions,
üüü) Short-circuit power: Highest apparent power occurring in a short-circuited
bus-bar,
vvv) Short-circuit ratio: Per unit value of synchronous reactance of a unit,
yyy) Short-term electric energy supply-demand projection: The generation capacity
supply-demand projection for the next 1 year, which is drawn up by the participation of all
relevant institutions and organizations under the coordination of the Ministry,
zzz) Short-term flicker intensity index (Pst): The flicker intensity index that is
measured at the periods of 10 minutes,
aaaa) Protection settings: Settings of the protection relays,
bbbb) User: Legal entities engaged in generation activities, distribution companies,
supply companies and eligible consumers directly connected to the transmission system,
cccc) Coupling feeder: The equipment which interconnects two main busbars at the
same voltage level,
çççç) Coupling breaker: The breaker which interconnects/disconnects the busbars
in the systems with two main busbars,
dddd) Carrier system: Radio-frequency transceiver that provides sound, protection
signaling and information communication over the energy transmission lines,
eeee) Board: Energy Market Regulatory Board,
ffff) Authority: Energy Market Regulatory Authority,
gggg) Pole slipping: Distortion of phase-angle balance in unit,
ğğğğ) Small power station: The plants with total Maximum Capacity of 10 MW or
below,
hhhh) Maneuver: Operations performed with circuit breakers and disconnectors to
commission or de-commission various parts of the system,
ıııı) Maneuver form: The form which is filled in by the RLDC and sent to the
relevant centers before the commencement of the maneuver for the purpose of specifying
the maneuver sequence to be followed by the substation operating technicians in the
maneuvers caused to be made by the RLDCs,
iiii) Maneuver diagram: Diagrams schematically showing the connections of the
circuits in switchyard with related numbering and labeling,
jjjj) National load dispatch center (NLDC): The control center which is under
TEIAS and which is engaged in the operation of the interconnected electric system of
Turkey in a safe, quality and economic manner in terms of generation, transmission and
consumption, which ensures that the electric energy supply and demand is balanced, which
operates the Real-time Market, which is responsible for the operation of the international
interconnection lines and the coordination of the energy exchanges made over the lines and
which provides the coordination between the Regional Load Dispatch Centers,
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kkkk) (N-1) constraint: Disconnection of any equipment or interconnected
equipment group of the transmission system due to failure,
llll) (N-2) constraint: The disconnection of two equipment of the transmission
system independent from each other at the same time due to failures,
mmmm) Negative component: In an instable electricity system, the vector of first
phase of the component with negative phase sequences among positive, negative, and null
components which states instability in current or voltage phases,
nnnn) Negative phase sequence: In an instable electricity system, stable vector
group with three components having equal amplitudes, hundred and twenty degrees of
phase difference from each other and sequenced in different directions in order to state
instability in current or voltage phases,
oooo) Nominal active power: The value (Watt) obtained by multiplying the
nominal apparent power of an element in the system by the nominal power factor,
öööö) Nominal apparent power: The value (Volt-ampere) obtained by multiplying
the maximum current value that an element in the system can continuously provide and/or
withstand by the nominal voltage,
pppp) Normal operating condition: Operating condition where voltage, frequency,
and line flows are in specified ranges, demand is met, ancillary services are provided and
operation of the system is stable,
rrrr) Medium voltage (OG) feeder: The line or cable outputs transmitting energy
from a central busbar to the customer or the customer group,
ssss) Common connection point: The common point at which more than one user is
or likely to be electrically connected to the transmission system,
şşşş) Automatic generation control: The control system hardware and software at
the National Load Dispatch Center, which sends the necessary signals to the speed
governors of the Power Generating Modules and adjusts the active power outputs of the
alternators in order to ensure the secondary frequency control against any change in the
generation or in the demand,
tttt) Automatic generation control (AGC) program: A program located in the NLDC
to send the active power generation target values automatically calculated by itself to the
Power Generating Modules which are controlled by this program via the SCADA system
in order to ensure that such Power Generating Modules will participate in the secondary
frequency control,
uuuu) Automatic generation control (AGC) system/interface: The
systems/interfaces which are located in the Power Generating Modules that will participate
in the secondary frequency control and which ensure that the related Power Generating
Modules will participate in the secondary frequency control by the signals sent by the
automatic generation control program located in the National Load Dispatch Center,
üüüü) Restoration of a system shutdown: In the event of a partial or total shutdown
of a transmission system, energizing the transmission system, supplying electric energy to
the customers and re-engaging of the other Power Generating Modules by the Power
Generating Modules that can be engaged without need for any external energy source,
vvvv) Performance tests: The tests carried out in order to determine the abilities of
the generation and consumption plants to provide ancillary services,
yyyy) Market: The electric energy market that consists of the generation,
transmission, distribution, market operation, wholesale, retail sale, import and export
activities and the works and transactions regarding these activities,
zzzz) Market Participant: legal person acting as License holder and any other legal
person who enters into transactions, including the placing of orders to trade, in the
wholesale energy market, including but not limited, to transmission system operators,
suppliers, traders, producers, brokers and large users.
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zzzz2) Licensed Holder: License holder legal persons as defined in the relevant
legislation which sets out the balancing and settlement procedures,
aaaaa) Market management system (MMS): The applications that are made
available to the Market Operator, the System Operator, the market participants and the
legal entities having transmission and distribution license and being responsible for reading
the meters and that run in the thin client structure for the purpose of conducting the
procedures with regard to the balancing mechanism and conciliation,
bbbbb) Positive component: In an instable electricity system, vector of first phase
of the component having positive phase sequence among positive, negative, and null
components which states instability in current or voltage phases,
ccccc) Positive phase sequence: In an instable electricity system, stable vector
group with three components having equal amplitudes, hundred and twenty degrees of
phase difference among each other and sequenced in same direction in order to state
instability in current or voltage phases,
[Modification, Harmonisation ENTSO-E LFC&R NC]
ççççç) Primary frequency control: a process that aims at stabilizing the System Frequency
by compensating imbalances by means of appropriate reserves (corresponding to
Frequency Containment Process),
ddddd) Primary frequency control reserve capacity: The whole reserve amount
determined by the primary frequency control performance tests and included in the primary
frequency control service agreements and required to be activated by the related Power
Generating Module,
eeeee) Primary frequency control reserve amount: The reserve amount reported by
the legal persons engaged in generating activities and to be provided by the Power
Generating Modules as a primary frequency control response in line with the deviations
occurring at the system frequency,
fffff) Primary frequency control response: Automatically increasing or decreasing
the active power output of a unit by the speed governor under the primary frequency
control service in the case of an increase or decrease in the system frequency,
ggggg) Reactive power control: Reactive power supply to or draw from the system
by a generating unit while operating as a generator or synchronous compensator,
ğğğğğ) Reactor: Winding lagging reactive power from its connected line,
transformer or busbar and used to lower the voltage,
[New definition, Harmonisation ENTSO-E OS NC]
...) Responsibility Area means a coherent part of the interconnected Transmission
System including Interconnectors, operated by a single TSO with connected Demand
Facilities, or Power Generating Modules , if any;
[New definition, Harmonisation ENTSO-E LFC&R NC]
...) Frequency Restoration Reserves (FRR) means the Active Power Reserves
activated to restore System Frequency to the Nominal Frequency and for Synchronous
Area consisting of more than one LFC Area power balance to the scheduled value
hhhhh) Secondary frequency reserve control: Bringing the system frequency to its
nominal value, and bringing the total electrical energy exchange with the adjacent
electricity grid to its scheduled value by either increasing or decreasing the active power
outputs of the generation companies participating in this control by the signals
automatically sent by NLDC means the Active Power Reserves automatically activated to
restore System Frequency to the Nominal Frequency and power balance to the scheduled
value (corresponding to Automatic Frequency Restoration Reserve),
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ııııı) Secondary frequency control reserve amount: The reserve amount formed by
the capacity between DDGP and available capacity and/or by the load up, load down
instructions given by the System Operator under the real-time market; and determined by
the System Operator and reported to the generation license holder legal persons who
provide secondary frequency control service and to be provided by the Power Generating
Modules as the secondary frequency control response, except for the capacity reserved by a
Power Generating Module as the primary frequency control reserve amount,
[New definition, Harmonisation ENTSO-E LFC&R NC]
....) Replacement Reserves (RR) means the reserves used to restore/support the
required level of FRR to be prepared for additional system imbalances. This category
includes operating reserves with activation time from Time to Restore Frequency up to
hours
....) Sharing of Reserves means a mechanism in which more than one TSO take the
same Reserve Capacity, being FCR, FRR or RR, into account to fulfil their respective
reserve requirements resulting for their reserve dimensioning processes
...) ACE Open-Loop means the sum of the ACE, Secondary Reserve Activation and
Tertiary Reserves Activation within the LFC Block and the Imbalance Netting Power
Exchange, Power Interchange of this LFC Block with other LFC Blocks
...) Dimensioning Incident means the highest expected instantaneously occurring
Active Power Imbalance within a LFC Block in both positive and negative direction
...) Exchange of Reserves means a concept for a TSO to have the possibility to
access Reserve Capacity connected to another LFC Area, LFC Block, or Synchronous
Area to comply with the amount of required reserves resulting from its own reserve
dimensioning process of either FCR, FRR or RR. These reserves are exclusively for this
TSO, meaning that they are not taken into account by any other TSO to comply with the
amount of required reserves resulting from their respective reserve dimensioning
processes;
...) Full Activation Time means the period between the occurrence of the reference
incident for Primary Reserve, the setting of a new Setpoint value by the frequency
restoration controller for Secondary Reserve, the setpoint change for Tertiary Reserves and
the corresponding activation or deactivation of the respective reserves.
....) Imbalance Netting means a process agreed between TSOs of two or more LFC
Areas within one or more than one Synchronous Areas that allows for avoidance of
simultaneous Secondary and Tertiary Restoration Reserves activation in opposite
directions by taking into account the respective ACEs as well as activated Reserves and
correcting the input of the involved Secondary Controller accordingly;
....) Level 1 Range means the first range used for System Frequency quality
evaluation purposes on LFC Block level within which the ACE should be kept for a
specified percentage of the time
...) Level 2 Range means the second range used for System Frequency quality
evaluation purposes on LFC Block level within which the FRCE should be kept for a
specified percentage of the time
....) LFCR NC European Network Code on “Load Frequency Control and
Reserves” (under preparation)
....) LFC Area means a part of a Synchronous Area or an entire Synchronous Area,
physically demarcated by points of measurement of Interconnectors to other LFC Areas,
operated by one or more TSOs fulfiling the obligations of a LFC Area
....) LFC Block means a part of a Synchronous Area or an entire Synchronous Area,
physically demarcated by points of measurement of Interconnectors to other LFC Blocks,
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consisting of one or more LFC Areas, operated by one or more TSOs fulfiling the
obligations of a LFC Block
....) Reserve Capacity means the amount of FCR, FRR or RR that needs to be
available to the TSO
iiiii) Synchronous compensation: Reactive power generation or consumption
through adjusting the excitation currents of running synchronous machines in order to keep
the power factor in the system at desired level,
jjjjj) Synchronization: Providing the necessary conditions, connection of a unit to
transmission system or connection of two separate systems in the transmission system to
each other,
kkkkk) Eligible consumer: The real or legal person who has the right to select his
supplier because he has more consumption than the electric energy amount determined by
the Board or he is directly connected to the transmission system or he is organized
industrial zone legal entity,
lllll) Serial capacitor: The capacitor group that is used to increase the system
stability by reducing the impedance in the line with which it has serial connection,
mmmmm) Serial reactor: The winding that is used to limit the current in the feeder
to which it is connected,
nnnnn) Null component: In an instable electricity system, each of three equal
vectors of the component having null phase sequence among positive, negative, and null
components and which state instability in current or voltage phases,
ooooo) Null component reactance: Impedance values calculated to find phase-toearth and phase-to-phase earth fault currents and valid for null phase sequence currents,
ööööö) Null phase sequence: In an instable electricity system, three equal vectors
used to state instability in current or voltage phases,
ppppp) Simulated frequency: A speed or frequency signal simulated to the
measured speed or frequency date and applied to the speed governor in order to carry out
the frequency control performance tests,
rrrrr) System: All user systems including the electricity transmission system and
distribution system,
sssss) System operator: Turkiye Elektrik Iletim Anonim Sirketi (TEİAS)
şşşşş) System use agreement: The agreement that includes the general provisions
with respect to the use of the transmission system or the distribution system by any
generation company, any company having supply license or any consumer and the
conditions and provisions specific to the relevant user,
ttttt) Black out: Unintended loss of energy of the electricity system partially or
completely,
uuuuu) Subsynchronous resonance: Fluctuations below normal system frequencies
and rated system frequency occurring between the system and mechanical shaft of the
turbine-alternator group,
üüüüü) Subsynchronous resonance protection: System providing protection for
generating units against sub synchronous resonance,
vvvvv) Switchyard: Site containing electrical connection components and equipment,
yyyyy) Shunt capacitor: Condenser group generating reactive power and in parallel
connection to the system,
zzzzz) Shunt reactor: The winding that draws reactive power from the line,
transformer or busbar to which it is connected and that is used to reduce the voltage,
aaaaaa) Demand: Amount of active and reactive power that will be consumed,
bbbbbb) Demand profile: In a certain time period, the curve showing the demand
change in the system total demand or at a certain point of the system,
cccccc) Demand forecast: Hourly consumption estimates issued daily by the
System Operator,
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çççççç) Tariff: The provisions covering prices, terms and conditions related to
transmission, distribution and sale of electricity and/or capacity and related services,
dddddd) The designed minimum output level: Active power output if system
frequency is above 50.2 Hz and unit or block does not have frequency control capacity,
eeeeee) Supplier: The generation companies providing electric energy and/or
capacity and the companies having the supply license,
ffffff) Supply company: The legal entity that can be engaged in the wholesale
and/or retail sale, import, expert and trade activities of the electric energy and/or capacity,
gggggg) TEIAS: Turkiye Elektrik Iletim Anonim Sirketi,
ğğğğğğ) Single line diagram: Single phase diagram showing the connections of
elements like busbar, conductor, power transformer and compensation equipment in a
certain part of the grid,
hhhhhh) Thermal capacity: The energy amount which is allowed to delay over a
circuit under certain conditions,
ıııııı) Tertiary frequency control: Increasing or decreasing the active power output
by the balancing units within the scope of real-time balancing of supply and demand so as
to ensure operating security and system integrity by the load up, load down instructions
specifying the output power change that may be made by the balancing units within 15
minutes under the real-time market as per the provisions of the relevant legislation which
sets out the balancing and settlement procedures,
iiiiii) Tertiary control reserve amount: The reserve amount to be provided by the
balancing units through output power change that may be made within 15 minutes,
jjjjjj) Tertiary frequency control reserve: Part of the operation reserves, which can
be put into service manually through the real-time market when needed, and selected to be
sufficient for releasing the secondary reserve,
[New definition, Harmonisation ENTSO-E LFC&R NC]
....) Tertiary Replacement Reserve means the reserves used to restore/support the
required level of Secondary and tertiary restoration reserves to be prepared for additional
system imbalances. This category includes operating reserves with activation time from 15
minutes up to hours.
....)Tertiary Restoration Reserve means the Active Power Reserves manually
activated to restore System Frequency to the Nominal Frequency and power balance to the
scheduled value (corresponding to Manual Frequency Restoration Reserves).
kkkkkk) Facility: Plant and equipment installed to perform the functions of
generation, transmission or distribution of electricity,
llllll) TETAS: Türkiye Elektrik Ticaret ve Taahhüt Anonim Şirketi,
mmmmmm) Black start capability: Ability of a plant to start with its own capability
in accordance with the instruction of TEIAS and without external feeding and to energize a
part of the system in case of black out,
nnnnnn) Total harmonic distortion (THBv): The value which is the rate of the
square root of the total of the squares of the effective values of the voltage harmonic
components to the effective value of the main component and which expresses the
distortion in the wave form as percentage,
oooooo) Total Demand Distortion (TDD): The value which is the ratio of the
square root of the total sum of the squares of the effective values of the current harmonic
components to the maximum load current (IL), and which expresses the distortion in the
waveform in percentage,
öööööö) Earthing: Connection of the de-energized equipment with the earth by
closing the earth disconnector or by using the earthing equipment,
11
pppppp) Earth fault factor: Ratio of after fault voltage and before fault voltage of
the working phase in single phase or two phase earth faults,
rrrrrr) Wholesale: Sale of the electric energy and/or capacity for resale,
ssssss) Transfer busbar: The busbar to which the equipment is connected by means
of the transfer breaker and/or disconnector,
şşşşşş) Transfer feeder: The equipment that can replace any feeder,
tttttt) Transfer breaker: The breaker that can replace any feeder’s own breaker and
that connects the main busbar to the transfer busbar,
uuuuuu) Transfer+coupling feeder: The equipment that can be used as transfer or
coupling,
üüüüüü) Consumer: The person who purchases the electricity for his own use,
vvvvvv) Electric energy demand projection of Turkey: The twenty-year demand
estimation report which is drawn up and released by the Ministry by taking the opinions of
the Ministry of Development and the Institution at two-year periods,
yyyyyy) International interconnection: The interconnection based on the operation
of the national electric system with the electric system belonging to the other countries by
using one of the synchronous parallel, asynchronous parallel, unit orientation or isolated
zone methods,
zzzzzz) International standards: International design, construction, manufacturing
and performance standards prepared, approved and used for electricity system plant and/or
equipment,
aaaaaaa) Long-term electric energy generation development plan: The work for the
Electric Energy Demand Projection of Turkey drawn up by the Ministry and the 20-year
generation development plan drawn up by TEIAS based on the source potential,
bbbbbbb) Long-term flicker intensity index (Plt): The flicker intensity index
calculated by using Pst values that are measured during two-hour time interval (12
consecutive measurements),
ccccccc) Unit: Each generating set which can load and unload independently, and,
as for combined cycle Power Generating Facilities, the share of each gas turbine and
alternator, and the steam turbine and alternator connected to the gas turbine and the
alternator,
ççççççç) Unit load controller: Control circuit in the speed governor controlling unit
loading,
ddddddd) Generation: The transformation of energy resources into electricity in
electricity Power Generating Facilities,,
eeeeeee) Generation capacity projection: The generation-consumption balance
analysis report drawn up by TEIAS according to the annual capacity increase expected to
be put into operation within the next 5 years based on the demand forecasts prepared by the
distribution companies, concluded by Turkiye Elektrik Iletim Anonim Sirketi and
approved by the Authority,
fffffff) Generation company: The legal entity subject to the special legal provisions,
which is engaged in electric energy generation or sale of the electricity it generates at the
Power Generating Module or Power Generating Facilities that it owns, has rented, has
acquired by financial leasing or has taken over the operating right,
ğğğğğğğ) Ancillary services: The services which are provided by the relevant legal
entities connected to the transmission system or the distribution system pursuant to the
Electricity Market Ancillary Services Regulation published in official Gazette No:27093
dated 27/12/2008 and which are described in detail in the relevant regulation in order to
ensure that the transmission system or the distribution system is operated in a reliable
manner and that the electricity is put into service under the necessary quality conditions,
hhhhhhh) Ancillary service agreements: The agreements which will be provided by
the generation companies, the distribution companies or the consumers connected to the
12
transmission and/or distribution system to TEIAS pursuant to this Regulation, and by the
generation companies or the consumers connected to the distribution system to the relevant
distribution license owner pursuant to the Electricity Market Distribution Regulation
published in Official Gazette No: 28870 dated 02/01/2014 and which determines the
ancillary service costs, conditions and provisions,
ııııııı) Ancillary service certificates: Documents issued by the authorized
independent companies to indicate that the ancillary service providing facilities can
provide service in accordance with the provisions of the Electricity Market Ancillary
Services Regulation and this Regulation,
iiiiiii) Annual load factor: The rate, expressed as percentage, of the actual annual
energy generation of any generation unit or Power Generating Module to the maximum
annual energy generation that this generation unit or Power Generating Module can
generate,
jjjjjjj) Load up: Energy selling by a balancing unit to the system by increasing its
generation or decreasing its consumption in line with the instructions given by the System
Operator,
kkkkkkk) Load up instruction: Notifications by the System Operator to the
participants of the real-time market for load up,
lllllll) Load up offer: Proposals including price, amount and validity period by the
participants of real-time market for load up,
mmmmmmm) Load down: Energy purchasing from the system by a balancing unit
by decreasing its generation or increasing its consumption in line with the instructions
given by the System Operator,
nnnnnnn) Load down instruction: Notifications by the System Operator to the
participants of the real-time market for load down,
ooooooo) Load down offer: Proposals including price, amount and validity period
by the participants of real-time market for load down,
ööööööö) Loading curve: Curve showing the loading capacity of a unit as active
and reactive, and
ppppppp) Loading speed: The output power change that may be made by the Power
Generating Module in the unit time.
[New definition, harmonization with ENTSO-E RfG and DCC codes]
Active Power - is the real component of the Apparent Power at fundamental Frequency,
expressed in watts or multiples thereof (e.g. kilowatts (kW) or megawatts (MW)).
Active Power Frequency Response - is an automatic response of Active Power
output from a Power Generating Module, in response to a change in system Frequency
from the nominal system Frequency.
Alternator – is a device that converts mechanical energy into electrical energy by
means of a rotating magnetic field.
Apparent Power - is the product of Voltage and Current at fundamental
Frequency. It is usually expressed in kilovolt-amperes (kVA) or megavolt-amperes
(MVA) and consists of a real component (Active Power) and an imaginary
component (Reactive Power).
Authorised Certifier - is an entity to issue Equipment Certificates. The
accreditation of the Authorised Certifier shall be given from the national affiliation
of the European co-operation for Accreditation (EA).
13
Automatic Voltage Regulator (AVR) - is the continuously acting automatic
equipment controlling the terminal Voltage of a Synchronous Power Generating Module
by comparing the actual terminal Voltage with a reference value and controlling by
appropriate means the output of an Excitation System, depending on the deviations.
Black Start Capability - is the capability of recovery of a Power Generating Module
from a total shutdown through a dedicated auxiliary power source without any energy
supply which is external to the Power Generating Facility.
Closed Distribution System Operator (CDSO) - is a natural or legal person
operating, ensuring the maintenance of and, if necessary, developing a closed distribution
Network according to ENTSO-E codes.
Cost-Benefit Analysis – is a process by which the Relevant Network Operator
weighs the expected costs of alternative actions aiming at the same objective against the
expected benefits in order to determine the alternative with the highest net socio-economic
benefit. If applicable, the alternatives include network-based and market-based actions.
Current - unless stated otherwise, Current refers to the root-mean-square value of
the positive sequence of the phase Current at fundamental Frequency.
Compliance Monitoring means the process of verification that the technical
capabilities for Power Generating Modules, Demand Facilities, Distribution Networks,
Distribution Network Connections or HVDC Systems are maintained compliant with the
specifications and requirements of this Regulation after starting operation.
Compliance Simulation means the process of verification that Power Generating
Modules, HVDC Systems, Demand Facilities, Distribution Networks or Distribution
Network Connections are compliant with the specifications and requirements of this
Regulation, for example before starting operation of new installations. The verification
should include, inter alia, the revision of documentation, the verification of the requested
capabilities of the facility, Distribution Network or Distribution Network Connections by
simulation studies and the revision against actual measurements.
Compliance Testing means the process of verification that Power Generating
Modules, HVDC Systems, Demand Facilities, Distribution Networks or Distribution
Network Connections are compliant with the specifications and requirements of this
Regulation, for example before starting operation of new installations. The verification
includes the revision of documentation, the verification of the requested capabilities of the
facility by practical tests and simulation studies and the revision of actual measurements
during trial operation.
Connection Agreement means a contract between the Relevant Network Operator
and either the Demand Facility Owner or Distribution Network Operator which includes
technical specifications and site specific requirements for the facility or Distribution
Network Connection; or a contract between the Relevant Network Operator and the Power
Generating Facility Owner which includes the relevant site and technical specific
requirements for the Power Generating Facility.
Connection Point means the interface as identified in the Connection Agreement at
which:

the Demand Facility is connected to a Transmission Network, or Distribution
Network, or;

the Distribution Network is connected to a Transmission Network, or:

the Closed Distribution Network is connected to the Distribution Network;
14

or the interface at which the Power Generating Module is connected to a
transmission, distribution or closed distribution Network according to ENTSO-E
codes as identified in the Connection Agreement.
Control Area means a part of the interconnected electricity transmission
system controlled by a single Transmission System Operator;
Droop - is the ratio of the steady-state change of Frequency (referred to
nominal Frequency) to the steady-state change in power output (referred to
Maximum Capacity).
Distribution System Operator (DSO) - is a natural or legal person
responsible for operating, ensuring the maintenance of and, if necessary,
developing the distribution Network in a given area and, where applicable, its
interconnections with other Networks and for ensuring the long-term ability of the
Network to meet reasonable demands for the distribution of electricity.
Energisation Operational Notification (EON) means a notification issued by
the Relevant Network Operator to either a Demand Facility Owner, Distribution
Network Operator, HVDC System Owner, Power Generating Facility Owner prior
to energisation of its internal Network.
Equipment Certificate means a document issued by an Authorised Certifier for
equipment used in a Demand Unit connected to the Distribution Network, Transmission
Connected Distribution Network or Transmission Connected Demand Facility or
equipment used in Power Generating Modules, confirming compliance with relevant
requirements of this Regulation as far as the influence on overall performance by this
specific equipment. The Equipment Certificate shall define the extent of its validity in
relation to parameters for which there is only a range of values defined in this document.
This will identify its validity at a national or other level at which a specific value is
selected from the range allowed at a European level. The Equipment Certificate for Power
Generating Modules can additionally include models confirmed against test results for the
purpose of replacing specific parts of the compliance process for Type B, C and D Power
Generating Modules. The Equipment Certificate will have a unique number allowing
simple reference to it in an Installation Document or to the Power Generating Module
Document.
Excitation System - is the equipment providing the field Current of a
synchronous electrical machine, including all regulating and control elements, as
well as field discharge or suppression equipment and protective devices.
Existing Power Generating Module - is a Power Generating Module which
is not a New Power Generating Module of this Regulation.
Final Operational Notification (FON) means a notification issued by the
Relevant Network Operator to a Demand Facility Owner, Distribution Network
Operator, HVDC System Owner or a Power Generating Facility Owner confirming
that the Demand Facility Owner or, Distribution Network Operator, HVDC System
Owner or Power Generating Facility Owner, respectively is entitled to operate its
Demand Facility, Distribution Network, HVDC System, Power Generating
Modules by using the Network connection because compliance with the technical
design and operational criteria has been demonstrated as referred to in this
Regulation.
Frequency - is the Frequency of the electrical power system that can be
measured in all Network areas of the synchronous system under the assumption of a
coherent value for the system in the time frame of seconds (with minor differences
15
between different measurement locations only); its nominal value is 50 Hz.
Frequency Control - is the capability of a Power Generating Module to control
speed by adjusting the Active Power Output in order to maintain stable system Frequency
(also acceptable as speed control for Synchronous Power Generating Modules).
Frequency Response Deadband - is used intentionally to make the Frequency
Control not responsive. In contrast to (in)sensitivity, deadband has an artificial nature and
basically is adjustable.
Frequency Response Insensitivity - is the inherent feature of the control system
defined as the minimum magnitude of the Frequency (input signal) which results in a
change of output power (output signal).
Frequency Sensitive Mode (FSM) - is a Power Generating Module operating mode
which will result in Active Power output changing, in response to a change in System
Frequency, in a direction which assists in the recovery to Target Frequency, by operating
so as to provide Frequency Response.
Houseload Operation - in case of Network failures resulting in disconnection of
Power Generating Modules from the Network and being tripped onto their auxiliary
supplies, house-load operation ensures that Power Generating Facilities are able to
continue to supply their in-house loads.
Inertia - is the fact that a rotating rigid body such as an Alternator maintains its state
of uniform rotational motion. Its angular momentum is unchanged, unless an external
torque is applied. In the context of this code, this definition refers to the technologies for
which Alternator speed and system Frequency are coupled.
Installation Document means a simple structured document, data of tick sheet,
containing information about a Demand Unit below 1000V or containing information
about a Type A Power Generating Module and confirming compliance with the relevant
requirements of this Regulation. The blank Installation Document shall be available from
the Relevant Network Operator for the Type A Power Generating Facility Owner or
alternatively the site installer on the owner’s behalf to fill in and submit to the Relevant
Network Operator.
Instruction means command given orally, manually or by automatic remote control
facilities, e.g. reconnection of a Demand Facility or Distribution Network Connection,
from a Network Operator to a Demand Facility Owner, Distribution Network Operator,
HVDC System Owner or Power Generating Facility Owner respectively, in order to
perform an action.
Interim Operational Notification (ION) means a notification issued by the Relevant
Network Operator to a Demand Facility Owner, Distribution Network Operator, HVDC
System Owner or Power Generating Facility Owner, confirming that they are entitled to
operate their equipment by using the Network connection for a limited period of time and
to undertake compliance tests to meet the technical design and operational criteria of this
Regulation
Island Operation - is the independent operation of a whole or a part of the Network
that is isolated after its disconnection from the interconnected system, having at least one
Power Generating Module supplying power to this Network and controlling the Frequency
and Voltage.
Limited Frequency Sensitive Mode – Overfrequency (LFSM-O) - is a Power
Generating Module operating mode which will result in Active Power output reduction in
response to a change in System Frequency above a certain value.
16
Limited Frequency Sensitive Mode – Underfrequency (LFSM-U) - is a
Power Generating Module operating mode which will result in Active Power output
increase in response to a change in System Frequency below a certain value.
Limited Operational Notification (LON) means a notification issued by the
Relevant Network Operator to a Demand Facility Owner, Distribution Network
Operator, HVDC System Owner or Power Generating Facility Owner, which has
previously reached FON status, but is temporarily subject to either a significant
modification or loss of capability which has resulted in non‐compliance to the
Regulation
Maximum Capacity - is the maximum continuous Active Power which a
Power Generating Module can feed into the Network as defined in the Connection
Agreement or as agreed between the Relevant Network Operator and the Power
Generating Facility Owner. It is also referred to in this Regulation as Pmax.
Minimum Regulating Level - is the minimum Active Power as defined in
the Connection Agreement or as agreed between the Relevant Network Operator
and the Power Generating Facility Owner, that the Power Generating Module can
regulate down to and can provide Active Power control.
Minimum Stable Operating Level - is the minimum Active Power as defined
in the Connection Agreement or as agreed between the Relevant Network Operator
and the Power Generating Facility Owner, at which the Power Generating Module
can be operated stably for unlimited time.
Network - is plant and apparatus connected together in order to transmit or
distribute electrical power.
New Power Generating Module - is a Power Generating Module for
which;

with regard to the provisions of the initial version of this Regulation, a final
and binding contract of purchase of the main plant has been signed after the
day, which is two years after the day of the entry into force of this
Regulation, or,

with regard to the provisions of the initial version of this Regulation, no
confirmation is provided by the Power Generating Facility Owner, with a
delay not exceeding thirty months as from the day of entry into force of this
Regulation, that a final and binding contract of purchase of the main plant
exists prior to the day, which is two years after the day of the entry into
force of this Regulation, or,

with regard to the provisions of any subsequent amendment to this
Regulation and/or after any change of thresholds pursuant to the reassessment procedure of ARTICLE 10(6), a final and binding contract of
purchase of the main plant has been signed after the day, which is two years
after the entry into force of any subsequent amendment to this Regulation
and/or after the entry into force of any change of thresholds pursuant to the
re-assessment procedure of ARTICLE 10(6).
Network Operator means an entity that operates a Network. This can be
either a TSO, a DSO, or the operator of a Closed Distribution Network;
17
Relevant Network Operator means the operator of the Network to which a Demand
Facility, Demand Unit or Distribution Network is or will be connected;
Statement of Compliance means a document provided by either a Demand Facility
Owner, Distribution Network Operator, HVDC System Owner or Power Generating
Facility Owner to the Relevant Network Operator stating the current status with respect to
compliance itemised for each element of this Regulation.
Aggregator means a legal entity which is responsible for the operation of a number
of Demand Facilities by means of Demand Aggregation;
Block Loading means the maximum step Active Power loading of reconnected
demand during system restoration after black‐out (is the state where the operation of part
or all Transmission System is terminated);
Closed Distribution Network means in the context of this Regulation, a Network
classified as closed distribution network pursuant to ENTSO-E codes. ENTSO-E codes
defines such a Network as a system which distributes electricity within a geographically
confined industrial, commercial or shared services site and does not (without prejudice to a
small number of households located within the area served by the system and with
employment or similar associations with the owner of the system) supply household
customers. This Closed Distribution Network will either have its operations or the
production process of the users of the system integrated for specific or technical reasons or
distribute electricity primarily to the owner or operator of the Closed Distribution Network
or their related undertakings;
Control Room means a Relevant Network Operator’s centralised operation centre;
Demand Aggregation means a set of Demand Facilities which can be operated as a
single facility;
Demand Facility means a facility which consumes electrical energy and is
connected at one or more Connection Points to the Network. For the avoidance of doubt a
Distribution Network and/or auxiliary supplies of a Power Generating Module are not to be
considered a Demand Facility;
Demand Facility Owner means the owner of the Demand Facility;
Demand Unit means an indivisible set of installations which can be actively
controlled by a Demand Facility Owner or Distribution Network Operator to moderate its
electrical energy demand. A storage device within a Demand Facility or Closed
Distribution Network operating in electricity consumption mode is considered to be a
Demand Unit. A hydro pump‐storage unit with both generating and pumping operation
mode is excluded. If there is more than one unit consuming power within a Demand
Facility, that cannot be operated independently from each other or can reasonably be
considered in a combined way, then each of the combinations of these units shall be
considered as one Demand Unit;
Distribution Network means an electrical Network, including Closed Distribution
Networks, for the distribution of electrical power from and to third party[s] connected to it,
a Transmission or another Distribution Network;
Distribution Network Connection means the electrical plant and equipment present
at the Connection Point, typically a substation, of either a new or existing Distribution
Network to the Transmission Network;
Distribution Network Operator (DNO) means either a Distribution System Operator
or an operator of a Closed Distribution Network;
18
ENTSO‐E Network Area means the geographic area covered by the
Network of the members of ENTSO‐E;
Existing Demand Facility means a Demand Facility which is not a New
Demand Facility.
Existing Distribution Network Connection means a Distribution Network
Connection which is not a New Distribution Network Connection;
Interim Compliance Statement means an itemized statement of compliance
provided by the Demand Facility Owner or, Distribution Network Operator, to the
Relevant Network Operator as established in this Regulation and as additionally
required by national legislation including the national codes;
Main Plant means at least one of the following equipment: motors,
transformers, high voltage equipment at the Connection Point and process
production plant;
Maximum Export Capability (MEC) means the maximum continuous
Active Power which a Demand Facility, or Distribution Network, can feed into the
Network at the Connection Point as defined in the Connection Agreement or as
agreed between the Relevant Network Operator and the Demand Facility Owner or
Distribution Network Operator respectively;
Maximum Import Capability (MIC) means the maximum continuous Active
Power which a Demand Facility or a Distribution Network, can consume from the
Network at the Connection Point as defined in the Connection Agreement or as
agreed between the Relevant Network Operator and the Demand Facility Owner or
Distribution Network Operator respectively;
New Demand Facility means a Demand Facility for which:

with regard to the provisions of the initial version of this Regulation, a final and
binding contract of purchase of the Main Plant has been signed after the date,
which is two years after the date of the entry into force of this Regulation, or,

with regard to the provisions of the initial version of this Regulation, no
confirmation is provided by the Demand Facility Owner, with a delay not
exceeding thirty months as from the date of entry into force of this Regulation, that
a final and binding contract of purchase of the Main Plant exists prior to the date,
which is two years after the date of the entry into force of this Regulation, or,

with regard to the provisions of any subsequent amendment to this Regulation
and/or after any change of thresholds pursuant to the re‐ assessment procedure of
ARTICLE 14, a final and binding contract of purchase of the main plant has been
signed after the date, which is two years after the entry into force of any subsequent
amendment to this Regulation and/or after the entry into force of any change of
thresholds pursuant to the re‐ assessment procedure of ARTICLE 14;
New Distribution Network Connection means a Distribution Network
Connection of either a new or existing Distribution Network, which is or will be
connected to the Transmission Network for which:
19

with regard to the provisions of the initial version of this Regulation, a final and
binding contract of purchase of the Main Plant has been signed after the date,
which is two years after the date of the entry into force of this Regulation, or,

with regard to the provisions of the initial version of this Regulation, no
confirmation is provided by the Distribution Network Operator, with a delay not
exceeding thirty months as from the date of entry into force of this Regulation, that
a final and binding contract of purchase of the Main Plant exists prior to the date,
which is two years after the date of the entry into force of this Regulation, or,

with regard to the provisions of any subsequent amendment to this Regulation
and/or after any change of thresholds pursuant to the re‐assessment procedure of
ARTICLE 14, a final and binding contract of purchase of the main plant has been
signed after the date, which is two years after the entry into force of any subsequent
amendment to this Regulation and/or after the entry into force of any change of
thresholds pursuant to the re‐assessment procedure of ARTICLE 14;
On Load Tap Changer means a device for changing the tap of a winding, suitable
for operation while the transformer is energized or on load;
On Load Tap Changer Blocking means an action that blocks the On Load Tap
Changer[s] during a low Voltage event in order to stop transformers from further tapping
and suppressing Voltages in an area.
Significant Demand Facility means a Demand Facility which is deemed significant,
either singularly or when considered aggregated, on the basis of its impact on the
cross‐border system performance via influence on the control area’s security of supply,
RES integration or market integration, which is identified according to the criteria set forth
in this Regulation in ARTICLE 11 to ARTICLE 16;
Significant Distribution Network means a Distribution Network which is deemed
significant on the basis of its impact on the cross‐border system performance via influence
on the control area’s security of supply, RES integration or market integration, which is
identified according to the criteria set forth in this Regulation in ARTICLE 11 to
ARTICLE 16;
Significant Distribution Network Connection means a Distribution Network
Connection which is deemed significant on the basis of its impact on the cross‐border
system performance via influence on the control area’s security of supply, RES integration
or market integration, which is identified according to the criteria set forth in this
Regulation in ARTICLE 11 to ARTICLE 16;
System Reserve means Active or Reactive Power reserves to actively manage the
Network predominantly to respond to Frequency and Voltage fluctuations;
Transmission Connected Closed Distribution Network means a Closed Distribution
Network which has a Connection Point to a Transmission Network;
Transmission Connected Demand Facility means a Demand Facility which has a
Connection Point to a Transmission Network;
Transmission Connected Demand Facility Owner means the owner of a
Transmission Connected Demand Facility;
Transmission Connected Distribution Network Operator means the operator of a
Transmission Connected Distribution Network;
20
Transmission Connected Distribution Network means a Distribution
Network which has a Connection Point to a Transmission Network;
Transmission Network means an electrical Network for the transmission of
electrical power from and to third party[s] connected to it, including Demand
Facilities, Distribution Networks or other Transmission Networks. The extent of
this Network is defined at a national level.
Overexcitation Limiter - is a control device within the AVR which prevents
the rotor of an Alternator from overload by limiting the excitation Current.
Power Factor - is the ratio of Active Power to Apparent Power.
Power Generating Facility - is a facility to convert primary energy to
electrical energy which consists of one or more Power Generating Modules
connected to a Network at one or more Connection Points.
Power Generating Facility Owner - is a natural or legal entity owning a
Power Generating Facility.
Power Generating Module - is either a
 Synchronous Power Generating Module, or
 a Power Park Module.
Power Generating Module Document (PGMD) - is a document issued by the
Power Generating Facility Owner to the Relevant Network Operator for a Type B
or C Power Generating Module. The PGMD is intended to contain information
confirming that the Power Generating Module has demonstrated compliance with
the technical criteria as referred to in this Regulation and provided the necessary
data and statements including a Statement of Compliance.
Power Park Module (PPM) - is a unit or ensemble of units generating
electricity, which
 is connected to the Network non-synchronously or through
power electronics, and

has a single Connection Point to a transmission, distribution or
closed distribution Network.
Power System Stabilizer (PSS) - is an additional functionality of the AVR
of a Synchronous Power Generating Module with the purpose of damping power
oscillations.
Pump-Storage - is a hydro unit in which water can be raised by means of
pumps and stored to be used later for the generation of electrical energy.
P-Q-Capability Diagram - describes the Reactive Power capability of a
Power Generating Module in context of varying Active Power at the Connection
Point.
Reactive Power - is the imaginary component of the Apparent Power at
fundamental Frequency, usually expressed in kilovar (kvar) or megavar (Mvar).
Relevant National Regulatory Authority - is the Energy Market Regulatory
(EMRA)
Relevant CDSO - is the CDSO to whose Network a Power Generating
Module is or will be connected. Relevant DSO - is the DSO to whose Network a
Power Generating Module is or will be connected.
21
Relevant Network Operator - is the operator of the Network to which a Power
Generating Module is or will be connected.
Relevant TSO - is the TSO in whose Control Area a Power Generating Module,
Demand Facility, Demand Unit or Distribution Network Connection is or will be
connected to the Network at any Voltage level
Secured Fault - is defined as a fault, which is successfully cleared by Network
protection according to the Network Operator’s planning criteria.
Setpoint - is a target value for any parameter typically used in control schemes.
Significant Power Generating Module - is a Power Generating Module which is
deemed significant on the basis of its impact on the cross-border system performance via
influence on the control area’s security of supply, which is identified according to the
criteria set forth in this Regulation and falls within one of the categories provided in
ARTICLE 10(6).
Slope - is the ratio of the change in Voltage, based on nominal Voltage, to a change
in Reactive Power infeed from zero to maximum Reactive Power, based on maximum
Reactive Power.
Statement of Compliance - is a document provided by the Power Generating
Facility Owner to the Network Operator stating the current status with respect to
compliance itemised for each relevant element of this Regulation.
Steady-State Stability - if the Network or a Synchronous Power Generating Module
previously in the steady-state reverts to this state again following a sufficiently minor
disturbance, it has Steady-State Stability.
Synchronous Compensation Operation - is the operation of an Alternator without
prime mover to regulate Voltage dynamically by production or absorption of Reactive
Power
Synchronous Area - means an area covered by interconnected TSOs with a
common System Frequency in a steady state such as the Synchronous Areas Continental
Europe (CE), Cyprus (CY), Great Britain (GB), Ireland (IRE), Northern Europe (NE) and
the power systems of Lithuania, Latvia and Estonia (Baltic) as a part of a Synchronous
Area.
Synchronous Power Generating Module - is an indivisible set of installations which
can generate electrical energy. It is either a

a single synchronous unit generating power within a Power Generating
Facility directly connected to a transmission, distribution or closed
distribution Network, or

an ensemble of synchronous units generating power within a Power
Generating Facility directly connected to a transmission, distribution or
closed distribution Network with a common Connection Point, or

an ensemble of synchronous units generating power within a Power
Generating Facility directly connected to a transmission, distribution or
closed distribution Network that cannot be operated independently from
each other (e. g. units generating in a combined-cycle gas turbine facility),
or
22

a single synchronous storage device operating in electricity generation mode
directly connected to a transmission, distribution or closed distribution
Network, or

an ensemble of synchronous storage devices operating in electricity
generation mode directly connected to a transmission, distribution or closed
distribution Network with a common Connection Point.
Synthetic Inertia - is a facility provided by a Power Park Module to replicate the effect of
Inertia of a Synchronous Power Generating Module to a prescribed level of performance.
Transmission System Operator (TSO) - is a natural or legal person
responsible for operating, ensuring the maintenance of and, if necessary,
developing the transmission system in a given area and, where applicable, its
interconnections with other systems, and for ensuring the long-term ability of the
system to meet reasonable demands for the transmission of electricity.
U-Q/Pmax-profile - is a profile representing the Reactive Power capability
of a Power Generating Module in context of varying Voltage at the Connection
Point.
Underexcitation Limiter - is a control device within the AVR, the purpose of
which is to prevent the Alternator from losing synchronism due to lack of
excitation.
Voltage - unless stated otherwise, Voltage refers to the root-mean-square
value of the positive sequence of the phase-to-phase Voltages at fundamental
Frequency.
1 pu grid Voltage - for the 400 kV grid Voltage level (or alternatively
commonly referred to as 380 kV level) the reference 1 pu value is 400 kV, for other
grid Voltage levels the reference 1 pu Voltage may differ for each TSO in the same
synchronous area i.e. the Voltage range in kV for all TSOs within a synchronous
area may not be the same
[Definitions added; harmonization with ENTSO-E code HVDC]
DC-connected Power Park Module means a Power Park Module that is
connected via one or more Interface Point(s) to one or more HVDC System(s).
Unless otherwise stated, Power Park Module referred to in this Regulation means a
DC-connected Power Park Module;
DC-connected Power Park Module Owner means a natural or legal entity
owning a DC-connected Power Park Module;
Embedded HVDC System means a HVDC System connected within a
Synchronous Area or within a Control Area that is not installed for the purpose of
connecting a DC-connected Power Park Module at the time of installation, nor
installed for the purpose of connecting a Demand Facility;
Existing HVDC System means an HVDC System which is not a New HVDC
System;
Grid User means the System User using the transmission or distribution system, as
identified in this Regulation in relevant requirements. The term means any System
User (other than the Relevant Network Operator or Relevant TSO) to whom the
requirement applies;
23
HVDC System Maximum Current means the highest phase Current, associated
with an operating point inside the U-Q/Pmax-profile of the HVDC Converter
Station at Maximum HVDC Active Power Transmission Capacity;
HVDC Converter Station means part of an HVDC System which consists of one
or more HVDC Converter Units installed in a single location together with
buildings, reactors, filters, reactive power devices, control, monitoring, protective,
measuring and auxiliary equipment;
HVDC Converter Unit means a unit comprising one or more converter bridges,
together with one or more converter transformers, reactors, converter unit control
equipment, essential protective and switching devices and auxiliaries, if any, used
for the conversion;
HVDC System means an electrical power system which transfers energy in the
form of high-voltage direct current between two or more AC buses. A HVDC
System comprises at least two HVDC Converter Stations with DC transmission
lines or cables between the HVDC Converter Stations. In case of a back-to-back
system the HVDC System comprises only one HVDC Converter Station with direct
DC circuit connection between the pair of HVDC Converter Units. A HVDC
System has at least two Interface Points;
HVDC System Owner means a natural or legal entity owning a HVDC System;
Maximum HVDC Active Power Transmission Capacity means the maximum
continuous Active Power which an HVDC System can exchange with the Network
at each Connection Point as defined in the Connection Agreement or as agreed
between the Relevant Network Operator and the HVDC System Owner. It is also
referred to in this Regulation as Pmax;
Minimum HVDC Active Power Transmission Capacity means the minimum
continuous Active Power which an HVDC System can exchange with the Network
at each Connection Point as defined in the Connection Agreement or as agreed
between the Relevant Network Operator and the HVDC System Owner. It is also
referred to in this Regulation as Pmin;
New HVDC System means a HVDC System for which
 with regard to the provisions of the initial version of this Regulation, a final
and binding contract of purchase of the main plant has been signed after the
day which is two years after the day of the entry into force of this
Regulation, or,
 with regard to the provisions of the initial version of this Regulation, no
confirmation is provided by the HVDC System Owner, with a delay not
exceeding thirty months as from the day of entry into force of this
Regulation, that a final and binding contract of purchase of the main plant
exists prior to the day which is two years after the day of the entry into force
of this Regulation, or,
 with regard to the provisions of any subsequent amendment to this
Regulation, a final and binding contract of purchase of the main plant has
been signed after the day which is two years after the entry into force of any
subsequent amendment to this Regulation;
[Definitions added; harmonization with ENTSO-E code OP& S]
24
D-2: two days ahead (before) “D”
D-1 : the day ahead (before) “D”
D+1: the day after “D”
Week. For the process of outage scheduling the week is defined from Saturday till Friday
Adequacy means the ability of in-feeds into an area to meet the demand in this area
Availability Plan means the combination of all planned Availability Statuses for a
Relevant Asset for a given time period
Availability Status means the capability for a given time period of a Power Generating
Module, grid element, Demand Facility, or another facility to provide service, whether or
not it is in operation;
Constraint means a situation in which there is a need to implement Remedial Action in
order to respect Operational Security Limits
Forced Outage means the unplanned removal from service of a Relevant Asset for any
urgency reason that is not under the operational control of the respective operator;
Outage Coordination Process means the process of coordinating the Availability Plans of
all Relevant Assets
Outage Coordinating TSO means the TSO to which a Relevant Asset is directly
connected to its Transmission System or connected via a Transmission Connected
Distribution Network or a Transmission Connected Closed Distribution Network
Outage Incompatibility means the state in which a combination of the Availability Status
of one or more Relevant Grid Elements, Relevant Power Generating Modules, and/or
Relevant Demand Facilities and the best estimate of the forecasted electricity grid situation
leads to violation of Operational Security Limits taking into account Non Costly Remedial
Actions at the TSO‘s disposal
Outage Planning Agent means the role of planning the Availability Status of a Relevant
Power Generating Module, a Relevant Demand Facility or a Relevant Grid Element
Relevant Asset means any Relevant Demand Facility, Relevant Power Generating
Module, or Relevant Grid Element partaking in the Outage Coordination Process
Relevant Demand Facility means a Demand Facility which participates in the Outage
Coordination Process as its Availability Status influences cross-border Operational
Security;
Relevant Grid Element means a grid element located in a Transmission System, in a
Distribution Network, or in a Closed Distribution Network which participates in the
Outage Coordination Process as its Availability Status influences cross-border Operational
Security
Relevant Power Generating Module means a Power Generating Module which
participates in the Outage Coordination Process as its Availability Status influences crossborder Operational Security
Week-Ahead means the week before the calendar week of operation
Year-Ahead means the year before the calendar year of operation
[Definitions added; harmonization with ENTSO-E code CACM]
Individual Grid Model means a data set, describing power system characteristics
(generation, load and grid topology) and related rules to change these characteristics during
capacity calculation, prepared by TEIAS, to be merged with other Individual Grid Model
components in order to create the Common Grid Model,
25
Physical Congestion means any network situation where forecasted or realised power
flows violate the thermal limits of the elements of the grid and voltage stability or the angle
stability limits of the power system,,
Remedial Action means a measure applied by TEIAS, manually or automatically, in order
to maintain operational security,
[Definitions added; harmonization with ENTSO-E code FCA]
Forward means the timeframe in which transmission rights are allocated ahead of the Day
Ahead timeframe;
Long Term means a time period longer than 24 hours;
(2) The other terms and abbreviations used in this Regulation have the meaning and
scope in the relevant legislation.
ARTICLE 5 Regulatory Aspects
[New Article, harmonization with ENTSO-E codes]
1.
This Regulation and its applications is based on the provisions set forth by Article
1 of the Electricity Market law No. 6446 dated 14/3/2013 and shall respect the principle of
non-discrimination, temperance and transparency and the principle of optimization
between the highest overall efficiency and lowest cost for all involved parties. It shall also
respect provisions set forth in Article 10 of the Constitution dated November 7, 1982.
2.
Notwithstanding the above, the application of the principle of non-discrimination
and the principle of optimisation between the highest overall efficiency and lowest total
costs while maintaining Operational Security as the highest priority for all involved parties
shall be balanced with the aim of achieving the maximum transparency in issues of interest
for the market and the assignment to the real originator of the costs. This shall be reflected
in objective differences in treatment of demand technologies with different inherent
characteristics. In addition, unnecessary investments in some geographic areas should be
avoided in order to ensure that their respective regional specificities are appropriately taken
into account. The Relevant Network Operator shall have the right to take into account
these differences when defining requirements, in compliance with the provisions of this
Regulation.
3.
Any decision by a Network Operator other than the Relevant TSO and any
agreement between a Network Operator other than the Relevant TSO and a Demand
Facility Owner or Distribution Network Operator shall be exercised in compliance with
and respecting the Relevant TSO’s responsibility to ensure system security according to
national legislation.
4.
Since the Distribution Network Operator is not the owner of the asset that it
operates, the Distribution Network Operator shall ensure that TEDAS is informed and
involved whenever necessary.
ARTICLE 6 Recovery of Cost
[New Article, harmonization with ENTSO-E codes]
1.
The costs related to the obligations referred to in this Regulation which have to be
borne by Regulated Network Operators shall be assessed by EMRA.
26
2.
Costs assessed as reasonable and proportionate shall be recovered by Regulated
Network Operators in a timely manner via network tariffs or any other appropriate
mechanisms as defined by EMRA.
3.
If requested to do so by EMRA, regulated Network Operators shall, within 3
months of such a request, use best endeavors to provide such additional information as
reasonably requested by EMRA to facilitate the assessment of the costs incurred
ARTICLE 7 Confidentiality Obligations
[New Article, harmonization with ENTSO-E codes]
1.
The present Article applies to TEIAS, and when appropriate to DSO, CDSO and
any other Reserve Provider, Power Generating Facility Operator, Demand Facility
Operator and Owners of these Facilities, Designated Nominated Electricity Market
Operators, Allocation Platforms and Market Participants, Significant grid users, and
Relevant network operators defined in the following sections as “ TEIAS and any relevant
Party”.
2.
TEIAS and any relevant Party, shall preserve the confidentiality of commercially
sensitive information obtained in the course of carrying out its activities, and shall prevent
information about its own activities which may be commercially advantageous to third
parties from being disclosed in a discriminatory manner.
In particular, TEIAS and any relevant Party, shall not disclose any commercially sensitive
information to the remaining parts of its own structure, unless this is necessary for carrying
out a business transaction. In order to ensure the full respect of the rules on information
unbundling, any relevant Party shall ensure that TEIAS remaining part of the undertaking
do not use joint services, such as joint legal services, apart from purely administrative or IT
functions. Such provision also applies in similar cases to TEIAS and any relevant Party.
The present Article shall comply with the provisions set forth in Articles 13 and 53 of the
Statistic Law N° 5429 of 10/11/2005.
3.
TEIAS and any relevant Party, shall not misuse commercially sensitive information
obtained from third parties in the context of providing or negotiating access to the system.
4.
Information necessary for effective competition and the efficient functioning of the
electricity market shall be made public. That obligation shall be without prejudice to
preserving the confidentiality of commercially sensitive information. TEIAS and any
relevant Party shall preserve the confidentiality of the information and data submitted to
them in fulfillment of the obligations under this Regulation and shall use them exclusively
for the purpose they have been submitted in compliance with this Regulation, notably to
verify the compliance of requirements set forth in this Regulation.
5.
Disclosure of confidential information and data may occur in case a TEIAS and any
relevant Part are obliged to disclose it. Such disclosure shall be reported to the owner of
such information and data.
6.
In case of disclosure for other purposes than those described above, TEIAS and any
relevant Party are shall seek the consent of the owner of such information and data.
27
7.
TEIAS and any relevant Party shall provide for – in writing - the motivation for
this disclosure. This consent cannot be unreasonably withheld. In case of disagreement, the
plaintive shall send a written request to TEIAS which is bound to send a reply within 60
days following the receipt of the complaint. In case of ongoing disagreement, dispute
resolution shall be treated under laws and regulations into force.
8.
In the event that the Regional Security Coordination Centre is implemented in
Turkey, the Centre shall preserve the confidentiality of the information and data submitted
to them in connection with this Regulation and shall use them exclusively for the purpose
they have been submitted, in compliance with this Regulation.
9.
In the frame of Interconnection Agreements, TEIAS and any relevant Party are
bound by the confidential provisions as described above.
ARTICLE 8 Relationship with European Network Codes
[New Article, harmonization with ENTSO-E codes]
1.
The Present Regulation has been drafted in accordance with Turkey’s commitment
to harmonize its own legislation with the ENSTO-E ones, without prejudice to a proper
functioning of national electricity market, and more particularly, transmission and
distribution activities.
2.
Any conflict arising between this Regulation, the ENTSO-E Network Codes, the
Electricity Transmission Grid Regulation published on 28th of May 2014 and other
existing regulations shall give the precedence to the present Regulation.
ARTICLE 9 Amendment of contracts and general terms and
conditions
[New Article, harmonization with ENTSO-E codes]
1.
The amendments made in the present Regulation are automatically binding to
existing Connection Agreements, to System Usage Agreements and related General Terms
and Conditions are amended according to the present Regulation.
PART II
Significant facilities and Significant Grid Users
ARTICLE 10 Significant Power Generating Modules
[New Article, harmonization with ENTSO-E code RFG Article 3]
1. The requirements set forth by this Regulation shall apply to New Power Generating
Modules which are significant according to the provisions of this Regulation unless
otherwise provided in this Regulation.
28
2. The requirements set forth by this Regulation shall apply to Existing Power Generating
Modules which are significant according to the provisions of this Regulation. TEIAS shall
have the right to re-assess, in case of factual change such as the evolution of system
requirements (e.g. penetration of renewable energy sources, smart grids, distributed
generation, demand response, etc.), the applicability of the requirements set forth by this
Regulation to Existing Power Generating Modules regularly, but not more often than every
three years. TEIAS shall notify the launch of the procedure for re-assessment on its
website. The date of notification on the website shall constitute the first day of the launch
of the procedure for re-assessment. A public consultation shall be conducted in the frame
of the procedure for re-assessment. Prior to TEIAS carrying out the quantitative CostBenefit Analysis an initial qualitative comparison of costs and benefits shall be undertaken
in order to determine the cases of sizes of Power Generating Modules or types of Power
Generating Modules or locations of Power Generating Modules or clauses of this
Regulation for which there may be a viable case for application to Existing Power
Generating Modules. Where this preparatory stage demonstrates that a subsequent
analytical Cost-Benefit Analysis has a reasonable prospect of demonstrating positive costbenefit, TEIAS may proceed with a sound and transparent quantitative Cost-Benefit
Analysis, including the costs of requiring compliance that shall demonstrate the socioeconomic benefit of application of the requirements set forth by this Regulation to Existing
Power Generating Modules. Where the preparatory stage or later stage demonstrate that
applicability of the Regulation to Existing Power Generating Modules is not required no
further action is to be undertaken.
3. With regard to Power Generating Modules not yet connected to the Network:
a) Within a delay not exceeding thirty months as from the day of entry into force of
this Regulation, the Power Generating Facility Owner shall provide the Relevant
Network Operator with a confirmation of final and binding contracts it has
concluded for the construction, assembly or purchase of the main plant of a Power
Generating Module with relevance to the provisions of this Regulation and which
exists prior to the day, which is two years after the day of entry into force of this
Regulation.
b) The confirmation shall at least indicate the contract title, its date of signature and
of entry into force, and the specifications of the main plant to be constructed,
assembled or purchased.
c) The Relevant Network Operator may demand that EMRA confirms the
existence, relevance and finality of such a contract, i.e. that its material terms can
no longer be changed by one of the parties to the contract unilaterally and that no
party to the contract has the right to terminate it at will. The Power Generating
Facility Owner shall supply EMRA with all documents EMRA requests in order to
ascertain that a binding and final contract exists.
1) In accordance with ARTICLE 10 (3) (a) and (b) above, the Relevant
Network Operator is provided with sufficient evidence of the existence of
binding and final contracts for the construction, assembly or purchase of the
main plant of a Power Generating Module exists prior to the day, which is
two years after the day of entry into force of this Regulation; or
2) Following the verification performed by EMRA in accordance with
ARTICLE 10 (3) (c), it is ascertained that binding and final contracts for the
29
construction, assembly or purchase of the main plant of a Power Generating
Module exist prior to the day, which is two years after the day of entry into
force of this Regulation.
d) In case the Power Generating Facility Owner does not provide the Relevant
Network Operator with the confirmation within the delay set forth in ARTICLE 10
(3) (a), the Power Generating Module shall be considered as a New Power
Generating Module.
4. The applicability and extent of the requirements a Power Generating Modules has to
comply with depends on the Voltage level of their Connection Point and their Maximum
Capacity according to the categories defined in ARTICLE 10 (6).
5. Power Generating Modules which are considered to be Significant Power Generating
Modules within the scope of this Regulation are categorized as follows:
a) A Power Generating Module is of Type A if its Connection Point is below 66 kV
and its Maximum Capacity is 0.8 kW or more. Requirements applicable to Type A
Power Generating Modules are the basic level requirements, necessary to ensure
capability of generation over operational ranges with limited automated response
and minimal system operator control of generation. They ensure there is no wide
scale loss of generation over system operational ranges, thereby minimizing critical
events, and include requirements necessary for wide spread intervention during
system critical events.
b) A Power Generating Module is of Type B if its Connection Point is below 66 kV
and its Maximum Capacity is at or above 1 MW. TEIAS shall have the right to reassess the determination of the threshold regularly, if relevant circumstances have
changed materially, but not more often than every three years. A public
consultation shall be conducted in the frame of the procedure for re-assessment.
Following any change to thresholds any Power Generating Module that has been
moved to a new type will not automatically have to comply retroactively with the
additional requirements but will be subject to the same procedure as applied to
Existing Power Generating Modules in line with ARTICLE 159. Requirements
applicable to Type B Power Generating Modules provide a wider level of
automated dynamic response with higher resilience to more specific operational
events to ensure use of this higher dynamic response and a higher level system
operator control and information to utilize these capabilities. They ensure
automated response to alleviate and maximize dynamic generation response to
system events, greater Power Generating Module resilience of these events to
ensure this dynamic response and better communication and control to leverage
these capabilities.
c) A Power Generating Module is of Type C if its Connection Point is below 110
kV and its Maximum Capacity is at or above 50 MW. TEIAS shall have the right to
re-assess the determination of the threshold regularly, if relevant circumstances
have changed materially, but not more often than every three years. A public
consultation shall be conducted in the frame of the procedure for re-assessment.
Following any change to thresholds any Power Generating Module that has been
moved to a new type will not automatically have to comply retroactively with the
additional requirements but will be subject to the same procedure as applied to
Existing Power Generating Modules in line with ARTICLE 159. Requirements
30
applicable to Type C Power Generating Modules provide refined, stable and highly
controllable (real time) dynamic response to provide principle ancillary services to
ensure security of supply. These requirements cover all operational Network states
with consequential detailed specification of interactions of requirements, functions,
control and information to utilize these capabilities. They ensure real time system
response necessary to avoid, manage and respond to system events. These
requirements provide sufficient generation functionality to respond to both intact
and system disturbed situations, and the need for information and control necessary
to utilise this generation over this diversity of situations.
Maximum
capacity Maximum
capacity Maximum
capacity
threshold from which on a threshold from which on a threshold from which on a
Power Generating Module Power Generating Module Power Generating Module
is of Type B
is of Type C
is of Type D
1 MW
50 MW
75 MW
Table 1: Thresholds for Type B, C and D Power Generating Modules
d) A Power Generating Module is of Type D if its Connection Point is at 110 kV or
above. A Synchronous Power Generating Module or Power Park Module is of Type
D as well if its Connection Point is below 110 kV and its Maximum Capacity is at
or above 75 MW. TEIAS shall have the right to re-assess the determination of the
threshold regularly, if relevant circumstances have changed materially, but not
more often than every three years. A public consultation shall be conducted in the
frame of the procedure for re-assessment. Following any change to thresholds any
Power Generating Module that has been moved to a new type will not
automatically have to comply retroactively with the additional requirements but
will be subject to the same procedure as applied to Existing Power Generating
Modules in line with ARTICLE 159. Requirements applicable to Type D Power
Generating Modules are in particular specific for higher Voltage connected
generation with impact on entire system control and operation. They ensure stable
operation of the interconnected Network, allowing the use of ancillary services
from generation Europe wide.
e) Pump-storage Power Generating Modules shall fulfil all requirements in both
generating and pumping operation mode. Synchronous Compensation Operation of
Pump-Storage Power Generating Modules shall not be limited in time by technical
design of the Power Generating Modules. Pump-Storage variable speed Power
Generating Modules shall fulfil all requirements applicable to synchronous Power
Generating Modules and in addition those set forth in ARTICLE 54 (2) (b), if they
are of Type B, C or D.
f) Without prejudice to the general applicability of the requirements set forth in this
Regulation, a Power Generating Facility Owner, the Network Operator of an
industrial site and the Relevant Network Operator to whose Network the Network
of the industrial site is connected to, shall have the right in coordination with
TEIAS, with respect to Power Generating Modules which are embedded in the
Networks of industrial sites, to agree on conditions for disconnection of such Power
Generating Modules together with critical loads, which secure production
processes, from the Relevant Network Operator’s Network. The only objective of
such an agreement shall be to secure production processes of such a site in case of
disturbed conditions in the Relevant Network Operator’s Network. The
31
requirements of this Regulation, notwithstanding such an agreement, shall apply to
Power Generating Modules embedded in the Networks of such industrial sites.
g) Without prejudice to the general applicability of the requirements set forth in this
Regulation, a requirement of this Regulation shall not apply to Power Generating
Modules of facilities for combined heat and power production (CHP) embedded in
the Networks of industrial sites in the following cumulative circumstances:
- the primary purpose of these facilities is to produce heat for production
processes of this industrial site;
- the generation of heat and power are rigidly coupled to each other, i. e. any
change of heat generation results inadvertently in a change of Active Power
generation and vice versa;
- the Power Generating Modules are of Type A, B or C according to
ARTICLE 10(6) (a) to (c); and
- the requirement is related to the capability maintain constant Active Power
output or to modulate Active Power output other than ARTICLE 47 (1) (c)
and (e).
h) For the avoidance of doubt, combined heat and power generating facilities will
be regarded on their electrical Maximum Capacity.
ARTICLE 11 Significant
Facilities
Distribution
Networks
and
Demand
[New Article, harmonization with ENTSO-E code DCC Article 3]
1. The requirements set forth by this Regulation shall apply to Demand Facilities,
Distribution Networks and Distribution Network Connections.
2. Any pump‐storage Power Generating Module which has both generating and pumping
operation mode does not have to meet the requirements of this Regulation.
3. Any pumping module within a pump‐storage station which only provides pumping
mode is subject to the requirements of this Regulation, and shall be treated as a Demand
Facility.
4. Without prejudice to the general applicability of the requirements set forth in this
Regulation, the Network Operator of an industrial site and the Relevant Network Operator
to whose Network the industrial site is connected to, shall have the right in coordination
with TEIAS, with respect to Power Generating Modules which are embedded in industrial
sites, to agree on conditions for disconnection of critical loads from the Relevant Network
Operator’s Network. The only objective of such an agreement shall be to secure production
processes of such a site in case of disturbed conditions in the Relevant Network Operator’s
Network, using power generated from these Power Generating Modules. The requirements
of this Regulation, notwithstanding such an agreement, shall apply to all Demand Units
embedded in such an industrial site.
ARTICLE 12 Significant
Facilities
Distribution
32
Networks
and
Demand
1. For the purposes of the respective requirements in this Regulation a Significant
Distribution Network is categorized as either a:
a) Distribution Network: either connected to another Distribution Network or
Transmission Network. The single frequency requirement applicable to all
Distribution Networks is a basic level requirement, ensuring there is no wide scale
loss of generation over system operational ranges, thereby minimizing critical
events. It includes requirements necessary for wide spread intervention during
system critical events;
b) Distribution Network Connection to the Transmission Network. Requirements
applicable to a Distribution Network Connection set the capabilities of these
interfaces and the necessary automated responses and data exchange. These
requirements ensure operability of the Transmission Network and the functionality
to utilise the generation embedded within these Networks over system operational
ranges, and critical events;
c) Transmission Connected Distribution Network. Requirements applicable to a
Transmission Connected Distribution Network set the operational range of these
networks, the necessary automated responses and data exchange. These
requirements ensure the effective development and operability of the Transmission
Network and the functionality to utilize the generation embedded within these
networks over system operational ranges, and critical events;
d) Closed Distribution Network either connected to a Distribution Network or
Transmission Network. Requirements applicable to a Closed Distribution Network
provide a wider level of automated response, ensuring the functionality to utilize
over system operational ranges, thereby minimizing critical events, and include
requirements necessary for wide spread intervention during system critical events.
2. For the purposes of the respective requirements in this Regulation a Significant Demand
Facility is categorized as either a:
a) Transmission Connected Demand Facility. Requirements set the capabilities of
these interfaces and the necessary automated responses and data exchange. These
requirements ensure operability of the Transmission Network over system
operational ranges, and critical events;
b) Demand Facility either connected to a Distribution Network or Transmission
Network. Requirements applicable to a Demand Facility provide a wider level of
automated response, ensuring the functionality to utilize over system operational
ranges, thereby minimizing critical events, and include requirements necessary for
wide spread intervention during system critical events.
ARTICLE 13 Application to existing Demand Facilities and Existing
Distribution Network Connections
[New Article, harmonization with ENTSO-E code DCC Article 5]
33
1. The requirements of this Regulation shall apply to Existing Demand Facilities, Existing
Distribution Networks and Existing Distribution Network Connections deemed significant
regarding the provisions of this Regulation, according to the provisions of ARTICLE 63 or
by a decision of EMRA according to the provisions of ARTICLE 160.
ARTICLE 14 Reassessment of significance of existing demand
facilities and existing Distribution network connections
[New Article, harmonization with ENTSO-E code DCC Article 6]
1. Regularly but not more than every three years, TEIAS may reassess the applicability of
the requirements set forth by this Regulation to Existing Demand Facilities and Existing
Distribution Network Connections.
2. This reassessment and submission for EMRA approval shall be made in the conditions
set forth in ARTICLE 160.
3. TEIAS shall notify the launch of the procedure for reassessment on its website. The date
of notification on the website shall constitute the first date of the launch of the procedure
for reassessment.
ARTICLE 15 New demand facilities and new distribution network
connections
[New Article, harmonization with ENTSO-E code DCC Article 7]
1. Demand Facilities or Distribution Network Connections, not yet connected to the
Network shall be considered as Existing Demand Facilities or Existing Distribution
Network Connections, provided that sufficient evidence is provided to the Relevant
Network Operator and the following procedure is observed:
a) No later than thirty months as from the date of the entry into force of this
Regulation, the Demand Facility Owner or Distribution Network Operator shall
provide the Relevant Network Operator with confirmation of a final and binding
contract it has concluded for the construction, assembly or purchase of the Main
Plant of a Demand Facility or Distribution Network Connection. Those contracts
shall exist prior to the date which is two years after the date of the entry into force
of this Regulation.
b) The confirmation shall at least indicate the contract title, its date of signature and
entry into force, as well as the specifications of the Main Plant to be constructed,
assembled or purchased.
c) The Relevant Network Operator may demand that EMRA confirms the
existence, relevance and finality of such a contract, i.e. that its material terms can
no longer be changed by one of the parties to the contract unilaterally and that no
party to the contract has the right to terminate it at will. The Demand Facility
Owner or Distribution Network Operator shall supply EMRA with all documents
EMRA requests in order to ascertain that a binding and final contract exists.
d) The Demand Facility or Distribution Network Connection confirmed, in
accordance with the procedure set forth in points a) to c) above, shall be considered
34
as an Existing Demand Facility or Existing Distribution Network Connection,
provided that:
1) In accordance with paragraphs 1 (a) and (b) above, the Relevant Network
Operator is provided with sufficient evidence of the existence of binding
and final contracts for the construction, assembly or purchase of the Main
Plant of a Demand Facility or Distribution Network Connection prior to the
date, which is two years after the date of entry into force of this Regulation;
or
2) Following the verification performed by EMRA in accordance with point
(c) above, it is ascertained that binding and final contracts for the
construction, assembly or purchase of the Main Plant of a Demand Facility
or Distribution Network Connection exist prior to the date, which is two
years after the date of entry into force of this Regulation.
e) In case the Demand Facility Owner or Distribution Network Operator does not provide
the Relevant Network Operator with the confirmation within the delay set forth in point (a)
above, the Demand Facility or Distribution Network Connection shall be considered as a
New Demand Facility or a New Distribution Network Connection.
ARTICLE 16 Significance of new demand facilities and new
distribution network Connections
[New Article, harmonization with ENTSO-E code DCC Article 8]
A New Transmission Connected Demand Facility, New Demand Facility, New
Distribution Network or New Distribution Network Connection shall be deemed as
significant.
ARTICLE 17 Significant HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 3]
1. HVDC Systems which are deemed as significant according to the provisions of this
Regulation are categorized as follows:
(a)HVDC Systems connecting Synchronous Areas or Control Areas, including
back to back schemes;
(b)Embedded HVDC Systems within one Control Area and connected to the
Transmission Network; and
(c) Embedded HVDC Systems within one Control Area and connected to the
Distribution Network when a cross-border impact is demonstrated by TEIAS.
TEIAS shall consider the long-term development of the Network in this
assessment.
2. ARTICLE 81 [article 22 of HVDC NC], ARTICLE 86ARTICLE 88 [Article 27 of
HVDC NC], ARTICLE 88 [Article 29 of HVDC NC], addressing contribution of data and
studies, apply to Existing Power Generating Modules, Existing Distribution Networks,
Existing Demand Facilities and Existing HVDC Systems.
35
3. The requirements set forth by this regulation shall apply to New HVDC Systems which
are deemed as significant according to the provisions of this Regulation unless otherwise
provided for in this regulation.
4. With regards to the Embedded HVDC Systems within one Control Area referred to in
paragraphs 1(b) and (c) above, when they fall into one of the categories listed below:
1. HVDC Systems with at least one HVDC Converter Station owned by
TEIAS;
2. HVDC Systems owned by an entity which exercises control over the
Relevant TSO; or
3. HVDC Systems owned by an entity directly or indirectly controlled by an
entity which also exercises control over the Relevant TSO,
the following shall apply:
a. The provisions of ARTICLE 150 to ARTICLE 158 and ARTICLE 9,
[Article 53 to Article 57, Article 65 to Article 69, and Article 76 of HVDC
NC], do not apply; and
b. The HVDC System Owner shall ensure that the HVDC System is
compliant with the requirements under ARTICLE 67 to ARTICLE 98
[Article 7 to Article 35, Article 49 and Article 51 of HVDC NC]. This
compliance shall be maintained throughout the lifetime of the facility.
ARTICLE 18 Significant Grid Users
[New Article, harmonization with ENTSO-E OS NC Article 1]
The Significant Grid Users within the scope of the Electricity Transmission Grid
Regulation and Electricity Market Distribution Regulation are:
a)
Existing and New Power Generating Modules of type B, C and D according to
the criteria defined in ARTICLE 10 [Article 3(6) of NC RfG];
b)
Existing and New Transmission Connected Demand Facilities according to the
criteria defined in ARTICLE 13 and ARTICLE 16 [Article 5 and Article 8 of
NC DC] and all Existing and New Transmission Connected Closed
Distribution Networks;
c)
Significant Demand Facilities, Closed Distribution Networks and Aggregators,
in the case where they provide Demand Side Response directly to the TSO;
d)
Redispatching Aggregators and Providers of Active Power Reserve.
36
PART III
Planning, Design and Performance of the Transmission
System
SECTION 1
Transmission System Planning and Design Principles
ARTICLE 19 Planning Principles of the Transmission System
[Previous Article 5]
(1) TEIAS plans and develops the transmission system according to the principles
and procedures set out in the relevant legislation and its license.
(2) The transmission system shall be planned so as to ensure that the transmission
facilities will be loaded below the thermal limits, no user will be lost, the system stability
will not be disturbed, and the system will not be divided into islands, ensuring that the
voltage and frequency will remain within the limits set out in this Regulation in the event
that the Power Generating Modules transfer their maximum production to the system and
in the case of (N-1) constraint conditions in the system under the normal operating
conditions of the system.
(3) In the cases of (N-2) constraint conditions, methods of disconnecting the loads
of the generation or consumption facilities may be resorted to in order to avoid system
black-out.
(4) In the case of (N-2) constraint conditions at the connection points of nuclear
Power Generating Facilities to the system, it is planned so as to ensure that the
transmission facilities will be loaded below the thermal limits, no user will be lost, the
system stability will not be disturbed, and the system will not be divided into islands,
ensuring that the voltage and frequency will remain within the limits set out in this
Regulation.
(5) The nominal voltage values of the transmission system are 400, 154 and 66 kV.
In the basic system design, the system pre-fault planning voltage limits are planned
between 370 and 420 kV for 400 kV; between 146 and 162 kV for 154 kV; between 62 and
70 kV for 66 kV. These limits shall be deemed between 140 and 170 kV for regions with
transmission constraints.
(6) For the relevant planning year, the transmission system is planned in such a
manner that the voltage levels will be within the limits described in the fifth paragraph of
this article under the condition of loading above 5% of the system peak load.
(7) For the step-down power transformers in the transmission system, the
characteristics described in the Annex-1 of this Regulation are used.
ARTICLE 20 Design Principles of the Transmission System
[Previous Article 6]
(1) The maximum number of 400 kV feeders to be connected to a substation is
designed as seven and, and the maximum number of 154 kV feeders as fourteen. However,
higher number of feeder connections can be made on the condition that short circuit current
levels remain within limits and taking into consideration the economic condition and
system security.
(2)
The transmission system is designed in such a way that it can bear adequate
capacity under primary or N-1 constraint circumstances when hydro-electric and thermal
units are operating in full capacity at the same time. For this purpose, connection and
37
integration of Power Generating Modules with a total output power of less than 1500 MW
to the transmission system is made in such a way that all of the generation is transferred to
the system in case of a transmission circuit loss or N-1 constraint; and connection and
integration of Power Generating Modules with a total output power of more than 1500
MW is made in such a way that minimum 80 % of generation is transferred to the system
in case of the loss of two transmission circuits or N-2 constraint. In respect of the nuclear
Power Generating Facilities, it is designed in such a manner that the transmission capacity
will also be adequate under (N-2) constraint conditions. For this purpose, connection and
integration of nuclear energy Power Generating Modules to the transmission system is
made in a way to be able to transfer the entire generation to the system in the event of loss
of two transmission circuits or (N-2) constraints, regardless of their respective installed
capacities.
(3)
Transmission system shall be designed in such a manner that the generation
loss which may arise in the case of loss of two interrelated transmission lines or N-2
constraints will not exceed 1200 MW.
(4)
Transmission system shall be designed so as not to cause more generation
loss than the largest generation unit in the system causes in the event that, while a
transmission circuit or busbar is deactivated due to management or repair, another
transmission circuit or busbar is disabled due to a fault.
(5)
The 400 kV and 154 kV portions of the 400/154 kV substations are
designed in the order of two main busbars and one transfer busbar, with transfer feeder and
coupling feeder. However, they may be designed with transfer-coupling feeder with single
breaker if necessary. If the substation is gas-insulated, the 400 kV and 154kV side will be
designed with two main busbars and coupling feeder.
(6)
The 400 kV part of the 400 kV substations is designed in the order of two
main busbars and one transfer busbar with transfer feeder and coupling feeder, with
transfer-coupling feeder with single breaker, or with one-and-a-half breaker. If the
substation is gas-insulated, it is designed with two main busbars and coupling feeder.
(7)
The 400/154 kV substations are designed as 4x250 MVA or 6x250 MVA,
and under specific circumstances, as 8x250 MVA transformer. However, if the substation
is 6x250 MVA or 8x250MVA, the 400 kV part is designed with two main busbars and one
transfer busbar.
(8)
The 400/33 kV substations are designed to be 2x125, 4x125 MVA.
(9)
The 154 kV substations are designed with coupling feeder in the order of
two main busbars to allow the system to be operated as a regional island or leveled
network, or if no island supply is necessary, the 154 kV part of the 154 kV substations is
designed with transfer feeder in the order of main+transfer busbar or main+transfer busbar
which can be converted into two main busbars. The substations with two main busbars
may be installed with transfer busbar within the bounds of physical possibilities, and
according to the system needs.
(10) AC/DC/AC converter centers shall be installed in the case of international
asynchronous parallel connection.
(11) New substations connecting the 154 kV system to the distribution system
shall be designed as 2x100 MVA, 3x100, 4x100 MVA transformer order. Although the
design at new substations is made on the basis of 100 MVA transformers, but lower
capacity transformers can be used in due regard to lower loads. Capacity increase is
planned for cases where the actual loads of transformers reach 70 % of their Maximum
Capacity. For the substations using 100MVA transformers, the number of 33 kV line
feeders per transformer is designed as 8+1, one being used for the equipment such as
capacitor, reactor, etc. Arc furnace plants are connected at appropriate voltage level
depending on the power and location where it will be installed and its power, in order to
restrict flicker severity, harmonics and sudden voltage changes. Flicker severity, harmonics
38
and sudden voltage changes are measured by a remote accessible, sealable and datarecording measuring system, which will be in continuous operation.
(12) In cases where direct transformation is necessary, the transformers
connecting the 400 kV system to the distribution system are designed as 400/33 kV and
125 MVA. If the transformer’s secondary is triangle-connected, such transformers are
earthed using an earthing transformer.
(13) Three-phase fluctuating loads and loads supplied with single-phase
alternative current are connected to points where the short circuit power of the system is
high enough. The step-down transformers supplying single-phase alternative current loads
are connected between different phase pairs in order to minimize voltage imbalances. In
order to minimize voltage imbalances, step-down transformers supplying single-phase
alternative current loads are connected to the system as three phases, at the points where
system short circuit power is not high enough.
(14) The transmission system is designed in such a way that it will be resistant to
switch-on current in 63 kA and 31.5 kA three-phase symmetric fault, for 400 kV switch
equipment and 154 kV switch equipment, respectively. Short circuit fault currents are
limited to 16 kA at the voltage level of 3 kV. In the 400/33 kV substations to which only
the Power Generating Modules are connected from medium voltage, the short circuit fault
current is limited to 25 kA at the voltage level of 33 kV.
(15) With respect to earthing in design of the 400 kV and 154 kV systems;
a) In 400 kV and 154 kV system designs, earth fault factor is accepted as 1.4,
unless otherwise indicated by TEIAS.
b) In cases where a special earthing infrastructure is required for connections
to the transmission system, the technical requirements to be fulfilled for earthing and
the results of analyses to be conducted upon rises in voltage is communicated to the
user by TEIAS before connection.
c) The high voltage windings of transformers whose primary side is 66 kV and
above are designed as star-connected, allowing earthing connection at the star point.
Minimum 120 mm2 copper shall be used for substation primary earthing line. Earthing
connections are made using the connection system approved by TEIAS.
ç) At substations where short circuit power is high, the neutral point of the
secondary side of power transformers is earthed through a neutral resistance or
neutral reactor in order to restrict phase-earth fault currents.
d) The neutral points of the primary and secondary windings of 400/154 kV
star-star-connected autotransformers are earthed directly and their neutral points are
connected to the earthing network of the switch center. The neutral point of the
primary windings of star-triangle transformers connecting 400kV system to a
distribution system is earthed directly and the secondary winding is earthed through
the earthing transformer. The neutral point of the primary windings of star-star nonreverse wounded transformers connecting the 154kV system to a distribution system is
earthed directly, while the neutral point of the secondary winding is through the
earthing resistance or neutral reactor.
e) The neutral point of the secondary winding of a transformer connecting the
154kV system to a distribution system is earthed through a 1000A resistor or neutral
reactor.
f) Provisions of the Regulation on Earthing in Electrical Installations
published in the official gazette dated 21/08/2001 and no 24500 shall apply to the
matters not included in this Paragraph.
39
(16) In respect of the 400kV long transmission lines, serial capacitors are used
for reducing the inductive reactance of the line, when necessary.
(17) Shunt compensation is ensured through shunt reactors and shunt capacitors
in the system. Shunt reactors are designed to be connected to both line and busbar, or to the
busbar, if no overhead line is available. They are designed to be connected to the busbar at
the 154kV level, and to the tertiary windings of the 400/158kV autotransformers. The
shunt capacitors are installed to the busbars on the primary or secondary side of the 154kV
substations. The standard capacities of shunt reactors installed in the 400kV system are 72
MVAr, 97 MVAr, 121 MVAr, 145 MVAr, 183 MVAr and 160-250 MVAr at the voltage
level of 420 kV. The standard capacities of shunt reactors installed in the 154kV system
are 5 MVAr, 10 MVAr and 20 MVAr. Shunt reactors are designed to continuously operate
at the system voltages of 420 kV and 170 kV. Shunt reactors may also be installed as
adjustable. 154kV shunt reactors and capacitors are installed in the 154kV substations by
calculating the short circuit power and harmonic resonance risks of the related substation. 5
MVAr, 10 MVAr and 2x10 MVAr shunt capacitor groups and dynamic compensation
systems or reactors with adequate power are installed at the busbar on the secondary side
of 25 MVA, 50 MVA, 100 MVA and 125 MVA transformers at the 154kV substations for
the purpose of voltage regulation. Shunt capacitors are installed in such a way that they
will not exceed 20 % of the transformer capacity and in the form of two capacitor groups
that are connected to different feeders when necessary. The shunt reactors and capacitors
are connected to the connection points through the breakers and disconnectors.
(18) In selecting the routes and substation locations of transmission lines; all
technical, economical, social and environmental protection issues as well as applicable
legislation are considered. TEIAS takes the necessary steps to taken the transmission
system master plans are taken into account in the settlement plans of the relevant
municipality. Compliance with these master plans is followed up, and expropriation
procedures of transmission lines are finalized within the shortest time possible. For the
locations outside the zoning area, TEIAS takes the necessary steps to obtain necessary
permits from the competent authorities. Low-capacity transmission lines are replaced with
high-capacity multi-circuit transmission lines on the same route at settlement units with
high population density and at industrial zone considering the conditions. Substations are
planned and installed with the necessary infrastructure that enables remote no-man
operation, and in compliance with international design, installation, manufacturing and
performance standards developed, approved and used for electricity system plant and
equipment.
(19) A complete three phase crossing is made along the line for 400 kV
transmission lines longer than 120 km as indicated in Annex 2 of this Regulation. The
same approach is valid for 154 kV transmission lines longer than 45 km.
(20) 400kV transmission lines are installed using single-circuit poles and steelreinforced aluminum conductors (ACSR) with standard 954 MCM Cardinal (546 mm2)
and 1272 MCM Pheasant (726 mm2) section, in the form of triple or more beams in each
phase, or using conductors with higher bearing capacity, if necessary, provided that the
outer diameter and unit weight of the conductor will not be exceeded. 400kV lines having
the abovementioned characteristics are used on standard single- or multiple-circuit poles
designed on the basis of appropriate climate and line profile/mechanical loading
conditions.
(21) In the exceptional regions or regions with extreme ice load, instead of the
triple or multiple conductor on each beam, the conductors having an equivalent currentcarrying capacity may be installed on the poles specifically designed for the cases
requiring additional safety.
40
(22) In dense settlement areas where no route can be ensured for the overhead lines,
400kV XLPE copper-conductor underground cables with a minimum section of 2000 mm2
are installed.
(23) The 400kV and 154kV submarine cable connections are installed with XLPE
copper conductors with a minimum section of 1600 mm2.
(24) The conductor thermal capacities and thresholds used for energy flow planning
in the 400kV transmission system are set out in the Annex-3 of this Regulation.
(25) 154kV transmission lines are installed using single- or double- or multiplecircuit poles and standard 468-mm2 795 MCM Drake, 546-mm2 954 MCM Cardinal and
726-mm2 1272 MCM Pheasant steel reinforced aluminum conductor (ACSR), or
conductors with higher bearing capacity, if necessary, provided that the outer diameter and
unit weight of the conductor will not be exceeded. 154 kV lines generally contain a
conductor in every phase. In order to increase the carrying capacity of transmission lines in
very high demand regions, 154 kV multiple-circuit lines with multiple-beam conductors
are installed.
(26) In dense settlement areas where overhead line routes cannot be ensured, 154
kV XLPE copper- or equivalent aluminum-conductor underground cables with 1000-mm2
or 1600-mm2 section are installed.
(27) The conductor thermal capacities and thresholds as well as the types and
capacities of underground power cables used for energy flow planning in 154kV
transmission system are set out in the Annex-3 of this Regulation.
(28) In addition to the phase conductors, galvanized steel earthing wire is installed
at the top of poles, in order to protect the transmission line from lightning. In general, one
or more earthing wires are used on the 400kV and 154kV standard poles depending on the
design of the pole in order to protect the lines from the lightning. 96 mm 2 and 70 mm2
protection conductors are used on the 400kV and 154kV lines, respectively, as a standard.
(29) In the newly installed 400-kV or 154-kV power transmission lines, optical
ground wires (OPGW) which includes optical fibers the number and characteristics of
which are determined by TEIAS and complies with the Type Technical Specification of
TEIAS shall be used instead of one or both of the steel ground wires.
(30) In order to ensure appropriate insulation levels for the phase conductors of
transmission lines, chain-type porcelain, glass or composite silicone insulators are used.
(31) The 400kV and 154kV ambient conditions and system information used in
substation system design are set out in the Annex-4 of this Regulation. In cases where
surge arrester is used to restrict switching over-voltages, TEIAS and the user exchange
information on the technical characteristics of these practices. Understanding on the details
of each practice is reached in order to ensure the integrity of the planned system and the
harmony of design. Design of substation switchyards are made in compliance with the
sample single line diagrams given in the Annex-5 of this Regulation and in accordance
with the standard technical specifications of TEIAS.
SECTION 2
Technical Criteria Regarding Transmission System
Performance, Plant and Equipment
ARTICLE 21 System frequency and variations
[Previous Article 7]
(1)The nominal frequency of the system, which is 50 Hertz, shall be checked by
TEIAS in the range of 49.8-50.2 Hz.
41
ARTICLE 22 System voltages and variation limits
[Previous Article 8]
(1) Rated voltages of transmission system are 400, 154 and 66 kV. Under
normal operating conditions; a transmission system of 400 kV is operated between 340
kV and 420 kV and a transmission system of 154 kV is operated between 140 kV and
170 kV. Voltage alteration for a transmission system of 66 kV or less is 10%.
(2) Distribution level in the transmission system and voltage levels for internal
consumption are 34.5, 33, 31.5, 15.8, 10.5 and 6.3 kV.
(3) 400 kV and 154 kV systems are planned and operated in accordance with the
voltage thresholds given in Annex-8. The operating voltage thresholds are applied as the
values prior to changing the unit main transformer step settings after fault, or prior to shunt
compensation switching.
(4) When a system failure occurs, some parts of the 400 kV transmission
system can be permitted for an excessive voltage exposure of 450 kV that is
determined as the top voltage limit to activate excessive voltage protection.
ARTICLE 23 Transmission system voltage wave shape quality
[Previous Article 9]
(1) Installations, equipment and fittings connected to the transmission system
are designed in accordance with the voltage harmonic planning limit values indicated
in the Table 1, Table 2 and Table 3 given according to the voltage level in the Annex7. The values given in the Tables represent the proportional value of each voltage
harmonic to the main component.
(2) Upon filtering of the data related to the transient events, or circumstances
such as short-time interruption, voltage dip, voltage swell, etc. which occur during the
measurement period of power quality at the common connection points in the
transmission system, minimum 95% of the 10-minute average of the effective value of
each voltage harmonic measured with 3-second resolution should be smaller than or
equal to the values given in the Table 4, Table 5 and Table 6 given in the Annex-7.
(3) Under normal operating conditions, the total harmonic distortion measured
in the event that a facility and/or equipment is disabled at a connection point in the
transmission system may not exceed, for a period longer than 5% of the power quality
measurement period;
a) the total harmonic distortion limit of 3.5%, without exceeding the upper
limits given in the Table 4 in the Annex-7 for each of the harmonic voltages up to 40th
harmonic at 400 kV, and
b) the total harmonic distortion limit of 5%, without exceeding the upper limits
given in the Table 5 in the Annex-7 for each of the harmonic voltages up to 40th
harmonic at 154 kV.
c) the total harmonic distortion limit of 4%, without exceeding the upper limits
given in the Table 6 in the Annex-7 for each of the harmonic voltages up to 40th
harmonic under the level of 154 kV
(4) The total harmonic distortion is calculated using the following formula.
2
40
THBV 
 (U
h2
U1
h
)
x100
(5) In the formula above ( 4th paragraph)the following stands for:
42
Uh: effective value of the voltage harmonic at the level of h
U1: effective value of the main component
(6) TEIAS may allow short duration peaks in the harmonic distortion limits
given in the items (a), (b) and (c) of the third paragraph under exceptional
circumstances.
(7) The users connected to the transmission system should operate without
causing the voltage harmonic planning limit values to be exceeded at the common
connection points and other connection points which are close to the common
connection points. The users shall install devices in compliance with the IEC 61000-430 Class A measuring standard, which are capable of continuously and uninterruptedly
recording the voltage harmonic values. The said devices shall be operated by the user
if located on the ownership site of the user or by TEIAS if located on the ownership
site of TEIAS. The provisions related to the format of the data provided by those
devices, and transfer of such data to the TEIAS system shall be included in the
connection agreement to be entered into with the user.
ARTICLE 24 Sudden voltage changes
[Previous Article 10]
(1) Sudden voltage changes in the system that result from switching operations
cannot exceed ±3% of rated system voltage.
(2) Sudden voltage changes that happen as a result of shunt compensation
switching operations cannot exceed ±5% of rated system voltage.
ARTICLE 25 Voltage fluctuations and flicker
[Previous Article 11]
(1) Related to the voltage fluctuations at a common connection point due to the
alternating load of the users who have direct connection to the transmission system;
a) Rapid changes of voltages, which occur less than 10 times within 1 hour,
may not exceed 1% of the voltage level. In the case of rapid changes of voltage, which
occur less than 3 times within 1 hour; or as soon as such changes will not put the
transmission system or another user connected to the transmission system at risk,
TEIAS may allow for any voltage change up to 3% of the voltage level under the
exceptional circumstances. Rapid changes of voltages, which occur more than 10
times within 1 hour, are considered as flicker.
b) The transmission system short-term (Pst) and long-term (Plt) planning flicker
limit values are shown in the Table 7 given in the Annex-7. The long-term flicker
severity is calculated using the short-term flicker values and following formula.
Plt  3
1 12
3
Pst j

12 j 1
Upon filtering of the data related to the transient events, or circumstances such
as short-time interruption, voltage dip, voltage swell, etc. which occur during the
measurement period of power quality, minimum 95% of the short-term flicker values
43
should be smaller than or equal to the values given in the Table 7, or 99% thereof
should be smaller than or equal to 1.5 times those values.
c) The position of the existing and prospective users’ plant and equipment
related to the flicker values are taken into consideration in the assessment of the
connection of the fluctuating loads to the transmission system which cause flicker
limits below those given in the table in Appendix-7, conducted by TEIAS.
(2) The users connected to the transmission system should operate without
causing the flicker planning limit values to be exceeded at the common connection
points and other connection points which are close to the common connection points.
The user shall install and operate devices in compliance with the IEC 61000-4-30
Class A measuring standard, which are capable of continuously and uninterruptedly
recording the flicker values. The provisions related to the format of the data provided
by those devices, and transfer of such data to the TEIAS system shall be included in
the connection agreement to be entered into with the user.
ARTICLE 26 Phase imbalance
[Previous Article 12]
(1) All plant and equipment connected to the transmission system and their
parts in the switchyards should be designed to stand disturbance in wave shape
resulting from to phase imbalance.
(2) Under the normal operating conditions, if the transmission system elements
are disabled in a planned way, the ratio of minimum 95% of the 10-minute averages of
the efficient values of voltage negative component at the network main frequency
measured with 3-second resolution during the measurement period of power quality to
the voltage positive components at the network main frequency may not exceed 1% at
the voltage level of 400 kV or 1.5% at the voltage level of 154 kV or 2% at the voltage
levels below 154kV. With the approval of TEIAS, this ratio may increase to 1.4% at
the voltage level of 400 kV or 2% at the voltage level of 154 kV at the points where
the single-phase or two-phase loads are fed.
(3) Phase imbalances resulting from planned outages of transmission system
elements may be permitted upon TEIAS’s approval, provided that total harmonic
distortion level does not exceed the planning limit values defined for the connected
voltage level, such imbalances do not occur very often and do not last long. This is
stated in the connection agreement between the parties.
ARTICLE 27 Current harmonics
[Previous Article 13]
(1) The users of the transmission system are obliged to comply with the current
harmonic limit values indicated in the table given in the Annex-8. The values given in the
Table represent the proportional value of the efficient values of each current harmonic at
the common connection point to the efficient value of the main component of the
maximum load current. The users shall install and operate devices in compliance with the
IEC 61000-4-30 Class A measuring standard, which are capable of continuously and
uninterruptedly recording the 10-minute averages of the current harmonic values. The
provisions related to the format of the data provided by those devices, and transfer of such
data to the TEIAS system shall be included in the connection agreement to be entered into
with the user.
44
ARTICLE 28 Reactive power compensation
[Previous Article 14]
(1)The ratio of the inductive reactive power monthly drawn from the system by the
consumers directly connected to the transmission system or legal entities having a
distribution license to the active power drawn from the system may not exceed twenty
percent; and the ratio of the capacitive reactive power monthly supplied to the system by
the consumers directly connected to the transmission system or legal entities having a
distribution license to the active energy drawn from the system may not exceed fifteen
percent.
(2)The following terms are applicable for the implementation of 1st paragraph:
a) In respect of the users connected from the voltage level of 36kV or below
of the TEIAS substations; if more than one users are fed by the same busbar,
in order to determine the ratio of the inductive reactive power drawn from
the system or capacitive reactive power supplied to the system by the user
with the less number of feeders, it shall be assessed by taking the total sum
of the active power and reactive power at the measurement points of the MV
feeders of that user. However, if connection of the same user at a substation
is established through multiple and different busbars, it shall be assessed
individually at each busbar for the user.
b) If the user has more than one connection points which are directly
connected to the transmission system by a single line from the voltage levels
over 36 kV or connected to the same busbar in the user’s facility by more
than one lines, in order to determine the ratio of the inductive reactive power
drawn from the system or capacitive reactive power supplied to the system
to the active power, it shall be assessed by taking the total sum of the active
power and reactive power at such measurement points. In order to determine
the ratio of the inductive reactive power drawn from the system or
capacitive reactive power supplied to the system by the user directly
connected to the transmission system with different busbars in the user’s
facility by more than one lines from the voltage levels over 36 kV to the
active power, it shall be assessed individually for each busbar through which
that user is connected to the transmission system.
(3)If the monthly average power to be calculated taking into account the total
monthly active energy consumption measured is less than 5% of the connection agreement
power at the points subjected to the said measurements, no reactive penalty shall be
imposed for that month.
(4) The sanctions to be imposed on the users who fail to meet the ratios given in the
first paragraph with respect to the reactive power are set out in the connection and system
use agreements.
ARTICLE 29 Constraint conditions
[Previous Article 15]
(1) Highly probable transmission constraints in the transmission system are;
a) (N-1) constraint, which covers the disintegration of one of the following from
the system:
1) A transmission circuit,
45
2) A generation unit,
3) One of the connection elements of the Power Generating Module to the
transmission system,
4) A shunt compensation unit such as synchronous compensator, static VAr
compensator, shunt reactor or capacitor,
5) A serial compensation unit,
6) A transformer unit, or
7) An outer interconnection.
b) (N-2) constraint, which covers the disintegration of one of the following from
the system:
1) A transmission circuit and a second transmission circuit regardless of the
first one,
2) A transmission circuit and a transformer unit,
3) A transmission circuit and one of the connection elements of the Power
Generating Module to the transmission system,
4) One of the connection elements of the Power Generating Module to the
transmission system and a transformer unit,
5) One of the connection elements of the Power Generating Module to the
transmission system and a shunt compensation unit,
6) One of the connection elements of the Power Generating Module to the
transmission system and a serial compensation unit,
7) A transformer unit and a second transformer unit,
8) A transformer unit and a shunt compensation unit,
9) A shunt compensation unit and a second shunt compensation unit,
10) A transmission circuit and a shunt compensation unit,
11) A generation unit and a transmission circuit,
12) A generation unit and a transformer unit,
13) A generation unit and another generation unit,
14) A generation unit and a shunt compensation unit,
15) A transmission circuit and the serial compensation unit of another line
associated with that circuit,
16) A transformer unit and a serial compensation unit,
17) A generation unit and a serial compensation unit, or
18) Double-circuit line on the same pole.
c) Low-probability transmission constraints in the transmission system include:
1) Busbar fault,
2) Busbar coupling breaker fault,
3) Breaker fault,
4) Protection system fault,
5) Communication protection channel fault,
6) Unexpected (N-2) constraint conditions.
ARTICLE 30 Operating principles
[Previous Article 16][Article modified; harmonisation with ENTSO-E codes]
(1) Operating principles cover [Addition to article, harmonization with ENTSO-E
Network Code OS, Art 8.4,. System States] all necessary economically efficient
measures, precautions and operating principles ensuring a Normal State operation
of the system and preventing the propagation of Alert or Emergency State outside
of its Responsibility Area under system real-time operation conditions without
losing the stability of voltage, frequency and load flows within the defined limits.
46
Monthly, weekly and daily system operating programs are defined considering
actual operating conditions, climate changes, planned outages as well as unplanned
events that may occur in real-time operation and outage of transmission system,
and also events such as unexpected demand and weather conditions. [Addition to
the article harmonization with ENTSO-E policy 4 - Capacity Assessment Guidelines - B-G5.4 - C-G5.1] Daily data sets will be supplied for at least the
reference times 3:30, 7:30, 10:30, 12:30, 17:30 and 19:30 (C.E.T.). The models of
the TSOs network are adjusted with updated expected load profiles, production
schedules and expected topology (including outages, phase shifter transformer tap
positions). The models could be based on a current snapshot of the TSOs network
Within the scope of the operating principles; necessary measures required for
operation of the system in compliance with the operation time schedules under
actual operating conditions.
(2) Transmission system shall be operated safely [Addition to article,
harmonization with ENTSO-E Network Code OS, Art 13.1,. Contingency analysis and
handling] in the N case and after the consideration of the following Ordinary and
Exceptional Contingencies of the Contingency List ;
a)
Failure of a single transmission circuit, generating unit, reactive
compensator or any other reactive power supplier,
b)
Failure of two transmission circuits or a single transmission circuit
and another transmission circuit that earlier stopped operating if it occurs in distant
points of the system or subject lines are loaded below their capacities,
c)
Failure of one of the busbar,
d)
Failure of a single transmission circuit and a unit that earlier stopped
operating, a reactive compensator or other reactive power supplier, or
e)
Failure of a single or two transmission circuits, generating unit,
reactive compensator or any other reactive power supplier or a busbar defined as
External Contingency in the Interconnection Operation Agreement.
In this case, the failure which leads to (N-1) constraint may not cause any transmission
equipment to be overloaded or any frequency or voltage to be outside the specified limits,
or system instability.
(3) The followings are exempted from the operation principles defined in second
paragraph and in case of the occurrence of following situations; in case of (N-1) constraint
with due regard to system operating principles, operating rules for (N-2) constraint may be
shifted to provided that such shifting is economically advantageous:
a) Situation of opening of circuits and disconnection of substation connections in
case of any feeder or line fault at substations consisting of key connected circuits
constituting a part of the transmission system,
b) Situation of applying the measures taken by TEIAS such as increasing system
reserve capacity, establishment of protection systems those enable automatic shut-down of
generating units, forming of proper alternative operating strategies regarding (N-1) and (N2) constraints or reducing load of power flows on transmission equipment by means of
increasing hot reserve capacity, in order to reduce risks where increased due to bad
weather conditions such as thundering, icing, snowing, snow storming, flooding, strong
winding,
c) Situation of increased risks for loss or supply or demand.
Such kind of an operating regime prevails till weather conditions become convenient and
the system made reliable.
(4) In cases of faults causing (N-2) constraints, in order to prevent unacceptable
overloading of the main transmission equipment and to prevent demand loss, a new
47
generation schedule is prepared promptly. If the aforementioned schedule cannot be
implemented, planned interruption/restriction is applied as a post-fault measure.
[Article to be deleted, in contradiction to the ENTSO-E network code CACM Art 41
Redispatching and Countertrading]
(5) Demand control may not be performed for economical reasons.
(6) All post-fault measures and their reasons are communicated to the relevant legal
entities engaged in generation activity and to eligible consumers who may possibly be
affected. In this case, the provisions of this Regulation, which are related to the emergency
operation conditions shall apply. Following the fault leading to (N-1) constraint, necessary
measures are taken in order to return to normal operating condition in the least possible
time frame.
(7) Operating safety principles and procedures are applied to distribution
companies, legal entities engaged in generation activities as directly connected to the
transmission system and consumers connected to the transmission system. However, if the
operating safety or integrity of the system is at risk, specific operating procedures and
principles other than these provisions may be applied upon negotiations with the parties.
(8) Signal driving operation may be made through the de-energized TEIAS feeder
in order to locate a fault in the cable network by which the distribution companies are
connected to TEIAS, and at the request of a distribution company, for the substations with
open-type MV part, provided that the distribution company will be solely responsible for
security of life and property.
(9) Equipment in the feeders by which the distribution companies are connected to
TEIAS shall be replaced by TEIAS with the materials to be requested by the distribution
company as soon as possible in accordance with the cable and/or overhead line capacity of
the distribution company, at the request of the distribution company.
(10) step-down transformers to be used in the transmission system may be operated
in parallel according to the Annex-1 during the maneuver period.
[New articles harmonization with ENTSO-E Network Code OS, Art 8.1, 8.2, 8.13, 8.14,
System States; art 9.6, 9.14 Frequency Control Management; art 10.2, 10.4, 10.9 Voltage
control and reactive power management; art 11.3, 11.4, 11.5 short-circuit management; art
12.3 Power flow management; art 13.2, art 13.3, 13.4 Contingency analysis and handling;
art 15.1, 15.3 Dynamic stability management; art 19.1 Structural data exchange between
TSOs and DSOs within the TSO's Responsibility Area; art 32.10 Responsibility of the
TSOs and DSOs; art 16.1, 16.2, 16.3 Data exchange general requirements; art 19.2
Structural data exchange between TSOs and DSOs within the TSO's Responsibility Area].
(11) TEIAS shall in real-time operation differentiate five System States, based on
the Operational Security Limits, Operational Security Analysis, frequency control
management provisions defined in the present Regulation. On this basis, TEIAS shall
classify the System State of its Transmission System applying the following criteria:
a)Normal State:
i. voltage and power flows are within the Operational Security Limits and
frequency is within the frequency limits for the Normal State as defined in
the present Regulation ;
48
ii. Active and Reactive Power reserves are sufficient to withstand
Contingencies from the Contingency List defined according to Article
16(2); and
iii. operation of its Responsibility Area is and will remain within
Operational Security Limits even after a Contingency from the Contingency
List defined according to Article 16(2) and after effects of Remedial
Actions;
b) Alert State:
i. voltage and power flows are within their Operational Security Limits as
defined in the present Regulation; and
ii. at least one of the following conditions is fulfilled:
a. Active Power Reserve requirements are not fulfilled with lack of
more than 20% of the required amount of any of the following: FCR,
FRR and RR according to the dimensioning criteria, for more than
30 minutes and with no means to replace them;
b. frequency is within the frequency limits for the Alert State as
defined in the present Regulation;
c. at least one Contingency from the Contingency List defined
according to Article 16(2) can lead to deviations from Operational
Security Limits, even after effects of Remedial Actions;
c) Emergency State:
i. there is at least one deviation from Operational Security Limits as defined
in the present Regulation; or
ii. frequency is outside the frequency limits for the Normal State and outside
the frequency limits for the Alert State as defined in the present Regulation;
or
iii. at least one measure of the System Defense Plan is activated; or
iv. there is a complete loss of all Dispatching tools and facilities for more
than 30 minutes;
d) Blackout State:
i. loss of more than 50% of load in the Responsibility Area; or
ii. total absence of voltage for at least 3 minutes in the Responsibility Area
and triggering Restoration plans;
e) Restoration:
i. Procedures are implemented to bring frequency, voltage and other
operational parameters within the Operational Security Limits as defined in
the present Regulation ; and
ii. Demand Facilities are connected at a pace decided by TEIAS, depending
on the technical capability and feasibility of the Transmission System
resources and Significant Grid Users which are Power Generating Facilities
49
(12) In order to determine the System States, TEIAS shall perform in real time, at
least every 15 minutes, and in all Operational Planning phases, Operational Security
Analysis based on State Estimation, load flow and if applicable, short-circuit and dynamic
calculations, in order to monitor and evaluate the impact of directly interconnected TSOs,
Transmission Connected Distribution Networks and Transmission Connected Closed
Distribution Networks, on the Operational Security Limits specified in the present
Regulation in the N case and after each Contingency of the Contingency list as defined in
the Article 16(2), while considering the effect of the Remedial Actions
(13) When performing the Operational Security Analysis, TEIAS shall use the best
available data and information which reflect as closely as possible the real and forecasted
situation in the Transmission System and shall minimize inaccuracies and uncertainties and
continuously ensure high quality of the data and information used.
(14)TEIAS shall be entitled to gather from their grid users and distribution
companies the information which is part of his Responsibility and Observability Areas and
is required for the Operational Security Analysis, at least related to the following items:
a)generation;
b)consumption;
c)schedules;
d)balance positions;
e)structural data, topologies and planned outage of the substation and grid
equipments and;
f)own forecasts.
(15) When preparing a Remedial Action, including Redispatching or
Countertrading, or a measure of the System Defense Plan TEIAS shall, in the case of
mutual implications, cooperate with the Significant Grid Users and DSOs with Connection
Point directly to the Transmission System. TEIAS shall ex-ante cooperate with the DSOs
involved with the Remedial Action or the measure of the System Defense Plan, to assess
the impact of the Remedial Action on the Distribution Network, and coordinate with those
DSOs to select the Remedial Action or the measure of the System Defense Plan which
enhances Operational Security for all involved parties. Each affected DSO shall ex-ante
provide all the information necessary for this cooperation.
(16) When implementing a Remedial Action or a measure of the System Defense
Plan, each Significant Grid User or DSO with Connection Point directly to the
Transmission System shall execute the instructions given by TEIAS to maintain
Operational Security of the Transmission System, without undue delay. If TEIAS does not
instruct SGUs connected to the Distribution Network, DSOs shall communicate the
instructions of TEIAS to the Significant Grid Users.
(17) Each Grid User with Connection Point directly to the Transmission System
shall adopt the criteria and conditions including requirements for permission to resynchronize, defined by the TEIAS for re-synchronization.
(18) TEIAS shall be entitled to use actions to improve System Frequency quality
including restrictions on the Ramping Rates of Significant Grid Users and HVDC
interconnectors.
50
(19) TEIAS shall ensure Reactive Power reserve, with adequate volume and time
response, in order to keep the voltages within its Responsibility Area within the specified
limits.
(20) TEIAS shall define the Observability Area of the Neighboring Transmission
Systems and Transmission Connected Distribution Networks, which is relevant to
accurately and efficiently determine the System State.
(21) TEIAS shall elaborate a list of high priority Significant Grid Users which are
Power Generating Facilities or Demand Facilities, in terms of the conditions for their
disconnection and re-energizing.
(22) Each DSO and grid user with Connection Point directly to the Transmission
System shall automatically disconnect at specified frequencies and in predefined Active
Power steps, defined by the TSO.
(23) Each grid user must be designed so as to operate remaining connected the
transmission network for unlimited period of time in the following volatge range:
- A transmission system of 400 kV is operated between 340 kV and 420 kV;
- A transmission system of 154 kV is operated between 140 kV and 170 kV.
- A system with Voltage equal or below to 66kV is operated in a range of +/- 10%
(24) Each grid user which is a demand facility shall automatically or manually
disconnect at specified voltage in the specified timeframe defined by the TSO or by the
DSO if the Demand Facility has connection point to the distribution network.
[New articles harmonization with ENTSO-E policy 4 - Congestion Forecast - Standards –
C-S2.3, C-S6, C-S7, C-S9]
(25) TEIAS has to provide its complete DACF load flow data set with exchange
program on the EH ftp-server before 6 p.m. (C.E.T.), where it is accessible to all other
participating TSOs and thus make it available to the European Merging Function.
(26) TEIAS participates in the DACF method. Datasets for DACF. Daily data sets
will be supplied for at least the reference times 3:30, 07:30, 10:30, 12:30, 17:30 and 19:30
(C.E.T.).
(27) TEIAS shall carry out DACF N-1 security calculations according to Policy 3
of Operation Handbook of ENTSO-E.
[New articles harmonization with ENTSO-E Network Code OP&S, Art 9.3 . Individual
and Common Grid Model general provisions]
(28) The Individual Grid Models shall include:
a) Topology of the 220 kV and higher voltage Transmission System within
the Responsibility Area of TEIAS;
b) a model or an equivalent of the Transmission System with voltage below
220 kV with significant impact to the Transmission System;
51
c) thermal limits of elements of the Transmission System.
[New articles harmonization with ENTSO-E Network Code OP&S, Art 15.3 D-1 and
intraday Grid Models]
(29) Individual Grid Models shall contain at least the following variables: up to
date demand and Generation forecasts; for Power Generating Facilities connected to
Distribution Networks, aggregated Active Power output differentiated according to the
type of primary energy source; Topology of the Transmission System; and Remedial
Actions proposed for Constraints management.
[New Articles, harmonization with ENTSO-E code CACM - Art 41 Redispatching and
Countertrading]
(30) TEIAS may redispatch all available generation units and loads in accordance with
the appropriate mechanisms and agreements applicable to its Control Area, including
interconnectors.
The pricing of Redispatching and Countertrading shall be based on prices in the
relevant electricity markets for the relevant timeframe, or the costs of Redispatching
and Countertrading resources, calculated transparently on the basis of incurred costs.
Generation units and loads shall ex-ante provide all information necessary for
calculating the Redispatching and Countertrading cost to TEIAS. This information
shall be shared between the relevant TSOs for Redispatching and Countertrading
purposes only.
ARTICLE 31 Technical criteria for plant and equipment
[Previous Article 17]
(1) It is the user’s responsibility to ensure that the facilities and/or equipment of
the user connected to the transmission system meet the technical design and operating
criteria set out in this Regulation.
(2) The User shall ensure that the user’s plant and/or equipment will be
properly designed so as not to be affected in case of the faults which are repaired
within the fault repair time applied in the transmission system.
(3) Performance of the transmission system and detailed information about the
provisions to be satisfied at the connection point are provided by TEIAS upon request
of the user.
(4) The Users shall follow the procedures and principles as considered
necessary by TEIAS within the framework of the relevant legislation on the protection,
control and measuring systems in the feeders through which they will connect to the
transmission system and/or associated feeders.
(5) The User shall keep 10% operating reserve, namely at least 1 ea. from the
primary and secondary equipment which are used in the system to be connected to the
transmission system, and which are part of the transmission system.
52
(6) The substation of a user and/or plant and equipment and materials that will
be provided in accordance with a system control agreement, are designed,
manufactured and tested according to the technical specifications of TEIAS.
(7) The user shall ensure that the user’s plant and equipment do not cause
interference to and is compatible with the transmission system and that they are
compatible with;
a) Insulation levels of 400 kV and 154 kV of transmission system,
b) The harmonic voltage limits set out in this Regulation, or when necessary,
determined by TEIAS at the connection point for the user,
c) The flicker severity limits set out in this Regulation, or when necessary,
determined by TEIAS at the connection point for the user.
(8) The User’s compliance with this Regulation may be inspected by TEIAS
taking measurements at the connection points, when necessary.
(9) The User, at the User’s facilities and connection points, has to use isolators
which meet the minimum rated specific creepage distance of 25 mm/kV defined as the
“contamination level III” in IEC-815 and the other technical requirements set out in
the technical specifications of TEIAS. If isolators with a minimum rated specific
creepage distance of 31 mm/kV are recommended by TEIAS, the user shall use such
isolators in the user’s facilities.
(10) The line connecting the Power Generating Module to the transmission
system shall be constructed considering the plant responsibility boundaries set out in
the connection agreement and the site responsibility schedule given in the Annex-9.
(11) The User shall follow the TEIAS instructions for the switching order in the
switchyard according to the short circuit power at the connection point.
(12) For the connections to the transmission system at 400 kV and lower levels;
when a special earthing infrastructure is required, user is informed as soon as possible
by TEIAS about the technical criteria that should be followed for earthing and
evaluation results in case of voltage increase.
(13) The withstand capability for the switchgear of the transmission system to
the three-phase symmetrical fault current is 50 kA for 400 kV and 31.5 kA for 154 kV.
(14) High voltage windings of transformers with primary side 66 kV or above
must be star connected with the star point suitable for connection to earth. At least 120
mm2 copper is used for substation’s primary ground line.
(15) In areas with high short circuit power, neutral point of power transformers’
secondary side, is grounded via the neutral resistance or neutral reactor in order to limit
phase to earth fault currents. In addition, neutral earthing transformer is installed in the
distribution busbar for some special circumstances.
[New articles harmonization with ENTSO-E Network Code OS, art 9.6 Frequency Control
Management; ]
53
(16) Each Power Generating Module with Connection Point directly to the
Transmission System shall adopt the criteria and conditions including requirements for
permission to re-synchronize, defined by the TEIAS for re-synchronization
(17) Each Power Generating Module shall automatically disconnect at specified
frequencies, defined by TEIAS.
ARTICLE 32 Protection of the transmission system
[Previous Article 18]
(1) TEIAS shall carry out periodical operation, maintenance and test studies for
the protection systems of all feeders of the facilities within the ownership limits of
TEIAS, and take necessary measures to repair the failures in an expeditious manner.
(2) Each user shall take all necessary protection and monitoring precautions in
his own plant in order that the faults which may occur in his own plant will not affect
the transmission system, and vice versa
(3) For effective disconnection of plant and equipment from the transmission
system during the connection or, when required in accordance with the criteria set out
in the connection agreement, protection settings are made by the user under control
and coordination of TEIAS and may not be changed without consent of TEIAS.
(4) The User shall prepare his designs with respect to the protection system and
methodology for the purpose of protecting the transmission system in accordance with
this Regulation, then submits the same to TEIAS for approval, and apply the
coordinated protection settings.
(5) Access to the busbar disconnector and breaker contact data in respect of all
medium voltage feeders in the medium voltage busbar of TEIAS substations,
including busbar input, coupling, transfer and line feeders is subject to permission of
TEIAS, at the request of the relevant distribution company.
(6) Fault clearance by TEIAS and the user includes time for relay operation,
opening of the circuit breaker and telecommunication signaling. Maximum fault
clearance time for 400 kV and 154 kV lines is 140 milliseconds.
(7) Trip time of the breaker of a output distribution feeder belonging to TEIAS
is determined by TEIAS considering the short-circuit resistance period of the
transformers stepping from transmission down to distribution, the number of shortcircuits to which the transformer has been subjected through the said feeder, and the
maximum phase-to-phase short-circuit current which may arise between the
distribution center and TEIAS center. The maximum fault repair time including the
start-up of relay of the distribution feeder and tripping time of breaker in the case of
fault of a distribution feeder belonging to the User’s initial distribution centers
connected to the TEIAS busbar is 1.0 second for phase-earth faults, and 0.14 second
for maximum short-circuit current in the case of a phase-phase fault. This period of
54
0.14 second is the instantaneous current relay coordination value of the overcurrent
relays.
(8) The Users shall carry out the periodic operating, maintenance and testing
works for the protection systems of all feeders belonging to their facilities within their
ownership boundaries and take all necessary measures for this purpose and keep the
relevant reports available. In addition, the users shall take the necessary measures to
urgently repair the protection system faults of all feeders belonging to their facilities
within their ownership boundaries.
(9) The Users shall submit the lists of operating and fault-repair teams of their
facilities within their ownership boundaries to TEIAS in the periods as required by
TEIAS.
(10) The Users shall take the necessary measures in the distribution busbar
arrangements in order that the fault currents which may arise in the distribution system
will not reflect in the TEIAS busbar through more than two feeders.
(11) In respect of the protection equipment which should be installed in the
Power Generating Modules as per the second paragraph,
a) An excitation protection system shall be installed, which deactivates the unit
alternator if unit excitation system fails.
b) If required, TEIAS may request the fitting of pole slipping protection to the
unit after determining the necessary provisions.
c) If required, TEIAS may determine the necessary provisions for fitting of subsynchronous resonance protection to the unit.
ç) Any work or modification on the protection equipment or setting change,
which may affect the transmission system, may only be made under the supervision of
a technical observer from TEIAS.
(12) TEIAS installs the low frequency relays required for disconnecting the
demand using the low frequency relays as described in the ARTICLE 189 [previous
Article 63].
(13) The amount of demand to be automatically disconnected by the low frequency
relays due to the fact that the system frequency drops to the determined frequency levels is
determined by October 31st for the following one year, by TEIAS considering the system
conditions and put in effect after the Authority is informed.
[New articles harmonization with ENTSO-E Network Code OS, art 14.2, 14.3, 14.4
Protection]
(14) TEIAS shall at least every five years review and analyze the protection
strategy and concepts and when necessary adapt the protection functions to ensure the
correct functioning of the protection and the maintaining of Operational Security. After
every protection operation having impact outside of its own Responsibility Area, each TSO
shall assess whether the protection system in its Responsibility Area worked as planned
and shall undertake corrective actions if necessary
(15) TEIAS shall operate the protection of its Transmission System with Set-Points
that ensure reliable, fast and selective fault clearing, including backup protection for Fault
clearing in case of malfunction of the main protection system
55
(16) Each TSO shall install the necessary protection and backup protection
equipment within its Transmission System in order to automatically prevent Disturbance
propagation which can endanger the Operational Security of the interconnected
Transmission System.
SECTION 3
Design and Performance Conditions of the Power Generating
Modules
ARTICLE 33 Design and connection principles of Power Generating
Module switchyards
[Previous Article 19]
(1)The Power Generating Module switchyards are designed and developed, and connected
to the transmission system considering the following;
a)it main power transformers are installed with minimum 5 step changers
when non-loaded and the regulation band is to be  2 x 2.5 %. A regulation band
of  8 x 1.25 % is adequate for transformers with step changers when loaded,
under normal conditions.
b)The Power Generating Module switchyards are designed and installed in a
manner that generation loss shall not be more than the generation of biggest unit in
the system in cases where a transmission circuit or busbar stops operating due to a
fault in the aftermath of the planned outage of a single transmission circuit or
busbar.
c) The maximum length of the overhead line connections of units directly
connected to the transmission system shall not be longer than 5 km for units
whose annual load factor is equal to or more than 30 %, and shall not be longer
than 20 km in other cases.
ç)The transmission capacity defined for the connection of the Power
Generating Module to the transmission system is planned in such a way that, before
any fault;
1) the equipment is not loaded above its capacity,
2) voltages outside the limits set for normal operating conditions and inadequate
voltage regulation possibility are avoided, and,
3) system instability is avoided.
d) The capacity between a Power Generating Module and the transmission system is
also planned by considering the outage of any one of the followings due to a fault;
1) A single transmission circuit, a compensator or another reactive power
supplier,
2) Two transmission circuits or a single transmission circuit and another
transmission circuit that stopped operating earlier,
3) One of the busbars,
4) A single transmission circuit and a unit that stopped operating earlier, a
compensator or another reactive power supplier.
56
The transmission system is planned in such a way to unsure avoiding of system instability
due to faults mentioned in this sub-paragraph. Connections of Power Generating Modules
are designed in compliance with the sample single line diagrams given in the Annex-10 of
this Regulation.
e) The Maximum Capacity of Power Park Modules based on wind energy that
may be connected to the System at a connection point shall be determined based on the
evaluation of the technical analysis to be performed according to the TS EN 61400
series standards within the limits of acceptable power quality, load flow, constraint,
short circuit and other system surveys set out in the relevant articles of this Regulation.
The requirements set out in the ANNEX-18 of this Regulation shall be applicable for
connection of wind energy Power Park Modules to the system.
ARTICLE 34 Design and performance principles of the existing
Power Generating Modules
[Previous Article 20]
(1) Design and performance conditions with respect to the generating units
include the technical and design criteria which should be fulfilled by the units directly
connected to the transmission system and the units connected to the user’s systems.
(2) The thermal and hydroelectric Power Generating Modules with an
Maximum Capacity below 30 MW are not subject to these conditions. For the Power
Park Modules based on the wind energy, the grid connection criteria in the ANNEX18 apply.
(3) Any Power Generating Module with an Maximum Capacity of 30 MW or
above, which is connected from the transmission system shall also meet the requirements
set out in this section, with respect to the reactive power control service. With respect to
the reactive power control, the grid connection criteria in the ANNEX-18 apply to the
Power Park Modules based on the wind energy.
(4) Conventional-type synchronous Power Generating Modules should be capable
of operating at any point between the power factor limit values of 0.85 with over-excitation
and 0.95 with low-excitation during continuous operation at the alternator terminals when
generating at their nominal active power level. If the output power is below the nominal
active output power, the alternators should be capable of operating at any point between
the reactive power capacity limits indicated in the performance schedule in the P-Q
alternator loading capability curves. However, if the user requests to increase the nominal
active powers of the existing alternators by amending the license in line with the consent of
the System Operator for the existing Power Generating Modules in service, the license
power may be increased in such a manner that the power factors at the alternator terminal
will be increased to maximum 0.9 with over-excitation. In this case, the producer shall
agree and undertake that they will decrease to the nominal active power level of the
alternator at the power factor of 0.85 with over-excitation at the request of the System
Operator within the scope of the Ancillary Service Agreements for Provision of Reactive
Power Support, that they will cover the extra cost of ancillary service reserve creation,
which will be calculated taking into account the market prices as a result of this instruction,
under the Regulation on Electricity Market Ancillary Services, and that they will fulfill all
special obligations to be determined by the System Operator.
57
(5) The Power Generating Modules in Nuclear Power Generating Facilities
should be capable of operating at any point between the power factor limit values of
0.9 with over-excitation and 0.95 with low-excitation during continuous operation at
the alternator terminals when generating at their nominal active power level. If the
output power is below the nominal active output power, the alternators should be
capable of operating at any point between the reactive power capacity limits indicated
in the performance schedule in the P-Q alternator loading capability curves.
(6) Short-circuit ratio of the unit may not be smaller than 0.5 for the thermal
and combined cycle gas turbine units; 0.75 for the hydroelectric units with an
Maximum Capacity of 10 MW or below, and 1.0 for the hydroelectric units with an
Maximum Capacity above 10 MW.
(7) Units which are capable of working as synchronous compensator should be
able to work with zero power factor. When thermal units work at overexcited
operation, their capacity should be able to produce reactive power up to 75% of their
nominal power and when they work at under-excited operation thermal units’ capacity
should be able to consume reactive power up to 30 % of their nominal apparent power.
When hydro units work at overexcited operation, their capacity should be able to
produce reactive power up to 75% of their nominal power and when they work at
under-excited operation hydroelectric units’ capacity should be able to consume
reactive power up to 60 % of their nominal power. The requirement for the Power
Generating Modules to have synchronous compensator feature is determined by
TEIAS prior to signing of the connection agreement.
(8) Since system frequency can rise up to 52.5 Hz and decrease down to 47.5
Hz under instable operation conditions, the plants and/or equipment of TEIAS and
users must be designed so as to operate remaining connected to the transmission
network for the minimum period specified in the table below.
Frequency Range
51.5 Hz <f≤ – 52.5 Hz
50.5 Hz ≤f< – 51.5 Hz
49 Hz ≤f< – 50.5 Hz
48.5 Hz ≤f< – 49 Hz
48 Hz ≤f< – 48.5 Hz
47.5 Hz ≤f< – 48 Hz
Minimum Period
10 minutes
1 hour
continuous
1 hour
20 minutes
10 minutes
(9) In line with the chart given in the Annex-15, the units should have the
capacity to;
a)produce constant active power output for the system frequency
changes within the range 50.5 to 49.5 Hz, and
b)produce active power at a level higher than the linear characteristic
values for system frequency changes within the range 49.5 to 47.5 Hz.
(10) Under normal operating conditions, active power output of a unit that is
directly connected to the transmission system should not be affected from the voltage
changes. In this case reactive power output of the unit should be fully available within the
voltage range ± 5 % at 400, 154, 66 kV and lower voltages.
58
(11) Restoration ability requirement for the Power Generating Modules is
determined by TEIAS prior to signing of the connection agreement.
(12) The conventional-type units with a unit power of 75 MW or above, or the
units of the conventional-type Power Generating Facilities with an Maximum Capacity
of 300 MW or above should include a power system stabilizer capable of electrical
damping at the automatic voltage regulator against the low-frequency
electromechanical oscillations in the range of 0-5 Hz, which may arise in the
interconnected grid system and damping the low-frequency interregional oscillations
which arise along with the ENTSO-E system connection. In respect of the
conventional-type units with a unit power of 75 MW or above, or the units of the
conventional-type Power Generating Facilities with an Maximum Capacity of 300
MW or above, the user shall, prior to signing the connection agreement, submit to
TEIAS the details and technical specifications with respect to the excitation system of
the unit, technical characteristics of the power system stabilizer, block diagram of the
power system stabilizer, and IEEE model; automatic voltage regulator and their
steady-state and dynamic performances as specified in the Annex-12. Settings of the
power system stabilizer shall be made by the user according to the setting procedure
stated in the Annex-12 whenever TEIAS considers it necessary. TEIAS may have an
observer present during such setting works, if it considers it necessary.
[New articles harmonization with ENTSO-E Network Code OS, Art 10.3 voltage control
and reactive power management]
(13) Each Power Generating Module must be designed so as to operate remaining
connected the transmission network for unlimited period of time in the following
voltage range:
- A transmission system of 400 kV is operated between 340 kV and 420 kV;
- A transmission system of 154 kV is operated between 140 kV and 170 kV.
- A system with Voltage equal or below to 66kV is operated in a range of +/- 10%
ARTICLE 35 Existing Power Generating Module control arrangements
[Previous Article 21]
(1) Every unit should contain control mechanisms that can contribute to the
frequency and voltage control by continuous modification of active and reactive power
that is given to the connected system.
(2) Every unit should posses a proportional speed governor or unit load
controller or equivalent control equipment that performs frequency control under
normal operating conditions and gives fast response in line with the criteria given in
the relevant articles of this regulation.
(3) Speed governor should be designed and operated in accordance with
standards that satisfy the rules of international interconnection condition. When such
standards do not exist speed governor should be designed and operated in accordance
with European Union’s frequency control system design and modification standards.
(4) Existing and prospective standards in the ENTSO-E documents are taken as
basis in accordance with the targets related to integration of Turkish electric system
with ENTSO-E system.
59
(5) Standards used for the speed governors are reported to TEIAS;
a) At application for connection agreement, or,
b) At application for a modification in the connection agreement, or,
c) Soon as possible prior to any modification on the speed governor.
(6) Speed governor must meet the following minimum requirements;
a) Speed governor must be able to control the active power output of the
unit within the operating interval in coordination with the other control equipment
and in accordance with the adjusted operating parameters,
b) Speed governor should be able to keep the frequency between 47.5 and
52.5 Hz. when the section that unit is connected is disconnected from the
transmission system as an island but the unit continues to feed the demand.
However, this should not cause the output power to go below the designed
minimum output level of the unit,
c) Speed governor should be so adjusted to operate with a speed drop in
accordance with the principles set out in the [previous Article 122] so as to meet the
maximum primary frequency control reserve capacity determined by the primary
frequency control performance tests,
ç) Insensitivity of the speed governor should not exceed ±0.010 Hz for any
unit providing primary frequency control service except for the steam turbine in
a block. In addition, sensitivity of the in-situ frequency measurement as used in
the speed governor should not exceed ±0.010 Hz.
(7) Minimum requirements determined for the speed governor should not prevent
the provision of the ancillary services based on the other parameters by the user if
requested by TEIAS.
(8) Related to the automatic voltage regulator (AVR), the automatic excitation
control system that keeps the unit’s voltage constant;
a) Detailed technical information for warning control equipment and power
system stabilizers are stated in the connection agreement.
b) Reactive power limiters that limit the reactive power output of the unit in
accordance with the system stability and excitation current limits in the operating
interval, are installed and set as specified in the connection agreement.
c) Related to the voltage control, other control facilities including the constant
reactive power output control modes and constant power factor modes are stated in the
connection agreement. However, if this facility is already present in the excitation
control system, it can be put out of use depending on TEIAS’s request.
(ç)When the power of the unit is increased slowly from zero to full load,
excitation control system should be accurate enough to make sure that the deviation in
the output voltage does not exceed 0.5% of the predetermined nominal value for
60
thermal Power Generating Modules and 0.2% for hydraulic Power Generating
Modules. The terminal output voltage of the unit should be adjustable to at least 95%105% of nominal voltage value.
d) If the unit is exposed to a drastic voltage change, the excitation control
system whose output is controlled by the automatic voltage regulator, should be able
to reach lower and upper voltage limits of the alternator warning winding in no longer
than 50 milliseconds.
e) If a sudden voltage change of 10% or greater occurs in the unit output,
excitation control system should be able to provide upper limit value of loaded
positive excitation voltage in maximum 50 milliseconds. At the same time, it should
be able to provide negative upper voltage limit value equal to 80% of positive upper
voltage limit. This value should not be less than twice of nominal excitation voltage
and 6-7 times the unloaded (no-load) excitation voltage.
f) Excitation system for the static excitation sources that derive excitation
power from the unit output with the help of a power transformer should be able to
automatically trigger, if unit output voltage drops to 20 -30% of its nominal value.
g) For the alternators with a nominal apparent power of 100 MVA or above:
(1) In the case of a short-circuit fault in the high voltage network, the upper
limit value of positive excitation voltage is met for minimum 3 seconds.
(2) During the system faults, excitation current is supplied for minimum 10
seconds, provided that it will not be less than 150% of the nominal excitation current.
ğ) A alternator with a nominal apparent power above 50 MVA provides a
voltage drop capacity corresponding to maximum 70-80% of the voltage drop of the
transformers belonging to the units connected to the transmission system.
ARTICLE 36 Steady state output power variations
[Previous Article 22]
(1) At steady state, standard deviation in the unit output power within half an
hour time should not exceed 2.5% of the Maximum Capacity of the unit.
(2) ARTICLE 36 (1) does not apply to Power Generating Modules which
primary energy source is based on wind, solar, wave and tidal power.
ARTICLE 37 Negative component loadings
[Previous Article 23]
(1) Negative component of voltage in 400 kV and 154 kV system, should not
exceed 1% of positive component. Units should be able to withstand without tripping the
negative component loadings that happen due to phase-phase faults in the transmission or
user’s system or instable loads, until the clearance of the system by the reserve protection.
61
ARTICLE 38 Earthing of the neutral points of unit transformer and
alternators
[Previous Article 24]
(1) Neutral points of the transformer windings that are on the side of the
transmission system are earthed directly. However, in the generation dense regions, in
order to limit the single phase earth fault current in the 154 kV system, neutral point of
the windings coil that is on the side of the transmission system is completely isolated
in the cases where the phase earth fault currents are higher than the three phase earth
fault currents in the 154 kV system. Isolation levels of neutral points shall be at the
voltage level of 154-kV in such transformers to be isolated.
(2)
Neutral point of the alternators are earthed through the resistance or earthing
transformer. Alternator earthing resistance is determined and established in accordance
with the provision that resisting and reactive components of phase earth fault current are
equal. Neutral points of the alternators should not be isolated completely and should not be
earthed directly or over the reactance.
ARTICLE 39 Unit frequency accuracy
[Previous Article 25]
(1) Legal entity which is involved in generation activity, is responsible for
protecting its units against the harms that can occur due to frequencies out of 47.5-52.5 Hz
range. Legal entity is responsible for cutting the connection between the equipment, unit
and the system and taking all of the preventive actions for the security of the facility and/or
personnel when the frequency is outside this range.
SECTION 4
Communication Conditions
ARTICLE 40 Communication
[Previous Article 26]
(1) A communication environment shall be established for the purposes of
voice, information and protection needed by the operation of the transmission system
and energy management.
(2) Technical properties, installation and operation and maintenance
responsibilities for the communication and control system that is established for
management, operation and control of the communication system between TEIAS and
the users are stated in the connection agreements.
(3) Data and voice communication in the transmission system are carried out
through power line carrier and optical fiber communication systems. In addition,
communication channels leased from the telecommunication companies are used when
necessary. In order to exchange data through the Supervisory Control and Data
62
Acquisition System (SCADA); the necessary hardware, software and communication
links are provided and installed at the substations and Power Generating Modules.
(4) Optical ground wire (OPGW) which includes optical fibers the number and
characteristics of which are determined by TEIAS according to the need and complies
with the Type Technical Specification of TEIAS is used instead of one or both of the
standard steel ground wires on the newly installed 400kV and 154kV power
transmission lines.
(5) The protection conductors on the power transmission lines in service are
replaced with the fiber optic protection conductor, when necessary.
[New articles harmonization with ENTSO-E Network Code OS, art 8.15, 8.16 System
states]
(6) TEIAS shall design its systems in order to ensure the availability, reliability
and redundancy of the following critical tools and facilities, which are required for
system operation:
a) facilities for monitoring the System State of the Transmission System,
including State Estimation applications;
b) means for controlling switching;
c) means of communication with control centers of other TSOs;
d) tools for Operational Security Analysis.
Where the above tools and facilities involve the DSOs with Connection
Point directly to the Transmission System or Significant Grid Users
which are involved in balancing, Ancillary Services, system defense,
Restoration or delivery of real-time operational data, the TSO, the DSOs
with Connection Point directly to the Transmission System and those
Significant Grid Users shall, cooperate and coordinate in ensuring the
availability, reliability and redundancy of these tools and facilities
(7) TEIAS shall adopt a business continuity plan detailing TSO’s responses to a
loss of critical tools and facilities, containing provisions for maintenance, replacement
and development of critical tools and facilities. The business continuity plan shall be
reviewed at least annually and updated as necessary or following any significant
change of critical tools and facilities or relevant system operation conditions. The
business continuity plan contents shall be shared with DSOs and Significant Grid
Users to the extent to which they are affected
ARTICLE 41 Voice communication system
[Previous Article 27]
(1) Voice communication system is a special communication system between
TEIAS and control operator of the user that is used for controlling, operating and
monitoring the system over a number of communication platforms.
(2) The voice communication between load dispatch centers and user facilities is
provided by installation of appropriate software and hardware compatible with TEIAS’s
existing communication facilities by the user. Users are responsible for making the
63
required technical changes and modifications that are stated in the connection agreement in
the other associated centers.
(3) In order to satisfy efficiency in management, operation and controlling of the
communication system, a fixed telephone or GSM shall be available in the related control
room of the user in accordance with the connection agreement.
(4) A fax machine using a separate line is kept in the control centers of TEIAS
and distribution companies, control room of the Power Generating Facilities, the
control points of the directly connected consumers and at points where commercial
transactions are carried out.
(5) Telephone and fax numbers and the changes that will be made in these
numbers are reported to TEIAS and/or distribution companies before the
communication plant and/or equipment are connected to the system.
ARTICLE 42 Protection signaling system
[Previous Article 28]
(1) The required hardware for signaling of the protection system in the
connection between the user’s system and transmission system shall be supplied and
installed by the user.
ARTICLE 43 Data communication system
[Previous Article 29]
(1) Data communication system is where data from user’s system is gathered,
processed, evaluated, and transmitted to the related load dispatch center and where the
required information and instructions are transmitted to the user’s facility from the
related dispatch center.
(2) Remote terminal unit or gateway, hardware, software, communication link
and equipment required for system control and data collection activities are installed in
user’s and TEIAS’s related facilities in accordance with the conditions stated in the
connection agreement. The users must establish connection in order to ensure
exchange with the data communication system of TEIAS for the Power Generating
Facilities that participate in the real-time market and are required to participate in the
ancillary services. User connects the required control inputs for TEIAS such as signal,
indicator, alarm, measurements, circuit breaker and disconnector location information,
load tap changer to the system control and data collection equipment over an
information collection panel which will be installed adjacent to the equipment.
(3) If user prefers computer control system which is an integral part of the
facility instead of remote terminal unit for data communication; and his preference is
accepted by TEIAS, a system compatible with the operating system of TEIAS for the
required performance is provided by the user. In the case of station automation, data
exchange with the related load dispatch center is ensured through a station computer
and gateway without need for a remote terminal unit or data collection panel.
64
(4) User is informed by TEIAS about the voltage, current, active and reactive
power signals and other signals to be collected in order to monitor transmission
system, and this data is exchanged with the related load dispatch center of TEIAS.
When, how and where the equipment related to obtaining these signals shall be
determined in accordance with the provisions set out in the connection agreement.
(5) Data communication between user and TEIAS control and system operation
centers is established in compliance with the NLDC rules, communication protocol
and communication medium stated in the connection agreement.
(6) Data communication is accomplished utilizing at least two separate links
one of which is main and the other reserve link. If the second link of the Power
Generating Modules below 50 MW cannot be created, the data communication may be
established via single link.
(7) In respect of the Power Generating Modules with an Maximum Capacity of
30 MW or above to be connected by the Electricity Distribution Companies/Organized
Industrial Zones (OIZ) a Distribution License to the distribution system and networks
of the OIZs holding a Distribution License, the data related to the total MW and MVar
on the basis of Power Generating Facility is transferred to the TEIAS SCADA System
from the SCADA control center installed/to be installed of the related Distribution
Company/OIZ holding a Distribution License. The said Power Generating Facilities
must install the necessary systems in their own facilities for this purpose, and connect
to the SCADA Systems of the related Electricity Distribution Networks/OIZs holding
a Distribution License by providing the necessary communication link. The works to
be performed with respect of the other equipment, apart from the communication link,
to be needed for this purpose on the SCADA control centers side of the electricity
distribution companies/OIZs holding a distribution license shall be under the
responsibility of the relevant distribution company/OIZ holding a distribution license.
(8) In respect of the Power Park Modules based on the solar or wind energy
from the renewable energy sources with an Maximum Capacity of 10 MW or above to
be connected by the Electricity Distribution Companies/Organized Industrial Zones
(OIZ) holding a Distribution License to the distribution system and networks of the
OIZs holding a Distribution License, the data related to the total MW and MVar on the
basis of Power Generating Facility is transferred to the TEIAS SCADA System from
the SCADA control center installed/to be installed of the related Distribution
Company. The said Power Generating Facilities must install the necessary systems in
their own facilities for this purpose, and connect to the SCADA Systems of the related
Electricity Distribution Networks/OIZs holding a Distribution License by providing
the necessary communication link. The works to be performed with respect of the
other equipment, apart from the communication link, to be needed for this purpose on
the SCADA control centers side of the electricity distribution companies/OIZs holding
a distribution license shall be under the responsibility of the relevant distribution
company/OIZ holding a distribution license.
(9) In respect of any Power Generating Module connected by the Electricity
Distribution Companies/OIZs holding a Distribution License from the distribution level in
the responsibility The total MW and MVAr values, total consumption values, information
related to the connection points, and other information to be requested by TEIAS are
transferred to the TEIAS SCADA System through the communication protocols used in the
TEIAS system via the communication link to be established between their own SCADA
control center and TEIAS SCADA System. The works to be performed with respect of the
65
other equipment, apart from the communication link, to be needed for this purpose on the
SCADA control centers side of TEIAS shall be under the responsibility of TEIAS.
ARTICLE 44 Additional communication requirements
[Previous Article 30]
(1) The requirements for modifications and adjustments in the user’s existing
voice and data communication system for the purpose of reinforcement, development
and renovation of the transmission system, including his specific requirements in the
connected TEIAS center, shall be provided by the user within the framework of the
plan to be made by TEIAS.
ARTICLE 45 Data communication grid
[Previous Article 31]
(1) The data communication grid and technical infrastructure of this grid which
will be used between TEIAS and the user for administrative, financial, commercial and
technical information exchange are established in accordance with standards and rules
prepared by TEIAS as per the relevant legislation.
ARTICLE 46 Secondary frequency control equipment and wind
Power Park Modules control systems
[Previous Article 32]
(1) Equipment and related connection required for secondary frequency control are
provided and installed in the Power Park Modules which are within this scope as per the
relevant provisions of the Regulation on Electricity Market Ancillary Services so as to
completely meet the requirements of the automatic generation control program located in
NLDC. The relevant generation company provides the necessary data for the settings of the
parameters of the automatic generation control program located in NLDC.
(2) The automatic generation control system/interface to be installed in the
Power Park Module should comply with the signal sent by the automatic generation
control program located in NLDC.
PART IV
Requirement for Connection of new users
SECTION 1
Requirement for Power Generating Facilities
1. 1
General Requirements
66
ARTICLE 47 General requirements for type A power generating
modules
[New Article, harmonization with ENTSO-E code RFG Article 8]
1. Type A Power Generating Modules shall fulfil the following requirements referring to
Frequency stability:
a) With regard to Frequency ranges:
1) A Power Generating Module shall be capable of staying connected to the
Network and operating within the Frequency ranges and time periods as
defined below:
Frequency Range
51 Hz ≤ f < 51.5 Hz
49 Hz ≤ f < 51 Hz
48.5 Hz ≤ f < 49 Hz
47.5 Hz ≤ f < 48.5 Hz
Minimum Time Period
30 minutes
Unlimited
1 hour
>30 minutes
2) While respecting the provisions of ARTICLE 47 (1) (a) point 1) a Power
Generating Module shall be capable of automatic disconnection at specified
frequencies, if required by the Relevant Network Operator. Terms and
settings for automatic disconnection shall be agreed between the Relevant
Network Operator and the Power Generating Facility Owner
b) With regard to the rate of change of Frequency withstand capability, a Power
Generating Module shall be capable of staying connected to the Network and operating at
rates of change of Frequency up to a value of -0.5 and +0.5 Hz/ sec, other than triggered by
rate-of-change-of-Frequency-type of loss of mains protection.
c) With regard to the Limited Frequency Sensitive Mode - Overfrequency (LFSM-O) the
following shall apply:
1) The Power Generating Module shall be capable of activating the
provision of Active Power Frequency Response according to Figure 1 at a
Frequency threshold, adjustable between and including 50.2 Hz and 50.5 Hz
with a Droop in a range of 2 - 12 %. The Frequency threshold is 50.2 Hz
and a Droop is 4% unless stated otherwise by TEIAS.
The Power Generating Module shall be capable of activating Active Power
Frequency Response as fast as technically feasible with an initial delay that
shall be as short as possible and reasonably justified by the Power
Generating Facility Owner to TEIAS if greater than 2 seconds. The Power
Generating Module shall be capable of either continuing operation at
Minimum Regulating Level when reaching it or further decreasing Active
Power output.
67
Figure 1: Active Power Frequency Response capability of Power Generating Modules in
LFSM-O. Pref is the reference Active Power to which ∆P is related and may be defined
differently for Synchronous Power Generating Modules and Power Park Modules. ∆P is
the change in Active Power output from the Power Generating Module. fn is the nominal
Frequency (50 Hz) in the Network and ∆f is the Frequency change in the Network. At
overfrequencies where ∆f is above ∆f1 the Power Generating Module has to provide a
negative Active Power output change according to the Droop S2.
2) The Power Generating Module shall be capable of stable operation during
LFSM-O operation. When LFSM-O is active, the LFSM-O Setpoint will
prevail over any other Active Power Setpoint.
d) The Power Generating Module shall be capable of maintaining constant output at its
target Active Power value regardless of changes in Frequency, unless output shall follow
the defined changes in output in the context ARTICLE 47 (1) (c), (e) or ARTICLE 49 (2)
(b), and ARTICLE 49 (2) (c) where applicable.
e) Admissible Active Power reduction from maximum output with falling Frequency
within is allowed and shall not exceed the values are given by the full lines in Figure 2:

Below 49.5 Hz by a reduction rate of 2 % of the Maximum Capacity at 50
Hz per 1 Hz Frequency droop.
68
Frekans (Hz)
47.5
49.5
50.5
%100 Aktif
Güç Çıkışı
%96 Aktif
Güç Çıkışı
Figure 2 – Maximum power capability reduction with falling Frequency.
f) The Power Generating Module shall be equipped with a logic interface (input port) in
order to cease Active Power output within less than 5 seconds following an Instruction
from the Relevant Network Operator. The Relevant Network Operator shall have the right
to define the requirements for further equipment to make this facility operable remotely.
g) The Power Generating Module shall fulfil the following requirement referring to system
restoration:
With regard to capability of reconnection after an incidental disconnection due to a
Network disturbance, a reconnection at the connection point is allowed when the following
conditions are fulfilled:

Frequency ranges between 47.5 Hz and 50.05 Hz

Voltage level (phase to phase) > 95 % Urated

The maximum admissible gradient of increase of Active Power output shall
be 10 % of the Maximum Capacity per minute.
Above the frequency of 50.05 Hz the PGM is allowed to be synchronized with the
network, a power export to the network is not allowed.
Installation of automatic reconnection systems shall be subject to prior authorization by the
Relevant Network Operator subject to reconnection conditions specified by TEIAS.
ARTICLE 48 General requirements for type B power generating
modules
[New Article, harmonization with ENTSO-E code RFG Article 9]
1. In addition to fulfilling the requirements listed in ARTICLE 47, Type B Power
Generating Modules shall fulfil the requirements in this Article.
2. Type B Power Generating Modules shall fulfil the following requirements referring to
Frequency stability:
a) In order to be able to control Active Power output, the Power Generating Module
shall be equipped with an interface (input port) in order to be able to reduce Active
Power output to a value included in a range between 20% and 100% of the prior
Active Power output, as instructed by the Relevant Network Operator and/or
TEIAS. The Relevant Network Operator will define the requirements for further
equipment to make this facility operable remotely.
69
3. Type B Power Generating Modules shall fulfil the following requirements referring to
robustness of Power Generating Modules:
a) With regard to fault-ride-through capability of Power Generating Modules:
1) TEIAS or the Relevant Network Operator shall define a voltage-against-timeprofile according to figure 3 at the Connection Point for fault conditions which
describes the conditions in which the Power Generating Module shall be capable of
staying connected to the Network and continuing stable operation after the power
system has been disturbed by Secured Faults on the Network.
2) This voltage-against-time-profile shall be expressed by a lower limit of the
course of the phase-to-phase Voltages on the Network Voltage level at the
Connection Point during a symmetrical fault, as a function of time before, during
and after the fault. This lower limit is defined using parameters in figure 3
according to tables 3.1.
3) TEIAS will define and make publicly available defining the pre-fault and postfault conditions for the fault-ride-through capability in terms of:

conditions for the calculation of the pre-fault minimum short circuit
capacity at the Connection Point;

conditions for pre-fault active and Reactive Power operating point of the
Power Generating Module at the Connection Point and Voltage at the
Connection Point; and

conditions for the calculation of the post-fault minimum short circuit
capacity at the Connection Point.
4) Each Relevant Network Operator will provide on request by the Power
Generating Facility Owner the pre-fault and post-fault conditions to be considered
for fault-ride-through capability as an outcome of the calculations at the Connection
Point as defined in ARTICLE 48 (3) (a) point 3) regarding:

pre-fault minimum short circuit capacity at each Connection Point
expressed in MVA;

pre-fault operating point of the Power Generating Module expressed in
Active Power output and Reactive Power output at the Connection Point
and Voltage at the Connection Point; and

post-fault minimum short circuit capacity at each Connection Point
expressed in MVA.
Alternatively generic values for the above conditions derived from typical cases
may be provided by the Relevant Network Operator.
70
Figure 3 – Fault-ride-through profile of a Power Generating Module. The diagram
represents the lower limit of a voltage-against-time profile by the Voltage at the
Connection Point, expressed by the ratio of its actual value and its nominal value in
per unit before, during and after a fault. Uret is the retained Voltage at the
Connection Point. During a fault, tclear is the instant when the fault has been cleared.
Urec1, Urec2, trec1, trec2 and trec3 specify certain points of lower limits of Voltage
recovery after fault clearance.
Voltage parameter [pu]
U ret :
0.00 pu
Time parameters [seconds]
t clear : 0.150 sec
U clear :
0.00 pu
t rec1 :
U rec1 :
0.90 pu
1.5 sec
(Unless stated otherwise.
TEIAS can extend the time
up to 3 sec)
Table 3.1 -Parameters for figure 3 for fault-ride-through capability of Power
Generating Modules
5) The Power Generating Module shall be capable of staying connected to the
Network and continue stable operation when the actual course of the phase-tophase Voltages on the Network Voltage level at the Connection Point during a
symmetrical fault, given the pre-fault and post-fault conditions according to
ARTICLE 48 (3) (a) points 3) and 4), remains above the lower limit defined in
ARTICLE 48 (3) (a) point 2), unless the protection scheme for internal electrical
faults requires the disconnection of the Power Generating Module from the
Network. The protection schemes and settings for internal electrical faults shall be
designed not to jeopardize fault-ride-through performance.
6) While still respecting ARTICLE 48 (3) (a) point 5), undervoltage protection
(either fault-ride-through capability or minimum Voltage defined at the connection
point Voltage) shall be set by the Power Generating Facility Owner to the widest
possible technical capability of the Power Generating Module unless the Relevant
Network Operator requires less wide settings according to ARTICLE 48 (5) (b).
The settings shall be justified by the Power Generating Facility Owner in
accordance with this principle.
71
7) Fault-ride-through capabilities in case of asymmetrical faults (1-phase or 2phase) shall be defined by TEIAS, considering ARTICLE 48 (3) (a) point (1).
4. Type B Power Power Generating Modules shall fulfil the following requirement
referring to system restoration:
a) With regard to capability of reconnection after an incidental disconnection due to
a Network disturbance, reconnection is allowed when the following conditions are
fulfilled at the connection point:

Frequency ranges between 47.5 Hz and 50.05 Hz

Voltage level (phase to phase) > 95 % Urated

The maximum admissible gradient of increase of Active Power output
should be 10 % of the Maximum Capacity per minute.
Above the frequency of 50.05 Hz the Power Generating Module is allowed to be
synchronized with the network but a power export to the network is not allowed.
Installation of automatic reconnection systems shall be subject to prior authorization by the
Relevant Network Operator subject to reconnection conditions specified by TEIAS.
5. Type B Power Generating Modules shall fulfil the following general system
management requirements:
a) With regard to control schemes and settings
1) Schemes and settings of the different control devices of the Power
Generating Module relevant for transmission system stability and to enable
emergency actions shall be coordinated and agreed between TEIAS, the
Relevant Network Operator and the Power Generating Facility Owner.
Following schemes and settings of the different control devices of the Power
Generating Module have to be coordinated:
 Remote Switch on/off
 Active Power Reduction
 Reactive Power Control
2) Any changes to the schemes and settings of the different control devices
of the Power Generating Module, relevant for transmission system stability
and to enable emergency actions, shall be coordinated and agreed between
the TEIAS, the Relevant Network Operator and the Power Generating
Facility Owner, especially if they concern the circumstances referred to
under ARTICLE 48 (5) (a) point 1).
b) With regard to electrical protection schemes and settings:
1) The Relevant Network Operator shall define the schemes and settings
necessary to protect the Network taking into account the characteristics of
the Power Generating Module. Protection schemes relevant for the Power
Generating Module and the Network and settings relevant for the Power
Generating Module shall be coordinated and agreed between the Relevant
Network Operator and the Power Generating Facility Owner. The protection
schemes and settings for internal electrical faults shall be designed not to
72
jeopardize the performance of a Power Generating Module according to
these Regulation requirements otherwise.
2) Electrical protection of the Power Generating Module shall take
precedence over operational controls taking into account system security,
health and safety of staff and the public and mitigation of the damage to the
Power Generating Module.
3) Protection schemes can protect against the following aspects:

external and internal short circuit;

asymmetric load (Negative Phase Sequence);

stator and rotor overload;

over-/underexcitation;

over-/undervoltage at the Connection Point;

over-/undervoltage at the Alternator terminals;

inter-area oscillations;

inrush Current;

asynchronous operation (pole slip);

protection against inadmissible shaft torsions (for example,
subsynchronous resonance);

Power Generating Module line protection;

unit transformer protection;

backup schemes against protection and switchgear malfunction;

overfluxing (U/f);

inverse power;

rate of change of Frequency; and

neutral Voltage displacement.
4) Any changes to the protection schemes relevant for the Power Generating
Module and the Network and to the setting relevant for the Power
Generating Module shall be agreed between the Network Operator and the
Power Generating Facility Owner and be concluded prior to the introduction
of changes.
c) With regard to priority ranking of protection and control, the Power Generating Facility
Owner shall organize its protections and control devices in compliance with the following
priority ranking, organized in decreasing order of importance:





Network system and Power Generating Module protection;
Synthetic Inertia, if applicable;
Frequency control (Active Power adjustment);
Power Restriction; and
Power gradient constraint.
d) With regard to information exchange:
1) Power Generating Facilities shall be capable of exchanging information
between the Power Generating Facility Owner and the Relevant Network
Operator and/or TEIAS in real time or periodically with time stamping as
defined by the Relevant Network Operator and/or TEIAS.
73
2) The Relevant Network Operator in coordination with the contents of
information exchanges and the precise list and time of data to be facilitated.
6. Type B Power Generating Modules connected to 33 kV busbar of substations connected
to transmission system or connected to voltage levels above shall fulfil the following
requirements referring to power quality:
a) All Power Generating Facility Owners shall ensure that their connection
to the Network does not result in excessive level of distortion or fluctuation of the
supply Voltage on the Network, at the Connection Point. The level of distortion or
fluctuation shall not exceed the thresholds defined in the articles ARTICLE 23 to
ARTICLE 27.
b) TEIAS has the right to require and to define the scope and extent of
studies which demonstrate that no excessive level of distortion may occur. If level
of distortion or fluctuation of the supply Voltage on the Network exceeding the
thresholds is identified, the studies shall identify possible recovery actions to be
implemented to ensure compliance with the requirements of this Regulation.
c) The studies shall be carried out by the Power Generating Facility Owner
with the participation of all other parties identified by TEIAS relevant to each new
Connection Point. Such other parties shall contribute to the studies and shall
provide their input as reasonably required to meet the purposes of the studies.
TEIAS shall collect this input and pass it on to the party responsible for the studies
in accordance with confidentiality obligations of ARTICLE 7.
d) TEIAS shall assess the result of the studies and, if necessary for the
assessment, TEIAS has the right to request the Power Generating Facility Owners
to perform further studies in line with this same scope and extent.
e) Any recovery actions identified by the studies carried out under the
provisions of this article and reviewed by TEIAS shall be undertaken as part of the
connection of the new Power Generating Facility.
ARTICLE 49 General requirements for type C power generating
modules
[New Article, harmonization with ENTSO-E code RFG Article 10]
1. In addition to fulfilling the requirements listed in ARTICLE 47and ARTICLE 48, except
for ARTICLE 47 (1) (f) and ARTICLE 48 (2) (a), Type C Power Generating Modules shall
fulfil the requirements in this Article.
2. Type C Power Generating Modules shall fulfil the following requirements referring to
Frequency stability:
a) With regard to Active Power controllability and control range, the Power
Generating Module control system shall be capable of adjusting an Active Power
Setpoint as instructed by the Relevant Network Operator or TEIAS to the Power
74
Generating Facility Owner. It shall be capable of implementing the Setpoint within
a period specified in the above Instruction and within a tolerance defined by the
Relevant Network Operator or TEIAS (subject to the availability of the prime
mover resource), subject to notification to EMRA. Manual, local measures shall be
possible in the case that any automatic remote control devices are out of service.
b) In addition to ARTICLE 47 (1) (c) the following shall apply accumulatively with
regard to Limited Frequency Sensitive Mode – Underfrequency (LFSM-U):
1) The Power Generating Module shall be capable of activating the
provision of Active Power Frequency Response according to figure 4 at a
Frequency threshold adjustable between and including 49.8 Hz and 49.5 Hz
with a Droop in a range of 2 – 12 %. The value of Frequency threshold is
49.8 Hz and the value of Droop is 4 %. In the LFSM-U mode the Power
Generating Module shall be capable of providing a power increase up to its
Maximum Capacity. The actual delivery of Active Power Frequency
Response in LFSM-U mode depends on the operating and ambient
conditions of the Power Generating Module when this response is triggered,
in particular limitations on operation near Maximum Capacity at low
frequencies according to ARTICLE 47 (1) (e) and available primary energy
sources. The Active Power Frequency Response shall be activated as fast as
technically feasible with an initial delay that shall be as short as possible and
reasonably justified by the Power Generating Facility Owner to TEIAS if
greater than 2 seconds.
Figure 4: Active Power Frequency Response capability of Power Generating
Modules in LFSM-U. Pref is the reference Active Power to which ∆P is related and
may be defined differently for Synchronous Power Generating Modules and Power
Park Modules. ∆P is the change in Active Power output from the Power Generating
Module. fn is the nominal Frequency (50 Hz) in the Network and ∆f is the
Frequency change in the Network. At underfrequencies where ∆f is below ∆f1 the
Power Generating Module has to provide a positive Active Power output change
according to the Droop S2.
2) Stable operation of the Power Generating Module during LFSM-U
operation shall be ensured. The LFSM-U reference Active Power shall be
75
the Active Power output at the moment of activation of LFSM-U and shall
not be changed unless triggered by frequency restoration action.
c) In addition to ARTICLE 49 (2) (b) the following shall apply accumulatively, when
operating in Frequency Sensitive Mode (FSM):
1) The Power Generating Module shall be capable of providing Active
Power Frequency Response with respect to figure 5 and in accordance with
the parameters specified by TEIAS within the ranges shown in table 4.
Unless stated otherwise by TEIAS the values of parameters for a Power
Generating Module shall be follows:



Active Power range related to Maximum capacity │∆P1│/ Pmax equal
to or higher than 2.5%
Frequency Response Insensitivity equal to or lower than│∆fi│=10 mHz
or │∆fi│/ fn = 0.02%
Frequency Response deadband equal to or lower than 10 mHz
Values of the Droop will be agreed between TEIAS and the owner of the
Power Generating Module in the connection agreement.
2) In case of overfrequency the Active Power Frequency Response is
limited by the Minimum Regulating Level.
3) In case of underfrequency the Active Power Frequency Response is
limited by Maximum Capacity. The actual delivery of Active Power
Frequency Response depends on the operating and ambient conditions of the
Power Generating Module when this response is triggered, in particular
limitations on operation near Maximum Capacity at low frequencies
according to ARTICLE 47 (1) (e) and available primary energy sources.
Figure 5: Active Power Frequency Response capability of Power Generating
Modules in FSM illustrating the case of zero deadband and insensitivity. Pmax is the
Maximum Capacity to which ∆P is related. ∆P is the change in Active Power
output from the Power Generating Module. fn is the nominal Frequency (50 Hz) in
the Network and ∆f is the Frequency deviation in the Network.
Parameters
Ranges
Active Power range related to 1.5 - 10%
76
Maximum Capacity │∆P 1 │/
P max
Frequency
│∆f i │
10-30 mHz
Response
Insensitivity
Frequency
│∆f i │/ f n
0.02 - 0.06%
Response
Deadband
Frequency
Response 0 - 500mHz
Deadband
Droop s 1
2 -12 %
Table 4: Parameters for Active Power Frequency Response in FSM (explanation
for figure 5)
4) The Frequency Response Deadband of Frequency deviation and Droop
are selected by TEIAS and must be able to be reselected subsequently
(without requiring to be online or remote) within the given frames in the
table 4, subject to notification to EMRA. The modalities of that notification
shall be determined in accordance with the applicable national regulatory
framework.
5) As a result of a frequency step change, the Power Generating Module
shall be capable of activating full Active Power Frequency Response, at or
above the full line according to figure 6 in accordance with the parameters
specified by TEIAS (aiming at avoiding Active Power oscillations for the
Power Generating Module) within the ranges according to table 5. This
specification shall be subject to notification to EMRA. The modalities of
that notification shall be determined in accordance with the applicable
national regulatory framework. The combination of choice of the parameters
according to table 5 shall take into account possible technology dependent
limitations. The initial delay of activation shall be as short as possible and
reasonably justified by the Power Generating Facility Owner to TEIAS, by
providing technical evidence for why a longer time is needed, if greater than
2 seconds.
Figure 6: Active Power Frequency Response capability. Pmax is the Maximum
Capacity to which ∆P is related. ∆P is the change in Active Power output from the
Power Generating Module. The Power Generating Modules have to provide Active
Power Output ∆P up to the point ∆P1 in accordance with the times t1 and t2 with the
values of ∆P1, t1and t2 being specified by TEIAS according to Table 5. t1 is the
initial delay. t2 is the time for full activation.
77
6) The Power Generating Module shall be capable of providing full Active
Power Frequency Response for a period for 15 min specified by the TEIAS,
considering the technical feasibility, for each Synchronous Area,
considering the Active Power headroom and primary energy source of the
Power Generating Module.
7) As long as a Frequency deviation continues Active Power control shall
not have any adverse impact on the Frequency response within the time
limits of ARTICLE 49 (2) (c) point 6).
Parameters
Ranges or values
Active Power range related to Maximum Capacity 10%
│∆P 1 │/ P max
Maximum admissible initial delay t 1 unless 2 seconds
justified otherwise for generation technologies
with Inertia
Maximum admissible choice of full activation 30 seconds
time t2, unless longer activation times are
admitted by TEIAS due to System stability
reasons
Table 5: Parameters for full activation of Active Power Frequency Response
resulted from Frequency step change (explanation for figure 6)
d) With regard to Frequency secondary and fast tertiary control, the Power Generating
Module shall provide functionalities compliant to specifications defined by TEIAS, aiming
at restoring Frequency to its nominal value and/ or maintain power exchange flows
between control areas at their scheduled values.
e) With regard to disconnection due to underfrequency, any Power Generating Facility
being capable of acting as a load except for auxiliary supply, including hydro PumpStorage Power Generating Facilities shall be capable of disconnecting its load in case of
underfrequency.
f) With regard to real-time monitoring of FSM:
1) To monitor the operation of Active Power Frequency Response the
communication interface shall be equipped to transfer on-line from the Power
Generating Facility to the Network control centre of the Relevant Network
Operator and/or TEIAS on request by the Relevant Network Operator and/or
TEIAS at least the following signals:
 status signal of FSM (on/off);
 scheduled Active Power output;
 actual value of the Active Power output;
 actual parameter settings for Active Power Frequency Response; and
 Droop and dead band.
2) The Relevant Network Operator and TEIAS shall define additional
signals to be provided by the Power Generating Facility for monitoring
and/or recording devices in order to verify the performance of the Active
Power Frequency Response provision of participating Power Generating
Modules.
78
3. Type C Power Generating Modules shall fulfil the following requirements referring to
Voltage stability:
a) The Relevant Network Operator in coordination with TEIAS shall have the right
to specify the Voltages at the Connection Point at which a Power Generating
Module shall be capable of automatic disconnection. The terms and settings for this
automatic disconnection shall be defined by the Relevant Network Operator in
coordination with TEIAS.
4. Type C Power Generating Modules shall fulfil the following requirements referring to
robustness of Power Generating Modules
a) In case of power oscillations, Steady-state Stability of a Power Generating
Module is required when operating at any operating point of the P-Q-Capability
Diagram. A Power Generating Module shall be capable of staying connected to the
Network and operating without power reduction notwithstanding the provisions of
ARTICLE 47 (1) (e), as long as Voltage and Frequency remain within the
admissible limits pursuant to this Regulation.
b) Single-phase or three-phase auto-reclosures on meshed Network lines, if
applicable to this Network, shall be withstood by Power Generating Modules
without tripping. Details of this capability shall be subject to coordination and
agreements on protection schemes and settings according to ARTICLE 48 (5) (b).
5. Type C Power Generating Modules shall fulfil the following requirements referring to
system restoration:
a) With regard to Black Start Capability:
1) Black Start Capability is not mandatory; nevertheless TEIAS shall have
the right to require Black Start capability, if TEIAS deems system security
to be a risk due to a lack of Black Start capability in a Control Area.
TEIAS shall have the right to require Black Start capability form Power
Generating Facility Owners and is determines by TEIAS prior to signing of
the connection agreement.
2) A Power Generating Module with a Black Start Capability shall be able
to start from shut down within a timeframe decided by the Relevant
Network Operator in coordination with TEIAS, without any external energy
supply. The Power Generating Module shall be able to synchronize within
the Frequency limits defined in ARTICLE 47 (1) and Voltage limits defined
by the Relevant Network Operator or defined by ARTICLE 50 (2) where
applicable.
3) The Power Generating Module Voltage regulation shall be capable of
regulating load connections causing dips of Voltage automatically.
The Power Generating Module shall:
 be capable of regulating load connections in block load;
 control Frequency in case of overfrequency and underfrequency within
the whole Active Power output range between Minimum Regulating
Level and Maximum Capacity as well as at houseload level;
79

be capable of parallel operation of a few Power Generating Modules
within one island; and - control Voltage automatically during the system
restoration phase.
b) With regard to capability to take part in Island Operation:
1) The capability to take part in Island Operation, if required by TEIAS,
shall be possible within the Frequency limits defined in ARTICLE 47 (1)
and Voltage limits according to ARTICLE 49 (3) or ARTICLE 50 (2) where
applicable.
2) If required, the Power Generating Module shall be able to operate in FSM
during Island Operation, as defined in ARTICLE 49 (2) (b). In the case of a
power surplus, it shall be possible to reduce the Active Power Output of the
Power Generating Module from its previous operating point to any new
operating point within the P-Q-Capability Diagram as much as inherently
technically feasible, but at least a Active Power output reduction to 55 % of
its Maximum Capacity shall be possible.
3) Detection of change from interconnected system operation to Island
Operation shall not rely solely on the Network Operator’s switchgear
position signals. The detection method shall be agreed between the Power
Generating Facility Owner and the Relevant Network Operator in
coordination with TEIAS.
c) With regard to quick re-synchronization capability:
1) Quick re-synchronization capability is required in case of disconnection
of the Power Generating Module from the Network in line with the
protection strategy agreed between the Relevant Network Operator in
coordination with TEIAS and the Power Generating Facility Owner in the
event of disturbances to the system.
2) The Power Generating Module whose minimum re-synchronization time
after its disconnection from any external power supply exceeds 15 minutes
shall be designed for tripping to houseload from any operating point in its PQ-Capability Diagram. For identifying houseload operation any Network
Operator’s switchgear position signals may be used only as additional
information which cannot be solely relied on.
3) Power Generating Modules shall be capable of continuing operation,
minimum for 30 minutes, following tripping to houseload, irrespective of
any auxiliary connection to the external Network. The minimum operation
time shall be defined by the Relevant Network Operator in coordination
with TEIAS taking into consideration the specific characteristics of the
prime mover technology.
6. Type C Power Generating Modules shall fulfil the following general system
management requirements:
a) With regard to loss of angular stability or loss of control a Power Generating
Module shall be capable of disconnecting automatically from the Network in order to
80
support preservation of system security and/or to prevent damage from the Power
Generating Module. The Power Generating Facility Owner and the Relevant Network
Operator in coordination with TEIAS shall agree on the criteria to detect loss of angular
stability or loss of control.
b) With regard to instrumentation:
1) Power Generating Facilities shall be equipped with a facility to provide fault
recording and dynamic system behaviour monitoring of the following
parameters:
 Voltage;
 Active Power;
 Reactive Power; and
 Frequency.
The Relevant Network Operator shall have the right to define quality of supply
parameters to be complied with provided a reasonable prior notice is given.
2) The settings of the fault recording equipment, including triggering criteria
and the sampling rates shall be agreed between the Power Generating Facility
Owner and the Relevant Network Operator in coordination with TEIAS.
3) The dynamic system behaviour monitoring shall include an oscillation
trigger, specified by the Relevant Network Operator in coordination with
TEIAS, detecting poorly damped power oscillations.
4) The facilities for quality of supply and dynamic system behaviour monitoring
shall include arrangements for the Power Generating Facility Owner, the
Relevant Network Operator and/or TEIAS to access the information. The
communications protocols for recorded data shall be agreed between the Power
Generating Facility Owner and the Relevant Network Operator and TEIAS.
c) With regard to the simulation models:
1) The Relevant Network Operator in coordination with TEIAS shall have
the right to require the Power Generating Facility Owner to provide
simulation models, that shall properly reflect the behaviour of the Power
Generating Module in both steady-state and dynamic simulations (50 Hz
component) and, where appropriate and justified, in electromagnetic
transient simulations.
The decision shall include:
 the format in which models shall be provided
 the provision of documentation of models structure and block diagrams
The models shall be verified against the results of compliance tests as of
PART V, SECTION4, 4.2 and 4.3. They shall then be used for the purpose
of verifying the requirements of this Network Code including but not
limited to Compliance Simulations as of PART V, SECTION4, Chapters 4.4
and 4.5 and for use in studies for continuous evaluation in system planning
and operation.
81
2) For the purpose of dynamic simulations, the models provided shall
contain the following sub-models, depending on the existence of the mentioned
components:
 Alternator and prime mover;
 Speed and power control;
 Voltage control, including, if applicable, Power System Stabilizer (PSS)
function and excitation system;
 Power Generating Module protection models as agreed between the
Relevant Network Operator and the Power Generating Facility Owner
and
 Converter models for Power Park Modules.
 In a format agreed with TEIAS
3) The Relevant Network Operator shall deliver to the Power Generating
Facility Owner an estimate of the minimum and maximum short circuit
capacity at the connection point, expressed in MVA, as an equivalent of the
Network.
4) The Relevant Network Operator or TEIAS shall have the right to require
Power Generating Module recordings in order to compare the response of
the models with these recordings.
d) With regard to the installation of devices for system operation and/or security, if
the Relevant Network Operator or TEIAS considers additional devices necessary to be
installed in a Power Generating Facility in order to preserve or restore system operation or
security, the Relevant Network Operator or TEIAS and the Power Generating Facility
Owner shall investigate this request and agree on an appropriate solution.
e) The Relevant Network Operator in coordination with TEIAS shall have the right
to define minimum and maximum limits on rates of change of Active Power output
(ramping limits) in both up and down direction for a Power Generating Module taking into
consideration the specific characteristics of the prime mover technology.
f) With regard to earthing arrangement of the neutral-point at the Network side of
step-up transformers, it shall be in accordance with the specifications of the Relevant
Network Operator.
g) With regard to changes to, modernization of or replacement of equipment of
Power Generating Modules, any Power Generating Facility Owner intending to change
plant and equipment of the Power Generating Module that may have an impact on the grid
connection and on the interaction, such as turbines, Alternators, converters, high-voltage
equipment, protection and control systems (hardware and software), shall notify in advance
(in accordance with agreed or decided national timescales) the Relevant Network Operator
in case it is reasonable to foresee that these intended changes may be affected by the
requirements of this Regulation and shall, agree on these requirements before the proposals
are implemented with the Relevant Network Operator in coordination with TEIAS. In case
of modernisation or replacement of equipment in existing Power Generating Modules the
new equipment shall comply with the respective requirements which are relevant to the
planned work. The use of existing spare components that do not comply with the
requirements has to be agreed with the Relevant Network Operator in coordination with
TEIAS in each case.
82
ARTICLE 50 General requirements for type D power generating
modules
[New Article, harmonization with ENTSO-E code RFG Article 11]
1. In addition to fulfilling the requirements listed in ARTICLE 47, ARTICLE 48 and
ARTICLE 49 unless referred to otherwise in this Article, except for ARTICLE 47 (1) (f),
(g), ARTICLE 48 (2) (a) and ARTICLE 49 (3) (a), Type D Power Generating Modules
shall fulfil the requirements in this Article.
2. Type D Power Generating Modules shall fulfil the following requirements referring to
Voltage stability:
a) With regard to Voltage ranges:
1) While still respecting the provisions according to ARTICLE 48 (3) (a)
and ARTICLE 50 (3) (a), a Power Generating Module shall be capable of
staying connected to the Network and operating within the ranges of the
Network Voltage at the Connection Point, expressed by the Voltage at the
Connection Point related to nominal Voltage (kV), and the time periods
specified by tables 6.1 and 6.2.
Rated Nominal Voltage
Voltage Range
[kV]
[kV]
170 - 172.5
140 - 170
130.9 - 140
72.5 - 75.9
59.4 - 72.5
56.1 - 59.4
154
66
Time period
operation
for
20 minutes
Unlimited
60 minutes
20 minutes
Unlimited
60 minutes
Table 6.1: This table shows the minimum time periods a Power Generating Module
shall be capable of operating for Voltages deviating from the nominal value at the
Connection Point without disconnecting from the Network.
Rated Nominal Voltage
Voltage Range
[kV]
[kV]
420 - 440
360 - 420
340 - 360
400
Time period
operation
for
60 minutes
Unlimited
60 minutes
Table 6.2: This table shows the minimum time periods a Power Generating Module
shall be capable of operating for Voltages deviating from the nominal value at the
Connection Point without disconnecting from the Network.
2) Wider Voltage ranges or longer minimum times for operation can be
agreed between the Relevant Network Operator in coordination with TEIAS
83
and the Power Generating Facility Owner to ensure the best use of the
technical capabilities of a Power Generating Module if needed to preserve
or to restore system security. If wider Voltage ranges or longer minimum
times for operation are economically and technically feasible, the consent of
the Power Generating Facility Owner shall not be unreasonably withheld.
3) While still respecting the provisions of ARTICLE 50 (2) (a) point 1), the
Relevant Network Operator in coordination with TEIAS shall have the right
to specify Voltages at the Connection Point at which a Power Generating
Module shall be capable of automatic disconnection. The terms and settings
for automatic disconnection shall be agreed between the Relevant Network
Operator and the Power Generating Facility Owner
3. Type D Power Generating Modules shall fulfil the following requirements referring to
robustness of Power Generating Modules:
a) With regard to fault-ride-through capability of Power Generating Modules:
1) The voltage-against-time-profile shall be defined by TEIAS using
parameters in figure 3 according to tables 7.1.
Voltage parameter Time parameters [seconds]
[pu]
U ret :
0.00 pu
t clear :
0.150 sec
U clear :
0.00 pu
t rec1 :
1.5 sec
(Unless stated otherwise.
U rec1 :
0.90 pu
TEIAS can extend the
time up to 3 sec)
Table 7.1 – Parameters for figure 3 for fault-ride-through capability of Power
Generating Modules
2) TEAIS shall define and make publicly available the pre-fault and postfault conditions for the fault-ride-through capability according to ARTICLE
48 (3) (a) point 3).
3) TEIAS shall provide on request by the Power Generating Facility Owner
the pre-fault and post-fault conditions to be considered for fault-ridethrough capability as an outcome of the calculations at the Connection Point
as defined in ARTICLE 48 (3) (a) point 3) regarding:
 pre-fault minimum short circuit capacity at each Connection Point
expressed in MVA;
 pre-fault operating point of the Power Generating Module expressed in
Active Power output and Reactive Power output at the Connection Point
and Voltage at the Connection Point; and
 post-fault minimum short circuit capacity at each Connection Point
expressed in MVA.
4) Fault-ride-through capabilities in case of asymmetrical faults shall be
defined by each TSO.
84
4. Type D Power Generating Modules shall fulfil the following general system
management requirements:
a) With regard to synchronization, when starting a Power Generating Module,
synchronization shall be performed by the Power Generating Facility Owner after
authorization by the TEIAS. The Power Generating Module shall be equipped with the
necessary synchronization facilities. Synchronization of Power Generating Modules
shall be possible for frequencies within the ranges set out in ARTICLE 47 (1) (a).
TEIAS and the Power Generating Facility Owner shall agree on the settings of
synchronization devices to be concluded prior to operation of the Power Generating
Module. An agreement shall cover the following matters: Voltage, Frequency, phase
angle range, phase sequence, deviation of Voltage and Frequency.
1. 2
Requirements for synchronous power generating
modules
ARTICLE 51 Requirements
generating modules
for
type
B
synchronous
power
[New Article, harmonization with ENTSO-E code RFG Article 12]
1. In addition to fulfilling the requirements listed in ARTICLE 47 and ARTICLE 48, Type
B Synchronous Power Generating Modules shall fulfil the requirements in this Article.
2. Type B Synchronous Power Generating Modules shall fulfil the following requirements
referring to Voltage stability:
a) With regard to Reactive Power capability the Relevant Network Operator shall
have the right to define the capability of a Synchronous Power Generating Module
to provide Reactive Power.
b) With regard to the Voltage control system, a Synchronous Power Generating
Module shall be equipped with a permanent automatic excitation control system in
order to provide constant Alternator terminal Voltage at a selectable Setpoint
without instability over the entire operating range of the Synchronous Power
Generating Module.
3. Type B Synchronous Power Generating Modules shall fulfil the following requirements
referring to robustness of Power Generating Modules:
a) With regard to post fault Active Power recovery after fault-ride-through, TEIAS
shall define magnitude and time for Active Power recovery the Power Generating
Module shall be capable of providing.
ARTICLE 52 Requirements
generating modules
for
type
C
synchronous
[New Article, harmonization with ENTSO-E code RFG Article 13]
85
power
1. In addition to fulfilling the requirements listed in ARTICLE 47, ARTICLE 48,
ARTICLE 49 and ARTICLE 51, except for ARTICLE 47 (1) (f), ARTICLE 48 (2) (a) and
ARTICLE 51 (2) (a), Type C Synchronous Power Generating Modules shall fulfil the
requirements in this Article.
2. Type C Synchronous Power Generating Modules shall fulfil the following requirements
referring to Voltage stability:
a) With regard to Reactive Power Capability, for Synchronous Power Generating
Modules where the Connection Point is not at the location of the high-voltage
terminals of the step-up transformer to the Voltage level of the Connection Point
nor at the Alternator terminals, if no step-up transformer exists, supplementary
Reactive Power may be defined by the Relevant Network Operator, to compensate
for the Reactive Power demand of the high-voltage line or cable between these two
points from the responsible owner of this line or cable.
b) With regard to Reactive Power capability at Maximum Capacity:
1) the U-Q/Pmax-profile, within the boundary of which the Type C
Synchronous Power Generating Modules shall be capable of providing
Reactive Power at its Maximum Capacity is a rectangular shape defined by
the coordinates in the following table.
Voltage at the Connection Point (kV)
33 kV busbar of 400/33 for
Q/Pmax [pu]
stations
66 kV:
x1=0.41pu (lag)
y1= 31.35
59.4 kV
x2=0.41pu (lag)
y2= 34.65
72.5 kV
x3=-0.33 (lead)
y3= 34.65
72.5 kV
x4=-0.33 (lead)
y4= 31.35
59.4 kV
Table of coordinates at the connection point for rectangular shape U-Q/Pmax-profile at
Maximum Capacity, for Type C Synchronous Power Generating Modules
2) The Reactive Power provision capability requirement applies at the
Connection Point.
3) The Synchronous Power Generating Module shall be capable of moving
to any operating point within its U-Q/Pmax profile in appropriate timescales,
adjustable between 10 seconds and 1 minute, to target values requested by
the Relevant Network Operator or TEIAS in terms and conditions related to
connection included into the connection agreement.
c) With regard to Reactive Power capability below Maximum Capacity, when operating at
an Active Power output below the Maximum Capacity (P<Pmax), the Synchronous Power
Generating Modules shall be capable of operating in every possible operating point in the
P¬Q Capability Diagram of the Alternator of this Synchronous Power Generating Module
at least down to Minimum Stable Operating Level. Even at reduced Active Power output,
Reactive Power supply at the Connection Point shall fully correspond to the P-QCapability Diagram of the Alternator of this Synchronous Power Generating Module,
taking the auxiliary supply power and the Active and Reactive Power losses of the step-up
transformer, if applicable, into account.
86
ARTICLE 53 Requirements
generating modules
for
type
D
synchronous
power
[New Article, harmonization with ENTSO-E code RFG Article 14]
1. In addition to fulfilling the requirements listed in ARTICLE 47, ARTICLE 48,
ARTICLE 49,ARTICLE 50, ARTICLE 51 and ARTICLE 52, except for ARTICLE 47 (1)
(f), ARTICLE 48(2) (a), ARTICLE 49 (3) (a), ARTICLE 51 (2) and ARTICLE 52 (2) (b),
Type D Synchronous Power Generating Modules shall fulfil the requirements in this
Article.
2. Type D Synchronous Power Generating Modules shall fulfil the following requirements
referring to Voltage stability:
a) The parameters and settings of the components of the Voltage control system
shall be agreed between the Power Generating Facility Owner and TEIAS. Such
agreement shall include:







specifications and performance of an Automatic Voltage Regulator (AVR)
with regards to steady-state Voltage and transient Voltage control; and
specifications and performance of the Excitation System:
bandwidth limitation of the output signal to ensure that the highest
Frequency of response cannot excite torsional oscillations on other Power
Generating Modules connected to the Network;
an Underexcitation Limiter to prevent the Automatic Voltage Regulator
from reducing the Alternator excitation to a level which would endanger
synchronous stability;
an Overexcitation Limiter to ensure that the Alternator excitation is not
limited to less than the maximum value that can be achieved whilst ensuring
the Synchronous Power Generating Module is operating within its design
limits;
a stator Current limiter; and
a PSS function to attenuate power oscillations, if the Synchronous Power
Generating Module size is above the value of Maximum Capacity defined
by TEIAS.
b) Type D Synchronous Power Generating Modules shall fulfil requirements
referring to Power System Stabilizer (PSS) function and excitation system as
defined by TEIAS. TEIAS shall have the right prior to connection to require PSS
function to attenuate power oscillations.
c) With regard to Reactive Power capability at Maximum Capacity:
1) the U-Q/Pmax-profile, within the boundary of which the Type D
Synchronous Power Generating Modules shall be capable of providing
Reactive Power at its Maximum Capacity is a rectangular shape defined by
the coordinates in the following table.
Q/Pmax [pu]
Voltage at the Connection Point (kV)
87
for
for
154 kV:
400 kV:
x1=0.41pu (lag)
y1= 140 kV
360 kV
x2=0.41pu (lag)
y2= 170 kV
420 kV
x3=-0.33 (lead)
y3= 170 kV
420 kV
x4=-0.33 (lead)
y4= 140 kV
360 kV
Table of coordinates at the connection point for rectangular shape U-Q/Pmax-profile at
Maximum Capacity, for Type D Synchronous Power Generating Modules
2) The Reactive Power provision capability requirement applies at the
Connection Point.
3) The Synchronous Power Generating Module shall be capable of moving
to any operating point within its U-Q/Pmax profile in appropriate timescales,
adjustable between 10 seconds and 1 minute, to target values requested by
the Relevant Network Operator or TEIAS in terms and conditions related to
connection included into the connection agreement.
3. Type D Synchronous Power Generating Modules shall fulfil the following requirements
referring to robustness of Power Generating Modules:
a) Technical capabilities in order to aid angular stability under fault conditions (e. g.
fast valving or braking resistor) shall be implemented if allowed or requested by
TEIAS. The specifications shall be agreed between TEIAS and the Power Generating
Facility Owner.
1. 3
Requirements for power park modules
ARTICLE 54 Requirements for type B power park modules
[New Article, harmonization with ENTSO-E code RFG Article 15]
1. In addition to fulfilling the general requirements listed in ARTICLE 47 and ARTICLE
48, Type B Power Park Modules shall fulfil the requirements in this Article.
2. Type B Power Park Modules shall fulfil the following requirement referring to Voltage
stability:
a) With regard to Reactive Power capability:
1) At Maximum capacity, the U-Q/Pmax-profile within the boundary of
which the Type B Power Park Modules shall be capable of providing
Reactive Power at its Maximum Capacity is a rectangular shape defined by
the coordinates in the following table.
Voltage at the Connection Point
Q/Pmax [pu]
x1=0.33pu (lag)
below 66 kV:
y1=
0.95 pu
88
x2=0.33pu (lag)
y2= 1.05 pu
x3=-0.33 (lead)
y3= 1.05 pu
x4=-0.33 (lead)
y4= 0.95 pu
Table of coordinates at the connection point for rectangular shape U-Q/Pmax-profile at
Maximum Capacity, for Type D Power Park
2) The Reactive Power provision capability requirement applies at the
Connection Point.
3) With regard to Reactive Power capability below Maximum Capacity
(P<Pmax),the P-Q/Pmax-profile at the connection point, within the
boundary of which the Type B Power Park Modules shall be capable of
providing Reactive Power below Maximum Capacity is a rectangular shape
defined by the following coordinates:
P/Pmax
at
the
Connection Point [pu]
x1=0.33pu (lag)
y1=1pu
x2=0.33pu (lag)
y2=0.1pu
x3=-0.33 (lead)
y3=0.1pu
x4=-0.33 (lead)
y4=1pu
Table of coordinates at the connection point for rectangular shape P-Q/Pmaxprofile below Maximum Capacity, for Type B Power Park Module
Q/Pmax
Below 0.1pu Active Power, Reactive Power Capability is not required.
b) The Relevant Network Operator in coordination with TEIAS shall have the right
to require in terms and conditions related to connection included into the
connection agreement. fast acting additional reactive Current injection at the
Connection Point to the pre-fault reactive Current injection in case of symmetrical
(3-phase) faults:
1) The Power Park Module shall be capable of activating this additional
reactive Current injection during the period of faults. The Power Park
Module shall be capable of either:
a. ensuring the supply of the additional reactive Current at the
Connection Point according to further specifications by the Relevant
Network Operator in coordination with TEIAS of the magnitude of
this Current, depending on the deviation of the Voltage at the
Connection point from its nominal value; or
b. alternatively, measuring Voltage deviations at the terminals of the
individual units of the Power Park Module and providing an
additional reactive Current at the terminals of these units according
to further specifications by the Relevant Network Operator in
coordination with TEIAS of the magnitude of this Current,
depending on the deviation of the Voltage at units’ terminals from its
nominal value.
89
2) The Power Park Module (ARTICLE 54 (2) (b) point 1) option a.) or the
individual units of the Power Park Module (ARTICLE 54 (2) (b) point 1)
option b.) shall be capable of providing at least 2/3 of the additional reactive
Current within a time period specified by TEIAS which shall not be less
than 10 milliseconds. The target value of this additional reactive Current
defined by ARTICLE 54 (2) (b) point 1) shall be reached with an accuracy
of 10% within 60 milliseconds from the moment the Voltage deviation has
occurred as further specified according to ARTICLE 54 (2) (b) point 1).
3) The total reactive Current contribution shall be not more than 1 pu of the
short term dynamic Current rating (covering up to 0.4 seconds) of the Power
Park Module (ARTICLE 54 (2) (b) point 1) option a.) or of the individual
units of the Power Park Module (ARTICLE 54 (2) (b) point 1) option b.)
taking into account the pre-fault reactive Current. If additional real Current
injection is given priority over additional reactive Current injection, the total
Current contribution can be further limited by the real Current based on
limiting the apparent Current (vector addition of real and reactive Current)
to 1 pu of the short term dynamic Current rating of the Power Park Module
(ARTICLE 54 (2) (b) point 1) option a.) or the individual units of the Power
Park Module (ARTICLE 54 (2) (b) point 1) option b.).
c) With regard to fast acting additional reactive Current injection in case of asymmetrical
(1¬ phase or 2-phase) faults the Relevant Network Operator in coordination with TEIAS
shall have the right to introduce a requirement for asymmetrical Current injection in terms
and conditions related to connection included into the connection agreement.
3. Type B Power Park Modules shall fulfil the following requirements referring to
robustness of Power Generating Modules:
a) With regard to post fault Active Power recovery after fault-ride-through, TEIAS
shall specify magnitude and time for Active Power recovery the Power Park
Module shall be capable of providing.
b) Type B Power Park Module based on wind energy connected to the distribution
system having Maximum Capacity of 10 MW and shall fulfil the following
requirement related to robustness:
They shall stop to provide electric power to the network, when Frequency is above
51.5 Hz.
During the period in which the grid phase-phase voltage at the connection point of
the transmission or distribution system remains in the zone no 1 and zone no 2
shown in the Figure E.18.1., the wind turbines should remain connected to the grid
in case of voltage drops arising in any phase or all phases.
90
Grid Phase-Phase voltage (p,u)
Time, millisecond
Figure E.18.1 – grid phase-phase voltage at the connection point of the transmission or
distribution system
In the cases that the voltage drop remains in the zone no 1 during failure, the active power
of the wind turbine should achieve the maximum active power value that can be generated
by being increased at least 20 % of the nominal active power in a second immediately after
the removal of the failure. In the cases that the voltage drop remains in the zone no 2
during failure, the active power of the wind turbine should achieve the maximum active
power value that can be generated by being increased at least 5 % of the nominal active
power in a second immediately after the removal of the failure.
In the voltage fluctuations higher than ±10% that will occur in the mentioned failure cases
at the grid connection point, each wind turbine generator should provide maximum
reactive current support in inductive or capacitive direction without exceeding the designed
transient rated values, at the levels to reach 100% of the nominal current if required.
ARTICLE 55 Requirements for type C power park modules
[New Article, harmonization with ENTSO-E code RFG Article 16]
1. In addition to fulfilling the requirements listed in ARTICLE 47, ARTICLE 48,
ARTICLE 49 and ARTICLE 54, except for ARTICLE 47 (1) (f), ARTICLE 48 (2) (a), and
ARTICLE 54(2) (a), Type C Power Park Modules shall fulfil the requirements in this
Article.
2. Type C Power Park Modules shall fulfil the following requirements referring to
Frequency stability:
91
a) With regard to the capability of providing Synthetic Inertia to a low Frequency
event:
1) TEIAS shall have the right to require in co-operation with other TSOs in
the relevant Synchronous Area, a Power Park Module, which is not
inherently capable of supplying additional Active Power to the Network by
its Inertia, to install a feature in the control system which operates the Power
Park Module so as to supply additional Active Power at the Connection
Point, in order to limit the rate of change of Frequency following a sudden
loss of infeed.
2) The operating principle of this control system and the associated
performance parameters shall be defined by TEIAS in terms and conditions
related to connection included into the connection agreement.
3. Type C Power Park Modules shall fulfil the following requirements referring to Voltage
stability:
a) With regard to Reactive Power Capability, for Power Park Modules where the
Connection Point is not at the location of the high-voltage terminals of its step-up
transformer nor at the terminals of the high-voltage line or cable to the Connection
Point at the Power Park Module, if no step-up transformer exists, supplementary
Reactive Power may be required by the Relevant Network Operator to compensate
for the Reactive Power demand of the high-voltage line or cable between these two
points from the responsible owner of this line or cable.
b) With regard to Reactive Power capability at Maximum Capacity:
1) the U-Q/Pmax-profile, within the boundary of which the Type C Power
Park Modules shall be capable of providing Reactive Power at its Maximum
Capacity is a rectangular shape defined by the coordinates in the following
table
2) The Reactive Power provision capability requirement applies at the
Connection Point .
Voltage at the Connection Point (kV)
33 kV busbar of 400/33 for
Q/Pmax [pu]
stations
66 kV:
x1=0.41pu (lag)
y1= 31.35
59.4 kV
x2=0.41pu (lag)
y2= 34.65
72.5 kV
x3=-0.33 (lead)
y3= 34.65
72.5 kV
x4=-0.33 (lead)
y4= 31.35
59.4 kV
Table of coordinates at the connection point for rectangular shape U-Q/Pmax-profile at
Maximum Capacity, for Type C Power Park Module
c) With regard to Reactive Power capability below Maximum Capacity,
1) the P-Q/Pmax-profile at the connection point, within the boundary of
which the Type C Power Park Modules shall be capable of providing
92
Reactive Power below Maximum Capacity is a rectangular shape defined by
the following coordinates:
P/Pmax
at
the
Connection Point [pu]
x1=0.41pu (lag)
y1=1pu
x2=0.41pu (lag)
y2=0.1pu
x3=-0.33 (lead)
y3=0.1pu
x4=-0.33 (lead)
y4=1pu
Table of coordinates at the connection point for rectangular shape P-Q/Pmaxprofile below Maximum Capacity, for Type C Power Park Module
Q/Pmax
2) Below 0.1pu Active Power, Reactive Power Capability is not required
(referring to Figure 9).
3) When operating at an Active Power output below the Maximum Capacity
(P<Pmax), the Power Park Module shall be capable of providing Reactive
Power at any operating point inside its P-Q/Pmax-profile, if all units of this
Power Park Module, which generate power, are technically available (i. e.
not out-of-service due to maintenance or failure). Otherwise the Reactive
Power capability may be less taking into consideration the technical
availabilities.
4) The Power Park Module shall be capable of moving to any operating
point within its P¬Q/Pmax profile in appropriate timescales, adjustable
between 10 seconds and 1 minute, to target values requested by TEIAS or
the Relevant Network Operator in terms and conditions related to
connection included into the connection agreement.
d) With regard to Reactive Power control modes:
1) The Power Park Module shall be capable of providing Reactive Power
automatically by either Voltage Control mode, Reactive Power Control
mode or Power Factor Control mode.
2) For the purposes of Voltage Control mode, the Power Park Module shall
be capable of contributing to Voltage control at the Connection Point by
provision of Reactive Power exchange with the Network with a Setpoint
Voltage covering at least 0.90 to 1.10 pu in steps no greater than 0.01 pu
with a Slope with a range of at least 2 to 7 % in steps no greater than 0.5 %.
The Reactive Power output shall be zero when the grid Voltage value at the
Connection Point equals the Voltage Setpoint.
The Setpoint may be operated with or without a deadband selectable in a
range from zero to +-5 % of nominal Network Voltage in steps no greater
than 0.5 %.
Following a step change in Voltage, the Power Park Module shall be
capable of achieving 90 % of the change in Reactive Power output within a
time t1 to be specified by TEIAS or the Relevant Network operator in the
range of 1 - 5 seconds and settle at the value defined by the operating Slope
within a time t2 to be specified by TEIAS or the Relevant Network Operator
in the range of 5 - 60 seconds, with a steady-state reactive tolerance no
93
greater than 5 % of the maximum Reactive Power. The times t 1 and t2 will
be specified by TEIAS or the Relevant Network Operator in the connection
agreement.
3) For the purposes of Reactive Power Control mode, the Power Park
Module shall be capable of setting the Reactive Power Setpoint anywhere in
the Reactive Power range, defined by ARTICLE 54 (2) (a) and by
ARTICLE 55 (3) (a) and (b), with setting steps no greater than 5 Mvar or 5
% (whichever is smaller) of full Reactive Power, controlling the Reactive
Power at the Connection Point to an accuracy within +-5 Mvar or +-5 %
(whichever is smaller) of the full Reactive Power.
4) For the purposes of Power Factor Control mode, the Power Park Module
shall be capable of controlling the Power Factor at the Connection Point
within the required Reactive Power range, defined by the Relevant Network
Operator according to ARTICLE 54 (2) (a) or defined by ARTICLE 55 (3)
(a) and (b), with a target Power Factor in steps no greater than 0.01. The
Relevant Network Operator shall define the target Power Factor value and
the tolerance expressed in Mvar or % on the Reactive Power value issued
from conversion of Power Factor value, within a period of time, following a
sudden change of Active Power output.
5) The Relevant Network Operator in coordination with TEIAS shall define
which of the above three reactive power control mode options and
associated Setpoints shall apply and further equipment to make the
adjustment of the relevant Setpoint operable remotely.
e) With regard to priority to Active or Reactive Power contribution, TEIAS shall
define, whether Active Power contribution or Reactive Power contribution has
priority during faults for which fault-ride-through capability is required. If priority
is given to Active Power contribution, its provision shall be established no later
than 150 ms from the fault inception. Requirements related to the priority to Active
or Reactive Power contribution will be defined in terms and conditions related to
connection included into the connection agreement.
f) With regard to power oscillations damping control, if required by TEIAS prior to
connection, a Power Park Module shall be capable of contributing to damping
power oscillations. The voltage and reactive power control characteristics of Power
Park Modules shall not adversely affect the damping of power oscillations.
ARTICLE 56 Requirements for type D power park modules
[New Article, harmonization with ENTSO-E code RFG Article 17]
1. Type D Power Park Modules shall fulfil the requirements listed in ARTICLE 47,
ARTICLE 48, ARTICLE 49, ARTICLE 50, ARTICLE 54 and ARTICLE 55, except for
ARTICLE 47 (1) (f),ARTICLE 48 (2) (a), ARTICLE 49 (3) (a), ARTICLE 54 (2) (a) and
ARTICLE 55 (3) (b).
2. Type D Power Park Modules shall fulfil the following requirements referring to Voltage
stability:
a) With regard to Reactive Power capability at Maximum Capacity:
94
1) the U-Q/Pmax-profile, within the boundary of which the Type C Power
Park Modules shall be capable of providing Reactive Power at its Maximum
Capacity is a rectangular shape defined by the coordinates in the following
table.
Voltage at the Connection Point (kV)
Q/Pmax [pu]
for
for
for
66 kV:
154 kV:
400 kV:
x1=0.41pu (lag)
y1= 59.4 kV
140 kV
360 kV
x2=0.41pu (lag)
y2= 72.5 kV
170 kV
420 kV
x3=-0.33 (lead)
y3= 72.5 kV
170 kV
420 kV
x4=-0.33 (lead)
y4= 59.4 kV
140 kV
360 kV
Table of coordinates at the connection point for rectangular shape U-Q/Pmax-profile at
Maximum Capacity, for Type D Power Park Module
2) The Reactive Power provision capability requirement applies at the
Connection Point.
SECTION 2
Requirement for demand connection
ARTICLE 57 General frequency requirements
[New Article, harmonization with ENTSO-E code DCC Article 13]
1. All Transmission Connected Demand Facilities, and all Distribution Networks, shall
fulfil the following Frequency stability requirements:
a) With regard to Frequency ranges:
1) A Transmission Connected Demand Facility Owner and Distribution
Network Operator shall use their best endeavours in the design of its
Transmission Connected Demand Facility and Distribution Network
respectively for it to cope with the Frequency ranges and time periods
specified below
Frequency Range
51 Hz ≤ f < 51.5 Hz
49 Hz ≤ f < 51 Hz
48.5 Hz ≤ f < 49 Hz
47.5 Hz ≤ f < 48.5 Hz
Minimum Time Period
30 minutes
Unlimited
1 hour
>30 minutes
2) Wider Frequency ranges or longer minimum times for operation can be
agreed between TEIAS and the Distribution Network Operator or Transmission
Connected Demand Facility Owner, in coordination with TEIAS. If wider
Frequency ranges or longer minimum times for operation are technically
feasible, the consent of the Distribution Network Operator or Transmission
Connected Demand Facility Owner shall not be unreasonably withheld.
95
ARTICLE 58 General voltage requirements
[New Article, harmonization with ENTSO-E code DCC Article 14]
1. All Transmission Connected Demand Facilities and all Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following Voltage stability requirements:
a) With regard to Voltage ranges:
1). In case of a deviation of the Network Voltage at the Connection Point from
its nominal value, any Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator with a Connection
Point at 110 kV or above, shall ensure its equipment at the Connection Point
site is capable of withstanding without damage the Voltage range at the
Connection Point, expressed in kV, within the time periods specified by table
below.
Rated Nominal Voltage
Voltage Range
[kV]
[kV]
420 - 440
360 - 420
340 - 360
170 - 172.5
140 - 170
130.9 - 140
400
154
Time period
operation
for
60 minutes
Unlimited
60 minutes
20 minutes
Unlimited
60 minutes
2). Notwithstanding the provisions of paragraph (1)a)1), a Transmission
Connected Demand Facility and Transmission Connected Distribution Network
shall be capable of automatic disconnection at specified Voltages, if required by
TEIAS. The terms and settings for automatic disconnection shall be agreed
between TEIAS and the Transmission Connected Demand Facility Owner or
the Transmission Connected Distribution Network Operator.
ARTICLE 59 Short‐circuit requirements
[New Article, harmonization with ENTSO-E code DCC Article 15]
1. All Transmission Connected Demand Facilities and Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following requirements referring to short‐circuit Current:
a) Based on the rated short‐circuit withstand capability of its equipment, TEIAS
shall define the maximum short‐circuit Current at the Connection Point that the
Transmission Connected Demand Facility and Transmission Connected
Distribution Network shall be capable of withstanding.
b) TEIAS shall deliver to the Transmission Connected Demand Facility Owner and
Transmission Connected Distribution Network Operator an estimate of the
96
minimum and maximum short‐circuit Currents at the Connection Point as an
equivalent of the Network.
c) TEIAS shall inform the Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator as soon as practicable, but
no later than one week after an unplanned event, of the changes above a threshold
in the maximum short‐circuit current that it shall be able to withstand from its
Network in paragraph (1)(a). The threshold will be set by either the Transmission
Connected Demand Facility Owner for their facility or Transmission Connected
Distribution Network Operator for their Distribution Network.
d) TEIAS shall inform the Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator as soon as practicable
before a planned event of changes above a threshold in the maximum short‐circuit
current that it shall be able to withstand from its Network in paragraph (1)(a). The
threshold will be set by either the Transmission Connected Demand Facility Owner
for their facility or Transmission Connected Distribution Network Operator for
their Distribution Network.
e) TEIAS shall request information from a Transmission Connected Demand
Facility Owner or a Transmission Connected Distribution Network Operator,
concerning the contribution in terms of short‐circuit current from that facility or
Network respectively. As a minimum this should be as an equivalent of the
Network for zero, positive and negative sequence.
f) The Transmission Connected Demand Facility Owner and Transmission
Connected Distribution Network Operator shall inform TEIAS as soon as
practicable, but no later than one week after an unplanned event, of the changes in
short‐circuit contribution above a threshold set by TEIAS, from its Demand Facility
or Distribution Network in paragraph 1(e).
g) The Transmission Connected Demand Facility Owner and Transmission
Connected Distribution Network Operator shall inform TEIAS as soon as
practicable before a planned event of changes in short‐circuit contribution above a
threshold set by TEIAS, from its Demand Facility or Distribution Network in
paragraph 1(e).
ARTICLE 60 Reactive power requirements
[New Article, harmonization with ENTSO-E code DCC Article 16]
1. All Transmission Connected Demand Facilities and all Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following requirements referring to Reactive Power exchange and control:
a) With regard to Reactive Power ranges:
1) Transmission Connected Distribution Networks and Transmission
Connected Demand Facilities shall be capable to maintain their steady‐state
operation at their Connection Point in a Reactive Power range specified by
TEIAS and the following conditions:
97







For Transmission Connected Demand Facilities without onsite
generation, the actual Reactive Power range specified by TEIAS for
importing reactive power shall not be wider than 0.9 to 1 Power
Factor of their Maximum Import Capability, except in situations
where either technical or financial system benefits are demonstrated
and accepted by TEIAS;
For Transmission Connected Demand Facilities with onsite
generation, the actual Reactive Power range specified by TEIAS
shall not be wider than 0.9 Power Factor of the larger of their
Maximum Import Capability or Maximum Export Capability in
import to 0.9 Power Factor of their Maximum Export Capability in
export, except in situations where either technical or financial system
benefits are demonstrated and accepted by TEIAS;
For Transmission Connected Distribution Networks, the actual
Reactive Power range
specified by TEIAS shall not be wider than 0.9 Power Factor of the
larger of their Maximum Import Capability or Maximum Export
Capability in import to 0.9 Power Factor of their Maximum Export
Capability in export, except in situations where either technical or
financial system benefits are demonstrated by TEIAS and the
Distribution Network Operator through joint analysis.
The scope of the analysis shall be agreed between TEIAS and
Distribution Network Operator and will consider the possible
solutions and determine the optimal solution for reactive power
exchange between their Networks taking adequately in consideration
the specific Network characteristics, variable structure of power
exchange, bidirectional flows and the Reactive Power capabilities in
the Distribution Network;
The use of other metrics than Power Factor to define equivalent
Reactive Power capability ranges can be specified by TEIAS.
The Reactive Power range requirement shall apply at the Connection
Point.
2) Transmission Connected Distribution Networks shall have the capability
at the Connection Point to not export Reactive Power (at nominal Voltage)
at an Active Power flow of less than 25% of the Maximum Import
Capability, except in situations where either technical or financial system
benefits are demonstrated by TEIAS and the Distribution Network Operator
through joint analyses.
3) The scope of the analysis will be agreed between TEIAS and Distribution
Network Operator and will consider the possible solutions and determine the
optimal solution for reactive power exchange between their Networks taking
adequately in consideration the specific Network characteristics, variable
structure of power exchange, bidirectional flows and the reactive
capabilities in the Distribution Network;
b) Without prejudice to the provisions of paragraph 1(a) of this article, TEIAS shall
have the right to require the ability of the Transmission Connected Distribution
Network to actively control the exchange of Reactive Power at the Connection
Point as part of a wider common concept for management of Reactive Power
98
capabilities for the benefit of the entire Network. The method of this control shall
be agreed between TEIAS and the Transmission Connected Distribution Network
Operator to ensure the justified level of security of supply for both parties. The
justification shall include a roadmap in which the steps and the timeline for
fulfilling the requirement are specified.
c) The Distribution Network Operator shall have the right to apply to TEIAS to be
considered for Reactive Power management set out in paragraph b).
ARTICLE 61 Protection and control
[New Article, harmonization with ENTSO-E code DCC Article 17]
1. All Transmission Connected Demand Facilities and all Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following requirements referring to the protection and control:
a) With regard to electrical protection schemes and settings:
1) TEIAS shall define the settings necessary to protect the Network while
respecting the characteristics of the Transmission Connected Demand
Facility or Transmission Connected Distribution Network. Protection
schemes as well as settings relevant for the Transmission Connected
Demand Facility or Transmission Connected Distribution Network shall be
agreed between TEIAS and the Transmission Connected Demand Facility
Owner or Transmission Connected Distribution Network Operator.
2) Electrical protection of the Transmission Connected Demand Facility or
Transmission Connected Distribution Network shall take precedence over
operational controls while respecting system security, health and safety of
staff and the public as well as mitigation of the damage to the Transmission
Connected Demand Facility or Transmission Connected Distribution
Network.
b) Protection scheme devices may cover the following aspects:
1) external and internal short circuit;
2) over‐ and under‐voltage at the Connection Point;
3) over‐ and under‐frequency;
4) demand circuit protection;
5) unit transformer protection; and
6) backup schemes against protection and switchgear malfunction.
c) TEIAS shall define the mandatory devices.
d) Any changes to the protection schemes, relevant for the Transmission Connected
Demand Facility or Transmission Connected Distribution Network and the
Network, as well as to the setting relevant for the Transmission Connected Demand
Facility or Transmission Connected Distribution Network, shall be agreed between
TEIAS and the Transmission Connected Demand Facility Owner or Transmission
Connected Distribution Network Operator.
99
2. With regard to control schemes and settings:
a) Schemes and settings of the different control devices of the Transmission
Connected Demand Facility or Transmission Connected Distribution Network,
relevant for system security, shall be agreed between TEIAS, and the Transmission
Connected Demand Facility Owner or Transmission Connected Distribution
Network Operator. This agreement shall cover the following aspects:
1) isolated (Network) operation;
2) damping of oscillations;
3) disturbances to the Network;
4) automatic switching to emergency supply and come‐back to normal
topology; and
5) automatic circuit‐breaker re‐closure (on 1‐phase faults).
b) Any changes to the schemes and settings of the different control devices of the
Transmission Connected Demand Facility or Transmission Connected Distribution
Network, relevant for system security, shall be agreed between TEIAS, and the
Transmission Connected Demand Facility Owner or Transmission Connected
Distribution Network Operator.
3. With regard to priority ranking of protection and control, the Transmission Connected
Demand Facility Owner or Transmission Connected Distribution Network Operator shall
organize the protection and control devices of its Transmission Connected Demand
Facility or Distribution Network Connection respectively, in compliance with the
following priority ranking, organized in decreasing order of importance:
a) Network and Demand Facility or Distribution Network protection;
b) Frequency control (Active Power adjustment); and
c) Power Restriction.
ARTICLE 62 Information exchange
[New Article, harmonization with ENTSO-E code DCC Article 18]
1. All Transmission Connected Demand Facilities and Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following requirements related to the information exchange:
a) Transmission Connected Demand Facilities shall be equipped according to the
standard defined by TEIAS, to transfer information between TEIAS and the
Transmission Connected Demand Facility with the defined time stamping. The
defined standard shall be made publically available by TEIAS.
b) Transmission Connected Distribution Networks shall be equipped according to
the standard defined by TEIAS to transfer information between TEIAS and the
Transmission Connected Distribution Network with the defined time stamping. The
defined standard shall be made publically available by TEIAS.
c) TEIAS shall define the information exchange standards. The precise list of data
required shall be made publically available by TEIAS.
100
ARTICLE 63 Development,
replacement
modernization
and
equipment
[New Article, harmonization with ENTSO-E code DCC Article 19]
1. All Existing Distribution Network Connections, Existing Transmission Connected
Demand Facilities, Existing Demand Facilities and Existing Closed Distribution Networks,
deemed significant pursuant to the provisions of this Regulation, shall fulfil the following
requirements related to equipment development:
a) A Demand Facility Owner or Distribution Network Operator intending to
develop, increasing plant and equipment, of the Existing Demand Facility or
Existing Distribution Network Connection in a way that may have an impact on its
performance and ability to meet the requirements of this Regulation shall notify
TEIAS directly or indirectly (including but not restricted to via an Aggregator). The
notification shall take place in advance to the national timescales defined. This
equipment development may include high‐voltage equipment, protection and
control systems, including hardware and software.
b) The developed equipment shall comply with the respective Regulation
requirements which are relevant to the planned work.
2. All Existing Distribution Network Connections, Existing Transmission Connected
Demand Facilities, Existing Demand Facilities and Existing Closed Distribution Networks,
deemed significant pursuant to the provisions of this Regulation, shall fulfil the following
requirements related to modernization and equipment replacement:
a) A Demand Facility Owner or Distribution Network Operator intending to
modernize and replace the equipment of the Existing Demand Facility or Existing
Distribution Network in a way that may have an impact on its performance and
ability to meet the requirements of this Regulation shall notify to TEIAS directly or
indirectly (including but not restricted to via an Aggregator). The notification shall
take place in advance to the national timescales defined. This modernization and
equipment replacement may include high‐voltage equipment, protection and control
systems, including hardware and software
b) The modernized and replaced equipment shall comply with the respective
Regulation requirements which are relevant to the planned work.
ARTICLE 64 Demand disconnection for system defence and demand
reconnection
[New Article, harmonization with ENTSO-E code DCC Article 20]
1. All Transmission Connected Demand Facilities and Transmission Connected
Distribution Networks, deemed significant pursuant to the provisions of this Regulation,
shall fulfil the following requirements related to Low Frequency Demand Disconnection
schemes:
a) Each Transmission Connected Distribution Network Operator and as specified
by TEIAS, Transmission Connected Demand Facility Owner, shall provide
capabilities that shall enable automatic low Frequency (or alternatively if specified
101
by TEIAS combined with rate‐of‐ change‐of‐Frequency) disconnection of a
percentage of their demand. The percentage of the demand shall be specified by
TEIAS. This specification shall be based on a rule set defined by TEIAS.
b) The Low Frequency Demand Disconnection schemes shall be capable of
disconnecting demand in stages for a range of operational frequencies. The number
of stages and their respective operational frequencies shall be defined by TEIAS.
c) The percentage of the demand disconnection at each Frequency shall be defined
by TEIAS.
d) The geographical distribution of this demand disconnection shall be provided by
the Transmission Connected Distribution Network Operator or Transmission
Connected Demand Facility Owner and approved by TEIAS. In cases of nested
Distribution Networks the geographical distribution shall be equitable to all the
associated Distribution Network Operators.
e) Each Distribution Network Operator and Transmission Connected Demand
Facility Owner shall notify TEIAS in writing of the details of the automatic Low
Frequency Demand Disconnection on its Network. This notification shall be made
every year and shall identify, for each Connection Point to the Transmission
Network, the Frequency settings at which demand disconnection shall be initiated
and the percentage of demand disconnected at every such setting.
f) The Low Frequency Demand Disconnection scheme shall be suitable for
operation from a nominal AC input to be defined by TEIAS, and shall have the
following functional capability:
1) Frequency Range: at least between 47‐50Hz, adjustable in steps of
0.05Hz;
2) Operating time: no more than 150 ms after triggering the Frequency
setpoint;
3) Voltage lock‐out: blocking of the scheme should be possible when the
voltage is within a range of 30 to 90% of nominal Voltage; and
4) Direction of Active Power flow at the point of disconnection.
2. With regard to Low Frequency Demand Disconnection schemes AC Voltage supply:
a) The voltage supply to the Low Frequency Demand Disconnection schemes shall
be derived from the Network at the Frequency signal measuring point, as defined in
the Low Frequency Demand Disconnection scheme in paragraph 1(f), so that the
Frequency of the Low Frequency Demand Disconnection schemes supply Voltage
is the same as that of the Network.
3. With regard to Low Voltage Demand Disconnection schemes:
a) Low Voltage Demand Disconnection schemes for Transmission Connected
Distribution
102
Networks shall be defined by TEIAS, in coordination with Transmission Connected
Distribution Network Operators. In cases of nested Distribution Networks the
geographical distribution shall be equitable to all the associated Distribution
Network Operators.
b) Low Voltage Demand Disconnection schemes for a Transmission Connected
Demand Facility shall be defined by TEIAS, in coordination with the Transmission
Connected Demand Facility Owner.
c) Based on the TEIAS assessment of system security the implementation of Low
Voltage Demand Disconnection shall be binding for Transmission Connected
Distribution Network Operators.
d) If TEIAS decides to implement a Low Voltage Demand Disconnection scheme,
Low Voltage Demand Disconnection shall be fitted in a coordinated way led by
TEIAS.
e) The method of Low Voltage Demand Disconnection shall be implemented by
relay or Control Room initiation.
f) The Low Voltage Demand Disconnection schemes shall have the following
functional capability:
1) The Low Voltage Demand Disconnection scheme shall monitor the
Voltage by measuring all three phases.
2) Blocking of the relays operation shall be based on direction of either
Active Power or Reactive Power flow.
4. With regard to blocking of On Load Tap Changers:
a) The automatic On Load Tap Changer Blocking scheme shall be specified by
TEIAS.
5. Transmission Connected Demand Facilities and Transmission Connected Distribution
Networks shall fulfil the following requirement referring to disconnection or reconnection
of a Transmission Connected Demand Facility or Transmission Connected Distribution
Network:
a) With regard to capability of reconnection after a disconnection, TEIAS shall
define, the conditions under which a Transmission Connected Demand Facility and
Transmission Connected Distribution Network is entitled to reconnect to the
Transmission Network. Installation of automatic reconnection systems shall be
subject to prior authorization by TEIAS.
b) With regards to reconnection of a Transmission Connected Demand Facility or
Transmission Connected Distribution Network, the Transmission Connected
Demand Facility and Transmission Connected Distribution Network shall be
capable of synchronization for Frequencies within the ranges set out in ARTICLE
57 (1)(a)(1). TEIAS and the Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator shall agree on the settings
of synchronization devices prior to connection of the Transmission Connected
103
Demand Facility or Transmission Connected Distribution Network, including:
Voltage, Frequency, phase angle range, deviation of Voltage and Frequency.
c) A Transmission Connected Demand Facility and Transmission Connected
Distribution Network shall be capable of being remotely disconnected from the
Transmission Network when required by TEIAS. Where automated disconnection
equipment is required (for reconfiguration of the Network in preparation for Block
Loading) these shall be defined by TEIAS. The time taken for remote disconnection
shall be defined by TEIAS.
ARTICLE 65 Power quality
[New Article, harmonization with ENTSO-E code DCC Article 25]
1.
All Transmission Connected Demand Facility Owners and Transmission Connected
Distribution Network Operators shall ensure that their connection to the Network does not
result in excessive level of distortion or fluctuation of the supply Voltage on the Network,
at the Connection Point. The level of distortion or fluctuation shall not exceed the
thresholds defined in the articlesARTICLE 23 to ARTICLE 27.
2.
TEIAS has the right to require and to define the scope and extent of studies which
demonstrate that no excessive level of distortion may occur. If level of distortion or
fluctuation of the supply Voltage on the Network exceeding the thresholds is identified, the
studies shall identify possible recovery actions to be implemented to ensure compliance
with the requirements of this Regulation.
3.
The studies shall be carried out by the Transmission Connected Demand Facility
Owner or Transmission Connected Distribution Network Operator with the participation of
all other parties identified by TEIAS relevant to each new Connection Point. Such other
parties shall contribute to the studies and shall provide their input as reasonably required to
meet the purposes of the studies. TEIAS shall collect this input and pass it on to the party
responsible for the studies in accordance with confidentiality obligations of ARTICLE 7.
4.
TEIAS shall assess the result of the studies and if necessary for the assessment,
TEIAS has the right to request the Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator to perform further studies in line
with this same scope and extent.
5.
Any recovery actions identified by the studies carried out under the provisions of
this article and reviewed by TEIAS shall be undertaken as part of the connection of the
new Transmission Connected Demand Facility or new Transmission Connected
Distribution Network.
ARTICLE 66 Simulation models
[New Article, harmonization with ENTSO-E code DCC Article 26]
1. All Transmission Connected Demand Facilities, Demand Facilities or Closed
Distribution Network and Transmission Connected Distribution Networks, shall fulfil the
104
following requirements related with regard to the simulation models or equivalent
information:
a) TEIAS shall have the right to require the simulation models or equivalent
information showing the behaviour of the Demand Facility, Closed Distribution
Network and/or Transmission Connected Distribution Network in both steady and
dynamic states.
TEIAS shall define, the content and format of those simulation models or
equivalent information. The content and format defined may include but is not
restricted to:
1) steady and dynamic states, including 50 Hz component;
2) electromagnetic transient simulations at the Connection Point ;
3) structure and block diagrams.
b) For the purpose of dynamic simulations, the simulation model or equivalent
information provided shall as defined in paragraph 1(a) contain the following
sub‐models or equivalent information:
1) Power control;
2) Voltage control;
3) Demand Facility and Transmission Connected Distribution Network
protection models;
4) The constituent demand types, i.e. electro technical characteristics of the
demand; and
5) Converter models.
c) TEIAS shall define requirements for Transmission Connected Demand Facilities
and/or Transmission Connected Distribution Network recordings in order to
compare the response of the model with these recordings.
SECTION 3
Requirement for HVDC connection
3.1
ARTICLE 67
Requirements for active power control and frequency
support
Frequency ranges
[New Article, harmonization with ENTSO-E HVDC code Article 7]
1. A HVDC System shall fulfil the following requirements referring to Frequency
stability:
a. An HVDC System shall be capable of staying connected to the Network and
remaining operable within the Frequency ranges and time periods specified by
Table 1, for the short circuit power range as specified in ARTICLE 89(1)b.
b. Notwithstanding ARTICLE 67(1)(a) above, a HVDC System shall be capable of
automatic disconnection at specified Frequencies.
c. The maximum admissible Active Power output reduction from its operating point if
the system Frequency falls below 49 Hz shall be limited to 2%.
105
Frequency
Time period for operation
range
47.0 Hz – 47.5
60 seconds
Hz
47.5 Hz – 48.5
90 minutes
Hz
48.5 Hz – 49.0
90 minutes
Hz
49.0 Hz – 51.0
Unlimited
Hz
51.0 Hz – 51.5
90 minutes
Hz
51.5 Hz – 52.0
15 minutes
Hz
Table 1: This table shows the minimum time periods an HVDC System shall be able to
operate for different Frequencies deviating from a nominal value without disconnecting
from the Network.
ARTICLE 68
Rate-of-change-of-Frequency withstand capability
[New Article, harmonization with ENTSO-E HVDC NC Article 8]
1. With regard to the rate of change of Frequency withstand capability, a HVDC System
shall be capable of staying connected to the Network and operable if the Network
Frequency changes at a rate between -2.5 and +2.5 Hz/s (measured at any point in time as
an average of the rate of change of Frequency for the previous 1s).
ARTICLE 69
rate
Active Power controllability, control range and ramping
[New Article, harmonization with ENTSO-E HVDC NC Article 9]
1. With regard to the capability of controlling the transmitted Active Power:
(a) The HVDC System shall be capable of adjusting the transmitted Active Power up
to the Maximum HVDC Active Power Transmission Capacity of the HVDC
System in each direction following an Instruction from the Relevant TSO(s).
i. The transmitted Active Power shall be adjustable by steps of at least 1 MW
ii. If the HVDC System Owner reasonably justifies that adjusting the transmitted
Active Power is technically not feasible at low level of transmitted Active
Power, this capability is not requested in the range of transmitted Active Power
where adjustment is not feasible. This range of transmitted Active Power cannot
exceed 2,5% of the HVDC Active Power Transmission Capacity in the
direction of transmission,
iii. The HVDC System shall be capable of adjusting the transmitted Active Power
as soon as possible upon receipt of a manual request from the Relevant TSO(s)
and within a maximum delay of 5 minutes.
106
(b) In case of Disturbance in one or more of the connecting AC Networks, the HVDC
System shall be capable of modifying the transmitted Active Power in accordance
with regulation sequences agreed between the Relevant TSO(s) and the HVDC
System Owner. These sequences include at least the blocking of the transmitted
Active Power (blocking means remaining connected to the Network with no Active
and Reactive Power contribution). This shall be achieved as fast as technically
feasible with an initial delay as short as possible. If the initial delay prior to the start
of the change is greater than 10 milliseconds from receiving the triggering signal
sent by the Relevant TSO(s), it shall be reasonably justified by the HVDC System
Owner to the Relevant TSO(s).
(c) The HVDC System shall be capable of fast Active Power reversal unless the
HVDC System Owner reasonably justifies that this capability is not technically
feasible. The power reversal shall be possible from the Maximum Active Power
Transmission Capacity in one direction to the Maximum Active Power
Transmission Capacity in the other direction as fast as technically feasible and
reasonably justified by the HVDC System Owner to the Relevant TSOs if greater
than 2 seconds.
(d) For HVDC Systems linking various Control Areas or Synchronous Areas, the
HVDC System shall be equipped with control functions enabling the Relevant
TSO(s) to modify automatically the transmitted Active Power according to a signal
sent periodically by the Relevant TSO(s). The period between two signals shall be
at least as short as 4 seconds. The modification of the transmitted Active Power
shall be achieved as fast as technically feasible with an initial delay as short as
possible. If the initial delay prior to the start of the change is greater than 10
milliseconds from receiving the signal sent by the Relevant TSO(s), it shall be
reasonably justified by the HVDC System Owner to the Relevant TSO(s).
2. With regard to the capability of controlling ramping rate, the HVDC System shall be
capable of adjusting the ramping rate of Active Power variations within its technical
capabilities in accordance with Instructions sent by the Relevant TSO(s). In case of
modification of Active Power according to ARTICLE 69(1) (b) and (c), ramping rate
adjustment shall be inhibited.
3. TEIAS shall have the right to require that the control functions of a HVDC System shall
be capable of taking automatic remedial actions including, but not limited to, stopping the
ramping and blocking FSM, LFSM-O, LFSM-U and Frequency control. The triggering and
blocking criteria shall be defined by the Relevant TSO(s) and subject to notification to
EMRA.
ARTICLE 70
Frequency Sensitive Mode (FSM)
[New Article, harmonization with ENTSO-E HVDC NC Article 11]
1. When operating in Frequency Sensitive Mode (FSM),the following shall apply:
(a) The HVDC System shall be capable of responding to Frequency deviations in each
connected AC Network by adjusting the Active Power transmission as indicated in
Figure 1 and in accordance with the parameters specified by TEIAS within the
ranges shown in Table 2. This specification shall be subject to notification to
EMRA.
107
(b) The adjustment of Active Power Frequency Response is limited by the Minimum
HVDC Active Power Transmission Capacity and Maximum HVDC Active Power
Transmission Capacity of the HVDC System (in each direction).
Figure 1: Active Power Frequency Response capability of a HVDC System in FSM
illustrating the case of zero deadband and insensitivity with a positive Active Power
Setpoint (import mode). P is the change in Active Power output from the HVDC System.
fn is the target Frequency in the AC Network where the FSM service is provided and f is
the Frequency deviation in the AC Network where the FSM service is provided.
Parameters
Ranges
Response 0
–
±500mHz
Minimum
Droop s1 (upward regulation)
0.1%
Droop
s2
(downward Minimum
regulation)
0.1%
Frequency
Response Maximum
Insensitivity
10 mHz
Table 2: Parameters for Active Power Frequency Response in FSM
Frequency
Deadband
(c) The HVDC System shall be capable, following an Instruction from TEIAS, of
adjusting the Droops for upward and downward regulation, the Frequency
Response Deadband and the operational range of variation within the Active Power
range available for FSM, defined in Figure 1 and more generally within the limits
set by ARTICLE 70 (1) (a) and (b).
(d) As a result of a Frequency step change, the HVDC System shall be capable of
adjusting Active Power to the Active Power Frequency response defined in Figure
1, such that the response is
i.
as fast as inherently technically feasible; and
ii.
at or above the solid line according to Figure 2 in accordance with the
parameters specified in Table 3:
108
- The HVDC System shall be able to adjust Active Power Output P
up to the limit of the Active Power range requested by TEIAS in
accordance with the maximum times t1 and t2 defined in Table 3,
where t1 is the initial delay and t2 is the time for full activation.
- The initial delay of activation shall be as short as possible. If greater
than 0.5 second, the initial delay of activation shall be reasonably
justified by the HVDC System Owner to TEIAS and shall be subject
to approval by TEIAS.
P
Pmax
P1
Pmax
t1
t s
t2
Figure 2: Active Power Frequency Response capability of a HVDC System. P is the
change in Active Power triggered by the step change in Frequency.
Parameters
Time
Maximum admissible initial delay 0.5
t1
seconds
Maximum admissible time for full 30
seconds
activation t2 ,
Table 3: Parameters for full activation of Active Power Frequency Response resulting
from Frequency step change.
(e) For HVDC Systems linking various Control Areas or Synchronous Areas, in
Frequency Sensitive Mode operation the HVDC System shall be capable of
adjusting full Active Power Frequency Response at any time and for a continuous
time period.
(f) As long as a Frequency deviation continues Active Power control shall not have
any adverse impact on the Active Power Frequency Response.
ARTICLE 71
O)
Limited Frequency Sensitive Mode Overfrequency (LFSM-
[New Article, harmonization with ENTSO-E HVDC NC Article 12]
1. In addition to ARTICLE 70 the following shall apply cumulatively with regard to
Limited Frequency Sensitive Mode – Overfrequency (LFSM-O):
109
(a) The HVDC System shall be capable of adjusting Active Power exchange with the
AC Network(s), during both import and export, according to Figure 3 at a
Frequency threshold f1 adjustable between and including 50.2 Hz and 50.5 Hz with
a Droop S3 adjustable from 0.1 % upwards. In the LFSM-O mode the HVDC
System shall be capable of adjusting power down to its Minimum HVDC Active
Power Transmission Capacity. The Frequency threshold is adjusted to 50.2 Hz and
the Droop is adjusted to 4% unless stated otherwise by TEIAS. In that last case,
Frequency threshold and Droop settings shall be subject to notification to EMRA.
The HVDC System shall be capable of adjusting Active Power Frequency
Response as fast as inherently technically feasible with an initial delay that shall be
as short as possible and not exceeding 0.5 seconds. The time for full activation shall
be shorter than 30 seconds.
Figure 3: Active Power Frequency Response of HVDC Systems in LFSM-O. P is the
change in Active Power output from the HVDC System, depending on the operation
condition a decrease of import power or an increase of export power. fn is the nominal
Frequency of the AC Network(s) the HVDC System is connected to and f is the
Frequency change in the AC Network(s) the HVDC is connected to. At overfrequencies
where f is above f1 the HVDC System shall reduce Active Power according to the Droop
setting.
(b) The HVDC System shall be capable of stable operation during LFSM-O operation.
When LFSM-O is active, hierarchy of control functions shall be organised in
accordance with ARTICLE 92.
ARTICLE 72
(LFSM-U)
Limited Frequency Sensitive Mode Underfrequency
[New Article, harmonization with ENTSO-E HVDC NC Article 13]
1. In addition to ARTICLE 70 the following shall apply cumulatively with regard to
Limited Frequency Sensitive Mode – Underfrequency (LFSM-U):
(a) The HVDC System shall be capable of adjusting the Active Power Frequency
Response to the AC Network(s), during both import and export, according to
Figure 4 at a Frequency threshold f2 adjustable between and including 49.8 Hz
and 49.5 Hz with a Droop S4 adjustable from 0.1 % upwards. In the LFSM-U
mode the HVDC System shall be capable of adjusting power up to its
Maximum HVDC Active Power Transmission Capacity. The Frequency
110
threshold is adjusted to 49.8 Hz and the Droop is adjusted to 4% unless stated
otherwise by TEIAS. In that last case, Frequency threshold and Droop settings
shall be subject to notification to EMRA. The Active Power Frequency
Response shall be activated as fast as inherently technically feasible with an
initial delay that shall be as short as possible and not exceeding 0.5 seconds.
The time for full activation shall be shorter than 30 seconds.
Figure 4: Active Power Frequency Response capability of HVDC Systems in LFSM-U.
P is the change in Active Power output from the HVDC System, depending on the
operation condition a decrease of import power or an increase of export power. fn is the
nominal Frequency in the AC Network(s) the HVDC System is connected and f is the
Frequency change in the AC Network(s) the HVDC is connected. At underfrequencies
where f is below f2, the HVDC System has to increase Active Power output according to
the Droop s4.
(b) The HVDC System shall be capable of stable operation during LFSM-U
operation. When LFSM-U is active, hierarchy of control functions shall be
organised in accordance with ARTICLE 92.
ARTICLE 73
Frequency Control
[New Article, harmonization with ENTSO-E HVDC NC Article 14]
1. With regard to the capability of providing additional Frequency Control to those
defined in Articles ARTICLE 70,ARTICLE 71 and ARTICLE 72
(a) The HVDC System shall be equipped with an independent control mode to
modulate the Active Power output of the HVDC Converter Station depending on
the Frequencies at all Connection Points of the HVDC System in order to maintain
stable system Frequencies.
(b) The operating principle, the associated performance parameters and the activation
criteria of this Frequency Control shall be defined by the Relevant TSO(s).
ARTICLE 74
Maximum loss of active power
[New Article, harmonization with ENTSO-E HVDC NC Article 15]
1. The HVDC System shall be configured such that its loss of Active Power injection
in the Turkish LFC block shall be limited to 1800 MW.
111
2. Where the HVDC System connects two or more LFC Blocks, TEIAS shall consult
the other Relevant TSOs in order to set a coordinated value of the maximum loss of
Active Power injection as referred to in ARTICLE 74(1) above, taking into account
common mode failures. This coordinated value cannot exceed 1800 MW.
3.2
Requirements for reactive power control and voltage
support
ARTICLE 75 Voltage ranges
[New Article, harmonization with ENTSO-E HVDC NC Article 16]
1. HVDC Converter Stations shall be capable of fulfilling the following requirements
with regard to steady state Voltage ranges:
(a) Notwithstanding the provisions of ARTICLE 82, a HVDC Converter Station shall
be capable of staying connected to the Network and capable of operating at HVDC
System Maximum Current, within the ranges of the Network Voltage at the
Connection Point, expressed by the Voltage at the Connection Point related to
nominal Voltage (in kV), and the time periods specified by Table 4.
Rated nominal
Voltage Range
voltage at the
(kV)
Connection Point
66 kV
154 kV
400 kV
Time period
operation
56,1 – 72,5
Unlimited
72,5 – 75,9
20 minutes
130,9 – 170
Unlimited
170 – 172,5
20 minutes
340 – 420
Unlimited
420 – 440
60 minutes
for
Table 4: This table shows the minimum time periods a HVDC System shall be capable of
operating for Voltages deviating from the nominal system value at the Connection Point(s)
without disconnecting from the Network.
(b) Wider Voltage ranges or longer minimum times for operation can be agreed
between the Relevant Network Operator in coordination with TEIAS and the
HVDC System Owner to ensure the best use of the technical capabilities of a
HVDC System if needed to preserve or to restore system security. If wider Voltage
ranges or longer minimum times for operation are economically and technically
feasible, the consent of the HVDC System Owner shall not be unreasonably
withheld.
(c) The Relevant Network Operator, in coordination with TEIAS, shall have the right
to specify Voltages at the Connection Point at which a HVDC Converter Station
112
shall be capable of automatic disconnection. The terms and settings for automatic
disconnection shall be agreed between the Relevant Network Operator in
coordination with TEIAS and the HVDC System Owner.
ARTICLE 76 Short circuit contribution during faults
[New Article, harmonization with ENTSO-E HVDC NC Article 17]
1.
HVDC Systems shall fulfil the following requirement referring to Voltage stability:
(a) The Relevant Network Operator in coordination with TEIAS shall have the right to
require the capability of a HVDC System to provide Fast Fault Current at a
Connection Point in case of symmetrical (3-phase) faults.
(b) The Relevant Network Operator in coordination with TEIAS shall specify to the
HVDC System Owner:
- How and when a Voltage deviation is to be determined as well as the
end of the Voltage deviation,
- The characteristics of the Fast Fault Current,
- The timing and accuracy of the Fast Fault Current, which may include
several stages.
(c) With regard to the supply of Fast Fault Current in case of asymmetrical (1-phase or
2-phase) faults, the Relevant Network Operator in coordination with TEIAS has the
right to introduce a requirement for asymmetrical current injection.
ARTICLE 77 Reactive Power capability
[New Article, harmonization with ENTSO-E HVDC NC Article 18]
1.
The HVDC Converter Station shall fulfil the following requirements referring to
Voltage stability, at the Connection Point(s) either at the time of connection or
subsequently, according to the agreement as referred to in ARTICLE 77(2) :
(a) With regard to the Reactive Power capability requirements in the context of varying
Voltage, the U-Q/Pmax-profile, within the boundary of which the HVDC Converter
Station shall be capable of providing Reactive Power at its Maximum Active Power
Transmission Capacity is a rectangular shape defined by the following points:
Q/Pmax [pu]
x1=0.46pu (lag)
x2=0.46pu (lag)
x3=-0.33 (lead)
x4=-0.33 (lead)
y1=
y2=
y3=
y4=
Voltage at the Connection Point
for
for
for
66 kV:
154 kV:
400 kV:
56.1 kV
130.9 kV 340 kV
72.5 kV
170 kV
420 kV
72.5 kV
170 kV
420 kV
56.1 kV
130.9 kV 340 kV
(b) The HVDC System shall be capable of moving to any operating point within its UQ/Pmax profile in timescales better than 10 seconds
113
(c) When operating at an Active Power output below the Maximum HVDC Active
Power Transmission Capacity (P<Pmax), the HVDC Converter Station shall be
capable of operating in every possible operating point included in the same
rectangular shape U-Q/Pmax-profile as defined in ARTICLE 77 (1) a.
2.
If Reactive Power capabilities required by ARTICLE 77(1) are not needed by the
Relevant Network Operator at the time of connection, the HVDC System Owner can
obtain a bilateral agreement with the Relevant Network Operator, in coordination with
TEIAS, delaying the fulfilment of the requirements of ARTICLE 77(1). In that case, the
HVDC System Owner has to fulfil the following requirements:
(a) Demonstrate that the HVDC Converter Station has the ability with additional plant
or equipment and/or software, to meet the Reactive Power capabilities required by
ARTICLE 77(1),
(b) The agreement shall include a contract by the HVDC System Owner that it will
finance and install Reactive Power capabilities required by this ARTICLE 77(1) for
its HVDC Converter Station at a point in time defined by the Relevant Network
Operator, in coordination with TEIAS. The Relevant Network Operator, in
coordination with TEIAS shall inform the HVDC System Owner of the proposed
completion date of any committed development which will require the HVDC
System Owner to install the full Reactive Power capability.
(c) This agreement shall precise the development time schedule of retrofitting the
Reactive Power capability to the HVDC Converter Station. The Relevant Network
Operator, in coordination with TEIAS, must account for this development time
schedule in specifying the point in time by which this Reactive Power capability
retrofitting is to take place.
ARTICLE 78 Reactive Power exchanged with the Network
[New Article, harmonization with ENTSO-E HVDC NC Article 19]
1. The HVDC System Owner shall ensure that the Reactive Power of its HVDC
Converter Station exchanged with the Network at the Connection Point is limited to a
value specified by the Relevant Network Operator in coordination with the Relevant
TSO(s) between the range 0.1 to 0.3 pu.
2. The Reactive Power variation caused by the Reactive power control mode operation of
the HVDC Converter Station, as listed in ARTICLE 79(1), shall not result in a Voltage
step exceeding the allowed value at the Connection Point according to ARTICLE 24 (±
3%).
ARTICLE 79 Reactive Power control mode
[New Article, harmonization with ENTSO-E HVDC NC Article 20]
1. Each HVDC Converter Station shall as a minimum be capable of operating in voltage
control mode either at the time of connection or subsequently, according to the agreement
as referred to in ARTICLE 79(5)
114
2. The Relevant Network Operator in coordination with TEIAS shall have the right to
require other control mode capabilities.
3. For the purposes of Voltage control mode, each HVDC Converter Station shall be
capable of contributing to Voltage control at the Connection Point utilising its capabilities,
while respecting the provisions of ARTICLE 77 and ARTICLE 78, in accordance with the
following control characteristics:
(a)
A Setpoint Voltage at the Connection Point shall be specified to cover a
specific operation range, either continuously or in steps, as defined by the Relevant
Network Operator in coordination with TEIAS;
(b)
The Voltage control may be operated with or without a deadband around the
Setpoint selectable in a range from zero to +/-5 % of nominal Network Voltage.
The dead band shall be adjustable in steps no greater than 0.5%.
(c)
Following a step change in Voltage, the HVDC Converter Station shall be
capable of
i.
achieving 90 % of the change in Reactive Power output within a
time t1 = 1 second; and
ii.
settling at the value defined by the operating Slope within a time t2=
5 seconds, with a steady-state tolerance no greater than ± 5 Mvar or 5 % of
the maximum Reactive Power (whichever is smaller).
(d)Voltage control mode shall include the capability to change Reactive Power
output based on a combination of a modified Setpoint Voltage and an additional
instructed Reactive Power component. The Slope will be specified by the Relevant
Network Operator in coordination with TEIAS within a range of 2 to 7 % and steps
shall not be greater than 0.5 %.
4.
The Relevant Network Operator in coordination with TEIAS shall define any
equipment needed to enable the remote selection of Setpoint(s).
5.
If voltage control mode required by ARTICLE 79(1) and ARTICLE 79(3) is not
needed by the Relevant Network Operator at the time of connection, the HVDC System
Owner can obtain a bilateral agreement with the Relevant Network Operator, in
coordination with TEIAS, delaying the fulfilment of the requirements of ARTICLE 79(3).
In that case, the HVDC System Owner has to fulfil the following requirements:
(a) Demonstrate that the HVDC Converter Station has the ability with additional
plant or equipment and/or software, to meet the voltage control mode according to
ARTICLE 79(3),
(b) The agreement shall include a contract by the HVDC System Owner that it will
finance and install voltage control mode required by this ARTICLE 79(3) for its
HVDC Converter Station at a point in time defined by the Relevant Network
Operator, in coordination with TEIAS. The Relevant Network Operator, in
coordination with TEIAS shall inform the HVDC System Owner of the proposed
completion date of any committed development which will require the HVDC
System Owner to install the voltage control mode.
(c) This agreement shall precise the development time schedule of retrofitting the
Reactive Power capability to the HVDC Converter Station. The Relevant Network
Operator, in coordination with TEIAS, must account for this development time
115
schedule in specifying the point in time by which this voltage control mode
retrofitting is to take place.
ARTICLE 80 Priority to Active or Reactive Power contribution
[New Article, harmonization with ENTSO-E HVDC NC Article 21]
1. The Relevant Network Operator in coordination with TEIAS shall have the right,
utilizing the capabilities of the HVDC System defined according to this Regulation, to give
priority either to Active Power contribution or to Reactive Power contribution during low
or high Voltage operation and during faults for which fault-ride-through capability is
required. Its provision shall be established as soon as possible and within a time no later
than 100 ms from the fault inception.
ARTICLE 81 Power quality
[New Article, harmonization with ENTSO-E HVDC NC Article 22]
1. An HVDC System Owner shall ensure that its HVDC System connection to the Network
does not result in a level of distortion or fluctuation of the supply Voltage on the Network,
at the Connection Point(s), exceeding the levels defined in ARTICLE 23 to ARTICLE 27.
The process for necessary studies to be conducted and relevant data to be provided by all
Grid Users involved, as well as recovery actions identified and implemented shall be in
accordance with the process in ARTICLE 86.
3.3
Requirements for fault ride through
ARTICLE 82 Fault ride through capability
[New Article, harmonization with ENTSO-E HVDC NC Article 23]
1. With regard to fault-ride-through capability of a HVDC System:
(a) The Voltage-against-time-profile defined according to Figure 5 and Table 5
applies at the Connection Point(s) for fault conditions, under which the HVDC
Converter Station shall be capable of staying connected to the Network and
continuing stable operation after the power system has recovered following fault
clearance. This Voltage-against-Time-profile is expressed by a lower limit of the
course of the phase-to-phase Voltages on the Network Voltage level at the
Connection Point(s) during a symmetrical fault, as a function of time before,
during and after the fault.
(b) TEIAS or the Relevant Network Operator shall provide on request by the HVDC
System Owner the pre-fault and post-fault conditions as defined in ARTICLE 89
regarding:
- pre-fault minimum short circuit capacity at the Connection Point(s)
expressed in MVA;
- pre-fault operating point of the HVDC Converter Station expressed in
Active Power output and Reactive Power output, and the operating
Voltage at the Connection Point[s];
- post-fault minimum short circuit capacity at the Connection Point(s)
expressed in MVA.
116
Alternatively, generic values for the above conditions derived from typical cases may be
provided by TEIAS or the Relevant Network Operator.
Figure 5: Fault-ride-through profile of a HVDC Converter Station. The diagram represents
the lower limit of a Voltage-against-time profile at the Connection Point, expressed by the
ratio of its actual value and its nominal value in per unit before, during and after a fault.
URET is the retained Voltage at the Connection Point during a fault, TCLEAR is the duration
of the fault, UREC1 and tREC1 specify a point of lower limits of Voltage recovery following
fault clearance. Ublock is the blocking Voltage at the Connection Point. The time values
referred to are measured from TFAULT.
Voltage parameters [pu]
Time parameters [seconds]
URET
0.00
tCLEAR
0.25
UREC1
0.425
tREC1
1,625
UREC2
0.85
tREC2
3.0
Table 5: Parameters for Figure 5 for the fault-ride-through capability of a HVDC
Converter Station.
(c) The HVDC Converter Station shall be capable of staying connected to the
Network and continue stable operation when the actual course of the phase-tophase Voltages on the Network Voltage level at the Connection Point during a
symmetrical fault, given the pre-fault and post-fault conditions described in
ARTICLE 89, remain above the lower limit defined in Figure 5, unless the
protection scheme for internal faults requires the disconnection of the HVDC
Converter Station from the Network. The protection schemes and settings for
internal faults shall be designed not to jeopardize fault-ride-through performance.
(d) The HVDC System is allowed to block when at least one of the Voltages at the
Connection Point(s) is lower than Ublock. Blocking means remaining connected
to the Network with no Active and Reactive Power contribution for a time frame
that shall be as short as technically feasible and no later than 150 ms from the
time all the Voltages at the Connection Point(s) are once again above Ublock.
Ublock is equal to 0.1 [pu] unless the HVDC System Owner reasonably justifies
that blocking is technically necessary for Voltages above 0.1 [pu]. In that case
117
Ublock is established at the lowest Voltage value the HVDC System can be
operated without blocking. In any cases Ublock shall not be higher than 0.5 [pu].
(e) In accordance with the provisions of ARTICLE 91, undervoltage protection shall
be set by the HVDC System Owner to the widest possible technical capability of
the HVDC Converter Station. The Relevant Network Operator in coordination
with TEIAS may require less wide settings according to ARTICLE 91.
(f) The Voltage-against-time-profile defined in ARTICLE 82 1(a) according to
Figure 5 and Table 5 also applies to single-phase fault. It applies at the
Connection Point(s) for fault conditions, under which the HVDC Converter
Station shall be capable of staying connected to the Network and continuing
stable operation after the power system has recovered following fault clearance.
This Voltage-against-Time-profile is expressed by a lower limit of the course of
the phase-to-ground Voltages on the Network Voltage level at the Connection
Point(s) during a single-phase fault, as a function of time before, during and after
the fault.
ARTICLE 83 Post fault Active Power recovery
[New Article, harmonization with ENTSO-E HVDC NC Article 24]
1. For fault conditions, under which the HVDC Converter Station has disconnected, while
respecting the provisions of ARTICLE 82, the HVDC System shall be capable upon
receipt of request from TEIAS of providing Active Power recovery until pre-fault
conditions or any other value of transmitted Active Power requested by TEIAS.
ARTICLE 84 Fast recovery of DC faults
[New Article, harmonization with ENTSO-E HVDC NC Article 25]
1. HVDC Systems including DC overhead lines shall be capable of fast recovery from
transient faults within the HVDC System. Details of this capability shall be subject to
coordination and agreements on protection schemes and settings according to ARTICLE
91.
3.4
Requirements for control
ARTICLE 85 Converter energisation and synchronisation
[New Article, harmonization with ENTSO-E HVDC NC Article 26]
1. Unless otherwise instructed by the Relevant Network Operator, the following shall
apply:
During the energisation or synchronisation of an HVDC Converter Station to the AC
Network, the HVDC Converter Station shall have the capability to limit any Voltage
changes to a steady-state level that shall not exceed at the Connection Point the allowed
value according to ARTICLE 24 (± 3%). The Relevant Network Operator, in coordination
with TEIAS, has the right to define the maximum magnitude, duration and measurement
window of the Voltage transients in terms and conditions related to connection included
into the connection agreement.
118
ARTICLE 86 Interaction between HVDC System(s) and/or other
plant(s) and equipment
[New Article, harmonization with ENTSO-E HVDC NC Article 27]
1. When several HVDC Converter Stations and/or other plant(s) and equipment are within
close electrical proximity, TEIAS has the right to require and to define the scope and
extent of studies which demonstrate that no adverse interaction (such as, but not limited to
interference with or jeopardisation of the operation of other HVDC Systems, Power
Generation Modules or any protection devices in the adjacent AC Network) may occur. If
adverse interaction is identified, the studies shall identify possible mitigating actions to be
implemented to ensure compliance with the requirements of this Regulation.
2. The studies shall be carried out by the connecting HVDC System Owner with the
participation of all other parties identified by TEIAS relevant to each new Connection
Point. Such other parties shall contribute to the studies and shall provide their input as
reasonably required to meet the purposes of the studies. TEIAS, in coordination with the
adjacent TSO(s) if needed, shall collect this input and pass it on to the party responsible for
the studies in accordance with confidentiality obligations of ARTICLE 7.
3. TEIAS shall assess the result of the studies based on their scope and extent as defined in
accordance with ARTICLE 86(1). If necessary for the assessment, TEIAS has the right to
request the HVDC System Owner to perform further studies in line with this same scope
and extent.
4. TEIAS has the right to review or replicate the study. The HVDC System Owner shall
provide TEIAS all relevant data and models that allow such study to be performed.
5. Any necessary mitigating actions identified by the studies carried out under the
provisions of ARTICLE 86 (2) and ARTICLE 86 (4) and reviewed by TEIAS shall be
undertaken as part of the connection of the new HVDC Converter Station.
6. TEIAS has the right to specify transient levels of performance associated with events
such as switching, load rejection and energisation, for the individual HVDC System or
collectively across HVDC Systems commonly impacted to both protect the integrity of
TSO equipment and that of Grid Users.
ARTICLE 87 Power oscillation damping capability
[New Article, harmonization with ENTSO-E HVDC NC Article 28]
1. The HVDC System shall be capable of contributing to the damping of power
oscillations in connected AC Networks. The control system of the HVDC System shall
not reduce the damping of power oscillations. TEIAS shall specify the Network
conditions and a Frequency range of oscillations which the control scheme shall
positively damp, at least accounting for the dynamic stability assessment studies as
prescribed in ARTICLE 74 of [NC OS]. The selection of the control parameter settings
shall be agreed between TEIAS and the HVDC System Owner.
ARTICLE 88 Subsynchronous
capability
torsional
interaction
[New Article, harmonization with ENTSO-E HVDC NC Article 29]
119
damping
1. With regard to subsynchronous torsional interaction (SSTI) damping
control, the
HVDC System shall be capable of contributing to electrical damping of torsional
frequencies.
2. TEIAS defines the necessary extent of SSTI studies and provide input parameters, to the
extent available, related to the equipment and relevant system conditions in its Network.
The SSTI studies shall be provided by the HVDC System Owner. The studies shall identify
the conditions, if any, where SSTI exists and propose any necessary mitigation procedure.
The necessary contribution to such studies from the owners of other plant(s) and
equipment, including but not limited to Existing Power Generating Modules, Existing
Distribution Networks, Existing Demand Facilities and Existing HVDC Systems shall not
be unreasonably withheld. TEIAS, in coordination with the adjacent TSOs if needed, shall
collect this input and pass it on to the party responsible for the studies in accordance with
confidentiality obligations of ARTICLE 7.
3. TEIAS shall assess the result of the SSTI studies. If necessary for the assessment,
TEIAS has the right to request the HVDC System Owner to perform further SSTI studies
in line with this same scope and extent.
4. TEIAS has the right to review or replicate the study. The HVDC System Owner shall
provide TEIAS all relevant data and models that allow such study to be performed.
5. Any necessary mitigating actions identified by the studies carried out under the
provisions of ARTICLE 88 (2) and ARTICLE 88(4) and reviewed by the TEIAS shall be
undertaken as part of the connection of the new HVDC Converter Station
ARTICLE 89 Network characteristics
[New Article, harmonization with ENTSO-E HVDC NC Article 30]
1. With regard to the Network characteristics, the following shall apply for the HVDC
Systems:
(a) TEIAS or the Relevant Network Operator shall define and make
publicly available the method and the pre-fault and post-fault conditions
for the calculation of at least the minimum and maximum short circuit
power at the Connection Point(s).
(b) The HVDC System shall be capable of operating within the range of
short circuit power and Network characteristics defined by TEIAS or the
Relevant Network Operator.
(c) Each Relevant Network Operator shall provide the HVDC System
Owner with Network equivalents describing the behaviour of the
Network at the Connection Point, enabling the HVDC System Owners
to design their system with regard to at least, but not limited to,
harmonics and dynamic stability over the lifetime of the HVDC System.
120
ARTICLE 90 HVDC System robustness
[New Article, harmonization with ENTSO-E HVDC NC Article 31]
1. The HVDC System shall be capable of finding stable operation points with a minimum
change in Active Power flow and Voltage level, during and after any planned or unplanned
change in the HVDC System or AC Network to which it is connected. TEIAS shall have
the right to specify the changes in the system conditions for which the HVDC Systems
shall remain in stable operation. The changes may include, but are not limited to:
(a) loss of communication
(b) reconfiguring the HVDC or AC system
(c) changes in load flow
(d) change of control mode
(e) control system failure
(f) trip of one pole or converter
2. The HVDC System Owner shall ensure that the tripping or disconnection of an HVDC
Converter Station, part of any multi-terminal or Embedded HVDC System, does not result
in transients at the Connection Point(s) beyond the limit specified in ARTICLE 23 to
ARTICLE 27 .
3. Transient faults on HVAC lines in the Network adjacent or close to the HVDC System
shall not cause any of the equipment in the HVDC System to disconnect from the Network
due to auto-reclosure of lines in the Network.
4. The HVDC System Owner shall provide information to TEIAS or to the Relevant
Network Operator(s) on the resilience of the HVDC System to AC system disturbances
3.5
Requirements for protection devices and settings
ARTICLE 91 Electrical protection schemes and settings
[New Article, harmonization with ENTSO-E HVDC NC Article 32]
1. The Relevant Network Operator shall define, in coordination with TEIAS, the schemes
and settings necessary to protect the Network taking into account the characteristics of the
HVDC System. Protection schemes relevant for the HVDC System and the Network and
settings relevant for the HVDC System shall be coordinated and agreed between the
Relevant Network Operator, TEIAS and the HVDC System Owner. The protection
schemes and settings for internal electrical faults shall be designed so as not to jeopardize
the performance of the HVDC System in accordance with this regulation.
2. Electrical protection of the HVDC System shall take precedence over operational
controls taking into account system security, health and safety of staff and the public and
mitigation of the damage to the HVDC System.
3. Any change to the protection schemes or their settings relevant to the HVDC System
and the Network shall be agreed between the Relevant Network Operator, TEIAS and the
HVDC System Owner before being implemented by the HVDC System Owner.
121
4. The HVDC System Owner shall prepare the protection schemes and their settings,
submit them to TEIAS and the Relevant Network Operator for approval, and apply the
approved protection settings.
ARTICLE 92 Priority ranking of protection and control
[New Article, harmonization with ENTSO-E HVDC NC Article 33]
1. A control scheme, defined by the HVDC System Owner consisting of different control
modes, including the settings of the specific parameters, shall be coordinated and agreed
between TEIAS, the Relevant Network Operator and the HVDC System Owner.
2. With regard to priority ranking of protection and control, the HVDC System Owner
shall organise its protections and control devices in compliance with the following priority
ranking, listed in decreasing order of importance, unless otherwise specified by TEIAS in
coordination with the Relevant Network Operator:
(a) Network system and HVDC System protection;
(b) Active Power control for emergency assistance
(c) Synthetic Inertia, if applicable;
(d) automatic remedial actions as specified in ARTICLE 69(3);
(e) LFSM;
(f) FSM and Frequency control ;
(g) power gradient constraint;
ARTICLE 93 Changes to protection and control schemes and settings
[New Article, harmonization with ENTSO-E HVDC NC Article 34]
1. The parameters of the different control modes and the protection settings of the HVDC
System shall be able to be changed in the HVDC Converter Station, if required by TEIAS
or the Relevant Network Operator, and in accordance with ARTICLE 93(3).
2. Any change to the schemes or settings of parameters of the different control modes and
protection of the HVDC System, including the procedure, shall be coordinated and agreed
between the Relevant Network Operator, TEIAS and the HVDC System Owner.
3. The control modes and associated Setpoints of the HVDC System shall be capable of
being changed remotely, as defined by the Relevant Network Operator, in coordination
with TEIAS.
3.6
Requirements for power system restoration
ARTICLE 94 Black start
[New Article, harmonization with ENTSO-E HVDC NC Article 35]
122
1. Black Start Capability is not mandatory.
2. If TEIAS deems system security to be at risk due to a lack of Black Start Capability in
its Control Area, TEIAS has the right to obtain a quote from the HVDC System Owner.
3. An HVDC System with Black Start Capability shall be able to energise the busbar of the
remote AC-substation to which it is connected, within a timeframe after shut down
determined by TEIAS. The HVDC System shall be able to synchronise within the
Frequency limits defined in ARTICLE 67and within the Voltage limits defined by TEIAS
or defined by ARTICLE 75, where applicable. Wider Frequency and/or Voltage ranges can
be defined by TEIAS where needed in order to restore system security.
4. TEIAS, in coordination with adjacent TSO(s) if needed, and the HVDC System owner
shall agree on the capacity and availability of the Black Start Capability and the
operational procedure.
3.7
Information exchange and coordination
ARTICLE 95 Operation
[New Article, harmonization with ENTSO-E HVDC NC Article 49]
1. With regard to instrumentation for the operation, each HVDC Converter Unit of the
HVDC System shall be equipped with an automatic controller capable of receiving
Instructions from the Relevant Network Operator(s) and from TEIAS. This automatic
controller shall be capable of operating the HVDC Converter Units of the HVDC System
in a coordinated way. The Relevant Network Operator(s) defines the automatic controller
hierarchy per HVDC Converter Unit.
a) The signal types exchanged from the automatic controller of the HVDC System
to the Relevant Network Operator(s) are:
- operational signals;
- alarm signals;
i.With regard to operational signals per HVDC Converter Unit, those are
classified, but not limited to, by the following, as applicable:
- Startup;
- AC and DC voltage measurements;
- AC and DC current measurements;
- Active and Reactive Power measurements on the AC side;
- Active DC power measurements;
- Multi-pole operational type at HVDC Converter Units level with regard
to HVDC System;
- Elements and topology status;
- FSM, LFSM-O and LFSM-U active power ranges;
ii. With regard to alarm signals per HVDC Converter Unit, those are classified,
but not limited to, by the following, as applicable:
- Emergency blocking;
123
-
Ramp blocking;
Fast Active Power reversal
b) The signal types exchanged from the Relevant Network Operator(s) to the automatic
controller of the HVDC system are:
- operational signals;
- alarm signals;
i. With regard to operational signals per HVDC Converter Unit, those are
classified, but not limited to, by the following, as applicable:
- Start-up command;
- Active Power Setpoints;
- Frequency Sensitive Mode settings;
- Reactive Power, Voltage or similar Setpoints;
- Reactive Power control modes;
- Power oscillation damping control;
- Synthetic Inertia;
ii. With regard to urgent alarm signals per HVDC Converter Unit, those are
classified, but not limited to, by the following, as applicable:
- Emergency blocking command;
- Ramp blocking command;
- Active Power flow direction;
- Fast Active Power reversal command
c) With regards to each signal, the Relevant Network Operator has the right to
define the quality of the supplied signal.
ARTICLE 96 Parameter setting
[New Article, harmonization with ENTSO-E HVDC NC Article 50]
The parameters and settings of the main control functions of the HVDC System shall be
agreed between the HVDC System Owner and the Relevant Network Operator in
coordination with the Relevant TSO(s). The parameters and settings shall be implemented
within such a control hierarchy that makes their modification possible if necessary. These
main control functions are at least:
 Frequency Sensitive Modes (FSM, LFSM-O, LFSM-U) defined in
ARTICLE 70, ARTICLE 71 and ARTICLE 72;
 Frequency Control, if applicable, defined in ARTICLE 73;
 Reactive Power control mode, if applicable as defined in ARTICLE 79;
 Power oscillation damping capability, defined in ARTICLE 87;
Subsynchronous torsional interaction damping capability, defined in ARTICLE 88.
ARTICLE 97 Fault recording and Monitoring
[New Article, harmonization with ENTSO-E HVDC NC Article 51]
1. With regard to instrumentation:
124
a) A HVDC System shall be equipped with a facility to provide fault recording and
dynamic system behaviour monitoring of the following parameters for each of its
HVDC Converter Stations:
 AC and DC voltage;
 AC and DC current;
 Active Power;
 Reactive Power; and
 Frequency.
The Relevant Network Operator has the right to define quality of supply parameters
to be complied with by the HVDC System, provided a reasonable prior notice is given.
b) The particulars of the fault recording equipment, including analogue and digital
channels, the settings, including triggering criteria and the sampling rates shall be
agreed between the HVDC System Owner, the Relevant Network Operator and TEIAS.
c) All dynamic system behaviour monitoring shall include an oscillation trigger,
specified by the Relevant Network Operator, in coordination with TEIAS for detecting
poorly damped power oscillations.
d) The facilities for quality of supply and dynamic system behaviour monitoring shall
include arrangements for the HVDC System Owner and/or the Relevant Network
Operator to access the information electronically. The communications protocols for
recorded data shall be agreed between the HVDC System Owner, the Relevant Network
Operator and TEIAS.
ARTICLE 98 Simulation models
[New Article, harmonization with ENTSO-E HVDC NC Article 52]
1.
The Relevant Network Operator in coordination with TEIAS shall have the right to
require the HVDC System Owner to deliver simulation models which properly reflect the
behaviour of the HVDC System in both steady-state, dynamic simulations (fundamental
frequency component) and in electromagnetic transient simulations.
The format in which models shall be provided and the provision of documentation of
models structure and block diagrams shall be defined by the Relevant Network Operator in
coordination with TEIAS.
2. For the purpose of dynamic simulations, the models provided shall contain at least, but
not limited to the following sub-models, depending on the existence of the mentioned
components:
 HVDC Converter Unit models
 AC component models
 DC grid models
 Voltage and power control
 Special control features if applicable e.g. Power Oscillation Damping
(POD) function, Subsynchronous Torsional Interaction (SSTI) control
 Multi terminal control, if applicable
 HVDC System protection models as agreed between TEIAS and the HVDC
System Owner
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3. The models shall be verified by the HVDC System Owner against the results of
compliance tests carried out according to SECTION8 and a report of this verification
shall be submitted to TEIAS. They shall then be used for the purpose of verifying the
requirements of this Regulation including but not limited to Compliance Simulations as
defined in SECTION8 for use in studies for continuous evaluation in system planning
and operation.
4. The Relevant Network Operator and TEIAS have the right to require HVDC System
recordings in order to compare the response of the models with these recordings.
PART V
Connection to the Transmission System
SECTION1
Principles for Connection to the Transmission System and
Parties
ARTICLE 99 Principles for connection to the transmission system
[Previous Article 33]
(1) Connection between the transmission system and any user is built in accordance
with the provisions of this Regulation.
(2) Total Maximum Capacity of the Power Generating Module to be connected to a
distribution busbar of TEIAS or a distribution system connected to this busbar may not
exceed 50 MW. If this power is 50 MW and above, connection is made at the transmission
level. However, the total Maximum Capacity of the Power Generating Modules to be
connected to a distribution busbar in the 400/33kV centers to which only the Power
Generating Module is connected from the medium voltage may exceed 50 MW, provided
that it will not exceed the short-circuit fault current limit of the related busbar. In order that
the feeders and transformer capacity at the substations can be used efficiently; the feeder
allocation requests are made by the legal entities holding a distribution license, considering
the feeder loading conditions. If it is required technically, TEIAS informs the related legal
entity holding a distribution license of the necessary feeder modification and/or regulation
at the substation. An independent feeder is not assigned for Power Generating Modules
below 10 MW.
(3) Connection requests are evaluated and finalized by TEIAS in accordance with
the related legislation and Article 35 of this Regulation within the appropriate time period.
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ARTICLE 100
Parties subject to connection principles
[Previous Article 34]
(1) Principles for connection to the transmission system apply to;
a) TEIAS,
b) Legal entities that are generating electricity and that are directly
connected to transmission system,
c) Consumers that are directly connected to transmission system, and,
ç) Legal entities holding distribution licenses.
(2) In addition, Power Generating Modules connected to the distribution system
that have a unit capacity of 50 MW or more on the issuance date of this Regulation are
evaluated within the context of principles for connection to the transmission system.
SECTION2
Connection to and/or Use of the Transmission System
ARTICLE 101
Evaluation of connection request
[Previous Article 35]
(1) Connections of the Power Generating Modules and consumption plants
shall be designed according to the sample single line diagrams given in the Annex-10
of this Regulation.
(2) TEIAS provides the Corporation with her opinions accompanied with
underlying rationale on a request for connection of Power Generating Modules to the
transmission system and/or a request for system usage within forty five days following
the receipt date of the opinion request in accordance with Electricity Market License
Regulation published in Official Gazette no: 28809 dated 02/11/2013.
(3) Other connection and/or system usage requests other than of Power
Generating Facilities made to TEIAS, are evaluated by taking into consideration of the
related provisions of Electricity Market Connection and System Use regulation within
forty five days following the application date and written proposal is sent to applicant.
(4) After the legal entity is awarded the preliminary license, standard planning
data and data about the plant and/or equipment that will be connected to the
transmission system which is given in Appendix-11 First Section, is presented to
TEIAS by the legal entity depending on the connection and/or system usage agreement
at the stage of application for the connection agreement.
ARTICLE 102
Connection agreement, system use agreement
and ancillary service agreement
[Previous Article 36]
(1) A connection and/or system use agreement will be proposed by TEIAS to
the legal entity within sixty days following the date on which the legal entity has
submitted a generation license to TEIAS. If TEIAS needs additional information in
order to propose connection to and/or use of system agreement, detailed planning data
127
given in Appendix-11 Second Section can be requested from the legal entity. In these
cases, the time period allowed for TEIAS for proposing the connection to and/or use of
system agreement is applied as ninety days. Legal entity gives a response to TEIAS’s
agreement proposal within thirty days.
(2) If the parties agree on the terms, connection to and/or use of system
agreement containing the terms and conditions regarding the connection to and/or use
of system is signed. If TEIAS and legal entity holding the license do not agree on
terms and conditions of the connection to and/or use of system agreement, disputes are
settled by the Authority in accordance with the clauses of the Law and parties’ related
licenses and Authority’s decision on the subject is binding.
(3) Same process is applied also for the Power Generating Facilities that are
currently connected to the transmission system and for the applications made to
TEIAS regarding the connection to and/or use of system by the persons and legal
entities other than Power Generating Facilities.
(4) For the facilities that will provide primary frequency control, secondary frequency
control, stand-by reserve, instantaneous demand control, reactive power control,
restoration of a system shutdown or regional capacity leasing service, an ancillary service
agreement shall be signed between the related legal entity and TEIAS in accordance with
the provisions of the Electricity Market Ancillary Services Regulation.
ARTICLE 103
Compliance and tests
[Previous Article 37]
(1) The user shall notify TEIAS that the user’s Power Generating Modules
and/or plant and/or equipment connected to the transmission system are compatible
with the plant and/or equipment existing in the system, and compliant with this
Regulation, connection to and/or use of system agreements and ancillary services
agreements within the framework of the following principles and procedures;
a) The user conducts open and loaded circuit and function tests that are parts
of commissioning test schedule conducted on automatic voltage and speed regulators,
other control and communication systems, under TEIAS’s supervision in accordance
with a test program and a schedule agreed upon with TEIAS,
b) The user submits the results of the aforementioned tests and information
containing the final settings of the control system parameters to TEIAS,
c) The user ensures that the performance tests with respect to the ancillary
services will be carried out in accordance with the procedures set out in the ANNEX17 of this Regulation.
ARTICLE 104
System connection approval
[Previous Article 38]
(1) Upon application of the user, TEIAS shall check if the User has fulfilled the
requirements set out in the connection and/or system use agreement. If it is determined
that the connection requirements are fulfilled, the user shall be informed of the date on
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which the physical connection will be made. If any deficiency is found and for this
reason, no approval is granted for connection; the deficiencies found shall be reported
to the user together with the reasons thereof no later than 60 days following the
application date, and the user shall be given additional time to correct the deficiencies.
(2) TEIAS has a right to monitor operation of the user’s plant and/or equipment
connected on the transmission system.
(3) Any request for a change on a plant and equipment on the transmission system
and/or settings of this plant and/or equipment, shall be notified to TEIAS allowing
adequate time to enable TEIAS to investigate the integrity of transmission system and the
effects on other users’ plant and/or equipment. TEIAS has the right to refuse changes that
might adversely impact the integrity of the transmission system.
SECTION3
Operation notification procedure for connection of new
Power Generating Modules
ARTICLE 105
General provisions
[New Article, harmonization with ENTSO-E code RFG Article 24]
1. The provisions of PART V SECTION3 shall apply to New Power Generating Modules
only.
2. The Power Generating Facility Owner shall demonstrate to the Relevant Network
Operator its compliance with the requirements referred to in Title 2 of this Regulation by
completing successfully the operational notification procedure for connection of each
Power Generating Module as defined in ARTICLE 106 to ARTICLE 113.
3. Further details of the operational notification procedure shall be defined and made
publicly available by the Relevant Network Operator and TEIAS.
ARTICLE 106
modules
Provisions for
type A
power generating
[New Article, harmonization with ENTSO-E code RFG Article 25]
1. The operational notification procedure for connection of each new Type A Power
Generating Module shall consist of an Installation Document. Based on an Installation
Document obtained from the Relevant Network Operator, the Power Generating Facility
Owner shall fill in the required information and submit it to the Relevant Network
Operator. For subsequent Power Generating Modules separate independent Installation
Documents shall be provided.
2. The content of the Installation Document shall be defined by the Relevant Network
Operator, at least containing the following:

the location at which the connection is made;

the date of the connection;

the Maximum Capacity of the installation in kW;
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



the type of primary energy source;
reference to Equipment Certificates used in the site installation;
for equipment used, which has not received an Equipment Certificate,
information shall be provided as directed by the Relevant Network
Operator; and
the contact details of the Power Generating Facility Owner and the installer
and their signatures.
3. On permanent decommissioning of a Power Generating Module the Power Generating
Facility Owner shall notify the Relevant Network Operator in writing.
ARTICLE 107
Provisions for type B, C and D power
generating modules
[New Article, harmonization with ENTSO-E code RFG Article 26]
1. The operational notification procedure for connection of each new Type B, C and D
Power Generating Module allows for the use of a Equipment Certificate.
2. The Equipment Certificate is intended to collate verified data and performance for a
specific make and type of Power Generating Module. The purpose of this process is to
repeatedly use this data, where relevant, to verify specific parts of data and performance in
place of part of the Operational Notification Procedure.
3. The Equipment Certificate cannot indicate total compliance, but can be used as validated
information about components of the Power Generating Module. The Power Generating
Facility Owner is advised to check with the Relevant Network Operator at an early stage of
a project what parts, if any, are acceptable instead of the full compliance process and how
to proceed to make use of this facility.
ARTICLE 108
modules
Provisions for type B and C power generating
[New Article, harmonization with ENTSO-E code RFG Article 27]
1. The operational notification procedure for connection of each new Type B and C Power
Generating Module shall comprise a Power Generating Module Document (PGMD). The
PGMD provided by the Power Generating Facility Owner shall contain information as
defined by the Relevant Network Operator and TEIAS, including a Statement of
Compliance. The selection of the required content of the PGMD shall be defined by the
Relevant Network Operator and TEIAS. Its content shall comprise the information defined
in ARTICLE 109 to ARTICLE 113 for Type D Power Generating Modules, but can be
simplified through delivery in a single stage of operational notification as well as reduced
requirements of details. The Power Generating Facility Owner shall provide the required
information and submit it to the Relevant Network Operator. For subsequent Power
Generating Modules separate independent PGMDs shall be provided.
2. The Relevant Network Operator or TEIAS on acceptance of a complete and adequate
PGMD shall issue a Final Operational Notification to the Power Generating Facility
Owner.
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3. On permanent decommissioning of a Power Generating Module the Power Generating
Facility Owner shall notify the Relevant Network Operator in writing.
ARTICLE 109
modules
Provisions for
type D
power generating
[New Article, harmonization with ENTSO-E code RFG Article 28]
The operational notification procedure for connection for each new Type D Power
Generating Module shall comprise:

Energisation Operational Notification (EON);

Interim Operational Notification (ION); and

Final Operational Notification (FON).
ARTICLE 110
Energisation operational notification (EON)
for type d power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 29]
1. An Energisation Operational Notification (EON) shall entitle the Power Generating
Facility Owner to energies its internal Network and auxiliaries for the Power Generating
Modules by using the grid connection that is defined by the Connection Point.
2. An Energisation Operational Notification (EON) shall be issued by TEIAS, subject to
completion of preparation including agreement on the protection and control settings
relevant to the Connection Point between the TEIAS and the Power Generating Facility
Owner
ARTICLE 111
Interim operational notification (ION) for type
d power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 30]
1. An Interim Operational Notification (ION) shall entitle the Power Generating Facility
Owner to operate the Power Generating Module and generate power by using the grid
connection for a limited period of time.
2. An Interim Operational Notification (ION) shall be issued by TEIAS, subject to the
completion of data and study review process as required by this Regulation.
3. With respect to data and study review, TEIAS shall have the right to request the
following from the Power Generating Facility Owner:

itemized Statement of Compliance;

detailed technical data of the Power Generating Module with relevance to
the grid connection as specified by the Relevant Network Operator;

Equipment Certificates of Power Generating Module, where these are relied
upon as part of the evidence of compliance;
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


simulation models as specified by ARTICLE 49 (6) (c) and as required by
the Relevant Network Operator ;
studies demonstrating expected steady-state and dynamic performance as
required by PART V, SECTION4, 4.4 and 4.5 of this Regulation; and
details of intended compliance tests according to PART V, SECTION4, 4.2
and 4.3.
4. The maximum period for the Power Generating Facility Owner to remain in the Interim
Operational Notification (ION) status shall not exceed twenty-four months. TEIAS is
entitled to specify a shorter ION validity period. The ION validity period shall be subject
to notification to EMRA. The modalities of that notification shall be determined in
accordance with the applicable national regulatory framework. ION extensions shall be
granted only if the Power Generating Facility Owner has made substantial progress
towards full compliance. At the time of ION extension, the outstanding issues should be
explicitly identified.
5. A prolongation of the maximum period for the Power Generating Facility Owner to
remain in the Interim Operational Notification (ION) status (beyond a total of twenty-four
months) may be granted upon request made to TEIAS.
ARTICLE 112
Final operational notification (FON) for type d
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 31]
1. A Final Operational Notification (FON) shall entitle the Power Generating Facility
Owner to operate the Power Generating Module by using the grid connection.
2. A Final Operational Notification (FON) shall be issued by TEIAS, upon prior removal
of all incompatibilities identified for the purpose of the Interim Operational Notification
(ION) status and subject to the completion of data and study review process as required by
this Regulation.
3. With respect to data and study review the following must be submitted to TEIAS by the
Power Generating Facility Owner:

itemized Statement of Compliance; and

update of applicable technical data, simulation models and studies as
referred to in ARTICLE 111 (3) (b), (c), (d) and (e), including use of actual
measured values during testing.
4. In case of incompatibility identified for the purpose of the granting of the Final
Operational Notification (FON), a request maybe made to TEIAS. A Final Operational
Notification (FON) shall be issued by TEIAS, if the Power Generating Module is
compliant with the provisions of the request. TEIAS shall have the right to refuse the
operation of the Power Generating Module, whose owner’s request was rejected. Until the
Power Generating Facility Owner and TEIAS have established a resolution of the
incompatibility and the Power Generating Module is considered to be compliant by
TEIAS.
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ARTICLE 113
Limited operational notification (LON) for
type d power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 32]
1. Power Generating Facility Owners to whom a Final Operational Notification (FON) has
been granted shall inform TEIAS immediately in the following circumstances:

it is temporarily subject to either a significant modification or loss of
capability, due to implementation of one or more modifications of
significance to its performance; or

in case of equipment failures leading to non compliance with some relevant
requirements.
2. The Power Generating Facility Owner shall apply to TEIAS for a Limited Operational
Notification (LON), if the Power Generating Facility Owner reasonably expects the
circumstances according to ARTICLE 113(1) to persist for more than three months.
3. A Limited Operational Notification (LON) shall be issued by TEIAS with a clear
identification of:
 the unresolved issues justifying the granting of the Limited Operational
Notification (LON);
 the responsibilities and timescales for expected solution; and
a) a maximum period of validity which shall not exceed twelve months. The initial
period granted may be shorter, with possibility for extension, if evidence to the
satisfaction of the Relevant Network Operator has been made, which demonstrates
that substantial progress has been made in terms of achieving full compliance.
4. The Final Operational Notification (FON) shall be suspended during the period of
validity of the Limited Operational Notification (LON) with regard to the subjects for
which the Limited Operational Notification (LON) has been issued.
5. A further prolongation of the period of validity of the Limited Operational Notification
(LON) may be granted upon request made to TEIAS.
6. TEIAS shall have the right to refuse the operation of the Power Generating Module, if
the Limited Operational Notification (LON) terminates without removal of the
circumstances which caused its issuing. In such a case the Final Operational Notification
(FON) shall automatically be invalid.
SECTION4
Compliance for connection of new Power Generating
Modules
4.1
Compliance monitoring
ARTICLE 114
owner
Responsibility of the power generating facility
[New Article, harmonization with ENTSO-E code RFG Article 34]
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1. The Power Generating Facility Owner shall ensure that a Power Generating Module is
compliant with the requirements under this Regulation. This compliance shall be
maintained throughout the lifetime of the facility.
2. Planned modifications of the technical capabilities of the Power Generating Module
with possible impact on its compliance to the requirements under this Regulation shall be
notified to the Relevant Network Operator by the Power Generating Facility Owner before
initiating such modification.
3. Any operational incidents or failures of a Power Generating Module that have impact on
its compliance to the requirements of this Regulation shall be notified to the Relevant
Network Operator by the Power Generating Facility Owner as soon as possible without
any delay after the occurrence of such an incident.
4. Any foreseen test schedules and procedures to verify compliance of a Power Generating
Module with the requirements of this Regulation shall be notified to the Relevant Network
Operator by the Power Generating Facility Owner in due time and prior to their launch and
shall be approved by the Relevant Network Operator.
5. The Relevant Network Operator shall be facilitated to participate in such tests and may
record the performance of the Power Generating Modules.
ARTICLE 115
Tasks of the network operator
[New Article, harmonization with ENTSO-E code RFG Article 35]
1. The Relevant Network Operator shall regularly assess the compliance of a Power
Generating Module with the requirements under this Regulation throughout the lifetime of
the Power Generating Facility. The Power Generating Facility Owner shall be informed of
the outcome of this assessment.
2. The Relevant Network Operator shall have the right to request that the Power
Generating Facility Owner carries out compliance tests and simulations not only during the
operational notification procedures according to PART V, SECTION5, 5.1 but repeatedly
throughout the lifetime of the Power Generating Facility according to a plan or general
scheme for repeated tests and simulations defined or after any failure, modification or
replacement of any equipment that may have impact on the Power Generating Module’s
compliance with the requirements under this Regulation. The Power Generating Facility
Owner shall be informed of the outcome of these compliance tests and simulations.
3. The Relevant Network Operator shall make publicly available the list of information and
documents to be provided as well as the requirements to be fulfilled by the Power
Generating Facility Owner in the frame of the compliance process. Such list shall, notably,
cover the following information, documents and requirements:

all documentation and certificates to be provided by the Power Generating
Facility Owner;

details of the technical data of the Power Generating Module with relevance
to the grid connection;

requirements for models for steady-state and dynamic system studies;

timely provision of system data required to perform the studies;
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


studies by the Power Generating Facility Owner for demonstrating expected
steady-state and dynamic performance referring to the requirements set forth
in PART V, SECTION4, 4.4 of this Regulation; and
conditions and procedures including the scope for registering Equipment
Certificates.
conditions and procedures for use of relevant Equipment Certificates by the
Power Generating Facility Owner instead of part of the activity for
compliance as described in this Regulation.
4. The Relevant Network Operator shall make publicly available the allocation of
responsibilities to the Power Generating Facility Owner and to the Network Operator for
compliance testing, simulation and monitoring.
5. The Relevant Network Operator may partially or totally assign the performance of its
compliance monitoring to third parties. In this case, the Relevant Network Operator shall
ensure compliance of ARTICLE 7 of this Regulation by appropriate confidentiality
commitments with the assignee.
6. The Relevant Network Operator shall not withhold unreasonably any operational
notification as per PART V, SECTION3, if compliance tests or simulations cannot be
performed as agreed between the Relevant Network Operator and the Power Generating
Facility Owner due to reasons which are in the sole control of the Relevant Network
Operator.
ARTICLE 116
Common provisions on compliance testing
[New Article, harmonization with ENTSO-E code RFG Article 36]
1. The testing of the performance of the individual Power Generating Modules within the
Power Generating Facility shall aim at demonstrating the fulfilment of the requirements of
this Regulation.
2. Notwithstanding the minimum requirements relating to the compliance testing laid down
by the provisions of this Regulation, the Relevant Network Operator is entitled to:

allow the Power Generating Facility Owner to carry out an alternative set of
tests, provided that those tests are efficient and sufficient to demonstrate
compliance of a Power Generating Module to the requirements under this
Regulation;

require the Power Generating Facility Owner to carry out an additional or
alternative set of tests in case information supplied to the Relevant Network
Operator by the Power Generating Facility Owner in relation to compliance
testing under the provisions of PART V, SECTION4, 4.2 and 4.3 of this
Regulation are not sufficient to demonstrate compliance to the requirements
under this Regulation; and

require the Power Generating Facility Owner to carry out appropriate tests
in order to demonstrate a Power Generating Module’s performance when
operating on alternative fuels or fuel mixes. The Relevant Network Operator
and the Power Generating Facility Owner shall agree on which types of fuel
are tested.
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3. The Power Generating Facility Owner is responsible for carrying out the tests in
accordance with the conditions laid down in PART V, SECTION4, 4.2 and 4.3 of this
Regulation. The Relevant Network Operator shall make its reasonable efforts to cooperate
and not unduly delay the performance of the tests.
4. The Power Generating Facility Owner is responsible for the safety of the personnel and
the plant during the tests.
5. The Relevant Network Operator shall be facilitated to participate to the test either on site
or remotely from the Network Operator’s control centre. For that purpose, the Power
Generating Facility Owner shall provide suitable monitoring equipment to record all
relevant test signals and measurements as well as ensure that the relevant representatives
from the Power Generating Facility Owner are available on site for the entire testing
period. Signals specified by the Relevant Network Operator shall be provided, if the
Relevant Network Operator wishes for selected tests to use own equipment to record the
performance during tests. The decision as regards the participation of the Relevant
Network Operator to the test and the form of this participation remains at the sole and
exclusive discretion of the Relevant Network Operator.
ARTICLE 117
Common provisions on compliance simulations
[New Article, harmonization with ENTSO-E code RFG Article 37]
1. The simulation of the performance of the individual Power Generating Modules within
the Power Generating Facility shall aim at demonstrating the fulfilment of the requirements
of this Regulation.
2. Notwithstanding the minimum requirements relating to the Compliance Simulations laid
down by the provisions of this Regulation, the Relevant Network Operator is, , entitled to:
a) allow the Power Generating Facility Owner to carry out an alternative set of
simulations, provided that those simulations are efficient and sufficient to
demonstrate compliance of a Power Generating Module to the requirements under
this Regulation or national legislation including national codes; and
b) require the Power Generating Facility Owner to carry out an additional or
alternative set of simulations in case information supplied to the Relevant Network
Operator by the Power Generating Facility Owner in relation to Compliance
Simulation under the provisions of PART V, SECTION4, 4.4 and 4.5 of this
Regulation are not sufficient to demonstrate compliance to the requirements under
this Regulation.
3. The Power Generating Facility Owner shall provide simulation results relevant to each
and any individual Power Generating Module within the Power Generating Facility in a
report form in order to demonstrate the fulfilment of the requirements of this Regulation.
The Power Generating Facility Owner shall produce and provide a validated simulation
model for a Power Generating Module. The coverage of the simulation models are
described in ARTICLE 49 (6) (c).
4. The Relevant Network Operator shall have the right to check the compliance of a Power
Generating Module with the requirements of this Regulation by carrying out its own
136
Compliance Simulations based on the provided simulation reports, simulation models and
compliance test measurements
5. The Relevant Network Operator shall provide to the Power Generating Facility Owner
the technical data and the simulation model of the Network, in the extent necessary for
carrying out the requested simulations according to PART V, SECTION4, 4.4 and 4.5of
this Regulation.
4.2
Compliance testing for synchronous power generating
modules
ARTICLE 118
Compliance tests for type B synchronous
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 38]
1. Type B Synchronous Power Generating Modules are subject to the following
compliance tests. The Equipment Certificate may be used instead of part or all of the tests
below, provided that they are provided to the Relevant Network Operator.
2. With regard to the LFSM-O response test:
a) The Power Generating Module shall demonstrate its technical capability to
continuously modulate Active Power to contribute to Frequency Control in case of
large increase of Frequency in the system and shall verify the steady-state
parameters of regulations, such as Droop and deadband, and dynamic parameters,
including Frequency step change response.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate at least 10 % of Maximum Capacity change in Active Power,
taking into account the Droop settings and the deadband. Simulated Frequency
deviation signals shall be injected simultaneously at both the speed and power
control loops of the control systems if required, taking in account the scheme of
these control system.
c) The test is deemed passed, provided that the following conditions are both
fulfilled:
1) the test results, for both dynamic and static parameters, are in line with
the requirements as referred to in ARTICLE 47 (1) (c); and
2) undamped oscillations do not occur after the step change response.
ARTICLE 119
Compliance tests for type C synchronous
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 39]
1. In addition to the compliance tests for Type B Synchronous Power Generating Modules
in the conditions as referred to in ARTICLE 118, Type C Synchronous Power Generating
Modules are subject to the following compliance tests. The Equipment Certificate may be
137
used instead of part or all of the tests below, provided that they are provided to TEIAS or
to the Relevant Network Operator.
2. With regard to the LFSM-U response test:
a) The Power Generating Module shall demonstrate its technical capability to
continuously modulate Active Power at operating points below Maximum Capacity
to contribute to Frequency Control in case of large drop of Frequency in the system.
2. With regard to the LFSM-U response test:
b) The test shall be carried out by simulating at appropriate Active Power load
points (e.g. 80 %) with low Frequency steps and ramps big enough to activate at
least 10 % of Maximum Capacity Active Power change, taking into account the
Droop settings and the deadband. Simulated Frequency deviation signals shall be
injected simultaneously into both the speed governor and the load controller
references if required, taking into account the speed governor and the load
controller scheme.
c) The test is deemed passed, provided that the following conditions are both
fulfilled:
1) the test results, for both dynamic and static parameters, are in line with
the requirements as referred to in Article 10(2) (b); and
2) undamped oscillations do not occur after the step change response.
3. With regard to the FSM response test:
a) The Power Generating Module shall demonstrate its technical capability to
continuously modulate Active Power over the full operating range between
Maximum Capacity and Minimum Regulating Level to contribute to Frequency
Control and shall verify the steady-state parameters of regulations, such as Droop
and deadband and dynamic parameters, including robustness through Frequency
step change response and large, fast Frequency changes.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate the whole Active Power Frequency response range, taking into
account the Droop settings, the deadband and the Real Power headroom or deload
(margin to Maximum Capacity in operational timescale). Simulated Frequency
deviation signals shall be injected simultaneously into the references of both the
speed governor and the load controller of the unit or plant control system if
required, taking into account the speed governor and load controller scheme.
c) The test is deemed to be passed, provided that the following conditions are all
fulfilled:
1) activation time of full Active Power Frequency response range as result
of a step Frequency change has been no longer than required by ARTICLE
49 (2) (c);
2) undamped oscillations do not occur after the step change response;
3) the initial delay time has been according to ARTICLE 49 (2) (c);
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4) the Droop settings are available within the range defined in ARTICLE 49
(2) (c) and deadband (thresholds) is not more than the value in ARTICLE 49
(2) (c); and
5) insensitivity of Active Power Frequency response at any relevant
operating point does not exceed the requirements set forth in ARTICLE 49
(2) (c).
4. With regard to the frequency restoration control test:
a) The Power Generating Module shall demonstrate its technical capability to
participate in Frequency restoration control. The cooperation of FSM and
Frequency restoration control
shall be checked.
b) The test is deemed passed, provided that the test results, for both dynamic and
static parameters, are in line with the requirements as referred to in ARTICLE 49
(2) (d).
5. With regard to the Black Start Capability test:
a) Power Generating Modules with Black Start Capability in accordance with
ARTICLE 49 (5) (a), shall demonstrate this technical capability to start from shut
down without any external energy supply.
b) The test is deemed passed, provided that the start-up time has been not longer
than the timeframe according to ARTICLE 49 (5) (a) point 2).
6. With regard to the tripping to houseload test:
a) Power Generating Modules shall demonstrate their technical capability to trip to
and stably operate on house load.
b) The test shall be carried out at the Maximum Capacity and nominal Reactive
Power of the Power Generating Module before load shedding.
c) Further conditions for this test shall be defined by the Relevant Network
Operator taking into account ARTICLE 49(5) (c).
d) The test is deemed passed, provided that tripping to houseload has been
successful and stable Houseload Operation has been demonstrated for time period
according to ARTICLE 49 (5) (c) and re-synchronisation to the Network has been
performed successfully
7. With regard to the Reactive Power Capability test:
a) The Power Generating Module shall demonstrate its technical capability to
provide leading and lagging Reactive Power capability according to ARTICLE 52
(2) (b) and (c).
b) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
139
1) the Power Generating Module has been operating no shorter than 1 hour
at maximum Reactive Power, both leading and lagging, for each of:
- Minimum Stable Operating Level;
- Maximum Capacity; and
- an Active Power operating point between those maximum and minimum
ranges;
2) the Power Generating Module demonstrates its capability to change to
any Reactive Power target value within the agreed or decided Reactive
Power range within the specified performance targets of the relevant
Reactive Power control scheme.
ARTICLE 120
Compliance tests for type D synchronous
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 40]
1. In addition to the compliance tests for Type B and C Synchronous Power Generating
Modules in the conditions as referred to in ARTICLE 118 and ARTICLE 119 except for
ARTICLE 119 (7), Type D Synchronous Power Generating Modules are subject to the
following compliance tests. The Equipment Certificate may be used instead of part or all of
the tests below, provided that they are provided to TEIAS.
2. With regard to the Reactive Power Capability test:
a) The Power Generating Module shall demonstrate its technical capability to
provide leading and lagging Reactive Power capability according to ARTICLE 53
(2) (b) and ARTICLE 52 (2) (c).
b) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the Power Generating Module has been operating no shorter than 1 hour
at maximum Reactive Power, both leading and lagging, for each of:
- Minimum Stable Operating Level;
- Maximum Capacity; and
- an Active Power operating point between those maximum and minimum
ranges;
2) the Power Generating Module demonstrates its capability to change to
any Reactive Power target value within the agreed or decided Reactive
Power range within the specified performance targets of the relevant
Reactive Power control scheme.
4.3
ARTICLE 121
modules
Compliance testing for power park modules
Compliance tests for type B power park
[New Article, harmonization with ENTSO-E code RFG Article 41]
140
1. The Equipment Certificate may be used instead of part or all of the tests below, provided
that they are provided to the Relevant Network Operator.
2. With regard to Type B Power Park Modules the LFSM-O response tests shall be carried
out reflecting the choice of control scheme selected by the Relevant Network Operator.
a) The Power Park Module shall demonstrate its technical capability to
continuously modulate Active Power to contribute to Frequency Control in case of
increase of Frequency in the system and shall verify the steady-state parameters of
regulations, such as Droop and deadband, and dynamic parameters, including
Frequency step change response.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate at least 10 % of Maximum Capacity change in Active Power,
taking into account the Droop settings and the deadband. Simulated Frequency
deviation signals shall be injected to perform this test.
c) The test is deemed passed, provided that the test results, for both dynamic and
static parameters, are in line with the requirements as referred to in ARTICLE 47
(1) (c).
ARTICLE 122
modules
Compliance tests for type c power park
[New Article, harmonization with ENTSO-E code RFG Article 42]
1. In addition to the compliance tests for Type B Power Park Modules in the conditions as
referred to in Article 41, Type C Power Park Modules are subject to the following
compliance tests. The Equipment Certificate may be used instead of part or all of the tests
below, provided that they are provided to TEIAS or to the Relevant Network Operator.
2. With regard to the Active Power controllability and control range test:
a) The Power Park Module shall demonstrate its technical capability to operate at a
load level no higher than the Setpoint set by the Relevant Network Operator or
TEIAS.
b) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the load level of the Power Park Module is kept below the Setpoint;
2) the Setpoint is implemented according to the requirements as referred to
in ARTICLE 49 (2) (a); and
3) the accuracy of the regulation is compliant with specified value according
to ARTICLE 49 (2) (a).
3. With regard to the LFSM-U response test:
141
a) The Power Park Module shall demonstrate its technical capability to
continuously modulate Active Power to contribute to Frequency Control in case of
large drop of Frequency in the system.
b) The test shall be carried out by simulating the Frequency steps and ramps big
enough to activate at least 10 % of Maximum Capacity Active Power change with a
starting point of no more than 80 % of Maximum Capacity, taking into account the
Droop settings and the deadband. Simulated Frequency deviation signals shall be
injected in the Power Park Module controller scheme, taking into account both
speed governor and load controller scheme, if applicable.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the test results, for both dynamic and static parameters, are in line with
the requirements as referred to in ARTICLE 49 (2) (b); and
2) undamped oscillations after the step change response does not occur.
4. With regard to the FSM response test:
a) The Power Park Module shall demonstrate its technical capability to
continuously modulate Active Power over the full operating range between
Maximum Capacity and Minimum Regulating Level to contribute to Frequency
Control and shall verify the steady-state parameters of regulations, such as
insensitivity, Droop, deadband and range of regulation, as well as dynamic
parameters, including Frequency step change response.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate whole Active Power Frequency response range, taking into
account the Droop settings and the deadband. Simulated Frequency deviation
signals shall be injected to perform this test.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the activation time of full Active Power Frequency response range as
result of a step Frequency change has been no longer than that required by
ARTICLE 49 (2) (c);
2) undamped oscillations do not occur after the step change response;
3) the initial delay has been according to ARTICLE 49 (2) (c);
4) the Droop settings are available within the ranges defined in ARTICLE
49 (2) (c) and deadband (thresholds) is not more than the value chosen by
TEIAS; and
5) the insensitivity of Active Power Frequency response does not exceed the
requirement according to ARTICLE 49(2) (c).
5. With regard to the frequency restoration control test:
142
a) The Power Park Module shall demonstrate its technical capability to participate
in Frequency restoration control. The cooperation of both FSM and Frequency
restoration control shall be checked.
b) The test is deemed passed, provided that the test results for both dynamic and
static parameters are in line with the requirements as referred to in ARTICLE 49(2)
(d).
6. With regard to the Reactive Power capability test:
a) The Power Park Module shall demonstrate its technical capability to provide
leading and lagging Reactive Power capability according to ARTICLE 55(3) (b)
and (c).
b) The Reactive Power Capability test shall be carried out at maximum Reactive
Power, both leading and lagging, and concerning the verification of the following
parameters:
1) operation in excess of 60 % of Maximum Capacity for 30 min;
2) operation within the range of 30 – 50 % of Maximum Capacity for 30
min; and
3) operation within the range of 10 – 20 % of Maximum Capacity for 60
min.
c) The test is deemed passed, provided that the following criteria are cumulatively fulfilled:
1) the Power Park Module has been operating no shorter than requested
duration at maximum Reactive Power, both leading and lagging, in each
parameter as referred to in ARTICLE 122 (6) (b);
2) the Power Park Module has demonstrated its capability to change to any
Reactive Power target value within the agreed or decided Reactive Power
range within the specified performance targets of the relevant Reactive
Power control scheme; and
3) no action of any protection within the operation limits defined by
Reactive Power capacity diagram occurs
7. With regard to the Voltage Control Mode test:
a) The Power Park Module shall demonstrate its capability to operate in Voltage
control mode in the conditions set forth in ARTICLE 55 (3) (d) point 2).
b) The Voltage Control Mode test shall apply concerning the verification of the
following parameters:
1) the implemented Slope and deadband of the static characteristic;
2) the accuracy of the regulation;
3) the insensitivity of the regulation; and
4) the time of Reactive Power activation.
143
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the implemented Slope and deadband of the static characteristic;
2) the range of regulation and adjustable the Droop and deadband is
compliant with agreed or decided characteristic parameters, according to
ARTICLE 55 (3) (d);
3) the insensitivity of Voltage Control is not higher than 0.01 pu, according
to ARTICLE 55 (3) (d); and
4) following a step change in Voltage, 90 % of the change in Reactive
Power output has been achieved within the times and tolerances according
to ARTICLE 55 (3) (d).
8. With regard to the Reactive Power Control Mode test:
a) The Power Park Module shall demonstrate its capability to operate in Reactive
Power control mode, according to the conditions referred to in ARTICLE 55 (3) (d)
point 3).
b) The Reactive Power Control Mode test shall be complementary to the Reactive
Power Capability test.
c) The Reactive Power Control Mode test shall apply concerning the verification of
the following parameters:
1) the Reactive Power Setpoint range and step;
2) the accuracy of the regulation; and
3) the time of Reactive Power activation.
d) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the Reactive Power Setpoint range and step is ensured according to
ARTICLE 55 (3) (d); and
2) the accuracy of the regulation is compliant with the conditions as referred
to in ARTICLE 55(3) (d).
9. With regard to the Power Factor Control Mode test:
a) The Power Park Module shall demonstrate its capability to operate in Power
Factor control mode according to the conditions referred to in ARTICLE 55(3) (d)
point 4).
b) The Power Factor Control Mode test shall apply concerning the verification of
the following parameters:
1) the Power Factor Setpoint range;
144
2) the accuracy of the regulation; and
3) the response of Reactive Power due to step change of Active Power.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the Power Factor Setpoint range and step is ensured according to
ARTICLE 55 (3) (d);
2) the time of Reactive Power activation as result of step Active Power
change does not exceed the requirement according to ARTICLE 55 (3) (d);
and
3) the accuracy of the regulation is compliant with the value, as referred to
in ARTICLE 55 (3) (d).
10. With regard to the tests identified in ARTICLE 122(7), (8) and (9) the Relevant
Network Operator may select only one of the three control options for testing.
ARTICLE 123
modules
Compliance tests for type D power park
[New Article, harmonization with ENTSO-E code RFG Article 43]
1. In addition to the compliance tests for Type B and C Power Park Modules in the
conditions as referred to in ARTICLE 121 and ARTICLE 122 except for ARTICLE 122
(6), Type D Power Park Modules are subject to the following compliance tests. The
Equipment Certificate may be used instead of part or all of the tests below, provided that
they are provided to TEIAS.
2. With regard to the Reactive Power Capability test:
a) The Power Park Module shall demonstrate its technical capability to provide
leading and lagging Reactive Power capability according to ARTICLE 56 (2) (a)
and ARTICLE 55(3) (c).
b) The Reactive Power Capability test shall be carried out at maximum Reactive
Power, both leading and lagging, and concerning the verification of the following
parameters:
1) operation in excess of 60 % of Maximum Capacity for 30 min;
2) operation within the range of 30 – 50 % of Maximum Capacity for 30
min; and
3) operation within the range of 10 – 20 % of Maximum Capacity for 60
min.
c) The test is deemed passed, provided that the following criteria are cumulatively
fulfilled:
145
1) the Power Park Module has been operating no shorter than requested
duration at maximum Reactive Power, both leading and lagging, in each
parameter as referred to in ARTICLE 122 (2) (b);
2) the Power Park Module has demonstrated its capability to change to any
Reactive Power target value within the agreed or decided Reactive Power
range within the specified performance targets of the relevant Reactive
Power control scheme; and
3) no action of any protection within the operation limits defined by
Reactive Power capacity diagram occurs
4.4
Compliance simulations for synchronous power
generating modules
ARTICLE 124
Compliance
simulations
synchronous power generating modules
for
type
B
[New Article, harmonization with ENTSO-E code RFG Article 45]
1. The Equipment Certificate may be used instead of part or all of the simulations below,
provided that they are provided to the Relevant Network Operator
2. Type B Synchronous Power Generating Modules are subject to the following
compliance simulations.
3. With regard to the LFSM-O response simulation:
a) The Power Generating Module shall demonstrate its capability to simulate
Active Power modulation at high Frequency according to ARTICLE 47 (1) b
b) The simulation shall be carried out by simulating high Frequency steps and
ramps reaching Minimum Regulating Level, taking into account the Droop settings
and the deadband
c) The simulation is deemed passed, provided that:
1) the simulation model of the Power Generating Module is validated
against the compliance test for LFSM-O response as referred to in
ARTICLE 118 (2); and
2) compliance with the requirement according to ARTICLE 47 (1) (c) is
demonstrated
4. With regard to the Type B fault-ride-through capability of Synchronous Power
Generating Modules simulation:
a) The Power Generating Module shall demonstrate its capability to simulate faultride-through capability in the conditions set forth in ARTICLE 48 (3) (a).
146
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 48 (3) (a) is demonstrated.
5. With regard to the Post Fault Power Active Recovery simulation:
a) The Power Generating Module shall demonstrate its capability to simulate post
fault Active Power recovery in the conditions set forth in ARTICLE 51(3) (a).
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 51 (3) (a) is demonstrated.
ARTICLE 125
Compliance simulations for type c synchronous
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 46]
1. In addition to the Compliance Simulations for Type B Synchronous Power Generating
Modules in the conditions as referred to in ARTICLE 124, Type C Synchronous Power
Generating Modules are subject to the following Compliance Simulations. The Equipment
Certificate may be used instead of part or all of the simulations below, provided that they
are provided to TEIAS or to the Relevant Network Operator.
2. With regard to the LFSM-U response simulation:
a) The Power Generating Module shall demonstrate its capability to simulate
Active Power modulation at low Frequencies according to ARTICLE 49(2) b.
b) The simulation shall be carried out by simulating low Frequency steps and ramps
reaching Maximum Capacity, taking into account the Droop settings and the
deadband.
c) The simulation is deemed passed, provided that:
1) the simulation model of the Power Generating Module is validated
against the compliance test for LFSM-U response as referred to in
ARTICLE 119 (2); and
2) compliance with the requirement according to ARTICLE 49 (2) (b) is
demonstrated.
3. With regard to the FSM response simulation:
a) The Power Generating Module shall demonstrate its capability to modulate
Active Power over the full Frequency range according to ARTICLE 49 (2) (c).
b) The simulation shall be carried out by simulating Frequency steps and ramps big
enough to activate whole Active Power Frequency response range, taking into
account the Droop settings and the deadband.
c) The simulation is deemed passed, provided that:
147
1) the simulation model of the Power Generating Module is validated
against the compliance test for LFSM-U response as referred to in
ARTICLE 119 (3); and
2) compliance with the requirement according to ARTICLE 49 (2) (c) is
demonstrated
4. With regard to the Island Operation simulation:
a) The Power Generating Module shall demonstrate its performance during Island
Operation in the conditions as referred to in ARTICLE 49 (5) (b).
b) The simulation is deemed passed, provided that the Power Generating Module
reduces or increases the Active Power output from its previous operating point to
any new operating point within the P-Q-Capability Diagram within the limits of
ARTICLE 49(5) (b) without disconnection of the Power Generating Module from
the island due to over /underfrequency; and
5. With regard to the Reactive Power Capability simulation:
a) The Power Generating Module shall demonstrate its capability to simulate
leading and lagging Reactive Power capability in the conditions referred to in
ARTICLE 52(2) (b) and (c).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the simulation model of the Power Generating Module is validated
against the compliance tests for Reactive Power Capability at the as referred
to in ARTICLE 119 (7); and
2) compliance with the requirements as referred to in ARTICLE 52(2) (b)
and (c) is demonstrated.
ARTICLE 126
Compliance
simulations
synchronous power generating modules
for
type
D
[New Article, harmonization with ENTSO-E code RFG Article 47]
1. In addition to the Compliance Simulations for Type B and C Synchronous Power
Generating Modules in the conditions as referred to in ARTICLE 125 and ARTICLE 126,
except for the Type B fault-ride¬through capability of Synchronous Power Generating
Modules as referred to in ARTICLE 124(4) and Reactive Power Capability simulation as
referred to in ARTICLE 125 (5), Type D Synchronous Power Generating Modules are
subject to the following Compliance Simulations. The Equipment Certificate may be used
instead of part or all of the simulations below, provided that they are provided to TEIAS.
2. With regard to the Power Oscillations Damping Control simulation:
148
a) The Power Generating Module shall demonstrate the performance of its control
system (PSS function) to damp power oscillations in the conditions set forth in
ARTICLE 53 (2) (g).
b) The tuning shall result in improved damping of corresponding Active Power
response of the AVR in combination with the PSS function compared to the Active
Power response of the AVR alone.
c) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the PSS function damps the existing power oscillations of the Power
Generating Module within a Frequency range specified by TEIAS. This
Frequency range shall include the local mode frequency of the Power
Generating Module and the expected Network oscillations; and
2) a sudden load reduction of the Power Generating Module from 1p.u. to
0.6p.u. of the Maximum Capacity has not lead to undamped oscillations in
Active or Reactive Power of the Power Generating Module.
3. With regard to the Type D fault-ride-through capability of Synchronous Power
Generating Modules simulation:
a) The Power Generating Module shall demonstrate its capability to simulate faultride-through capability in the conditions set forth in ARTICLE 50 (3) (a).
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 50 (3) (a) is demonstrated.
4. With regard to the Reactive Power Capability simulation:
a) The Power Generating Module shall demonstrate its capability to simulate
leading and lagging Reactive Power capability in the conditions referred to in
ARTICLE 53 (2) (b) and ARTICLE 52(2) (c).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the simulation model of the Power Generating Module is validated
against the compliance tests for Reactive Power Capability at the as referred
to in ARTICLE 120 (2); and
2) compliance with the requirements as referred to in ARTICLE 53 (2) (b)
ARTICLE 52(2) (c) is demonstrated.
4.5
Compliance simulations for power park modules
149
ARTICLE 127
modules
Compliance simulations for type B power park
[New Article, harmonization with ENTSO-E code RFG Article 48]
1. Type B Power Park Modules are subject to the following compliance simulations. The
Equipment Certificate may be used instead of part or all of the simulations below, provided
that they are provided to the Relevant Network Operator.
2. With regard to the LFSM-O response simulation:
a) The Power Park Module shall demonstrate its capability to simulate Active
Power modulation at high Frequency according to ARTICLE 47 (1) b.
b) The simulation shall be carried out by simulating high Frequency steps and
ramps reaching Minimum Regulating Level, taking into account the Droop settings
and the deadband.
c) The simulation is deemed passed, provided that:
1) the simulation model of the Power Park Module is validated against the
compliance test for LFSM-O response as referred to in ARTICLE 121 (2);
and
2) compliance with the requirement according to ARTICLE 47 (1) (c) is
demonstrated.
3. With regard to the fast acting additional reactive Current injection simulation:
a) The Power Generating Module shall demonstrate its capability to simulate fast
acting additional reactive Current injection in the conditions set forth in ARTICLE
54 (2) (b).
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 54 (2) (b) is demonstrated.
4. With regard to the Type B fault-ride-through capability of Power Park Modules
simulation:
a) The Power Generating Module shall demonstrate its capability to simulate faultride-through capability in the conditions set forth in ARTICLE 48 (3) (a).
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 48(3) (a) is demonstrated.
5. With regard to the Post Fault Power Active Recovery simulation:
a) The Power Generating Module shall demonstrate its capability to simulate post
fault Active Power recovery in the conditions set forth in ARTICLE 54 (3) (a).
b) The simulation is deemed passed, provided that compliance with the requirement
according to ARTICLE 54(3) (a) is demonstrated.
150
ARTICLE 128
modules
Compliance simulations for type C power park
[New Article, harmonization with ENTSO-E code RFG Article 49]
1. In addition to the Compliance Simulations for Type B Power Park Modules in the
conditions as referred to in ARTICLE 127, Type C Power Park Modules are subject to the
following Compliance Simulations. The Equipment Certificate may be used instead of part
or all of the simulations below, provided that they are provided to TEIAS or to the
Relevant Network Operator.
2. With regard to the LFSM-U response simulation:
a) The Power Park Module shall demonstrate its capability to simulate Active
Power modulation at low Frequencies according to ARTICLE 49 (2) b.
b) The simulation shall be carried out by simulating low Frequency steps and ramps
reaching Maximum Capacity, taking into account the Droop settings and the
deadband.
c) The simulation is deemed passed, provided that:
1) the simulation model of the Power Park Module is validated against the
compliance test for LFSM-U response as referred to in ARTICLE 122 (3);
and
2) compliance with the requirement according to ARTICLE 49 (2) (b) is
demonstrated
3. With regard to the FSM response simulation:
a) The Power Park Module shall demonstrate its capability to modulate Active
Power over the full Frequency range according to ARTICLE 49 (2) (c).
b) The simulation shall be carried out by simulating Frequency steps and ramps big
enough to activate whole Active Power Frequency response range, taking into
account the Droop settings and the deadband.
c) The simulation is deemed passed, provided that:
1) the simulation model of the Power Park Module is validated against the
compliance test for LFSM-U response as referred to in ARTICLE 122 (4);
and
2) compliance with the requirement according to ARTICLE 49(2) (c) is
demonstrated.
4. With regard to the Island Operation simulation:
a) The Power Generating Module shall demonstrate its performance during Island
Operation in the conditions as referred to in ARTICLE 49 (5) (b).
b) The simulation is deemed passed, provided that the Power Generating Module
reduces or increases the Active Power output from its previous operating point to
151
any new operating point within the P-Q-Capability Diagram within the limits of
ARTICLE 49(5) (b) without disconnection of the Power Generating Module from
the island due to over¬/underfrequency; and
5. With regard to the simulation of the capability of providing Synthetic Inertia:
a) The model of the Power Generating Module shall demonstrate its capability to
simulate the capability of providing Synthetic Inertia to a low Frequency event in
the conditions as referred to in ARTICLE 55(2) (a).
b) The simulation is deemed passed, provided that the model demonstrates
compliance with the conditions of ARTICLE 55(2) (a).
6. With regard to the Reactive Power capability simulation:
a) The Power Park Module shall demonstrate its capability to simulate leading and
lagging Reactive Power capability in the conditions referred to in ARTICLE 55(3) (b)
and (c).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
1) the simulation model of the Power Park Module is validated against the
compliance tests for Reactive Power Capability at the as referred to in Article
42(6); and
2) compliance with the requirements as referred to in ARTICLE 55 (3) (b) and (c)
is demonstrated.
7. With regard to the power oscillations damping control simulation:
a) The model of the Power Generating Module shall demonstrate its capability to
simulate power oscillations damping capability in the conditions as referred to in
ARTICLE 55 (3) (f).
b) The simulation is deemed passed, provided that the model demonstrates compliance
with the conditions of ARTICLE 55(3) (f).
ARTICLE 129
modules
Compliance simulations for type D power park
[New Article, harmonization with ENTSO-E code RFG Article 50]
1. In addition to the Compliance Simulations for Type B and C Power Park Modules in the
conditions as referred to in ARTICLE 128 and ARTICLE 129, except for the Type B faultride-through capability of Power Park Modules as referred to in ARTICLE 127 (4), Type
D Power Park Modules are subject to the Type D fault-ride-through capability of Power
Park Modules Compliance Simulation. The Equipment Certificate may be used instead of
part or all of the simulations below, provided that they are provided to TEIAS.
2. The model of the Power Generating Module shall demonstrate its capability to simulate
fault¬ride-through capability in the conditions as referred to in ARTICLE 50 (3) (a).
152
3. The simulation is deemed passed, provided that the model demonstrates compliance
with the conditions of ARTICLE 50(3) (a) respectively.
SECTION5
Operation notification procedure for connection of new
demand
5.1
Operational notification procedure for new demand
facilities and new distribution network connections
ARTICLE 130
General provisions
[New Article, harmonization with ENTSO-E code DCC Article 27]
1. The provisions of PART V, SECTION5 shall apply only to New Demand Facilities and
New Distribution Network Connections as described in ARTICLE 11, ARTICLE 15 and
ARTICLE 16.
2. Each Demand Facility Owner or Distribution Network Operator to which one or more of
the requirements in PART IV, SECTION 2 apply, shall confirm to the Relevant Network
Operator its ability to satisfy the technical design and operational criteria as referred to in
Chapter 2 of this Regulation.
3. Further details of the operational notification procedure shall be defined and made
publically available by the Relevant Network Operator and TEIAS.
ARTICLE 131
Provisions for demand units within a demand
facility connected at or below 1000V
[New Article, harmonization with ENTSO-E code DCC Article 28]
1. The operational notification procedure for a new Demand Unit, within a Demand
Facility connected at or below 1000V, shall comprise an Installation Document.
The Installation Document template will be provided by the Relevant Network Operator,
and the contents agreed with TEIAS.
Based on an Installation Document, the Demand Facility Owner shall fill in the required
information and submit it, either directly or indirectly (via an Aggregator), to the Relevant
Network Operator.
The content of the Installation Document of individual Demand Units may be aggregated
(including but not restricted to via an Aggregator) as specified, and where accepted, by the
Relevant Network Operator or TEIAS.
2. The content of the Installation Document shall be defined by the Relevant Network
Operator. The Installation Document shall contain the following items:
153
a) the location at which the Demand Unit is connected to the Network;
b) the maximum capacity of the installation in kW;
c) for equipment used information shall be provided as directed by the Relevant
Network Operator (an Equipment Certificate may be used); and
d) the contact details of the Demand Facility Owner.
The Relevant Network Operator may define, additional items to be included in the
Installation Document.
ARTICLE 132
Common provisions for demand facilities and
closed distribution networks and connected above 1000 v,
transmission connected demand facilities and transmission
connected distribution network connections
[New Article, harmonization with ENTSO-E code DCC Article 29]
1. The operational notification procedure for connection of a Demand Facility or Closed
Distribution Network, a Transmission Connected Distribution Network and a Transmission
Connected Demand Facility, allows for the use of an Equipment Certificate.
2. The Equipment Certificate process may be used to collate verified data and performance
for a specific type of Demand Unit. If accepted by the Relevant Network Operator,
Equipment Certificates shall be used to verify specific parts of data and performance in
place of part of the operational notification procedure. An Equipment Certificate can be
used repeatedly to demonstrate compliance within the same Demand Facility and Closed
Distribution Network, Transmission Connected Demand Facility and Transmission
Connected Distribution Network.
3. If accepted by the Relevant Network Operator, the Demand Facility Owner or
Distribution Network Operator may use Equipment Certificates as validated information
about components of the Demand Facility or Distribution Network, but Equipment
Certificates shall not be used to indicate total compliance. The Relevant Network Operator
will make available upon request by the Demand Facility Owner or Distribution Network
Operator what parts of a project, if any, are acceptable in lieu of the full compliance
process and how to proceed to make use of Equipment Certificates in this process.
ARTICLE 133
Provisions
for
transmission
connected
distribution network connections and transmission connected
demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 31]
The operational notification procedure for connection for each new Transmission
Connected Distribution Network and Transmission Connected Demand Facility shall
comprise:
a) Energisation Operational Notification;
b) Interim Operational Notification; and
c) Final Operational Notification.
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ARTICLE 134
Energisation operational notification for
transmission connected distribution network connections and
transmission connected demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 32]
1. Energisation Operational Notification shall entitle the Transmission Connected Demand
Facility Owner or Transmission Connected Distribution Network Operator to energise its
internal Network by using the Network connection that is defined by the Connection Point.
2. An Energisation Operational Notification shall be issued by TEIAS, subject to the
completion of preparation and the fulfilment of the requirements of TEIAS in the relevant
operational procedures. This preparation will include agreement on the protection and
control relevant to the Connection Point between TEIAS and the Demand Facility Owner
or Distribution Network Operator.
ARTICLE 135
Interim
operational
notification
for
transmission connected distribution network connections and
transmission connected demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 33]
1. Interim Operational Notification shall entitle the Transmission Connected Demand
Facility Owner or Transmission Connected Distribution Network Operator to operate the
Transmission Connected Demand Facility, Transmission Connected Distribution Network,
and/or Demand Unit by using the Network connection that is defined by the Connection
Point for a limited period of time.
2. An Interim Operational Notification shall be issued by TEIAS subject to the completion
of data and study review process.
3. For the purpose of the completion of data and study review, TEIAS shall have the right
to request the following from the Transmission Connected Distribution Network or
Transmission Connected Demand Facility:
a) interim Statement of Compliance;
b) detailed technical data of the Transmission Connected Demand Facility or
Transmission Connected Distribution Network with relevance to the Network
connection, that is defined by the Connection Point, as specified by TEIAS;
c) Equipment Certificates of Demand Facilities and/or Distribution Network
Connections where these are relied upon as part of the evidence of compliance;
d) studies demonstrating expected steady‐state and dynamic performance as
required by PART V, SECTION6, 6.4 and 6.6 of this Regulation; and
e) details of intended practical method of completing compliance tests according to
PART V, SECTION6.
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4. The maximum period for the Transmission Connected Demand Facility Owner or
Transmission Connected Distribution Network Operator to remain in the Interim
Operational Notification status shall not exceed twenty four months. TEIAS shall be
entitled to specify a shorter Interim Operational Notification validity period. In that case,
an Interim Operational Notification extension shall be granted only if the Demand Facility
Owner or Distribution Network Operator demonstrates substantial progress towards full
compliance of the Demand Unit. At the time of Interim Operational Notification extension,
the outstanding issues should be explicitly identified.
5. A prolongation of the twenty four month period for the Demand Facility Owner or
Distribution Network Operator for the Demand unit to remain in the Interim Operational
Notification status may be granted upon request made to TEIAS. The request shall be
made before the expiry of the twenty four month period.
ARTICLE 136
Final operational notification for transmission
connected distribution network connections and transmission
connected demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 34]
1. Final Operational Notification shall entitle the Transmission Connected Demand Facility
Owner or Transmission Connected Distribution Network Operator to operate the
Transmission Connected Demand Facility or Transmission Connected Distribution
Network by using the Network connection that is defined by the Connection Point.
2. A Final Operational Notification shall be issued by TEIAS upon prior removal of all
incompatibilities identified for the purpose of the Interim Operational Notification status
and subject to the completion of data and study review process.
3. For the purpose of the completion of data and study review, TEIAS shall have the right
to request the following from the Transmission Connected Distribution Network Operator
or Transmission Connected Demand Facility Owner:
a) Statement of Compliance; and
b) Update of applicable technical data, simulation models and studies as referred to
in ARTICLE 135 (3)(b),(c),(d) and (e), including use of actual measured values
during testing.
4. In case of incompatibility identified for the purpose of issuing the Final Operational
Notification, a request maybe made to TEIAS.
5. The Final Operational Notification shall be issued by TEIAS, if the request addressed by
Transmission Connected Demand Facility Owner or Transmission Connected Distribution
Network Operator was approved.
6. The Transmission Connected Demand Facility Owner or Transmission Connected
Distribution Network Operator whose request was rejected by TEIAS, shall not be
connected until a resolution removing the incompliance is agreed between the
Transmission Connected Demand Facility Owner or Transmission Connected Distribution
Network Operator, and TEIAS. In case when the incompliance cannot be removed an
Interim Operational Notification, for a New Demand Facility or a New Distribution
156
Network Connection, or a Limited Operational Notification, for a failure in service or a
change or modification, shall be issued.
ARTICLE 137
Limited
operational
notification
for
transmission connected distribution network connections and
transmission connected demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 35]
1. The Transmission Connected Demand Facility Owner or Transmission Connected
Distribution Network Operator, to whom a Final Operational Notification has been
granted, shall as soon as practicable inform TEIAS of the following circumstances:
a) a temporary modification or loss of capability of the Transmission Connected
Demand Facility or Transmission Connected Distribution Network, which affects
the performance of the Transmission Demand Facility or Transmission Connected
Distribution Network to meet the requirements of PART IV SECTION 2; or
b) equipment failures leading to non‐compliance with any relevant requirements
2. The Transmission Connected Demand Facility Owner or Transmission Connected
Distribution Network Operator shall apply within 1 month to TEIAS for a Limited
Operational Notification, if they expect the circumstances described in paragraph 1 to
persist for more than three months.
3. Limited Operational Notification shall be issued by TEIAS with a clear identification of:
a) the unresolved issues justifying the granting of the Limited Operational
Notification;
b) the responsibilities and timescales for expected solution; and
c) an initial period of validity.
4. This initial period of validity, specified in paragraph 3(c), might be extended provided
that evidence is given to demonstrate substantial progress in terms of achieving full
compliance. The total period of validity of a Limited Operational Notification shall not
exceed twelve months.
5. A prolongation of the twelve month period for the Transmission Connected Demand
Facility Owner or Transmission Connected Distribution Network Operator to remain in the
Limited Operational Notification status may be granted upon request made to TEIAS.
6. The request shall be made before the expiry of the twelve month period.
7. TEIAS shall have the right to refuse the operation of the Transmission Connected
Demand Facility or Transmission Connected Distribution Network Connection, if the
Limited Operational Notification terminates without removal of the circumstances which
caused its issuing. In such a case, the Final Operational Notification shall automatically be
invalid.
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SECTION6
Compliance for connection of new demand
6.1
Compliance general
ARTICLE 138
Responsibility of the demand facility owner or
demand network owner
[New Article, harmonization with ENTSO-E code DCC Article 37]
1. The Demand Facility Owner and the Distribution Network Operator shall ensure that
respectively the Demand Facility, Distribution Network and/or the Distribution Network
Connection is compliant with the requirements that apply to it under this Regulation. This
compliance shall be maintained throughout the lifetime of the Demand Facility or
Distribution Network.
2. Where the requirements of this code are defined by or are for the purpose of operation
by the TSO, alternative tests or criteria for test result acceptance for these requirements
will be agreed with TEIAS.
3. The Demand Facility Owner or Distribution Network Operator may partially or totally
delegate to third parties the task of gathering relevant documentation evidencing
compliance.
4. Any intention to modify the technical capabilities of the Demand Facility, Distribution
Network or Distribution Network Connection with possible impact on its compliance
requirements of PART V, SECTION6, 6.2 to 6.6 of this Chapter of the Regulation shall be
notified to TEIAS, directly or indirectly (including but not restricted to via an Aggregator),
and prior to pursuing such modification in a time scale provided by TEIAS.
5. Any operational incidents or failures of the Demand Facility or Distribution Network
Connection that have impact on its compliance requirements of PART V, SECTION6, 6.2
to 6.6 of this Chapter of the Regulation shall be subject to notification to TEIAS, directly
or indirectly (including but not restricted to via an Aggregator), as soon as possible and
without any intentional delay after the occurrence of such an incident.
6. Any foreseen test schedules and procedures to verify compliance of the Demand Facility
or Distribution Network Connection to the requirements of this Regulation shall be subject
to notification and approval by TEIAS within the deadlines defined by the Relevant
Network Operator and prior to their commencement.
7. TEIAS shall be facilitated to participate to such test and may record the performance of
the Demand Facility, Distribution Network and/or Distribution Network Connection.
ARTICLE 139
Tasks of the network operator
[New Article, harmonization with ENTSO-E code DCC Article 38]
158
1. TEIAS shall be allowed to monitor compliance of the Demand Facility, Distribution
Network or Distribution Network Connection to the requirements under this Regulation
throughout the lifetime of the Demand Facility, Distribution Network or Distribution
Network Connection. The Demand Facility Owner of Distribution Network Operator shall
be informed of the outcome of this assessment.
2. TEIAS shall have the right to request that the Demand Facility Owner or Distribution
Network Operator carries out compliance tests and simulations not only during the
operational notification procedures according to PART V SECTION5 but repeatedly
throughout the lifetime of the Demand Facility, Distribution Network or Distribution
Network Connection. Such a request may be made in particular according to a plan or
general scheme for repeated tests and simulations or after any failure, modification or
replacement of any equipment with possible impact on the compliance of the Demand
Facility or Distribution Network Connection to the requirements under this Regulation.
3. The Relevant Network Operator shall make publicly available the list of information and
documents to be provided as well as the requirements to be fulfilled by the Demand
Facility Owner or Distribution Network Operator in the frame of the compliance process.
Such list shall, notably, cover the following information, documents and requirements:
a) all documentation and certificates to be provided by the Demand Facility Owner
or Distribution Network Operator;
b) details of the technical data required from the Demand Facility, Distribution
Network or Distribution Network Connection with relevance to the Network
connection or operation;
c) requirements for models for steady‐state and dynamic system studies;
d) timely provision of system data required to perform studies;
e) studies by the Demand Facility Owner or Distribution Network Operator for
demonstrating expected steady‐state and dynamic performance referring to the
requirements set forth in PART V, SECTION6, 6.4 and 6.6 of this Regulation;
f) conditions and procedures including scope for registering Equipment
Certificates; and
g) conditions and procedures for use by the Demand Facility Owner or Distribution
Network Operator of relevant Equipment Certificates instead of part of the activity
for compliance as described in this Regulation.
4. TEIAS shall make publicly available the allocation of responsibilities to the Demand
Facility Owner or Distribution Network Operator and to the Network Operator for
Compliance Testing, certification and monitoring.
5. TEIAS may partially or totally delegate the performance of its Compliance Monitoring
to third parties.
6. TEIAS shall not withhold unreasonably any operational notification as described in
ARTICLE 134 to ARTICLE 136, if compliance tests or simulations cannot be performed
as agreed between TEIAS and the Demand Facility Owner or Distribution Network
159
Operator due to reasons which are in the sole control of the Relevant Network Operator or
outside the sole control of the Demand Facility Owner or Distribution Network Operator.
ARTICLE 140
Common provisions on compliance testing
[New Article, harmonization with ENTSO-E code DCC Article 39]
1. The testing of the Demand Facility or Distribution Network Connection as specified in
ARTICLE 142 to ARTICLE 145 shall aim at demonstrating the fulfilment of the
requirements of this Regulation.
2. Tests shall be run in the following circumstances:
a) a new connection is required;
b) a further development, replacement or modernization of equipment takes place;
or
c) alleged incompliance by TEIAS with the requirements of this Regulation.
3. Notwithstanding the minimum requirements relating to the Compliance Testing, laid
down in PART V, SECTION6, 6.2 and 6.3, the TEIAS shall be, entitled to:
a) allow the Demand Facility Owner or Distribution Network Operator to carry out
an alternative set of tests, provided that those tests are efficient and sufficient to
demonstrate compliance of the Demand Facility, Distribution Network or
Distribution Network Connection with the requirements of this Regulation; and
b) require the Demand Facility Owner or Distribution Network Operator to carry
out an additional or alternative set of tests in case information supplied to TEIAS
by the Demand Facility Owner or Distribution Network Operator, in relation with
the compliance testing under the provisions of PART V, SECTION6, 6.2 and 6.3, is
not sufficient to demonstrate compliance with the requirements of this Regulation.
Any additional or alternative tests should be sufficient to demonstrate compliance
and be undertaken efficiently.
4. The Demand Facility Owner or Distribution Network Operator shall be responsible for
carrying out the tests in accordance with the conditions laid down in PART V, SECTION6.
TEIAS shall use its best endeavors to cooperate and not unduly delay the performance of
the tests.
5. The Demand Facility Owner or Distribution Network Operator shall be responsible for
the safety of the personnel and the plant during the tests.
6. The costs of the relevant tests including necessary deviation from the commercially
preferred operating point in order to facilitate the tests shall be covered by the Demand
Facility Owner or Distribution Network Operator.
7. TEIAS shall be facilitated to participate to the test either on site or, if possible, remotely
from the Network Operator’s Control Room.
For that purpose, the Demand Facility Owner or Distribution Network Operator shall
provide suitable monitoring equipment to record all relevant test signals and
measurements, as well as ensure that the relevant representatives from both the Demand
160
Facility or Distribution Network and the manufacturer are available on site for the entire
testing period.
Signals specified by TEIAS shall be provided in case the Relevant Network Operator
intends to use its own equipment for selected tests, in order to record the performance
during tests. The decision as regards the participation of TEIAS to the test and the form of
this participation shall remain at the sole and exclusive discretion of the Relevant Network
Operator.
8. Where provided, TEIAS shall have the right to specify a method for testing,
directly or indirectly (including but not restricted to via an Aggregator) of the active
control of Reactive Power according to ARTICLE 60.
ARTICLE 141
Common provisions on compliance simulations
[New Article, harmonization with ENTSO-E code DCC Article 40]
1. The simulation of the Demand Facility, Distribution Network or Distribution Network
Connection performance as specified ARTICLE 146 to ARTICLE 147 shall aim at
demonstrating the fulfilment of the requirements of this Regulation.
2. Simulations shall be run in the following circumstances:
a) a new connection is required;
b) a further development, replacement or modernization of equipment takes place;
or
c) alleged incompliance by the Relevant Network Operator with the requirements
of this Regulation.
3. Notwithstanding the minimum requirements relating to the Compliance Simulations laid
down in PART V, SECTION6, 6.4 and 6.5, the Relevant Network Operator shall be,
entitled to:
a) allow the Demand Facility Owner or Distribution Network Operator to carry out
an alternative set of simulations, provided that those simulations are efficient and
sufficient to demonstrate compliance of the Demand Facility or Distribution
Network with the requirements of this Regulation; and
b) require the Demand Facility Owner or Distribution Network Operator to carry
out an additional or alternative set of simulations in case information supplied to
TEIAS by the Demand Facility Owner or Distribution Network Operator in relation
to Compliance Simulation under the provisions of PART V, SECTION6, 6.4 or 6.6,
is not sufficient to demonstrate compliance with the requirements of this
Regulation.
4. The Demand Facility Owner shall provide simulation results relevant to each and any
individual Demand Unit within the Demand Facility, in order to demonstrate the
compliance with the requirements of this Regulation.
5. The Demand Facility Owner or Distribution Network Operator shall produce and
provide a validated simulation model or equivalent information. The scope and format of
the simulation models or equivalent information are described in ARTICLE 66 (1)(a)-(b).
161
6. TEIAS shall have the right to verify the compliance of the Demand Facility, Distribution
Network or Distribution Network Connection with the requirements of this Regulation by
carrying out its own Compliance Simulations based on the information provided in
ARTICLE 61, ARTICLE 62, ARTICLE 66 and PART V, SECTION6, 6.2 and 6.3.
7. TEIAS shall provide to the Demand Facility Owner or Distribution Network Operator
with the technical data and the simulation model of the Network, to the extent it is
necessary to carry out the requested simulations according to PART V, SECTION6, 6.4 or
6.6.
6.2
Compliance testing for transmission connected
distribution networks
ARTICLE 142
Compliance tests for disconnection for system
defence and reconnection
[New Article, harmonization with ENTSO-E code DCC Article 41]
1. The Transmission Connected Distribution Networks shall be compliant with TEIAS
requirements for system defence and reconnection referred to in ARTICLE 64 and shall be
subject to the following compliance tests:
a) with regard to testing of the capability of reconnection after an incidental
disconnection due to a Network disturbance, reconnection shall be achieved
through a reconnection procedure, preferably by automation, authorized by TEIAS;
b) with regard to synchronization testing, if required by TEIAS, the Transmission
Connected Distribution Network shall demonstrate the synchronisation facilities.
This test shall verify the settings of the synchronisation devices. It shall cover the
following matters: Voltage, Frequency, phase angle range, deviation of Voltage and
Frequency;
c) with regard to remote disconnection testing, the Transmission Connected
Distribution Network shall be capable of remote disconnection at the Connection
Point[s] from the Transmission Network when required by TEIAS within the time
specified by TEIAS;
d) with regard to Low Frequency Demand Disconnection testing, the Distribution
Network Operator shall be able to demonstrate the capability of automatic low
Frequency disconnection of a percentage of demand to be specified by TEIAS, in
coordination with adjacent TSOs, where equipped as defined in ARTICLE 64;
e) with regard to Low Frequency Demand Disconnection relays testing, the Low
Frequency relays shall be tested to demonstrate, in accordance with ARTICLE 64
(1) and (2), their functional capability for operation from a nominal AC supply
input. This AC supply input shall be specified by TEIAS; and
f) with regard to Low Voltage Demand Disconnection scheme testing, the Low
Voltage Demand Disconnection scheme shall be tested to demonstrate, in
accordance with ARTICLE 64 (3), that their operation can be performed in a single
action
162
ARTICLE 143
Compliance tests for information exchange
[New Article, harmonization with ENTSO-E code DCC Article 42]
1. With regard to information exchange between TEIAS and the Transmission Connected
Distribution Network, the Transmission Connected Distribution Network Operator shall
demonstrate the technical capability to comply with the standard defined in ARTICLE
61(1)(b) and (c), with time stamping as specified.
2. The Equipment Certificate may be used instead of part of the test above, provided that it
is registered with TEIAS.
6.3
ARTICLE 144
reconnection
Compliance testing for demand facilities
Compliance tests for system defence and
[New Article, harmonization with ENTSO-E code DCC Article 43]
1. The Transmission Connected Demand Facility as specified by TEIAS shall be compliant
with the requirements for system restoration referred to in ARTICLE 64 and shall be
subject to the following compliance tests:
a) with regard to testing of the capability of reconnection after an incidental
disconnection due to a Network disturbance, reconnection shall be achieved
through a reconnection procedure, preferably by automation, authorized by TEIAS;
b) with regard to synchronization testing where required by TEIAS, the
Transmission Connected Demand Facility shall be equipped with the necessary
synchronisation facilities. This test shall cover the following matters: Voltage,
Frequency, phase angle range, deviation of Voltage and Frequency;
c) with regard to remote disconnection testing, the Transmission Connected
Demand Facility shall be capable of remote disconnection at the Connection
Point[s] from the Transmission Network when required by TEIAS;
d) with regard to Low Frequency Demand Disconnection scheme tests, the Low
Frequency Demand Disconnection shall be tested to demonstrate, in accordance
with ARTICLE 64 (1) and (2), their functional capability for operation from a
nominal AC input. This AC input shall be specified by TEIAS; and
e) with regard to Low Voltage Demand Disconnection schemes, the Low Voltage
Demand Disconnection scheme shall be tested to demonstrate, in accordance with
ARTICLE 64 (3)(c) that their operation can be performed in a single action.
2. The Equipment Certificate may be used to replace part of the tests below, provided that
it is registered with TEIAS.
163
ARTICLE 145
Compliance tests for information exchange
[New Article, harmonization with ENTSO-E code DCC Article 45]
1. With regard to information exchange between TEIAS and the Transmission Connected
Demand Facilities in real time or periodically with time stamping, the Transmission
Connected Demand Facility shall demonstrate the technical capability to comply with the
standard defined by TEIAS pursuant to ARTICLE 62.
2. The Equipment Certificate may be used instead of part of the tests above, provided that
it registered with the Relevant Network Operator.
6.4
Compliance simulations for transmission connected
distribution networks
ARTICLE 146
Compliance simulations for reactive power
ranges of transmission connected distribution networks
[New Article, harmonization with ENTSO-E code DCC Article 46]
1. With regard to Transmission Connected Distribution Networks, Reactive Power demand
Compliance Simulations shall be carried out in the following conditions:
a) a steady‐state load flow simulation model of the Network of the Transmission
Connected Distribution Network shall be used to calculate the Reactive Power
demand under different load conditions and under different generation conditions.
A combination of steady‐state minimum and maximum load and generation
conditions resulting in the lowest and highest Reactive Power demand shall be part
of the simulations. Calculation of the Reactive Power export at an Active Power
flow of less than 25% of the Maximum Import Capability at the Connection Point
shall be part of the simulations;
b) TEIAS shall have the right to specify the method for compliance simulation of
the active control of Reactive Power as defined in ARTICLE 60 (1)(c); and
c) the simulation is deemed passed if the simulations demonstrate compliance with
the requirements as described in ARTICLE 60(1)(a),(b) and (c).
6.5
Compliance simulations for demand facilities
ARTICLE 147
Compliance simulations for reactive power
ranges of transmission connected demand facilities
[New Article, harmonization with ENTSO-E code DCC Article 47]
1. With regard to Transmission Connected Demand Facilities without onsite generation,
Reactive Power demand compliance simulations shall be carried out in the following
conditions:
a) the Transmission Connected Demand Facility without onsite generation shall
demonstrate its Reactive Power capability at the Connection Point;
164
b) a load flow simulation model of the Transmission Connected Demand Facility
shall be used to calculate the Reactive Power demand under different load
conditions. Minimum and maximum load conditions resulting in the lowest and
highest Reactive Power demand at the Connection Point shall be part of the
simulations;
c) the simulation is deemed passed if the simulations demonstrate compliance with
the requirements as described in ARTICLE 60 (1)(a).
2. With regard to these Transmission Connected Demand Facilities with onsite generation,
Reactive Power compliance simulations shall be carried out in the following conditions:
a) a load flow simulation model of the Network of the Transmission Connected
Demand Facility shall be used to calculate the Reactive Power demand under
different load conditions and under different generation conditions. A combination
of minimum and maximum load and generation conditions resulting in the lowest
and highest Reactive Power capability at the Connection Point shall be part of the
simulations; and
b) the simulation is deemed passed if the simulations demonstrate compliance with
the requirements as described in ARTICLE 60(1)(a).
6.6
Compliance monitoring
ARTICLE 148
Compliance monitoring
connected distribution connected networks
for
transmission
[New Article, harmonization with ENTSO-E code DCC Article 49]
1. With regard to Compliance Monitoring of the Reactive Power requirements of
Transmission Connected Distribution Networks:
a) The Reactive Power shall be measured at each Connection Point;
b) The Connection Point of the Transmission Connected Distribution Network shall
be equipped with necessary equipment to measure the Active and Reactive Power,
in accordance with ARTICLE 60 and
c) The Relevant Network Operator shall specify the time schedule for Compliance
Monitoring.
ARTICLE 149
Compliance
connected demand facilities
monitoring
for
transmission
[New Article, harmonization with ENTSO-E code DCC Article 50]
1. With regard to Compliance Monitoring of the Reactive Power requirements of
Transmission Connected Demand Facilities:
a) The Reactive Power shall be measured at the Connection Point;
165
b) The Connection Point of the Transmission Connected Demand Facility shall be
equipped with necessary equipment to measure the Active and Reactive Power, in
accordance with ARTICLE 60; and.
c) The Relevant Network Operator shall specify the time schedule for Compliance
Monitoring.
SECTION7
Operation notification procedure for connection new
HVDC systems
ARTICLE 150
General provisions
[New Article, harmonization with ENTSO-E HVDC NC Article 53]
1. The provisions of SECTION7 [CHAPTER 5, Section 1 of HVDC NC] shall apply
to New HVDC Systems only.
2. The HVDC System Owner shall demonstrate to the Relevant Network Operator(s)
its compliance with the requirements referred to in SECTION 3 [CHAPTER 2 to
CHAPTER 4 of HVDC NC] at the respective Connection Point by completing
successfully the operational notification procedure for connection of the HVDC
System as defined in ARTICLE 151 through to ARTICLE 154.
3. The operational notification procedure shall be defined and made publicly available
by TEIAS and the Relevant Network Operator(s).
4. The operational notification procedure for connection for each New HVDC System
shall comprise:
a) Energisation Operational Notification (EON);
b) Interim Operational Notification (ION), and
c) Final Operational Notification (FON).
ARTICLE 151
Energisation Operational Notification (EON)
for HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 54]
1. An Energisation Operational Notification (EON) shall entitle the HVDC System
Owner to energise its internal Network and auxiliaries and connect it to the
Network at its defined Connection Point(s).
2. An EON shall be issued by TEIAS or by the Relevant Network Operator(s), subject
to completion of preparation and the fulfilment of the requirements defined by
TEIAS or by the Relevant Network Operator(s), in the relevant operational
procedures. This preparation will include agreement on the protection control
166
relevant to the Connection Point(s) between TEIAS or the Relevant Network
Operator(s) and the HVDC System Owner.
ARTICLE 152
Interim Operational Notification (ION) for
HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 55]
1. Interim Operational Notification (ION) shall entitle the HVDC System Owner or
HVDC Converter Unit Owner to operate the HVDC System or HVDC Converter
by using the Network connection(s) that is defined by the Connection Point(s) for a
limited period of time.
2. An ION shall be issued by TEIAS or by the Relevant Network Operator(s) on the
completion of data and study review process, if applicable.
3. For the purpose of the completion of data and study review, TEIAS or the Relevant
Network Operator(s) have the right to request the following from the HVDC
System Owner or HVDC Converter Unit Owner:
- itemized Statement of Compliance;
- detailed technical data of the HVDC System with relevance to the Network
connection, that is defined by the Connection Point(s), as specified TEIAS or by
the Relevant Network Operator(s) in coordination with the Relevant TSO(s);
- Equipment Certificates of HVDC Systems or HVDC Converter Units where
these are relied upon as part of the evidence of compliance;
- simulation models as specified by ARTICLE 98 and as required by the Relevant
Network Operator(s) in coordination with the Relevant TSO(s);
- studies demonstrating expected steady‐state and dynamic performance as
required by SECTION 3 [CHAPTER 2 and CHAPTER 4 of HVDC NC];
details of intended Compliance Tests according to ARTICLE 157.
- details of intended practical method of completing Compliance Tests according
to SECTION8 [CHAPTER 6 of HVDC NC].
4. The maximum period for the HVDC System Owner or HVDC Converter Unit
Owner to remain in the ION status shall not exceed twenty four months. TEIAS or
the Relevant Network Operator(s) are entitled to specify a shorter ION validity
period in accordance with ARTICLE 5[Article 4(2)of the HVDC NC]. The ION
validity period shall be subject to notification to EMRA. The modalities of that
notification shall be determined in accordance with the applicable national
regulatory framework. ION extension shall be granted only if the HVDC System
Owner demonstrates substantial progress towards full compliance. At the time of
ION extension, the outstanding issues shall be explicitly identified.
5. A prolongation of the twenty four month period for the HVDC System to remain in
the ION status may be granted upon request for derogation made to the Relevant
Network Operator(s). The request shall be made before the expiry of the twenty
four month period.
167
ARTICLE 153
Final Operational
HVDC Systems
Notification (FON) for
[New Article, harmonization with ENTSO-E HVDC NC Article 56]
1. A Final Operational Notification (FON) shall entitle the HVDC System Owner to
operate the HVDC System or HVDC Converter Unit(s) by using the grid
Connection Point(s).
2. A FON shall be issued by TEIAS or by the Relevant Network Operator(s), upon
prior removal of all incompatibilities identified for the purpose of the ION status
and subject to the completion of data and study review process as required by this
regulation.
3. For the purpose of the completion of data and study review, TEIAS or the Relevant
Network Operator(s) in coordination with the Relevant TSO(s) shall have the right
to request the following from the HVDC System Owner:
- itemized Statement of Compliance; and
- update of applicable technical data, simulation models and studies as referred to
in ARTICLE 152, including use of actual measured values during testing.
4. TEIAS or The Relevant Network Operator(s) shall have the right to refuse the
operation of the HVDC System or HVDC Converter Unit(s) until the HVDC
System Owner and TEIAS or the Relevant Network Operator(s) have established a
resolution of the incompatibility and the HVDC System is considered to be
compliant by TEIAS or by the Relevant Network Operator(s).
ARTICLE 154
Limited Operational Notification (LON) for
HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 57]
1. HVDC System Owners to whom a FON has been granted shall inform the Relevant
Network Operator(s) immediately in the following circumstances:
- the HVDC System is temporarily subject to either a significant modification or
loss of capability, due to implementation of one or more modifications of
significance to its performance; or
- in case of equipment failures leading to non-compliance with some relevant
requirements.
2. The HVDC System Owner shall apply to TEIAS or to the Relevant Network
Operator(s) for a Limited Operational Notification (LON), if the HVDC System
Owner reasonably expects the circumstances according to ARTICLE 154(1) to
persist for more than three months.
3. A LON shall be issued by TEIAS or by the Relevant Network Operator(s) with a
clear identification of:
- the unresolved issues justifying the granting of the Limited Operational
Notification (LON);
- the responsibilities and timescales for expected solution; and
- a maximum period of validity which shall not exceed twelve months. The initial
period granted may be shorter, with possibility for extension, if evidence to the
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satisfaction of TEIAS or of the Relevant Network Operator(s) has been made,
which demonstrates that substantial progress has been made in terms of
achieving full compliance.
4. The FON shall be suspended during the period of validity of the LON with regard
to the subjects for which the LON has been issued.
5. TEIAS or the Relevant Network Operator(s) have the right to refuse the operation
of the HVDC System, if the LON terminates without removal of the circumstances
which caused its issuing. In such a case the FON shall automatically be invalid.
SECTION8
Compliance of new HVDC System
ARTICLE 155
Responsibility of the HVDC System Owner
and DC-connected Power Park Module Owner
[New Article, harmonization with ENTSO-E HVDC NC Article 65]
1. The HVDC System Owner shall ensure that the HVDC System and HVDC
Converter Station(s) are compliant with the requirements under this Regulation.
This compliance shall be maintained throughout the lifetime of the facility.
2. Planned modifications of the technical capabilities of the HVDC System or HVDC
Converter Station with possible impact on its compliance to the requirements under
this regulation shall be notified to TEIAS by the HVDC System Owner before
initiating such modification.
3. Any operational incidents or failures of a HVDC System or HVDC Converter
Station that have impact on its compliance to the requirements of this regulation
shall be notified to TEIAS by the HVDC System Owner as soon as possible
without any delay after the occurrence of such an incident.
4. Any foreseen test schedules and procedures to verify compliance of a HVDC
System or HVDC Converter Station with the requirements of this regulation shall
be notified to TEIAS by the HVDC System Owner in due time and prior to their
launch and shall be approved by TEIAS.
5. TEIAS shall be facilitated to participate in such tests and may record the
performance of the HVDC Systems or HVDC Converter Stations.
ARTICLE 156
Tasks of the Relevant Network Operator
[New Article, harmonization with ENTSO-E HVDC NC Article 66]
1. The Relevant Network Operator shall regularly assess the compliance of an HVDC
System and HVDC Converter Station with the requirements under this regulation
throughout the lifetime of the HVDC System or HVDC Converter Station. The
HVDC System Owner shall be informed of the outcome of this assessment.
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2. The Relevant Network Operator shall have the right to request that the HVDC
System Owner or DC-connected Power Park Module Owner carries out compliance
tests and simulations not only during the operational notification procedures
according toSECTION7 [CHAPTER 5 of HVDC NC], but repeatedly throughout
the lifetime of the HVDC System or HVDC Converter Station according to a plan
or general scheme for repeated tests and simulations or after any failure,
modification or replacement of any equipment that may have impact on the
compliance with the requirements under this Regulation. The HVDC System
Owner shall be informed of the outcome of these compliance tests and simulations.
3. The plan or general scheme for repeated tests and simulations, the list of
information and documents to be provided as well as the requirements to be
fulfilled by the HVDC System Owner in the frame of the compliance process shall
be defined and made publicly available by TEIAS and the Relevant Network
Operator(s). Such list shall, notably, cover the following information, documents
and requirements:
 all documentation and certificates to be provided by the HVDC System
Owner;
 details of the technical data of the HVDC System or HVDC Converter
Station with relevance to the grid connection;
 requirements for models for steady-state and dynamic system studies;
 timely provision of system data required to perform the studies;
 studies by the HVDC System Owner for demonstrating expected steadystate and dynamic performance referring to the requirements set forth in
SECTION 3 [CHAPTER 2 and CHAPTER 4 of HVDC NC]; and
 conditions and procedures including the scope for registering Equipment
Certificates.
4. The allocation of responsibilities to the HVDC System Owner and to the Network
Operator for compliance testing, simulation and monitoring shall be defined and made
publicly available by TEIAS and the Relevant Network Operator(s).
5. TEIAS or the Relevant Network Operator may partially or totally assign the
performance of its compliance monitoring to third parties. In this case, TEIAS or the
Relevant Network Operator shall ensure compliance with ARTICLE 7 by appropriate
confidentiality commitments with the assignee.
6. TEIAS or the Relevant Network Operator shall not withhold unreasonably any
operational notification as per SECTION7[CHAPTER 5of HVDC NC], if compliance tests
or simulations cannot be performed as agreed between TEIAS or the Relevant Network
Operator and the HVDC System Owner due to reasons which are in the sole control of the
Relevant Network Operator.
7. The Relevant Network Operator shall provide TEIAS when requested the compliance
test and simulation results referred to in this Section.
ARTICLE 157
Compliance testing for HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 67]
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1. The Equipment Certificate may be used instead of part of the tests below, provided
that they are provided to the Relevant Network Operator.
2. With regard to the Reactive Power Capability test:
a) The HVDC Converter Unit or the HVDC Converter Station shall demonstrate
its technical capability to provide leading and lagging Reactive Power
capability according to ARTICLE 77.
b)
The Reactive Power Capability test shall be carried out at maximum Reactive
Power, both leading and lagging, and concerning the verification of the
following parameters:
i. Operation at Minimum HVDC Active Power Transmission Capacity;
ii. Operation at Maximum HVDC Active Power Transmission Capacity;
and
iii. Operation at Active Power Setpoint between those Minimum and
Maximum HVDC Active Power Transmission Capacity.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
the HVDC Converter Unit or the HVDC Converter Station has been
operating no shorter than 1 hour at maximum Reactive Power, both
leading and lagging, for each parameter as referred to in point b);
ii. the HVDC Converter Unit or the HVDC Converter Station demonstrates
its capability to change to any Reactive Power target value within the
applicable Reactive Power range within the specified performance
targets of the relevant Reactive Power control scheme; and
iii. no action of any protection within the operation limits defined by
Reactive Power capacity diagram occurs.
3. With regard to the Voltage Control Mode test:
a) The HVDC Converter Unit or the HVDC Converter Station shall demonstrate
its capability to operate in Voltage control mode in the conditions set forth in
ARTICLE 79(3) at the time set forth in ARTICLE 79(1).
b) The Voltage Control Mode test shall apply concerning the verification of the
following parameters:
i.
the implemented Slope and deadband of the static characteristic;
ii. the accuracy of the regulation;
iii. the insensitivity of the regulation; and
iv.
the time of Reactive Power activation.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
the implemented Slope and deadband of the static characteristic;
ii. the range of regulation and adjustable the Droop and deadband is
compliant with agreed or decided characteristic parameters, according to
ARTICLE 79(3);
iii. the insensitivity of Voltage Control is not higher than 0.01 pu, according
to ARTICLE 79(3); and
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iv.
following a step change in Voltage, 90 % of the change in Reactive
Power output has been achieved within the times and tolerances
according to ARTICLE 79(3).
4. With regard to the FSM response test:
a) The HVDC System shall demonstrate its technical capability to continuously
modulate Active Power over the full operating range between Maximum
HVDC Active Power Transmission Capacity and Minimum HVDC Active
Power Transmission Capacity to contribute to Frequency Control and shall
verify the steady-state parameters of regulations, such as Droop and deadband
and dynamic parameters, including robustness through Frequency step change
response and large, fast Frequency changes.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate at least 10% of the full Active Power Frequency response
range, taking into account the Droop settings and the deadband. Simulated
Frequency deviation signals shall be injected into the controller of the HVDC
Converter Unit or the HVDC Converter Station.
c) The test is deemed to be passed, provided that the following conditions are all
fulfilled:
i.
ii.
iii.
iv.
v.
activation time of full Active Power Frequency response range as
result of a step Frequency change has been no longer than required
by ARTICLE 70(1) (d);
undamped oscillations do not occur after the step change response;
the initial delay time has been according to ARTICLE 70(1) (d);
the Droop settings are available within the range defined in
ARTICLE 70(1) (a) and deadband (thresholds) is not more than the
value in ARTICLE 70(1)(a); and
insensitivity of Active Power Frequency response at any relevant
operating point does not exceed the requirements set forth in
ARTICLE 70(1) (d).
5. With regard to the LFSM-O response test:
a) The HVDC System shall demonstrate its technical capability to continuously
modulate Active Power to contribute to Frequency Control in case of large
increase of Frequency in the system and shall verify the steady-state parameters
of regulations, such as Droop and deadband, and dynamic parameters, including
Frequency step change response.
b) The test shall be carried out by simulating Frequency steps and ramps big
enough to activate at least 10 % of the full operating range for Active Power in
each direction, taking into account the Droop settings and the deadband.
Simulated Frequency deviation signals shall be injected into the controller of
the HVDC Converter Unit or the HVDC Converter Station.
c) The test is deemed passed, provided that the following conditions are both
fulfilled:
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i.
ii.
the test results, for both dynamic and static parameters, are in line with
the requirements as referred to in ARTICLE 71(1); and
undamped oscillations do not occur after the step change response.
6. With regard to the LFSM-U response test:
a) The HVDC System shall demonstrate its technical capability to continuously
modulate Active Power at operating points below Maximum HVDC Active
Power Transmission Capacity to contribute to Frequency Control in case of
large drop of Frequency in the system.
b) The test shall be carried out by simulating at appropriate Active Power load
points with low Frequency steps and ramps big enough to activate at least 10 %
of the full operating range for Active Power, taking into account the Droop
settings and the deadband. Simulated Frequency deviation signals shall be
injected into the controller of the HVDC Converter Unit or the HVDC
Converter Station.
c) The test is deemed passed, provided that the following conditions are both
fulfilled:
i.
the test results, for both dynamic and static parameters, are in line with
the requirements as referred to in ARTICLE 72(1); and
ii. undamped oscillations do not occur after the step change response.
7. With regard to the Active Power Controllability test:
a) The HVDC System shall demonstrate its technical capability to continuously
modulate Active Power over the full operating range according to ARTICLE
69(1)a) and d).
b) The test shall be carried out by sending manual and automatic instructions by
the Relevant TSO(s).
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
The HVDC System has demonstrated stable operation
ii. The time of adjustment of the Active Power is shorter than the delay
defined according to ARTICLE 69(1)a.
iii. The dynamic response of the HVDC System when receiving
instructions aiming at performing exchange and sharing of primary
reserve, automatic or manual tertiary restoration reserve or participation
in Imbalance Netting Process is compliant with the requirements
defined by TEIAS in terms and conditions related to connection
included into the connection agreement.
8. With regard to the ramping rate modification test:
a) The HVDC System shall demonstrate its technical capability to adjust the
ramping rate according to ARTICLE 69(2).
b) The test shall be carried out by sending instructions of ramping modifications
by the Relevant TSO(s)
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c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
Ramping rate is adjustable
ii. The HVDC System has demonstrated stable operation during ramping
periods
9. With regard to the black start test, if applicable:
a) The HVDC System shall demonstrate its technical capability to energise the
busbar of the remote AC substation to which it is connected, within a time
frame specified by TEIAS, according to ARTICLE 94(3).
b) The test shall be carried out while the HVDC System starts from shut down.
c) The test is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
The HVDC System has demonstrated being able to energise the busbar
of the remote AC-substation to which it is connected
ii. The HVDC System operates from a stable operating point at agreed
capacity, according to the procedure of ARTICLE 94(4).
ARTICLE 158
Compliance simulations for HVDC Systems
[New Article, harmonization with ENTSO-E HVDC NC Article 69]
1. The Equipment Certificate may be used instead of part of the simulations below,
provided that they are provided to the Relevant Network Operator.
2. With regard to the fast acting additional reactive Current injection simulation:
a) The HVDC Converter Unit Owner or the HVDC Converter Station Owner shall
simulate the capability for fast acting additional reactive Current injection in the
conditions set forth in ARTICLE 76.
b) The simulation is deemed passed, provided that compliance with the
requirement according to ARTICLE 76 is demonstrated.
3. With regard to the fault-ride-through capability simulation:
a) The HVDC System Owner shall simulate the capability for fault-ride-through
capability in the conditions set forth in ARTICLE 82.
b) The simulation is deemed passed, provided that compliance with the
requirement according to ARTICLE 82 is demonstrated.
4. With regard to the Post Fault Power Active Recovery simulation:
a) The HVDC System Owner shall simulate the capability for post fault Active
Power recovery in the conditions set forth in ARTICLE 83.
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b) The simulation is deemed passed, provided that compliance with the
requirement according to ARTICLE 83 is demonstrated.
5. With regard to the Reactive Power capability simulation:
a) The HVDC Converter Unit Owner or the HVDC Converter Station Owner
shall simulate the capability for leading and lagging Reactive Power
capability in the conditions referred to in ARTICLE 77(1)(a)-(c).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
the simulation model of the HVDC Converter Unit or the HVDC
Converter Station is validated against the compliance tests for Reactive
Power Capability at the as referred to in ARTICLE 157; and
ii. compliance with the requirements as referred to in ARTICLE 77(1)(a)(c) is demonstrated.
6. With regard to the Power Oscillations Damping Control simulation:
a) The HVDC System Owner shall demonstrate the performance of its control
system (POD function) to damp power oscillations in the conditions set
forth in ARTICLE 87.
b) The tuning shall result in improved damping of corresponding Active Power
response of the HVDC control in combination with the POD function
compared to the Active Power response of the HVDC control alone.
c) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
The POD function damps the existing power oscillations of the HVDC
System within a Frequency range specified by TEIAS. This Frequency
range shall include the local mode Frequency of the HVDC System and
the expected Network oscillations; and
ii. a change of Active Power transfer of the HVDC System as specified by
TEIAS does not lead to undamped oscillations in Active or Reactive
Power of the HVDC System.
7. With regard to the simulation of Active Power modification in case of disturbance:
a) The HVDC System Owner shall simulate the capability to quickly modify
Active Power according to ARTICLE 69(1)(b).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
The HVDC System has demonstrated stable operation when following
the pre-defined sequence of active power variation.
ii. The initial delay of the adjustment of the Active Power is shorter than
the value specified in ARTICLE 69(1)(b) or reasonably justified if
greater
8. With regard to the fast active power reversal simulation, as applicable:
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a) The HVDC System Owner shall simulate the capability to quickly modify
Active Power according to ARTICLE 69(1)(c).
b) The simulation is deemed passed, provided that the following conditions are
cumulatively fulfilled:
i.
The HVDC System has demonstrated stable operation
ii. The time of adjustment of the Active Power is shorter than the value
specified in ARTICLE 69(1)(c) or reasonably justified if greater
SECTION9
Operational notification procedure for existing facilities
ARTICLE 159
Operational notification procedure for existing
power generating modules
[New Article, harmonization with ENTSO-E code RFG Article 33]
1. In order to assess the advantages of the applicability of any requirement set forth in this
Regulation to Existing Power Generating Modules, TEIAS shall initiate the process
referred to in ARTICLE 10(2) by a preparatory stage aimed at identifying cases of merit
with the phases defined in ARTICLE 159 (1) to (7) below. This preparatory stage shall
consist of a qualitative comparison of costs and benefits related to the requirement under
consideration for application to Existing Power Generating Modules taking into account
network-based or market-based alternatives, where applicable. If TEIAS deems the cost of
applying the requirement to be low and the benefit to be high then the case can proceed as
defined below. If however, the cost is deemed high and or the benefit is deemed low then
TEIAS may not proceed further.
2. TEIAS shall carry out a quantitative Cost-Benefit Analysis of a requirement under
consideration for application to Existing Power Generating Modules that has demonstrated
potential benefits as a result of the preparatory stage according to ARTICLE 159 (1)
above. This Cost-Benefit Analysis shall be followed by a public consultation. The public
consultation shall include, amongst others, a proposal for a transition period for applying a
requirement to Existing Power Generating Modules. Such a transition period should not
exceed two years from the decision of EMRA on the applicability.
3. Power Generating Facility Owners, DSOs and CDSOs shall assist and contribute to this
Cost-Benefit Analysis and provide the relevant data as requested by TEIAS within three
months after reception of the request, unless agreed otherwise.
4. The Cost-Benefit Analysis shall be undertaken using one or more of the following
calculating principles:
 net present value;
 return on investment;
 rate of return; and
 time to break-even.
The quantified benefits shall include any marginal socio-economic benefits in terms of
improvement of security of supply including, but not limited to:
 associated reduction in probability of loss of supply over the lifetime of the
modification;
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

the probable extent and duration of such loss of supply;
the societal cost per hour of such loss of supply;
as well as benefits to the internal market in electricity, cross-border trade and integration of
renewable energies including, but not limited to:
 Frequency response;
 reserve holding;
 Reactive Power provision;
 congestion management; and
 Defense measures.
The quantified costs shall include as appropriate, but are not limited to:
 costs for implementing the requirement;
 any attributable loss of opportunity; and/or
 change in maintenance and operating costs.
5. If the socio-economic benefits outweigh the costs of applying the requirement under
consideration to Existing Power Generating Modules, TEIAS shall summaries the analysis
within three months in a report which shall include a recommendation on how to proceed.
This report shall be subject to public consultation. If, taking due account of the outcome of
the public consultation, TEIAS decides to proceed with the issue, the report including such
consultation outcome and a proposal on the applicability of the requirement under
consideration to Existing Power Generating Modules, shall be forwarded to EMRA within
six months for decision.
6. The proposal by TEIAS to EMRA on applicability of any requirement of this Regulation
according to ARTICLE 10(2) to Existing Power Generating Modules according to
ARTICLE 10 (2) shall include the following:
a) an operational notification procedure in order to demonstrate the implementation
of the requirements by the Power Generating Facility Owner;
b) an appropriate transition period for implementing the requirements. The
determination of the transition period shall take into account the category of the
Power Generating Module according to ARTICLE 10 (6) (a) to (e) and any
underlying obstacles for efficient undertaking of the equipment
modification/refitting.
EMRA shall decide on the case within three months after receipt of the report and
the recommendation of TEIAS. The decision of TEIAS on how to proceed with the
issue and the decision of EMRA, if any, shall be published.
7. All relevant clauses in contracts and/or relevant clauses in general terms and conditions
relating to the grid connection of Existing Power Generating Modules shall be amended to
achieve compliance with the requirements of this Regulation, that shall apply to them
according to ARTICLE 159 (6). The relevant clauses shall be amended within three years
after the decision of EMRA on the applicability according to ARTICLE 10 (2). This
requirement for amendment shall apply regardless of whether the relevant contracts or
general terms and conditions provide for such an amendment.
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ARTICLE 160
Operational notification procedure for existing
demand facilities or existing distribution network connections
[New Article, harmonization with ENTSO-E code DCC Article 36]
1. In order to assess the advantages of the applicability of any requirement set forth in
this Regulation to Existing Demand Facilities or Existing Distribution Network
Connections, TEIAS shall initiate a preparatory stage to identify cases which merit
initiating the phases defined in paragraphs 4 to 9. This preparatory stage shall consist
of an initial qualitative comparison of costs and benefits related to the requirement
under consideration for application to Existing Demand Facilities or Existing
Distribution Network Connections.
2. In case, TEIAS considers that this preparatory stage demonstrates that a subsequent
analytical Cost Benefit Analysis has a reasonable prospect of determining a positive
result, TEIAS shall initiate the phases defined in paragraphs 4 to 9.
3. In case, TEIAS considers that this preparatory stage does not demonstrate that a
subsequent Cost Benefit Analysis has a reasonable prospect of determining a positive
cost‐ benefit, TEIAS may not initiate the phases defined in paragraphs 4 to 9.
4. TEIAS shall carry out a quantitative Cost Benefit Analysis of a requirement under
consideration for application to Existing Demand Facilities or Existing Distribution
Networks, which has demonstrated potential benefits as a result of the preparatory
stage according to paragraph 1. This quantitative Cost Benefit Analysis shall be
followed by a public consultation. The public consultation shall include, amongst
others, a proposal for a transition period for implementing an application to Existing
Demand Facilities or Existing Distribution Network Connections. Such proposed
transition period should not exceed two years from the decision of EMRA on the
applicability.
5. Demand Facility Owners or Distribution Network Operators shall assist and
contribute to this Cost Benefit Analysis and provide the relevant data as requested by
TEIAS within three months after receipt of the request, unless a longer period is
agreed. As far as Distribution Networks are concerned, Distribution Network
Operators shall be fully integrated in the Cost Benefit Analysis.
6. The Cost Benefit Analysis shall be undertaken using one or more of the following
calculating principles:
a) net present value;
b) return on investment;
c) rate of return; and
d) time to break even.
The quantified benefits shall include any marginal socio‐economic benefits in terms of
improvement of security of supply including, but not limited to:
a) associated reduction in probability of loss of supply over the lifetime of the
modification;
b) the probable extent and duration of such loss of supply; and
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c) the societal cost per hour of such loss of supply;
as well as benefits to the internal market in electricity, cross‐border trade and
integration of renewable including, but not limited to:
a) Frequency response;
b) reserve holding;
c) Reactive Power provision;
d) congestion management; and
e) defense measures.
The quantified costs shall include as appropriate, but are not limited to:
a)costs for implementing the requirement;
b) any attributable loss of opportunity; and/or
c) change in maintenance and operating costs.
7. If the socio‐economic benefits do not outweigh the costs of applying the
requirement under consideration no further action is to be taken. If the socio‐economic
benefits outweigh the costs of applying the requirement under consideration to the
Existing Demand Facilities or Existing Distribution Network Connections, TEIAS
shall summarise the analysis in a report. The report shall include a recommendation
and a proposal for a transition period for implementing any application to Existing
Demand Facilities or Existing Distribution Network Connections. Such proposed
transition period should not exceed two years from the decision of EMRA on the
applicability. This report shall be subject to public consultation.
If taking account of the outcome of the public consultation TEIAS decides to proceed
with the issue, the report including such consultation outcome and the
recommendation on the applicability of the requirement under consideration to
Existing Demand Facilities or Existing Distribution Network Connections, shall be
forwarded within six months of the closure of the consultation to EMRA for decision.
8. The proposal by TEIAS to EMRA on applicability of any requirement of this
Regulation to Existing Demand Facilities or Existing Distribution Network
Connections shall include the following:
a) an operational notification procedure in order to prove the implementation of the
requirements by the Demand Facility Owner or Distribution Network Operator; and
b) an appropriate transition period for implementing the requirements which should
not exceed two years from the decision of EMRA on the applicability. The
determination of the transition period shall take into account the obstacles for
efficient undertaking of the equipment modification and replacement.
EMRA shall decide on the case within three months after the receipt of the report
including the recommendation of TEIAS. The decision of TEIAS on the applicability
of the requirement under consideration to Existing Demand Facilities or Existing
Distribution Network Connections and the decision of EMRA shall be published.
9. In case of a positive decision by EMRA, all relevant clauses in contracts and/or
relevant clauses in general terms and conditions relating to the Network connection of
Existing Demand Facilities or Existing Distribution Networks shall be amended to
179
achieve compliance with the requirements of this Regulation which shall apply to them
according to decision of EMRA. The relevant clauses shall be amended within three
years after the positive decision of EMRA on their applicability. This requirement for
amendment shall apply regardless of whether the relevant contracts or general terms
and conditions provide for such an amendment.
PART VI
Planning
SECTION 1
Principles of Planning and Related Parties
ARTICLE 161
Principles of Planning
[Previous Article 39] . [Addition, harmonization with ENTSO-E code OP&S Adequacy - Art 46. 1 & 2]
(1) Five-Year Production Capacity Projections will be annually prepared and published by
TEIAS based on the Electric Energy Demand Projections of Turkey prepared by the
Ministry. TEIAS shall assess the adequacy under various operational scenarios, taking into
account the required level of Active Power Reserves. When performing an Adequacy
analysis TEIAS shall use the latest Availability Plans and the latest available data for
capabilities of Power Generating Modules and their Availability Statuses and cross border
capacities; take into account contributions of Generation from Renewable Energy Sources;
and demand; assess the probability and expected duration of an absence of Adequacy and
the expected energy not served as a result of such a deviation
(2) Following the Ministry publishes the Electric Energy Demand Projection Report of
Turkey, TEIAS prepares and submits to the Ministry for approval a Long-Term Electric
Energy Generation Development Plan in order to use in determination of the energy
policies, considering the demand forecast covering the next twenty years, existing supply
potential, potential supply opportunities, fuel sources, structure and development plans of
transmission and distribution system, import or export opportunities, and resource diversity
policies. This plan is published by the Ministry following its approval. When a Long-Term
Electric Energy Generation Development Plan is prepared; the possibility of not meeting
the load shall be considered to be annually 2% or less which means not meeting the peak
load for totally seven days in a year.
(3) The Short-Term Electric Energy Supply-Demand Projections will be put into report
form by TEIAS with participation of all related institutions and organizations under the
coordination of the Ministry for sharing with the public.
[New Article, harmonization with ENTSO-E code OP&S - Adequacy - Art 47.5]
(4) TEIAS shall monitor the quality of the summer and winter Generation Adequacy
outlooks
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[New Article, harmonization with ENTSO-E code OP&S - Adequacy - Art 48.2]
(5) TEIAS shall perform an updated Responsibility Area Adequacy assessment
when it considers the changes observed to be significant in light of maintaining Adequacy
[New Article, harmonization with ENTSO-E code OP&S - Adequacy - Art 49.1]
(6)TEIAS shall perform a Responsibility Area Adequacy analysis on a D-1 and
intraday basis by using:
a)Market Participant Schedules in accordance with the applicable national legal
framework;
b) forecasted demand;
c) forecasted Generation from Renewable Energy Sources;
d) Active Power Reserves;
e) cross border capacities consistent with Cross Zonal Capacities;
f) capabilities of Power Generating Modules and their Availability Statuses;
g)capabilities of Demand Units with Demand Side Response and their Availability
Statuses
[New Article, harmonization with ENTSO-E code OP&S - Adequacy - Art 49.2]
(7) TEIAS shall evaluate:
a) the maximum level of import and export capacity compatible with its
Responsibility Area Adequacy;
b) the expected duration of a potential absence of Adequacy; and
c) the expected energy not served in the absence of Adequacy
[New Article, harmonization with ENTSO-E code OP&S - Adequacy - Art 49.3]
(8) If Adequacy is not fulfilled, TEIAS shall inform EMRA. TEIAS shall
provide EMRA with an analysis of the causes of the absence of Adequacy as soon as
reasonably practicable
ARTICLE 162
Parties subject to planning
[Previous Article 40]
(1) Principles of planning concerning the transmission system development are
applied to;
a) TEIAS,
b) Legal entities engaged in generation, and,
c) Distribution companies.
ARTICLE 163
Responsibilities of parties subject to planning
[Previous Article 41]
(1) The detailed and standard planning data included in the Annex-11 shall be
submitted to TEIAS by the parties subject to planning by the dates specified in the
Annex-11.
181
(2) The standard planning data sent by the parties shall be recorded by TEIAS.
This data shall be used in the studies carried out by TEIAS and may be provided to the
relevant public institutions and organizations, provided that it will not be shared with
third parties.
(3) The parties are obliged to report the standard planning data to TEIAS
completely and timely.
(4) Where there is no change in the data with respect to the previous year,
TEIAS is informed by the user in writing of the condition that there is no change in the
data between the current and the previous year.
(5) For new applications regarding connection to and/or use of system, standard
planning data is presented to TEIAS.
SECTION 2
Plans and Projections
ARTICLE 164
Generation capacity projection and short-term
electric energy supply-demand projection
[Previous Article 42]
(1) According to the demand projections prepared by distribution companies
and concluded by TEİAS and approved by the Board, TEIAS prepares the Generation
Capacity Projection including the five-year projection in order that the electric energy
demand can be met in a quality, continuous and reliable way, and the License Holders
are guided.
(2) The Generation Capacity Projection includes the following sections: actual
demand, demand development for the following five calendar years, existing
generation system, generation capacity development for the five calendar years, and
supply-demand balance.
(3) The Demand development part of The Generation Capacity Projection
contains:
a) The loss/leakage quantity and ratios and demand forecast of the
previous year that are prepared by distribution companies, concluded by
TEİAS and approved by the Board
b) The development of the demand in sectorial basis,
c) The analysis of the comparison of the physical realization of the
previous year, with demand forecasts,
ç) The data regarding the peak demand and the main factors effecting
the demand.
(3) The Generation part of The Generation Capacity Projection contains:
a) The fuel type of previous year and the total installed energy power in
Turkey, available capacity and generation quantity,
b) The fuel type of previous year and the total commissioned energy
power in Turkey, available capacity and generation quantity,
c) The required increase in yearly basis of the Maximum Capacity and
available capacity in order to ensure the demand reliability,
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d) The imported and exported energy quantity in previous year,
e) The Power Generating Facilities that were out of service during the
previous year and their capacities,
f) The generation quantity and out of service duration of the Power
Generating Facilities that are expected to be out of service more than a
year.
(4) The possible scenarios of demand-supply balance of generation part of the
projection are based on following data: the available capacity in last 3 years of the
Power Generating Facilities, the capacity data of the existing plants are used for the
plants to be commissioned.
(5) The demand forecasts of The Ministry of Energy and Natural Resources are
used for Generation Capacity Projection if the demand forecasts prepared by the
Distribution companies are not submitted to TEİAS before 31st March of the year.
(6) If the b), c), ç) articles of the 3rd paragraph are not included in demand
forecasts that are submitted to TEİAS on time, the Generation Capacity Projection is
prepared excluding these analysis.
(7) The Short-term Electric Energy Supply-Demand Projection includes the
data and charts regarding the electricity energy generation, and consumption in
Turkey, peak demand, available capacity and water for the next year.
ARTICLE 165
The Long-Term Electric Energy Generation
Development Plan
[Previous Article 43]
(1) The Long-Term Electric Energy Generation Development Plan contains the
following:
a) Acknowledgements and assumptions taken into account and methodology
used in the study,
b)
Existing system at the beginning of the planning period,
c)
Source potential and candidate Power Generating Facilities,
ç)
Electric energy and peak power demand forecasts for 20 years,
d)
Electric energy supply-demand balance for 20 years,
e) Fuel consumption forecasts for 20 years,
f) Development of the Maximum Capacity and generation,
g) Emission values of the thermal Power Generating Facilities according to their
production,
ğ) Results related to the system reliability,
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SECTION 3
Planning Data
ARTICLE 166
Data to be prepared
[Previous Article 44]
(1) Planning data, as it is in the Appendix-11, consists of two types; standard
and detailed.
(2) Standard planning data is prepared periodically by the users while the
detailed planning data is prepared upon TEIAS’s request.
(4) Planning data follows the following levels according to the development
phases of the project;
a)
Preliminary project data,
b)
Committed project data,
c)
Contracted project data.
ARTICLE 167
Preliminary project data
[Previous Article 45]
(1) Information and documents concerning the user’s connection to and/or use
of the transmission system are accepted to be project preliminary data until connection
and/or use of system agreement is signed. Data at this level is confidential and cannot
be disclosed to third parties by TEIAS until further levels have been reached.
(2) Under normal conditions, project preliminary data only consists of standard
planning data. Detailed planning data is also included in the preliminary project data in
order to perform more detailed transmission system analysis where requested by
TEIAS.
ARTICLE 168
Committed project data
[Previous Article 46]
(1) Additional data requested by TEIAS along with data that has been
submitted as project preliminary data following the signing of the connection to and/or
use of system agreement are accepted as committed project data. This data along with
other data belonging to TEIAS are utilized to evaluate new applications, to prepare
Generation Capacity Projection and Transmission System Statement Reports and also
to plan investments.
(2) Committed project data consists of standard and detailed planning data.
(3) Committed project data cannot be disclosed to third parties except under the
following circumstances:
184
a) Preparatory works for the Long-term Electric Energy Development
Plan, Generation Capacity Projection, Short-term Electric Energy
Supply-Demand Projection and Transmission System Development
Report,
b) Operational planning purposes,
c) International interconnection works.
ARTICLE 169
Contracted project data
[Previous Article 47]
(1) Contracted project data can be exchanged with validated actual data before
connection to the transmission system is realized. Similarly, future data can be
exchanged with updated forecast data by taking into account demand as well. Data
provided at this phase will form the basis for the contracts and agreements between
parties.
(2) Contracted project data, along with other data of TEIAS, will form the basis for
evaluating new applications and transmission system planning.
(3) Contracted project data consists of standard and detailed planning data.
(5) Contracted project data cannot be disclosed to third parties except under the
following circumstances:
a)Preparatory works for the Long-term Electric Energy
Development Plan, Generation Capacity Projection, Short-term
Electric Energy Supply-Demand Projection and Transmission
System Development Report,
b)Operational planning purposes,
c)International interconnection works.
PART VII
Operating Rules
SECTION 1
Principles of Demand and Energy Forecast and Related Parties
ARTICLE 170
Principles of demand and energy forecast
[Previous Article 48]
(1) Demand and energy forecast is performed daily by meeting the criteria
concerning system integrity, security and quality of supply and also with information
obtained from parties subject to the relevant legislation which sets out the balancing
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and settlement procedures and in accordance with the system constraints and bids and
offers.
(2) Demand and energy forecasts are taken as a basis in the studies concerning
the transmission system, in the planned maintenance of generation, transmission and
distribution facilities, and in the coordination of outages of the Power Generating
Facilities.
ARTICLE 171
Parties subject to demand and energy forecast
[Previous Article 49]
(1) Principles of demand and energy forecast are applicable to;
a)
b)
c)
d)
TEIAS,
Distribution companies,
Legal entities that operate as Generation companies, and,
Eligible consumers that are directly connected to transmission system.
SECTION 2
Operational Planning
ARTICLE 172
Principles of operational planning
[Previous Article 50]
(1) Operational planning involves coordination by TEIAS of the outages for
maintenance, repair and construction of plant and equipment in accordance with the
demand and energy forecast.
(2) TEIAS performs operational planning through coordinating the planned
outage programs of the units between the parties which are subject to operational
planning and transmission system plant and equipment in order to minimize outages
that would adversely affect the system and to maintain continuous and reliable
fulfillment of demand.
(3) Operational planning includes the following situations that involve planned
outage of the units that are subject to the operational planning, transmission or distribution
system plant and equipment;
a) Situations where the availability of a unit subject to the
operational planning decreases because of any problem with
the generation services including a problem in the provision
of fuel,
b) Situations that adversely affect the availability of a standby
Power Generating Facility within normal modes of
operation,
c) Situations which constrain units subject to operational
planning from supplying of energy to the transmission
system,
d) Occurrence of the programmed disconnection of the plant
or equipment of the transmission system or the distribution
system.
186
[New Articles, harmonization with ENTSO-E code OP&S - Operational Security
Analysis in Operational Planning - Art 16]
(4) With regard to Operational Security Analyses on operational planning:
1) TEIAS shall perform coordinated Operational Security Analyses at
least at the following time horizons: Year-Ahead; D-1; and intraday
2) TEIAS shall perform Operational Security Analyses for Year-Ahead,
D-1 and intraday in N-Situation by simulating each Contingency from
the Contingency List and verifying that the Operational Security Limits
in the (N-1)-Situation are not exceeded
3) When simulating each Contingency, TEIAS shall take into account
the capabilities of the Significant Grid Users.
[New Articles, harmonization with ENTSO-E code OP&S - Operational Security
Analysis in Operational Planning - Art 17]
4) TEIAS shall perform Operational Security Analyses for assessing that
the Operational Security Limits of its Responsibility Area are not
exceeded, taking into account all the Contingencies from its
Contingency List and using the applicable Common Grid Models.
5) TEIAS shall perform Operational Security Analyses, in accordance
with the coordination methodology of ENTSO-E in order to detect at
least the following Network Constraints:
a) power flows and voltages over Operational Security Limits;
b) breaches of Stability Limits of the Transmission System; and
c) violation of short-circuit thresholds of the Transmission
System.
6) When, as a result of Operational Security Analysis, TEIAS detects
possible Constraints, it shall prepare, with concerned TSOs, and if
applicable with affected DSOs or Significant Grid Users, and if
available, Non Costly Remedial Actions to solve the Constraint. If these
are not available, this shall be considered an Outage Incompatibility and
a coordination process shall be initiated.
[New Article, harmonization with ENTSO-E code OP&S - Operational Security
Analysis in Operational Planning - Art 19.3]
7) TEIAS shall apply the methodology for coordinating Operational
Security Analysis established for the Synchronous Area ENTSO-E
Continental Europe, starting from a date agreed on ENTSO-E level.
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[New Article, harmonization with ENTSO-E code CACM - Art 21 Individual Grid
Model]
(5) TEIAS shall provide all necessary data in the Individual Grid Model to
allow active and reactive power flow and voltage analyses in steady state.
[New Article, harmonization with ENTSO-E code CACM - Art 33 Creation of the
Common Grid Model]
(6) For each Capacity Calculation Timeframe, each Power Generating Facility
or load unit included in the generation and load data provision methodology shall
provide the data specified in the generation and load data provision methodology
within the specified deadlines to TEIAS.
Each Power Generating Facility or load unit providing information shall deliver the
most reliable set of estimations practicable.
[New Article, harmonization with ENTSO-E code CACM - Art 34 Regional
Calculation of Cross Zonal Capacity]
(7) TEIAS shall perform an operational security analysis applying operational
security limits by using the Common Grid Model created for each scenario.
ARTICLE 173
Parties subject to operational planning
[Previous Article 51]
(1) Principles of operational planning are applicable to;
a) TEIAS,
b) Distribution companies,
c) Legal entities directly connected to the transmission system that operate as
Generation companies,
ç) Eligible consumers that are directly connected to the transmission system.
ARTICLE 174
Principles of programmed outages
[Previous Article 52]
(1) Power Generating Facilities located between the parties which are subject to
operational planning should submit their requests for outages of their plant and
equipment for the next year to TEIAS by 30 April of the current year. The information
submitted to TEIAS must apply to each generating unit and include weekly availability
for Years 1 and 2. This notification includes also the availabilities of the units. These
requests are included also in the plan which will be prepared by TEIAS. The
notifications made in compliance with the template requested shall be included into the
plan to be drawn up by TEIAS for the Power Generating Facilities at the Maximum
Capacity to be determined by TEIAS or above. This notification includes also the
availabilities of the units.
(2) TEIAS shall conduct an analysis of plant margins for the next year taking
into account transmission system constraints by 31 May every year. TEIAS shall on
the basis of this analysis prepare the first draft of the annual plan and suggest changes
(if any) to the relevant party in writing until 30 June. The relevant party may object to
188
the TEIAS’s change proposals by 31st day of July, and they shall notify TEIAS about
their alternative suggestions regarding their objections by August 31st.
(3) TEIAS prepares the first draft of the annual report by 30 September after
negotiations with users on suggested changes and notifies any changes to the relevant
party whose outage programs are revised.
(4) The annual plan prepared for the next year is finalized by 31 October. This
information regarding the outages of plants subject to balancing system will be
reviewed by TEIAS within confidentiality rules until the annual plan has been
finalized.
(5) Once a maintenance outage included in the final annual outage plan is
approved by TEIAS, it may only be changed;
a)
by notice from TEIAS prior to the commencement of the outage,
for reasons of security of supply or security of the power system or
safety of user’s staff or public safety,
b)
by TEIAS’s approval following a request by the user for reasons
of security of supply or economics of operation,
c)
by agreement between TEIAS and a User where only that user is
affected by the proposed changes.
(6) The users must comply with the final operation planning that is approved by
TEIAS.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 22. Regional coordination procedure]
(7) TEIAS shall provide all DSOs of Transmission Connected Distribution
Networks located in its Responsibility Area with all relevant information at its disposal on
the Transmission System related infrastructure projects that impact on the operation of the
Distribution Network of these DSOs. TEIAS shall provide all CDSOs of Transmission
Connected Closed Distribution Networks located in its Responsibility Area with all
relevant information at its disposal on the Transmission System related infrastructure
projects that impact on the operation of the Closed Distribution Network of these CDSOs
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 24. List of Relevant Power Generating Modules and Relevant
Demand Facilities]
(8) TEIAS shall apply the coordinated methodology for ENTSO-E RGCE, starting
from a date agreed on ENTSO-E level, to assess the relevance of Power Generating
Modules and Demand Facilities for the Outage Coordination Process.
TEIAS shall participate to the establishment of a single list of Relevant Power Generating
Modules and Relevant Demand Facilities for the Outage Coordination Process, starting
from a date agreed on ENTSO-E level.
The list of Relevant Power Generating Modules and Relevant Demand Facilities shall
contain all Power Generating Modules and Demand Facilities for which the Availability
Status impacts on another Responsibility Area to a level beyond the thresholds defined in
the methodology.
189
TEIAS shall inform EMRA of the list of Relevant Power Generating Modules and
Relevant Demand Facilities.
For every Relevant Power Generating Module and every Relevant Demand Facility,
TEIAS shall:
a) inform the owners of the Relevant Power Generating Modules and the Relevant
Demand Facilities about their inclusion in the list;
b) inform DSOs on the Relevant Power Generating Modules and the Relevant
Demand Facilities for which they are the Connecting DSO; and
c) inform CDSOs on the Relevant Power Generating Modules and the Relevant
Demand Facilities for which they are the Connecting CDSO.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 25. Re-assessment of the list of Relevant Power Generating
Modules and Relevant Demand Facilities]
(9) Before 1 July of each calendar year, TEIAS shall re-apply the methodology for
assessing the relevance of Power Generating Modules and Demand Facilities for the
Outage Coordination Process.
When TEIAS identifies a need to update the list of Relevant Power Generating
Modules and Relevant Demand Facilities, it shall update this list as soon as reasonably
practicable and shall make the updated list available
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 26. List of Relevant Grid Elements]
(10) TEIAS shall apply the coordinated ENTSO-E RGCE methodology for assessing the
relevance of grid elements located in a Transmission System, in a Distribution Network, or in a
Closed Distribution Network for the Outage Coordination Process, starting from a date agreed on
ENTSO-E level.
The list of Relevant Grid Elements shall contain the types of information which shall
be provided by TEIAS to the ENTSO-E Operational Planning Data Environment,
including at least:
a) the reason for every unavailable status of a Relevant Grid Element;
b) specific conditions that need to be fulfilled before executing an
unavailable status of a Relevant Grid Element; and
c) the time required to restore a Relevant Grid Element to service if necessary to
maintain Operational Security.TEIAS shall inform EMRA of the list of
Relevant Grid Elements.
190
For every Relevant Grid Element, TEIAS shall:
a) inform the owners and the operators of the Relevant Grid Elements
about their inclusion in the list;
b) inform DSOs of the Relevant Grid Elements for which they are the
Connecting DSO; and
c) inform CDSOs of the Relevant Grid Elements for which they are the
Connecting CDSO.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 27. Re-assessment of the list of Relevant Grid Elements]
(11) Before 1 July of each calendar year, TEIAS shall re-apply the methodology for
assessing the relevance of grid elements located in a Transmission System, in a
Distribution Network, or in a Closed Distribution Network for the Outage Coordination
Process. When TEIAS identifies a need to update the list of Relevant Grid Elements, it
shall update this list as soon as reasonably practicable.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 28. Appointing Outage Planning Agents]
(12) For each Relevant Asset, the owner shall ensure that an Outage Planning
Agent is appointed. TEIAS is appointed as the Outage Planning Agent for every Relevant
Grid Element that is operated by TEIAS.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 29. Treatment of Relevant Assets located in a Distribution Network
or in a Closed Distribution Network]
(13) For the Relevant Assets that are located in a Distribution Network, TEIAS
shall coordinate the outage planning with the Connecting DSO. For the Relevant Assets
that are located in a Closed Distribution Network, TEIAS shall coordinate the outage
planning with the Connecting CDSO.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 32. General provisions on Availability Plans]
(14) The Availability Plans shall contain a separate Availability Status for each
Relevant Asset with at least an hourly granularity.
On the timeframes when Generation Schedules and Consumption Schedules are submitted
to TEIAS, Availability Plans shall have a time granularity consistent with Generation
Schedules and Consumption Schedules.
The Availability Status shall be one of the following three states: available; unavailable;
testing.
The Availability Status “testing” shall only be used when there is a potential impact on the
Transmission System, and shall be limited to the time periods between first connection and
final commissioning of the Relevant Asset; and directly following maintenance of the
Relevant Asset.
191
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 33. Long-term indicative Availability Plans]
(15) Two years prior to the start of the Year-Ahead coordination process, TEIAS
shall assess the indicative Availability Plans for Relevant Assets, provided by the Outage
Planning Agents.
Following this assessment, TEIAS shall provide its preliminary comments, including
detected Outage Incompatibilities, to all impacted Outage Planning Agents.
The assessment of TEIAS shall be repeated every 12 months until the start of the YearAhead coordination process.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 42. Detailing the testing status of Relevant Assets]
(16) The Outage Planning Agent of a Relevant Asset for which the testing
Availability Status is declared shall provide TEIAS, and if connected to a Distribution
Network or to a Closed Distribution Network also the Connecting DSO or the Connecting
CDSO respectively, as early as reasonably practicable, and no later than one month before
the start of the testing Availability Status with:
a) a detailed test plan;
b) an indicative Generation or Consumption Schedule if the concerned
Relevant Asset is a Power Generating Module or a Demand Facility; and
c) changes to the Transmission System or Distribution Network Topology if
the concerned Relevant Asset is a Relevant Grid Element.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 44. Real-time execution of the Availability Plans]
(17) Each Power Generating Module Owner shall ensure that all Relevant Power
Generating Modules under its responsibility which are declared available are ready to
produce electricity pursuant to their declared technical capabilities when necessary to
maintain Operational Security, except in case of Forced Outages.
Each Relevant Grid Element owner shall ensure that all Relevant Grid Elements under
its responsibility that were declared available, are ready to transport electricity
pursuant to their declared technical capabilities when necessary to maintain
Operational Security, except in case of Forced Outages.
Upon the request from TEIAS before executing a planned test of Relevant Assets
which puts the Transmission System out of Normal State, each concerned party shall
delay the corresponding test according to the instructions of TEIAS to the extent
possible while respecting the technical and safety limits.
ARTICLE 175
Outage planning procedures for the current year
[Previous Article 53]
(1) Outage planning procedures for the current year are prepared based on;
a) By 11.00 AM each business day, each generating legal entity shall
notify NLDC in writing the forecast return to service of any of their units
192
under planned outage, unplanned outage, forced outage or breakdown for
the period from Day 2 ahead to Day 14 ahead and each distribution
company shall notify NLDC in writing with corresponding information
relating to its distribution system.
b) Between 11.00 AM to 16.00 PM each business day, NLDC shall
analyze the upper and lower limits of actual generation capacity, taking
account both the transmission and the distribution systems’ planned
outages, transmission and distribution constraints and including a
reasonable contingency allowance for generating unit breakdowns.
c) NLDC shall notify the postponement request to generating legal
entities and distribution companies in writing if it is understood as a result
of the analysis performed that the existing availabilities lead to plant
margin shortfalls within the period from Day 2 ahead to Day 14 ahead.
[Addition to the Article, harmonization with ENTSO-E code OP&S - NC OP&S Outage Coordination - Art 41. Updates to the Year-Ahead Availability Plans - 2]
d) in the event that Outage Incompatibilities are detected, initiate a
coordination process involving users, Connecting DSOs, and Connecting
CDSOs for the Relevant Assets of which the Availability Status is
impacted; incorporate the validated change request in the coordinated
Availability Plan and notify all impacted parties; and update the
ENTSO-E Operational Planning Data Environment, if the change
request is validated.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 36. Year-Ahead coordination of the Availability Status of Relevant
Assets for which the Outage Planning Agent is an Outage Coordinating TSO, DSO or
CDSO]
(2) TEIAS shall coordinate the Availability Status of Relevant Grid Elements
interconnecting different Responsibility Areas and for which it is an Outage Planning
Agent with other TSOs on borders within ENTSO-E area in accordance with the
following principles: minimizing the impact on the market while preserving
Operational Security; and using as a basis the proposed Availability Plans for Relevant
Assets.
a) TEIAS, each DSO and each CDSO shall plan the Availability Status of the
Relevant Grid Elements for which they are the Outage Planning Agent.
b) In case of Outage Incompatibilities, TEIAS shall be entitled to propose a
change to the proposed Availability Plans of the Relevant Assets for which
the Outage Planning Agent is not an Outage Coordinating TSO, DSO or
CDSO and shall in this event initiate coordination with the concerned
Outage Planning Agents.
c) In the event that a DSO or CDSO has been unable to plan the “unavailable”
Availability Status of a Relevant Grid Element, this DSO or CDSO shall
report to TEIAS. In this case or if TEIAS has been unable to plan the
193
“unavailable” Availability Status of a Relevant Grid Element, TEIAS and
all affected Outage Planning Agents shall use all available economically
efficient and feasible means under their control to plan the “unavailable”
Availability Status of the Relevant Grid Element.
d) In the event that the unavailable Availability Status of the Relevant Grid
Element has not been planned, and if in the reasoned opinion of TEIAS, not
planning this unavailable Availability Status would threaten Operational
Security, TEIAS shall:
i. take such actions as it deems necessary to plan this unavailable
Availability Status while ensuring Operational Security, taking into
account the impact reported to TEIAS by affected Outage Planning
Agents;
ii. provide a notification of these actions to all affected parties; and
iii. inform EMRA and the affected DSO or CDSO if any, and the
affected Outage Planning Agents of the actions taken, the impact
reported to TEIAS by affected Outage Planning Agents, the threats
which required such actions to be taken and the rationale for using
the chosen actions.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 38. Validation of Year-Ahead Availability Plans within Outage
Coordination Regions]
(3) TEIAS shall analyze whether Outage Incompatibilities arise when
combining all preliminary Availability Plans impacting its Responsibility Area.
a) In the event that Outage Incompatibilities impacting the Year-Ahead
Availability Plans for Relevant Assets are identified, TEIAS shall
coordinate with the concerned Outage Planning Agents, DSOs, CDSOs
and/or other TSOs on borders within ENTSO-E area to find a solution.
b) Once a solution is found for each Outage Incompatibility, TEIAS shall
validate the Year-Ahead Availability Plans for all Relevant Grid
Elements for which the Outage Planning Agent is TEIAS, or an Outage
Coordinating DSO or CDSO.
[New Article, harmonization with ENTSO-E code OP&S – Outage Coordination - Art
41. Updates to the Year-Ahead Availability Plans - 1]
(4) After the finalization of the Year-Ahead coordination process and before
real-time execution, all Outage Planning Agents shall have the right to initiate an
adaptation of the coordinated Availability Plan.
[New Article, harmonization with ENTSO-E code OP&S – Outage Coordination - Art
41. Updates to the Year-Ahead Availability Plans – 3&4]
(5) If TEIAS initiates an adaptation of the coordinated Availability Plan of
Relevant Grid Elements it shall follow the following procedure:
194
a) assess as soon as reasonably practicable whether Outage
Incompatibilities arise as a result of this change to the
coordinated Availability Plan of Relevant Assets;
b) send a change request and report detected Outage
Incompatibilities to all impacted TSOs;
c) consider additional Outage Incompatibilities related to the
change request detected by other TSOs;
d) in the event that Outage Incompatibilities are detected, initiate
a coordination process involving Outage Planning Agents,
affected Outage Coordinating TSOs on borders within ENTSO-E
area, Connecting DSOs, and Connecting CDSOs for the Relevant
Assets of which the Availability Status is impacted;
e) receive a reasoned decision on the change request from all
parties that are impacted by the adaptation of the coordinated
Availability Plan at the end of the coordination process,
validating the change request when no Outage Incompatibility is
detected or no Outage Incompatibility remains after coordination
and rejecting the change request when not all of the detected
Outage Incompatibilities can be relieved after coordination;
f) incorporate the validated change request in the coordinated
Availability Plan and notify all impacted parties; and
g) update the ENTSO-E operational planning data environment if
the change request is validated.
(6) In the event that TEIAS detects that Outage Incompatibilities arise, it shall
initiate a coordination process involving all Outage Planning Agents, affected TSOs
on borders within ENTSO-E area, Connecting DSOs, and Connecting CDSOs for the
Relevant Assets of which the Availability Status is impacted
ARTICLE 176
Short term planned outages
[Previous Article 54]
(1) Short term planned outages are scheduled outages which are not
included in the final annual outage plan, but agreed on and have a planned start time
and duration.
(2) For outages of less than eight hours, the notification period should be
not less than twenty-four hours notice.
(3) For outages from eight hours duration up to forty-eight hours duration,
the notification period should be not less than seven calendar days notice.
195
[New Article, harmonization with ENTSO-E code OP&S - Operational Security
Analysis in Operational Planning - Art 18.4]
(4) On a D-1 and intraday basis, if Constraints are detected by TEIAS, it
shall evaluate the effectiveness of joint Remedial Actions with other TSOs on borders
within ENTSO-E area and the technical-economic efficiency of the joint Remedial
Action.
ARTICLE 177
Notified unplanned outages
[Previous Article 55]
(1) Where due to unavoidable circumstances of their plants and equipment, a
user needs to arrange an outage, then the parties which are subject to the operational
planning must include in his written notification to TEIAS:
a) Full details of all plant and/or equipment affected including any
restrictions in availability,
b)The expected date and start time of the unplanned outage,
d) The estimated return to service time and date, of the plant and/or
equipment affected and the time and date of the removal of any
temporary capacity restrictions,
ç) Details of any restrictions, or risk of trip, on other plant and
equipment caused by the unplanned outage.
(2) TEIAS may request the user to advance or defer an unplanned outage where in
the opinion of TEIAS the unplanned outage would adversely affect the security of the
power system. If the user agrees to this alteration then it will send written confirmation to
TEIAS of the new suggestion regarding the unplanned outage dates.
[New Article, harmonization with ENTSO-E code OP&S - NC OP&S - Outage
Coordination - Art 40. Coordination processes in case of detected Outage
Incompatibilities]
(3) For all Outage Planning Agents involved in the coordination process, TEIAS
shall conduct the process of detected Outage Incompatibilities for the Relevant Assets of
the Outage Planning Agents located in its Responsibility Area in line with the applicable
national legal framework.
(4) TEIAS shall use the means at its disposal according to the applicable national
legal framework to find a solution for the detected Outage Incompatibilities
ARTICLE 178
Forced outages
[Previous Article 56]
(1) Plants and/or equipment of TEIAS and users must operate as connected to
the grid during the minimum time corresponding to the frequency range set out in the
paragraph eight of the ARTICLE 34 [previous Article 20] of this Regulation.
196
(2) In the event that there is a forced outage, or a decrease in capacity, or
disconnection from the transmission or distribution system or there are transmission
constraints related to a plant or equipment which is subject to operational planning
without the prior agreement of TEIAS, then the user shall immediately notify TEIAS
of the event.
(3) The user must provide its best estimate of the likely duration of the forced
outage of his plant and equipment and such reasonable data as TEIAS requires.
Information regarding the outage shall be notified to TEIAS as soon as practicable as
they get more clear.
ARTICLE 179
Data requirements
[Previous Article 57]
(1) Each legal entity that is subject to the operational planning, shall notify to
TEIAS by 31 March in each calendar year data relating to their units such as; any
changes to the operating characteristics with respect to the previous year, the technical
specifications of the unit transformer and the unit loading curve according to
Appendix-13 and the unit planning parameters according to Appendix-14.
(2) The legal entities which are engaged in generation activity and the system
users the switchyard of which does not belong to TEIAS are obliged to give the
information requested by TEIAS with regard to the system operation to TEIAS on a
daily basis within the period and in the manner determined by TEIAS.
[New Article, harmonization with ENTSO-E network code CACM, Art 16]
(3) TEIAS shall publish no later than two months after the approval by EMRA:
(a) a list of entities required to provide load and generation information
for capacity calculation to TEIAS;
(b) a list of information to be provided; and
(c) deadlines for providing information.
ARTICLE 180
Data publication obligation of TEIAS
[Previous Article 58]
(1) TEIAS shall use the necessary internet tools to announce any planned,
unplanned or forced outage conditions reported to TEIAS within the scope of this
section as soon as possible once TEIAS has been informed.
SECTION 3
Operating Reserves Planning
ARTICLE 181
Principles of operating reserves planning
[Previous Article 59]
197
(1) During system operation, TEIAS plans the adequate generation capacity which
make up operating reserves to comply with this Regulation.
(2) Operating reserves established for system operation are utilized for the
purpose of balancing supply and demand real-timely in the system.
ARTICLE 182
Parties subject to operating reserves planning
[Previous Article 60]
(1) Operating reserves planning principles apply to;
a)
b)
c)
d)
TEIAS,
TETAŞ,
Legal entities that operate as Generation companies, and,
Distribution companies.
ARTICLE 183
Operating reserves
[Previous Article 61]
(1) Operating reserve is that additional output available from units in service
and/or units that can return to service within times determined by the System Operator
in order to contribute correction of the system frequency deviations and ensuring
system stability. Operating reserve consists of the following reserves:
a) Primary frequency control reserve is the part of the operating reserve used in
order to keep the system frequency under the target operating conditions by
automatically using the turbine speed governors and provided to be sufficient for
this purpose pursuant to the Regulation on Electricity Market Ancillary Services.
The primary frequency control reserve needed by the system is determined by
TEIAS within a certain tolerance and considering the principles set out by
ENTSO-E. Primary frequency control reserve must be continuously ensured. It
should be noted that the primary frequency control reserve must be distributed in
a balanced manner on the basis of Power Generating Modules and regions.
b) Secondary frequency control reserve is the part of the operating reserve used
through the automatic generation control program and provided to be sufficient
for this purpose pursuant to the Regulation on Electricity Market Ancillary
Services in order that the primary frequency control reserve used for frequency
control is released, and the frequency can return to its nominal value, and the total
electric energy exchange with the neighbouring electric grids can be kept at the
scheduled level. The secondary frequency control reserve needed by the system is
determined by TEIAS, considering the principles set out by ENTSO-E, at an
amount that will allow the primary frequency control reserve is released and that
the total electric energy exchange with the neighbouring electric grids can be kept
at the scheduled level. If the secondary frequency control reserve fails to meet
this need, a tertiary frequency control reserve may be used additionally. The
198
secondary frequency control reserve must be continuously ensured in order to use
both in possible deviations under the normal operating conditions and in the case
of any instability between generation and consumption due to a major failure.
c) Tertiary frequency control reserve is the part of the operating reserve
which is manually put into service when needed after activation of the
secondary frequency control reserve and selected to be sufficient for ensuring
that the secondary reserve can be released in the case of any other frequency
deviation. The tertiary frequency control reserve is provided by the output
power change that may be made by the balancing units within 15 minutes
through the load up and load down instructions given under the real-time
market.
ç) Standby reserve is an operating reserve provided by enabling a disabled
Power Generating Module in line with the instruction of NLDC when
necessary. The standby reserve is used in order to release the tertiary control
reserve or create a tertiary control reserve if it is insufficient when the
consumption is realized beyond the calculated demand forecasts due to the
unpredictable reasons such as uncertainties in availability of the Power
Generating Modules and unexpected changes in weather conditions. Such
reserves are provided by the units which are unsynchronized but available for
being synchronized within a time specified in the tender notice issued as per
the Electricity Market Ancillary Services Regulation.
(2) Activation order of the operating reserves should be as follows under the normal
operating conditions.
Tertiary Control
Secondary
Frequency Control
Primary Frequency
Control
30 sec
15 min
Time elapsed from the
frequency deviation
(3) When determining the amounts of operating reserves, TEIAS may use
ability to meet the needs of all islands as a criterion within the bounds of
technical possibilities in the event that the transmission system is split into
islands due to failures, if TEIAS considers it necessary.
ARTICLE 184
Reserve Dimensioning
[New Article, harmonization with ENTSO-E, LFC&R code Articles 46]
199
(1) TEIAS shall define Secondary and Tertiary Restoration Reserves Dimensioning
Rules by a date agreed with ENTSO-E.
(2) The Dimensioning Rules shall comprise at least the following requirements:
a) TEIAS shall determine the required Secondary and restoration Tertiary
Capacity of the LFC Block based on consecutive historical records at least
comprising historical ACE Open-Loop values. The sampling of these
historical records shall be at least the Time to Restore Frequency. The
considered time period of these records shall be representative and include
at least one full year period ending not earlier than 6 months prior to the
calculation;
b) TEIAS shall determine the Secondary and restoration Tertiary Capacity of
the LFC Block such that it is sufficient to respect the current ACE Target
Parameters in accordance with ARTICLE 186 [NC LFC&R Article 20] for
the considered historical period of time based at least on a probabilistic
methodology. In this methodology, restrictions due to agreements for the
Sharing or Exchange of Reserves due to possible violations of Operational
Security and the Secondary and Tertiary Restoration Reserves Availability
Requirements shall be taken into account. TEIAS shall take expected
significant changes to the distribution its ACE Open-Loop or other relevant
influencing factors relative to the considered time period into account for
this determination;
c) TEIAS shall determine the ratio of Secondary Reserves Capacity, Tertiary
Restoration Reserve Capacity, the Secondary Reserve Full Activation Time
and Tertiary Restoration Reserve Full Activation Time such that
requirement (b) can be fulfilled. For this the Secondary Reserve Full
Activation Time of the LFC Block and the Tertiary Restoration Reserve
Full Activation Time of the LFC Block shall at most be the Time to Restore
Frequency.
d) TEIAS shall determine the size of its Dimensioning Incident. The
Dimensioning Incident shall be the largest imbalance that may result from
an instantaneous change of active power of a single Power Generating
Module, single Demand Facility, and single HVDC interconnector or from a
tripping of an AC-Line within the LFC Block.
e) TEIAS shall determine the positive Secondary and Tertiary Restoration
Reserves Capacity such that it is not smaller than the positive Dimensioning
Incident of the LFC Block;
f) TEIAS shall determine the negative Secondary and Tertiary Restoration
Reserves Capacity such that it is not smaller than the negative
Dimensioning Incident of the LFC Block;
g) TEIAS shall determine the Secondary and Tertiary Restoration Reserves
Capacity of a LFC Block and possible geographical limitations for its
distribution within the LFC Block and possible geographical limitations for
any Exchange of Reserves or Sharing of Reserves with other LFC Blocks to
respect the Operational Security;
200
h) TEIAS shall ensure that the positive Secondary and Tertiary Restoration
Reserves Capacity or a combination of Secondary and Tertiary Restoration
Reserves and Tertiary Replacement Reserve Capacity is sufficient to cover
the positive ACE Open-Loop in at least 99 % of the time based on the
historical record as defined in (a);
i) TEIAS shall ensure that the negative Secondary and Tertiary Restoration
Reserves Capacity or a combination of Secondary and Tertiary Restoration
Reserves and Tertiary Replacement Reserve Capacity is sufficient to cover
the negative ACE Open-Loop in at least 99 % of the time based on the
historical record as defined in (a);
j) TEIAS is allowed to reduce the positive Secondary and Tertiary Restoration
Reserves Capacity of its LFC Block, resulting from the Secondary and
Tertiary Restoration Reserves Dimensioning Process, by concluding a
Secondary and Tertiary Restoration Reserves Sharing Agreement with other
LFC Blocks in accordance with the provisions of ARTICLE 241 (Exchange
and sharing of reserves). The reduction of the positive Secondary and
Tertiary Restoration Reserves Capacity :
i. is limited to the difference, if positive, between the size of the positive
Dimensioning Incident and the Secondary and Tertiary Restoration
Reserves Capacity required to cover the positive ACE Open-Loop in
99 % of the time based on historical records as defined in (a); and
ii. shall never exceed 30 % of the size of the positive Dimensioning
Incident.
k) TEIAS is allowed to reduce the negative Secondary and Tertiary
Restoration Reserves Capacity of the LFC Block, resulting from the
Secondary and Tertiary Restoration Reserves Dimensioning Process, by
concluding a Secondary and Tertiary Restoration Reserves Sharing
Agreement with other LFC Blocks in accordance with the provisions of
ARTICLE 241(Exchange and sharing of reserves). The reduction of the
negative Secondary and Tertiary Restoration Reserves Capacity :
i. Is limited to the difference, if positive, between the size of the negative
Dimensioning Incident and the Secondary and Tertiary Restoration
Reserves Capacity required to cover the Negative ACE Open-Loop in
99 % of time based on historical records as defined in (a); and
ii. shall never exceed 30 % of the size of the Negative Dimensioning
Incident.
(3) TEIAS shall have sufficient Secondary and Tertiary Restoration Reserves
Capacity according to the Secondary and Tertiary Restoration Reserves Dimensioning
Rules at any time. For the case of a severe risk of insufficient Secondary and Tertiary
Restoration Reserves Capacity an escalation procedure shall be defined by TEIAS.
ARTICLE 185
Data requirements
[Previous Article 62]
(1) The legal entities engaged in generation activities provide the services for
in-situ measurement and recording and reporting of the data specified by TEIAS with
201
respect to the related Power Generating Modules providing operating reserves in a
manner to be determined by TEIAS. The data specified by TEIAS and included in the
related ancillary service agreement is continuously measured and recorded as long as
the ancillary services subjecting to the agreement are provided, except for the failures,
planned or certain interventions.
(2) Data specified by TEIAS is recorded and reported by the legal entities
engaged in generation activities to TEIAS as per the provisions related to data
recording as set out in the Part Seven of this Regulation.
ARTICLE 186
ACE Quality indicators
[New Article, harmonization with ENTSO-E, LFC&R code Article 20]
(1) TEIAS shall define ACE Quality indicators in cooperation with ENTSO-E.
After a date agreed with ENTSO-E, these indicators shall include but not be limited to the
following requirements:
a) the number of 15 minutes time intervals per year outside Level 1 Range
calculated by ENTSO-Eon a yearly basis, proportionally to K-Factor, shall
be less than 30 % of the time intervals of the year; and
b) the number of 15 minutes time intervals per year outside the Level 2
Range calculated by ENTSO-E on a yearly basis, proportionally to KFactor, shall be less than 5 % of the time intervals of the year.
ARTICLE 187
System states related to System Frequency
[New Article, harmonization with ENTSO-E , LFC&R code Article 42 and NC OS Article
18 : Real-Time Data exchange between TSOs]
(1)TEIAS shall establish a real-time data exchange, in compliance with the
Interconnection Operating Agreements mentioned in ARTICLE 224, of:
a) the System State of the Transmission System; and
b) the real-time measurement data of the ACE of the LFC Block.
(2)TEIAS shall agree with the other TSOs of the Synchronous Area common rules
for the operation of Load-Frequency Control in Normal State and Alert State (Synchronous
Area Operational Agreement).
(3)TEIAS shall reduce the ACE of the LFC Block by activation of Active Power
Reserves and if necessary by application of the actions as defined in (10).
(4)TEIAS shall define operational procedures for the case of exhausted Secondary
and Tertiary Reserves. For these procedures TEIAS shall have the right to require changes
in the Active Power production or consumption of Power Generating Modules and
Demand Units.
(5) TEIAS shall make reasonable endeavours to avoid ACE persisting for more
than the Time to Restore Frequency.
202
(6) For the case of an Alert State due to a violation of System Frequency limits,
TEIAS shall agree with the other TSOs of the Synchronous Area CE operational
procedures to reduce the System Frequency Deviation, to restore the System State to
Normal State and to limit the risk to enter into Emergency State. For these actions TEIAS
shall define procedures for which TEIAS shall have the right to deviate from the obligation
related to the Frequency Restoration Process in Normal State.
(7) In case of an Alert State due to there being insufficient Active Power Reserves
according to ARTICLE 30 (11) [Harmonized with NC OS Article 8] to meet the
requirements of TEIAS, TEIAS shall in close cooperation with the other TSOs of the
Synchronous Area and TSOs of other Synchronous Areas act to restore and replace
necessary levels of Active Power Reserves. For this purpose TEIAS shall have the right to
require changes in the Active Power production or consumption of Power Generating
Modules or Demand Units within its area with the aim to reduce or to eliminate the
violation of Active Power Reserve requirements.
(8) For the case the 1-minute average of the ACE of the LFC Block is above the
Level 2 Range for at least the Time to Restore Frequency and in case the ACE is not
expected to be reduced sufficiently by the actions defined in (10) TEIAS shall have the
right to require changes in the Active Power production or consumption of Power
Generating Modules and Demand Units within its area with the aim to reduce the ACE.
(9) For the case the ACE of TEIAS exceeds 25 % of the Reference Incident of the
Synchronous Area for more than 30 consecutive minutes and in case the ACE is not
expected to be reduced sufficiently by the actions defined in (10) TEIAS shall require
changes in the Active Power production or consumption of Power Generating Modules and
Demand Units within its area with the aim to reduce the ACE.
(10) For the cases as specified in (6) to (9) TEIAS shall agree with the other TSOs
of the Synchronous Area actions to enable the TSOs of a LFC Block to actively reduce the
Frequency Deviation by cross-border activation of reserves.
ARTICLE 188
Grid
Reserve Providing units connected to the DSO
[New Article, harmonization with ENTSO-E LFC&R code Article 68]
(1)TEIAS shall have the right to set cooperation with DSOs for reserve providing units
connected to the DSO grids whenever needed. This cooperation shall be as follows.
a. TEIAS and DSOs shall collaborate and use reasonable endeavours to facilitate
and enable the delivery of Active Power Reserves by Reserve Providing Groups
or Reserve Providing Units located in Distribution Networks.
b. The Reserve Connecting DSO and each intermediate DSO shall process the
application of a Reserve Providing Unit or Reserve Providing Group connected
to its Distribution Network within 2 months after provision of the notification
and all the required information including:
i. voltage levels and Connection Points of the Reserve Providing Units or
Groups;
ii. the type of Active Power Reserves;
203
iii. the maximum Reserve Capacity provided by the Reserve Providing
Units or Groups at each Connection Point; and
iv. the maximum rate of change of Active Power for the Reserve Providing
Units or Groups.
c. During the Prequalification of a Reserve Providing Unit or Reserve Providing
Group connected to its Distribution Network and in accordance with applicable
legislation each Reserve Connecting DSO and each intermediate DSO shall
have the right to set limits to or exclude the delivery of Active Power Reserves
located in its Distribution Network in cooperation with TEIAS and in a nondiscriminatory and transparent way based on technical arguments such as the
geographical distribution of the Reserve Providing Units and Reserve Providing
Groups.
d. In accordance with applicable legislation each Reserve Connecting DSO and
each intermediate DSO shall have the right to set temporary limits at any point
in time before reserve activation in cooperation with TEIAS and in a nondiscriminatory and transparent way to the delivery of Active Power Reserves
located in its Distribution Network. The respective TSOs shall agree with its
Reserve Connecting DSOs and intermediate DSOs on the applicable
procedures.
e. In accordance with applicable legislation, the respective TSOs shall agree with
its Reserve Connecting DSOs and intermediate DSOs on procedures and
methodologies for the information exchange required in relation to
Prequalification and the delivery of Active Power Reserves, including the
notification of the Reserve Connecting DSO and intermediate DSOs.
SECTION 4
Emergency Measures
ARTICLE 189
Principles related to the emergency measures
[Previous Article 63]
(1) Operating conditions are determined based on the system frequency. The
following operating conditions are defined according to the value range of the system
frequency (f):
a) Target operating conditions: 49.8 Hz ≤ f ≤50.2 Hz
b) Acceptable operating conditions: 49.5 Hz ≤ f < 49.8 Hz and
50.2 Hz < f ≤ 50.5 Hz
c) Critical operating conditions: 47.5Hz ≤ f < 49.5Hz and 50.5Hz < f ≤ 52.5Hz
d) Unstable operating conditions: f < 47.5 Hz and 52.5 Hz < f
(2) In the event that critical or unstable operation conditions occur due to the
insufficiency of the operating reserves in case of a decrease in the generation capacity
and/or fault-related trip and/or overloading in the transmission system, including the
international interconnection lines, or in the case of excessive voltage drops beyond
204
the voltage limits specified in the relevant articles of this Regulation, TEIAS and users
shall apply emergency measures as per the following principles:
a) Notification of emergency to the legal entities engaged in generation
activities within the scope of the relevant article of this Regulation,
b) Provision of instantaneous demand control service by the legal
entities having consumption facilities under the Electricity Market
Ancillary Services Regulation,
c) Automatic disconnection of the demand by the low frequency relays,
ç) Planned or unplanned interruption/reduction of demand by TEIAS.
(3)In the case of partial system crush or split or similar situations, the emergency
measures given in the second paragraph may be implemented in order to keep the system
frequency within the acceptable limits and maintain the operational safety.
[New Article, harmonization with ENTSO-E Policy 5 B. System Defence plan - Standards
- B-S5, 5.1, 5.2, B-S6, 6.1, 6.2, 6.3, 6.4, 6.4.1.1, 6.4.1.2]
(4) TEIAS shall provide maximal assistance through tie lines in case of an
emergency situation experienced by neighboring TSO in ENTSO-E and tie lines between
control areas are considered the backbone of the interconnected system, with respect to the
security of their systems, to limit the propagation of disturbance.
(5) Disconnection from the synchronous system will be considered the ultimate
remedial action and will only be undertaken after coordination with the neighboring TSOs
in ENTSO-E ensuring that this action will not endanger the remaining synchronous area:
● Keeping the interconnection in operation as long as possible is of utmost
importance, but shall be consistent with the operating constraints. Therefore any
manual emergency opening of tie lines shall be announced in advance, predefined
and duly prepared in a coordinated way with the neighboring TSO in ENTSO-E.
● Opening of a tie line has to be assessed and agreed upon in advance in a
transparent way; automatic opening may be performed when given events occur
and if certain thresholds are exceeded (e.g. overload damage of the equipment).
● Urgent opening can be carried out in case of physical danger to human beings or
installations without prior information to the involved neighboring TSOs in
ENTSO-E.
(6) In Emergency State, TEIAS shall undertake actions that cope with frequency
deviation, prevent further deterioration and contribute to quicker restoration to normal
operation according to the principles commonly defined at synchronous area level
ARTICLE 190
Parties subject to emergency measures
[Previous Article 64]
(1) Emergency measures set out under the ARTICLE 189 [previous Article 63]
apply to;
a) TEIAS,
b) Distribution companies and/or eligible consumers connected to the
distribution system,
205
c) Eligible consumers directly connected to the transmission system,
d) Legal entities having generation license.
ARTICLE 191
Emergency measures to be implemented in the
Power Generating Modules
[Previous Article 65]
NLDC and/or RLDC gives emergency notifications to the legal entities
engaged in generation activities and/or other users in order to protect the operational
security of the transmission system under emergency conditions. In respect of the
emergency notifications, the requirements of compliance of the instruction with the
offers submitted within the scope of the real-time market regarding the relevant
balancing unit shall not be sought. The System Operator may give emergency
instruction to any License Holder who is a balancing unit but have not submitted any
offer within the scope of the real-time market or who is not a balancing unit for the
related Power Generating Modules. The Users are obliged to comply with the
emergency notifications of NLDC and/or RLDC. If it is understood that a user will fail
to follow such instructions, that user shall immediately inform NLDC and/or RLDC
via communication means such as PYS or phone, fax, or pax.
ARTICLE 192
Instantaneous demand control
[Previous Article 66]
(1) Instantaneous demand control is ensured in addition to the primary
frequency control by disconnecting the loads of the consumption facilities using the
instantaneous demand control relays in order to prevent the frequency from dropping
to the level at which the low frequency relays work.
(2) Instantaneous demand control service is provided by the consumption
facilities within the scope of the ancillary service agreement related to the
instantaneous demand control service signed in accordance with the Electricity Market
Ancillary Services Regulation. In the event that the system frequency drops to a
frequency level determined by TEIAS according to the dynamic simulation and/or
system requirements, consumption of the consumption facilities within the scope of
the ancillary service agreement related to the instantaneous demand control service is
automatically disconnected by the instantaneous demand control relays.
(3) Instantaneous demand control service shall be obtained from the
consumption facilities determined to be qualified for providing instantaneous demand
control service according to the instantaneous demand control performance tests in
accordance with the procedures set out in the ANNEX-17 of this Regulation.
(4) The instantaneous demand control reserve is formed by the whole load
amount that is optionally proposed by the consumption facilities and can be
disconnected by the instantaneous demand control relays upon dropping of the system
frequency. The instantaneous demand control reserve is planned by TEIAS to be
engaged in addition to the primary frequency control reserve so as to prevent the
system frequency from dropping to the 49.0 Hz level. Accordingly, amount of the
instantaneous demand control reserve to be needed by the system is determined by
TEIAS.
206
ARTICLE 193
Forced
frequency relay
disconnection
of
demand
by
low
[Previous Article 67]
(1) Demand is automatically disconnected by means of low frequency relays in
the event of a fall in frequency to the frequency levels determined as 49.0, 48.8, 48.6,
48.4 Hz. If the system frequency drops to 49.0 Hz, 10% to 20% of demand is
automatically and forcedly disconnected. Amount of demand to be disconnected at
each frequency level following 49.0 Hz is determined by the System Operator
considering the technical requirements of the system users. TEIAS performs rotations
without any discrimination between equal parties every 4 months for demand to be
automatically disconnected by the low frequency relays.
(2) Automatic and forced disconnection of demand by low frequency relays is
performed for the purpose of eliminating a short-term supply-demand imbalance.
(3) The low frequency relays should be technically able to start in 100-150
milliseconds when the system frequency drops to a determined level. Sensitivity of the low
frequency relays should not exceed 0.05 Hz.
ARTICLE 194
Unplanned forced interruption/reduction
[Previous Article 68]
(1) In the event that any critical or instable operation condition beyond the
voltage limits as set out in the ARTICLE 189 [previous article 63] occurs in the whole
system or any important part thereof, unplanned forced interruption/reduction may be
applied if the system operator considers it necessary in order to avoid partial or general
system black-out.
ARTICLE 195
Planned forced interruption/reduction
[Previous Article 69]
(1) Planned forced interruption/reduction is applied without discrimination
between the equal parties in the case that any emergency stated in the ARTICLE 189
[previous article 63] of this Regulation occurs, including the necessary interruption
schedule to be implemented as a result of a demand reduction notification given by the
Market Operator within the scope of the relevant legislation which sets out the
balancing and settlement procedures. This application is performed alternately within
the framework of a schedule including interruption/reduction of the demands. In order
to employ this interruption/reduction method, it should be reasonably foreseen by
TEIAS that all other measures stated under the ARTICLE 189 would remain
insufficient, even if they all are implemented, and an emergency is likely to occur. If
necessary, the Authority may request the reasons which constitute a basis for such
foresights from TEIAS.
(2) TEIAS turns the demand reduction notification given by the Market
Operator into a planned forced interruption/reduction schedule which is applicable
within the framework of the procedure of emergency measures without changing the
total amount of interruption.
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ARTICLE 196
measures
Notification
of
procedure
for
emergency
[Previous Article 70]
(1) For the protection of the transmission system integrity, the Emergency
Measures Procedure covering various scenarios regarding the emergency measures
shall be prepared by TEIAS to open it for opinions in the official website.
(2) The procedure for emergency measures are to consist of two parts, namely
emergency notification and emergency measures. This procedure may be modified by
TEIAS when necessary, subject to Authority’s approval.
(3) Emergency notifications sent by TEIAS to users are as follows:
a) When it is necessary to implement emergency measures,
1) The notifications shall be made by the pertinent RLDCs
to the legal entities which are engaged in generation activity as
soon as possible without delay once the decision for giving an
emergency instruction has been taken but in any case, no later
than 30 minutes before the commencement of the application
with the means of communication in the definition of
“Emergency notification” set out in the Article “Definitions” of
this Regulation,
2) The notifications of interruption/reduction shall be
made by the relevant RLDCs to the users with the possibility of
interruption/reduction as soon as possible without delay once the
decision for said interruption/reduction has been taken, before the
commencement of the application, with the means of
communication in the definition of “Emergency notification” set
out in the Article “Definitions” of this Regulation. Notification
period may not be shorter than 30 minutes before the
commencement of interruption/reduction, provided that the
aforementioned conditions are effective.
b) If the possibility of interruption/reduction is eliminated, the warnings made
to the users shall be cancelled by the relevant RLDCs 30 as soon as possible before the
commencement of the application with the means of communication set out in the 4 th
Article definition of “Emergency notification” set out in the Article “Definitions” of
this Regulation.
c) The notification of cancellation of planned interruption/reduction application
shall be made by the relevant RLDCs to the users having the possibility of demand
outage within a short period of time with the means of communication in the definition
of “Emergency notification” set out in the Article 4 “Definitions” of this Regulation as
soon as possible without delay once the cancellation decision has been taken and
before the commencement of the application if possible or right after the application if
not possible.
(4) The Emergency Measures Procedure shall be notified to the users by being
published by TEIAS. In the cases where an agreement cannot be reached with the user
208
in the application, TEIAS shall take the opinion of the Authority and shall perform the
application within this framework.
[New Article, Harmonization with ENTSO-E network code CACM Art 80 and network
code FCA Art 62 Firmness in case of Force Majeure]
(5)If a Force Majeure situation or an Emergency Situation is invoked, TEIAS shall
limit the consequences and duration of the Force Majeure situation or Emergency
Situation.
SECTION 5
Operational Communication and Liaison
ARTICLE 197
Principles of operational communication
[Previous Article 71]
(1) Operational communication covers the principles regarding the two-way
reliable communication system to be established between TEIAS and users.
ARTICLE 198
Parties subject to operational communication
[Previous Article 72]
(1) Principles of operational communication apply to;
a) TEIAS,
b) TETAŞ,
c) Legal entities directly connected to the transmission system that operate as
Generation companies,
ç) Distribution companies,
d) Eligible customers.
ARTICLE 199
Notification of operational activities and events
[Previous Article 73]
(1) TEIAS and users shall inform to each other regarding the operational
activities and events in accordance with the procedures and methods below.
(2) In the case of a planned operation by TEIAS regarding system operation,
which will lead to a change in the operations of a user’s Power Generating Module or
grid, TEIAS shall notify the user via NLDC or RLDC within the shortest possible
period.
(3) In the case of a planned operation performed by a user on a user grid or user
Power Generating Module which will lead to a change in the operations of the
transmission system, the user shall notify TEIAS within the shortest possible period.
TEIAS shall notify other users [Addition to article harmonization with ENTSO-E
Network Code OS, 32.9 Responsibility of the TSOs and DSOs] or TSOs who will be
affected by this operational effect.
209
(4) A notification under conditions above must contain sufficient detail
regarding the associated possible risks and their implications. These notifications must
be given as far in advance as possible to allow the recipient time to assess the risk and
deal with any matters arising.
(5) Where there is not enough time for a written notification for unplanned
events in the system like fault or erroneous operation caused by personnel or
malfunctioning of equipment and/or control equipment or events that cause deviations
from the normal operating conditions, then oral communications can be performed
within 30 minutes following the occurrence of the event. A written confirmation by
fax, e-mail or letter is required afterwards to confirm the oral agreement.
[New articles harmonization with ENTSO-E Network Code OS, 31.5, 31.6, 31.7
Responsibility of the Significant Grid Users; 32.8, Responsibility of the TSOs and DSOs;
art 33.2, 33.3 Common testing and incident analysis responsibilities]
(6) TEIAS shall approve the foreseen tests, or test schedules and procedures,
prior to their launch. Operational Security Analysis using the last available Common
Grid Model shall be used to ensure that tests in its Responsibility Area are carried out
in a manner that minimizes the impact on Operational Security and economic
operation of the interconnected Transmission Systems and Significant Grid Users
(7) TEIAS shall have the right to participate in the test, record the performance
of the facility and/or request any compliance test results.
(8) TEIAS shall have the right the interrupt, cancel or delay any test in case of
risk for the security of the system.
ARTICLE 200
Requirement to notify significant incidents
[Previous Article 74]
(1) A significant incident includes; system voltage and frequency outside
normal operating limits, transmission system instability, overloading of plant and
equipment and danger to persons and/or public as a result of these.
(2) When in the opinion of TEIAS, the event notified by the user to TEIAS is
found to have a significant effect on the transmission system, TEIAS may request a
written significant incident report from the user. This report is prepared in the first
business day following the request according to Appendix-16 and sent to TEIAS.
(3) TEIAS may, when deemed necessary, require a significant incident report,
concerning any event, from users.
ARTICLE 201
Warnings
[Previous Article 75]
(1) A warning shall be sent by TEIAS, usually by PYS, phone, pax, fax or email, to users who may be adversely affected by significant incidents in the
transmission system. This warning shall indicate the likely reason for the disturbance,
the impact on the system, and the duration of the disturbance.
210
SECTION 6
Access and Work Safety
ARTICLE 202
Access
[Previous Article 76]
(1) Provisions regarding the access to sites that are owned by or under the
responsibility of Users or TEIAS are stated in the connection agreement signed by
TEIAS and the User.
ARTICLE 203
Principles of work safety
[Previous Article 77]
(1) Principles of work safety specify the procedures for the establishment and
coordination of essential safety precautions when one or more than one party is
involved in the work to be done on plant and/or equipment.
ARTICLE 204
Parties subject to work safety
[Previous Article 78]
(1) Principles of work safety apply to;
a) TEIAS,
b) Distribution companies,
c) Legal entities operating as Generation Companies that are directly
connected to transmission system,
d) Eligible consumers that are directly connected to the transmission system.
ARTICLE 205
Safety measures
[Previous Article 79]
(1) Each party must approve the other party’s safety rules in relation to
isolation and earthing prior to any work commencing. Safety rules are maintained until
the parties confirm the termination of their work to each other. Where there is a change
in safety precautions to either user, the change is confirmed by each of the users and
the safety precautions are re-approved.
ARTICLE 206
Authorized persons that can request work permit
[Previous Article 80]
(1) TEIAS and the user shall produce a list of names of all personnel who can
request work permit. TEIAS and the user exchange the lists of authorized persons. The
new list will be confirmed by both parties when there is a change to the list.
211
ARTICLE 207
Request for work permit
[Previous Article 81]
(1) For the preventive maintenance/repair works to be carried out on any equipment
that affects the transmission and/or distribution system or that causes interruption in
providing electric energy to the users if it is disconnected, the work permit request shall be
forwarded by the user who will perform the work to the pertinent load dispatch center at
least one week before the commencement of the work by filling in the form (Form YTİM1) given in the Annex-19 in order to be able to take the safety measures before the
commencement of the works. In certain circumstances, this duration may be shorted due to
mandatory reasons. In order to allow the work to be coordinated and the measures to be
taken, the permit should be requested at least 24 hours before. Otherwise, the work permit
shall not be given.
(2) The work permit shall be given following the acceptance of the work permit
request by the pertinent load dispatch center. The work permit request shall be
cancelled only by the approval of the pertinent load dispatch center. In the applications
made for the cancellation of the work permit, the form (Form YTİM-2) given in the
Annex-20 shall be filled in.
(3) No request for work permit shall be needed for the fault situation works to
be performed on the equipment disabled or to be disabled due to a failure in the
system.
ARTICLE 208
Commencement of work
[Previous Article 82]
(1) Coordination of the switch-out, isolation and earthing processes of the plant
or equipment shall be carried out by the respective control centers of the two parties
involved. The form (Form YTİM-3) given in the Annex-21 shall be filled in by the
RLDC and the mentioned maneuvers shall be made according to this form.
(2) Agreement on safety precautions to be established and the adequacy of
those precautions shall be reached by both parties before any work commences. This
agreement shall be recorded in writing at both parties’ control locations.
(3) Before work begins, the safety precautions agreed in advance shall be
established by both parties. All isolation points identified in the form with number,
nomenclature and position shall be locked and the equipment shall be provided with
cards. Completion of this procedure shall be recorded in the safety log at the respective
location and confirmed to the other party.
(4) Following the establishment of isolation at all points of infeed, actions to
apply agreed earthing may commence. The precise identity of every earth applied shall
be checked by the number, nomenclature and position.
(5) All fixed earths shall be locked in the closed position and a warning notice
applied. Completion of earthing shall be recorded in the safety log at the respective
location and confirmed to the other party. Only when all isolation and all earthing as
previously agreed between the two parties has been completed may a work permit be
written out.
212
(6) It is the responsibility of the crew chief or coordination supervisor who will
perform the work and who is named on the work permit to ensure that safety
precautions written on the work permit are maintained and not removed until
cancellation of work permit or termination of work. Safety precautions may be
removed only when work is completed or work permit is cancelled.
ARTICLE 209
Completion of work
[Previous Article 83]
(1) When the work has been completed, the respective RLDC is informed by
the crew chief or coordination supervisor that the earthing and isolation on his system
is no longer required and may be removed. This process regarding the return to service
of the plant and/or equipment shall be coordinated by the respective RLDCs.
ARTICLE 210
Safety logs
[Previous Article 84]
(1) TEIAS and the user, shall maintain at every operational site, a safety log,
which shall be a chronological record of all sent and received messages relating to
safety at that site. All safety logs shall be retained for at least one year.
ARTICLE 211
environment
Responsibilities regarding safety, training and
[Previous Article 85]
(1) The party performing work on plant and/equipment that is owned by or
under the responsibility of one of the parties must perform its operations according to
the safety rules and legal obligations related to safety of the party that is the owner.
Similarly, TEIAS personnel performing work on a site that is owned by or under the
responsibility of a user must perform his operations according to the safety rules and
the legal obligations related to safety of that user. TEIAS and users provide training
for their personnel on these issues with periods not longer than 1 year.
(2) Where settings, principle, fundamental procedure, site responsibility schedule
and maneuver diagram that shows the condition of the site including the boundaries for
operations and asset ownership between the parties or that that forms the basis of this
concept is requested for the connections of one of the parties, they are given by the party
that is the owner to the other party.
(3) TEIAS and the users establish the essential precautions related to the protection
of the environment during the work they perform.
ARTICLE 212
Maintenance works while the system is energized
[Previous Article 86]
TEIAS can carry out or cause to be carried out maintenance works while the system
is energized in the necessary cases in the transmission system.
213
SECTION 7
Power System Restoration
ARTICLE 213
Principles of power system restoration
[Previous Article 87]
(1) Power system restoration covers the principles related to achievement of
continuous supply to all customers as quickly and as safely as possible and with
minimum adverse consequences by TEIAS in the event of a partial or total shutdown
of the power system.
ARTICLE 214
Parties subject to power system restoration
[Previous Article 88]
(1) Principles of power system restoration apply to;
a) TEIAS,
b) The Power Generating Modules which have black start capability and
included in the scope of an ancillary service agreement related to the restoration of
system black out,
c) Legal entities that export.
ARTICLE 215
capability
Power Generating Modules with black start
[Previous Article 89]
(1) The Power Generating Modules that can return to service without the need
for external power supplies are registered by TEIAS as Power Generating Modules
having the capability of starting up by including in the scope of the ancillary service
agreements entered into as per the Electricity Market Ancillary Services Regulation.
Power supplied from a black start station can be used to energize the transmission
system, to supply power to the customers and to reconnect the other Power Generating
Modules.
(2) The performance tests concerning the restoration of the system black out
service set out in the ANNEX-17 should be completed at the Power Generating
Modules from which ancillary services will be received with regard to the restoration
of the system black out, and it should be found out that the relevant Power Generating
Modules have the black start capability.
(3) Interconnection connections and plants and/or equipment between islanded
power systems shall also be utilized if appropriate to provide a means of power system
restoration.
[New articles harmonization with ENTSO-E Policy 5 C. System Restoration Standards CS1.2.1.3]
214
(4) Black start capabilities of units shall be tested regularly on-site at least once per
three years.
ARTICLE 216
System restoration plan
[Previous Article 90]
(1) A detailed system restoration plan is prepared and updated when necessary
by TEIAS that will cover the Power Generating Modules included in the scope of the
ancillary service agreements related to the restoration of system black out.
(2) The overall restoration strategy to be followed by the users shall be set out
in this plan which will provide for the following sequential steps:
a) The establishment of a number of islanded systems, centered on the start
up of black start stations,
b) the feeding of local load from the Power Generating Modules,
c) the synchronization of these islanded power systems with each other,
ç) the final full restoration to normal operation of the total power system.
(3) In addition to setting out the overall restoration strategy to be adopted, the
plan shall also address such issues as:
a) Restoration priorities,
b) Plants and/or equipment available for restoration,
c) Guidelines to be given to Power Generating Facilities, distribution
companies, and other users who must act on TEIAS instructions or, in the
event of failure of communications, act independently to create an islanded
system,
ç) Communication with government, media and the public.
[New articles harmonization with ENTSO-E Policy 5 C. System Restoration Standards CS1.1, S1.2.1, S1.2.1.1, S2.1, S2.2.1.1, S2.3, S3.1, S3.3, S3.3, S3.5, S3.5.1, S3.6, S3.7, S4.2,
S5.1]
(4) TEIAS shall start the restoration process based on procedures after all the
System Defense Plan measures have been applied and once the grid is in a stabilized
situation.
(5) TEIAS has to develop proper reenergizing procedures allowing the
progressive restoration back to normal system state. Such procedures have to be
proved at least by simulation or off-line calculations.
(6) TEIAS has to know the status of any component of their power system after
a blackout e.g. tripped grid elements, islanded areas, blacked-out areas, generation
units in correct house-load operation and ready to reenergize, units having difficulty in
supplying their house load and thus in urgent need of an external source of voltage,
black start capabilities.
(7) During the restoration phase, TEIAS has to guarantee that they will respect
the agreed limits of active and reactive flows on interconnection line(s).
(8) When reenergizing and restoring the system from the voltage sources of the
interconnected system, TEIAS shall stop the frequency secondary controller in the area
that called for reenergizing.
215
(9) TEIAS has to identify:
 the situation of its control area (with one or more separated
asynchronous areas)
 the extent and border of its synchronous area including neighboring
TSOs in coordination with neighbors in ENTSOE.
 the state of the available power reserve in its own control area (with
possibly separated areas)
(10) TEIAS shall support the frequency leader, even far from its area, when
requested and in accordance with the principles defined at synchronous area level.
(11) During the reenergizing processes, TEIAS shall balance consumption and
production with the aim of returning near to 50 Hz, with a maximum tolerance of 200
mHz, under the coordination of the area’s frequency leader.
(12) TEIAS shall manage the reenergizing of the load step by step in order to
minimize the impact on the frequency deviation and the reserve margins. The process
of reenergizing customers has to be done stepwise in block loads of maximum size
defined by TEIAS with respect to the load of TEIAS’s grid.
(13) TEIAS has to coordinate the reconnection of cut consumption with DSOs.
Local and remote reconnection of customers’ consumption has to be agreed in advance
in cooperation between TEIAS and its DSOs. Automatic reconnection has to be
avoided.
(14) In case of restoration, when interconnected with other TSOs, TEIAS has to
coordinate the reconnection of Power Generating Modules tripped due to abnormal
frequency excursion based on the instructions of frequency leader, keeping adequate
margins of the downward balancing reserve sufficient at least to cope with the next
generation power to reconnect. TEIAS defines the criteria for reconnection and
disconnection with the constraint to avoid over-frequency conditions. For installation
connected to DSOs grids the local and remote reconnection has to be agreed in
advance in cooperation between TEIAS and DSOs for the main units. Automatic
reconnection is forbidden.
(15) When resynchronizing his system with the neighboring systems, TEIAS
shall follow the instructions of the resynchronization leader according to the principles
commonly defined at synchronous area level.
(16) TEIAS shall ensure at the end of the restoration that the ACE of his control
area shall be back to zero and his load frequency secondary control is back to normal
mode under the instructions of the Frequency Leader.
ARTICLE 217
Updating the power system restoration plan
[Previous Article 91]
(1) TEIAS shall review and update the power system restoration plan when
additional plant and/or equipment are connected to the transmission system and when
some existing plant and/or equipment are decommissioned. Apart from these
conditions, the plan shall be reviewed and updated at least every two years.
216
(2) TEIAS may issue revisions to the plan, to take account of developments
affecting the transmission system or other changed circumstances.
ARTICLE 218
Application of the system restoration plan
[Previous Article 92]
(1) The power system restoration plan sets out guidance to assist those involved
in the restoration process to achieve total restoration of the power system as quickly
and as safely as possible.
(2) The power system restoration plan may vary with the availability of Power
Generating Module and/or equipment, with time, with their usage and maintenance
needs. When the plan cannot cater for all possible partial or total shutdown scenarios
due to the mentioned changes, TEIAS, acting through NLDC, shall evaluate the status
of the Power System, and determine a new system restoration plan.
(3) Each legal entity operating as Generation company or distributor shall abide by
NLDC instructions during the restoration process, even in the event that they may conflict
with certain details contained in the power system restoration plan.
ARTICLE 219
Power system restoration training
[Previous Article 93]
(1) It shall be the responsibility of each user to ensure that their personnel who
are nominated to be involved with the power system restoration plan are adequately
trained and have sufficient qualifications and experience.
SECTION 8
Numbering and Nomenclature of Plant and/or Equipment at
Connection Points
ARTICLE 220
Principles of numbering and nomenclature
[Previous Article 94]
(1) Principles of numbering and nomenclature sets out the responsibilities and
procedures for determining the numbering and nomenclature of plant and/or
equipment to be used at connection points belonging to TEIAS or the user including
the naming of the substations.
(2) The numbering and nomenclature of plant and/or equipment is to be included in
an maneuver diagram prepared for connection points.
(3) The format for numbering and nomenclature of plant and/or equipment shall be
as shown in Annex-22.
217
ARTICLE 221
Parties subject to numbering and nomenclature
[Previous Article 95]
(1) The principles for numbering and nomenclature of plant and/or equipment
at the connection points apply to TEIAS and the users 66 kV or higher.
ARTICLE 222
Procedure
[Previous Article 96]
(1) The following procedures are applied regarding the numbering and
nomenclature of plant and/or equipment at the connection points:
a) All users’ plant and/or equipment at a connection point shall have
numbering and/or nomenclature which cannot be confused with TEIAS’ or
any other user’s plant and/or equipment. These numbers and names will be
clearly shown on the maneuver diagram.
b) The maneuver diagram shall be maintained and revised by the owner of
the plant and/or equipment to show correct numbering and/or nomenclature.
A current copy of the maneuver diagram shall be clearly displayed at every
connection point.
c) The numbering of the connection points is carried out by TEIAS.
ç) In case of a dispute regarding the numbering and/or nomenclature at a
connection point, TEIAS will determine the numbering and/or
nomenclature to be implemented.
d) The notifications regarding numbering and nomenclature of new
connections are done not later than 3 months prior to the commissioning of
the unit or at a shorter notice upon the agreement between users.
ARTICLE 223
Labeling of plant and/or equipment
[Previous Article 97]
(1) Users, including TEIAS, shall provide, erect and maintain clear and
unambiguous weatherproof labeling showing the numbering and/or nomenclature of
all plant and equipment at connection points. These labels must be fitted before
commissioning.
218
SECTION 9
Inter-TSOs Operating Agreements on borders within
ENTSO-E area
ARTICLE 224
Inter-TSO Operating Agreements
[New Article, harmonization with ENTSO-E code OS, art 8.8, 8.9, 8.10, 8.12, System
States; art 9.13 Frequency control management; art 10.11 voltage control and reactive
power management; art 13.1, 13.10, 13.14, Contingency analysis and handling; art 14.5
Protection; art 15.4 Dynamic Stability management; art 17.1, 17.2, 17.3, 17.4, Structural
and forecast data exchange between TSOs; art 18.1, 18.2 Real time data exchange between
TSOs; 30.13, 30.16, 30.17, 30.18 Operational training and certification; 32.2
Responsibility of the TSOs and DSOs; Policy 5 A. Awareness of system states - Standards
- A-S3, B. System Defence plan - Standards - B-S1, C. System Restoration - Standards - CS1.4 and OP&S]
(1) TEIAS shall define with each of his interconnected TSO on borders within
ENTSO-E area an Interconnection Operating Agreement that shall cover at least
the following :

Arrangements to exchange the values of exchange programs per market party,
control area exchanges, control area schedules

Arrangements for the matching process of exchange programs and control area
exchanges and the troubleshooting process

The electronic data exchange to be used

Acquisition of tie-line measurements and treatment of perturbation of
measurement equipment on cross-border lines

Definition of the accounting point on cross-border lines

The arrangements related to the settlement of unintentional deviations

Arrangements for outage scheduling and in particular the exchange of the list of
relevant and critical network elements, the coordination on planned outages and
the agreement on the list of planned outages.

For the purpose of capacity calculation on a border the exchange of the
information needed to calculate the capacity and the agreement process to arrive
at a common value

Information exchange on significant changes in the network in intraday and
close to real-time

The process of coordination of remedial actions for system security

For each Interconnector, the common definition of Operational Security Limits
including: current limits in terms of thermal rating and Transitory Admissible
Overload and voltage ranges
219

Pre-fault and Post-Fault cross-border Remedial Actions which are available to
ensure or restore Normal State and to prevent the propagation of Alert or
Emergency State outside of its Responsibility Area and the coordination
procedure to determine and activate them

the cross border measures of the System Defense Plan which are available to
restore the Alert or Normal State, and to prevent the propagation of Emergency
State outside of its Responsibility Area and the coordination procedure to
determine and activate them.

The provisions and the procedures for the management of scheduled exchange
or sharing of reserves among the TSOs to ensure that the resulting power flows
do not endanger the Operational Security Limits during the exchange of
reserves or activation of reserve

The voltage range and Reactive power flow limits on the Interconnectors

The Contingency of the internal Contingency list of the neighbouring TSO
which needs to be considered as external Contingency in the TEIAS'
Contingency List

The structural forecast and real time data and information which need to be
exchanged in order to ensure for each TSO a correct modelisation of the
Observability area in his Operational Security Analysis;

The protection Set Points for the interconnectors and the procedure for defining
and changing the settings;

The procedure to handle potential voltage, rotor angle or frequency stability
issues with the neighbouring TSO;

The necessary data to support coordinated Dynamic Stability Assessment;

The purpose and frequency of inter-TSO training and exchange of experiences;

The language used for communication between system operators;

The list and coordinates of functional positions directly involved in the system
operation to be contacted at any time;

The bilateral principles and adequate information exchange to be applied in
case of system restoration.
(2) TEIAS shall be entitle to exchange with the TSOs of ENTSOE the
structural, dynamic, forecast and real time data which are necessary to perform
Operational Security Analysis and Dynamic Stability Assessment at European level.
(3) TEIAS will have the right to make an Interconnection Operating Agreement
with other non ENTSO-E TSOs, covering some or all of the above mentioned.
220
SECTION 10
Operational Training and Certification
ARTICLE 225
Operational Training and Certification
[New Article, harmonization with ENTSO-E network code OS art 30.1, 30.2, 30.3, 30.4,
30.5, 30.6, 30.7, 30.8, 30.9, 30.10, 30.11, 30.12, 30.14, 30.15, 30.16, 30.19]
(1) TEIAS shall adopt and develop a training program for its System Operator
Employees in charge of real-time operation of the Transmission System. TEIAS shall
provide upon request to its relevant national authority the scope and details of its
training and certification processes. In addition TEIAS shall adopt and develop
training programs for the System Operator Employees who are outside of the control
rooms, who are carrying out operational planning and market balancing roles.
(2) TEIAS shall include in its training programs the knowledge of the
Transmission System elements, the operation of the Transmission System, use of the
on-the-job systems and processes, inter-TSO operations and market arrangements.
TEIAS shall also include in its training programs training on recognizing of and
responding to exceptional situations as defined by the TSO.
(3) To maintain and extend the System Operator Employees’ skills, TEIAS
shall carry out training. The detailed contents and frequency of the training for all
relevant roles shall be defined in the training program of TEIAS. The training shall
include but not be limited to:
a) relevant areas of electrical power engineering;
b) relevant aspects of the European Internal Electricity Market;
c) safety and security for persons, nuclear and other equipment in
Transmission System operation;
d) Transmission System operation in a Normal and all other System
States;
e) inter-TSO cooperation and coordination in real-time operation and
in operational planning at the level of main control centers; this part of
the training shall, if not otherwise specified and agreed, be in English;
and
f) exchange and training in conjunction with DSOs and Significant
Grid Users with Connection Point directly to the Transmission System
where deemed appropriate.
(4) TEIAS shall prepare and carry out training plans, in accordance with Article
220(1), for all new System Operator Employees in training - trainees. The training
plans shall be structured and detailed and take account of the trainees background and
experience relative to the position they are being trained for. Adequate records of
221
System Operators Employees’ training plans shall be retained by TEIAS for the period
of employment as a System Operator Employee.
(5) The training plans shall comprise:
a) an initial program, to be followed by a trainee training for the role of
System Operator Employee in real-time operation, before certification;
and
b) a program for the continuous development and extension of validity
of the certification of a System Operators Employee in real-time
operation, at least every five years;
c) an program, to be followed by a trainee training for the operational
planning.
(6) TEIAS shall appoint an experienced training coordinator, who is
responsible for designing, monitoring and updating the complete training process. The
training coordinator shall be responsible for defining:
a) qualifications for System Operator Employees;
b) training required for certification of the System Operator
Employees in real-time operation;
c) processes with documentation for initial and continuous training;
d) process for certification of System Operator Employees in real-time
operation;
e) process for extension of a training and certification period for the
System Operator Employees in real-time operation; and
f) competences for on-the-job trainers and training of trainers in
teaching and mentoring skills
(7) TEIAS shall define the skills and the level of competence of the on-the-job
trainers. This shall include the necessary practical experience. System Operator
Employees acting as trainers shall be registered by TEIAS and their on-the-job trainer
status reviewed at the same time as their certification extension of valid until date is
assessed.
(8) Each TSO shall review training programs at least annually or following any
significant system changes and update them to reflect changing operational
circumstances, market rules, network configuration and system characteristics, with
particular focus on new transmission and generation technologies, changing generation
patterns and market evolution.
(9) TEIAS shall ensure the training includes on-the-job training and training
offline. On-the-job training shall be carried out under the supervision of an
experienced System Operator Employee. Offline training shall, as far as practicable,
resemble the actual control room equipment with network modelling details
appropriate to the role being trained for.
222
(10) TEIAS shall ensure that training is based on a comprehensive database
model with respective data also from neighboring networks at a sufficient level to
replicate inter-TSO operational issues. Where relevant, the role of neighboring TSOs,
DSOs and Significant Grid Users with Connection Point directly to the Transmission
System shall also be simulated or directly involved in the offline training.
(11) TEIAS shall co-ordinate regularly with DSOs and Significant Grid Users
with Connection Point directly to the Transmission System to ensure TSO offline
training regarding the impact of users’ systems is as comprehensive as reasonably
practical and reflects the latest developments in systems and equipment.
(12) TEIAS shall ensure that System Operator Employees in real-time
operation have a certification, issued by a nominated representative from their TSO,
for the role they are to perform before they can work unsupervised in the control room.
(13) Each TSO shall define the level of competence and process to gain a
certification for each relevant role for System Operator Employee in real-time
operation within the control room. The certification shall only be awarded to the
System Operator Employees in real-time operation following the passing of a formal
assessment. A copy of the issued certificate shall also be retained by the TSO. The
formal assessment shall comprise an oral exam and/or a written exam, and/or a
practical assessment with pre-defined success criteria. The records of the formal
assessment shall be retained by the TSO. NRAs shall, upon request, be provided with
the TSOs certification examination records.
(14) Each TSO shall record the period of validity of the certification issued to
any System Operator Employee in real-time operation. The maximum period of any
certification shall be defined by each TSO and shall not exceed five years. The
extension of the valid until date of the certification before expiry shall be based on
criteria defined by each TSO, including the System Operator Employees’ participation
in a continuous training program with sufficient practical experience.
(15) TEIAS shall train the relevant System Operator Employees to achieve a
sufficient skill in the languages which are needed to carry out their tasks, including
communication with neighboring TSOs.
(16) TEIAS shall ensure that each System Operator Employee as a part of their
initial training undergoes training in interoperability issues between neighboring
systems based upon operational experiences and feedback from the joint training
carried out with their neighboring TSOs. This part of the initial training regarding
interoperability issues shall include awareness of coordinated actions required under
Normal and all other System States.
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PART VIII
Balancing Principles
SECTION 1
Day Ahead Planning
ARTICLE 226
Principles of Day Ahead Planning
[Previous Article 98]
(1) The day ahead planning includes preparation of generation-consumption
plans for the next day by the NLDC and License Holders and keeping the generation
capacity available with sufficient amount of reserves in order to provide sufficient
operational reserves, and ensuring real-time security and quality of supply and system
integrity.
ARTICLE 227
Parties subject to Day Ahead Planning
[Previous Article 99]
(1) Principles of day ahead planning apply to;
a) TEIAS,
b) Any License Holder having at least one supply/draw unit based on
settlement and meeting the conditions for having a balancing unit registered under its
name,
c) Legal entities providing ancillary services,
ç) Distribution companies.
(2) The active power forecasting related to the Power Park Facilities based on
the wind energy and connected to the transmission system shall be submitted to
TEIAS daily at 12:00 in hourly periods for the following 48 hours.
ARTICLE 228
Day-ahead planning procedure
[Previous Article 100]
(1) The day ahead planning shall be performed in line with the following
procedure:
a) The day-ahead market activities for the purpose of balancing the supply and
demand in the system and enabling the License Holders to day-ahead balance their
contractual commitments and generation and/or consumption plans are conducted
as per the day-ahead market related provisions of the relevant legislation which sets
out the balancing and settlement procedures.
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b) The License Holders of the real-time market shall notify the following as
required pursuant to the relevant legislation which sets out the balancing and
settlement procedures to the system operator via MMS;
1) Their relevant definite daily generation/consumption programs
and available capacities including the hourly generation or
consumption values for all of their relevant supply-draw units
based on settlement which are generation and/or consumption
facilities registered under their name as a balancing unit,
2) Their load up and load down proposals related to the real-time
market, and,
3) The technical and commercial parameters related to providing
the primary and secondary frequency control services as per the
Electricity Market Ancillary Services Regulation.
c) The system operator controls the notifications made as per the provisions of the
relevant legislation and within the period specified in the provisions of the relevant
legislation, and contacts with the related License Holder for the wrong notifications and
ensures the necessary corrections are made.
ç) As from control of the notifications made and completion of the necessary
corrections, in order to create capacity for correcting the energy deficit or surplus
which occurs or is expected to occur in the system for the related day, correcting the
system constraints, and/or providing any ancillary service, the load up, load down
instructions related to the load up and load down proposals, which have been
submitted under the real-time market, evaluated and approved by the System Operator
as per the provisions of the relevant legislation are notified to the related License
Holders in accordance with the provisions of the relevant legislation. In addition, after
the notifications made are checked and the necessary corrections are completed, the
System Operator evaluates the load up, load down proposals and/or the parameters
with respect to the related ancillary service submitted under the real-time market in
accordance with the provisions of the relevant legislation, and gives the instruction
related to provision of ancillary service to the related License Holders in accordance
with the provisions of the relevant legislation.
ARTICLE 229
Preparation of generation timescales
[Previous Article 101]
(1) Within the scope of the day-ahead planning activities, the following
schedules are prepared by NLDC with respect to the generation-consumption balance,
planned generation’s compliance with the bilateral agreements, and planning of
operating reserves;
a) Load guide: This guide indicates that hourly target generation values planned
by the balancing units participating in the real-time market for the next day
pursuant to the DDGP, and load up, load down instructions received by them
considering the system constraints and ancillary service requirements.
b) Operating reserves plan is prepared by NLDC so as to indicate the amounts
of primary frequency control reserve, secondary frequency control reserve,
225
tertiary frequency control and stand-by reserves to be provided by the balancing
units in the next day.
ARTICLE 230
Synchronization program
[Previous Article 102]
(1) The activation and deactivation times of the units included in the load guide
are determined by the relevant License Holders as per the load up, load down and
ancillary service instructions given by the System Operator. The units are kept
available for synchronization according to the load guide. NLDC is entitled to put the
activation and deactivation times determined by the relevant License Holders back
and/or postpone the same considering the system conditions and safety.
ARTICLE 231
Liability to provide data
[Previous Article 103]
(1) The user shall notify the NLDC of the bid and parameters related to the unit
pursuant to the provisions of the relevant legislation which sets out the balancing and
settlement procedures and Electricity Market Ancillary Services Regulation provided
that this notification will not be made after the notification time.
SECTION 2
Ancillary Services
ARTICLE 232
Principles related to the ancillary services
[Previous Article 104]
(1) The following ancillary services are used in such a manner that the operating
safety, and system integrity and reliability are ensured and in order to operate the system in
compliance with the criteria related to the supply quality and operating conditions as set
out in this Regulation:
a) Primary frequency control,
b) Secondary frequency control,
c) Stand-by reserve service,
ç) Instantaneous demand control,
d) Reactive power control,
e) Restoration of system black out,
f) Regional capacity leasing.
(2) For a unit that provides the primary frequency control, secondary frequency
control and tertiary frequency control services together, the distribution of the primary
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frequency control reserve amount, secondary frequency control reserve amount and tertiary
frequency control reserve amount should be as follows.
(3) The legal entities who will provide any ancillary service must install, test and
commission the necessary systems and equipment in their facilities for participation in the
related ancillary service(s). Performance tests should be carried out on the basis of unit,
block or Power Generating Module for the secondary frequency control and on the basis of
unit for other ancillary services.
(4) Within the scope of the ancillary services, the technical criteria governing the use
of energy storage systems shall be determined in accordance with the procedures and
principles to be prepared by TEIAS and approved by the Authority.
(5) The distribution of reserve amount for primary frequency control reserve,
secondary frequency control reserve, and tertiary frequency control reserve of a unit
providing combination of primary frequency control, secondary frequency control, and
tertiary frequency control must be as shown below.
Pmax
PmaxRT
RPA
RP
RT+
PmaxRS
RS
RSA
RS
PminRS
RTPminRT
RPA
Pmin
RP
(6) The parameters shown in the figure in the third paragraph of this article are
calculated using the following formulas:
RPA  RP  2
(1a)
RSA  RS  2
(1b)
RT
RT

 Pmax RT  Pmax RS
(1c)

 Pmin RS  Pmin RT
(1d)
(7) The following expressions in the figure in the third paragraph and in the formula
in the fourth paragraph of this article shall mean as follows;
227
Pmax
Available capacity of the unit,
Pmin
Minimum design output level of the unit,
PmaxRS
Maximum output power level that can be provided by the unit under the
secondary frequency control service,
PminRS
Minimum output power level that can be provided by the unit under the
secondary frequency control service,
PmaxRT
Maximum output power level that can be provided by the unit under the
tertiary frequency control service,
PminRT
Minimum output power level that can be provided by the unit under the
tertiary frequency control service,
RPA
The range in which the unit provides primary frequency control service,
RP
Amount of primary frequency control reserve provided by the unit,
RSA
The range in which the unit provides secondary frequency control
service,
RS
Amount of secondary frequency control reserve provided by the unit,
RT+
Tertiary frequency control reserve amount ensured by giving load up
instruction to the unit,
RT-
Tertiary frequency control reserve amount ensured by giving load down
instruction to the unit.
ARTICLE 233
Primary Frequency Control
[Previous Article 105]
[Modified article, Harmonisation with ENTSO-E LFC&R code, Article 45]
(1) The Power Generating Module shall make contribution by providing
automatically the primary frequency control reserve amount that is informed before
the day in proportion with the adjusted speed droop value during the period of
frequency deviation without any central intervention in order to balance the deviated
system frequency at a constant value when the generation and consumption is not
equal to each other.
(2) Primary frequency control reserve shall be supplied from the Power
Generating Modules that are found as to have the qualification to provide primary
frequency control service as a result of the primary frequency control performance
tests given in the ANNEX-17.
(3) Primary frequency control reserve amount should be available at all times
without subject to any interruption. The operation range of unit is adjusted by changing
constantly according to the operating conditions that affect the nominal active power of the
set output power value (Pset) in order to be able to supply the primary frequency control
reserve amount (RP) continuously and constantly unless otherwise required by National
Load Distribution Center (MYTM). Accordingly, if there is a drop of 200 mHz in the
system frequency, the unit must be operated at a Pset value that can increase the unit output
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power as RP, and if there is an increase of 200 mHz in the system frequency, it must be
operated at a Pset value that can decrease the unit output power as RP.
(4) The primary frequency control performance of units shall be able to activate
the primary frequency control reserve amount within maximum 30 seconds according
to the speed droop by which the speed governor is set in the event of a deviation in the
system frequency, and must have the capacity to maintain this output power for
minimum 15 minutes. The unit must follow up the deviation constantly at the system
frequency by increasing or decreasing the active output power and must give the
expected reaction automatically. Primary frequency control must be maintained
uninterruptedly during the deviation in the system frequency.
(5) The primary frequency control reserve amount that is supplied continuously
must be within +/- 10% tolerance of the primary frequency control reserve amount that
is informed before the day.
(6) The speed droop and dead band values of the units must be adjustable. The
speed droop value adjusted during the primary frequency control performance tests
shall also be used during the normal operation and it may not be changed unless
otherwise stated by TEIAS. The primary frequency control reserve amount to be
supplied by the unit must be supplied with a restrictive or a similar function in
charging and discharging direction. It must be possible to set the dead band of speed
control system of units to 0 (zero) when requested. If speed droop and dead band
values are required by TEIAS to be a different value according to the system need,
these values must be adjusted as defined by TEIAS.
(7) The speed droop of Power Generating Module is calculated using the
following formula according to the maximum primary frequency control reserve
capacity that is defined in the primary frequency control service agreement, which is
signed within the framework of Electricity Market Ancillary Services Regulation:
s g (%) 
f / f n
 100
PG / PGN
(8) Whereas;
s g (%)
Speed-Droop (%)
fn
Nominal Frequency (50 Hz)
f
Amount of deviation in System Frequency
PG
Amount of variation at Unit Output Power
PGN
Nominal Active Power of the Unit
(9) The primary frequency control reaction of the Power Generating Module
against a specific frequency deviation depends on the speed droop of the related unit. The
output power variations of units (a) and (b) that supply the same primary frequency control
reserve amount, but that are set to different speed droop values are shown below.
229
Output power
Çıkış Gücü
Pmax
a
b
fa
Primary Frequency
Primer Frekans
Kontrol Control
Reserve
Amount
Rezerv Miktarı
f0
Frequency
Frekans
fb
f0 = nominalnominal
frekans frequency
(10) The active power output change must be as shown in the following graph
according to the in-service frequency deviations in the system of units that provide primary
frequency control service.
(11) Whereas;
Pset
set value of the unit output power
f0
frequency range that unit control system does not react to frequency
deviations (dead band, Hz)
230
RP
primary frequency control reserve amount supplied by the unit
fG
frequency deviation amount detected by the unit after the dead band
f
amount of deviation in system frequency
(12) If dead band is placed in the unit under the operating conditions as per the
sixth paragraph, while calculating the speed droop that has to be set according to the
maximum primary frequency control reserve capacity, fG (fG = 0,2-f0) given in the
eleventh paragraph is used instead of f in the speed droop formula.
(13) When procuring Primary Control Reserve, TEIAS shall ensure that the
share of the Primary Control Reserve provided per Primary Reserve Providing Unit
shall be limited to 5 % of the Primary Reserve Capacity required for the Synchronous
Area for CE
ARTICLE 234
Secondary frequency control
[Previous Article 106]
(1) The Power Generating Modules that are obliged to involve in the secondary
frequency control pursuant to the provisions of Electricity Market Ancillary Services
Regulation in order to bring the system frequency to the nominal value and the total
exchange of electrical energy to the programmed value have to increase or decrease
their active power outputs by means of the equipment that receive and process the
signals to be sent by the automatic generation control program located in NLDC.
(2) The secondary frequency control reserve shall be supplied from the Power
Generating Modules that are revealed to have the capacity to provide secondary
frequency control service as a result of the secondary frequency control performance
tests given in the ANNEX-17.
(3) For the commencement of variation at the output power of unit, block or Power
Generating Module that provides secondary frequency control service, the maximum
reaction time has to be 30 seconds and the desired generation level has to be reached
according to the charging speed defined as a result of the tests. The charging speed rate in
the Power Generating Modules that are to provide secondary frequency control has to be as
follows depending upon the type of fuel:
a) by minimum 6% per minute of the nominal active power of the gas turbines
of the total change in the output power of the gas turbines with a nominal active
power below 200 MW for the natural gas powered Power Generating Modules,
b) by minimum 4% per minute of the nominal active power of the gas turbines
of the total change in the output power of the gas turbines with a nominal power of
200 MW or above for the natural gas powered Power Generating Modules
c) by minimum 6% per minute of the nominal active power for the natural gas
fired gas motors and diesel or fuel-oil fueled Power Generating Modules,
ç) in the range of 1.5% and 2.5% per second of the nominal active power for the
hydroelectric Power Generating Modules with reservoirs,
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d) in the range of 2% and 4% per minute of the nominal active power for the
coal powered Power Generating Modules,
e) in the range of 1% and 2% per minute of the nominal active power for the
lignite powered Power Generating Modules,
f) in the range of 1% and 5% per minute of the nominal active power for the
nuclear Power Generating Modules.
(4) The loading speed of nuclear Power Generating Modules during their
participation to secondary frequency control must be minimum 1% per minute. The
conditions for the participation of the nuclear Power Generating Module to secondary
frequency control are determined in the secondary frequency control service
agreement that will be signed between the nuclear Power Generating Module operator
and system operator considering the operation safety conditions.
(5)Any Power Generating Module that use any fuel other than those
aforementioned shall be considered in the class of the fuel type which has the closest
calorific value to itself.
(6) Producer shall provide the secondary frequency control service within the
operation range of the unit, block or Power Generating Module. The operation range
of the unit, block or Power Generating Module is the area where exchange of charge
can be performed between the minimum stable generation level and the maximum
output power that can be achieved without taking extra precautions.
(7) Involvement of the unit in secondary frequency control should not decrease
its primary frequency control performance.
(8) For the commencement of frequency to reach the nominal value and the total
exchange of electrical energy with the adjacent electrical grids to reach the programmed
value as a result of secondary frequency control on system basis, the maximum reaction
time has to be 30 seconds and correction process has to be completed within maximum 15
minutes.
ARTICLE 235
Stand-by reserve service
[Previous Article 107]
(1) The standby reserve service is provided by the Power Generating Facilities
which could not sell their generation capacity through the bilateral agreements, dayahead market or real-time market and which are preselected in accordance with the
provisions of the Electricity Market Ancillary Services Regulation.
(2) If the tertiary control reserve that can be quickly activated is released by
engaging the Power Generating Facilities providing standby reserve service by the
System Operator or the tertiary control reserve is insufficient, a tertiary control reserve
must be created and the energy deficit must be balanced.
(3) The activation time determined by TEIAS in the notice of tender related to
supply of standby reserve may not be less than 15 minutes and the minimum amount
of bid placed by the Power Generating Facility may not be less than 10 MW. The
232
loading speed specified in the related notice of tender is determined by TEIAS
according to the operating conditions.
(4) Activation time and loading speed for the units that will provide standby
reserve are determined as a result of the performance tests related to the standby
reserve determined by TEIAS.
(5) In order to use in the evaluation of the Power Generating Facilities that will
provide standby reserve service, the amount of standby reserve to be needed by the system
on the monthly basis, average generation amount expected from the Power Generating
Facilities that will provide standby reserve at each activation, and number of activations
expected for providing the standby reserve are estimated by TEIAS annually and by the
end of previous year at the latest considering the availability of units, demand forecast and
actual demands, and present situation. These estimations are updated by TEIAS within the
year whenever necessary.
ARTICLE 236
Instantaneous demand control
[Previous Article 108]
(1) Instantaneous demand control is executed in accordance with the provisions
of the Article 65 of this Regulation.
ARTICLE 237
Reactive power control
[Previous Article 109]
(1) All licensed Power Generating Modules with an Maximum Capacity of 30
MW or above, which are connected from the transmission system must participate in
the reactive power control through the automatic voltage regulator continuously
between 0.85 power factor of over-excited operation and 0.95 power factor of underexcited operation and/or in line with the instruction of RLDC and transmission system
operator, respectively. However, the wind energy-based Power Park Modules must be
able to work at every point for the power factor values within the limits set out in the
ANNEX-18. Generation unit step-up transformers and the Power Generating Units
which are not directly connected to the 154 kV - 380 kV transmission system and of
which generation and consumption plants are located in the same generation busbar
are exempted from the requirements of this article.
(2) The Power Generating Modules within the scope of an ancillary service
agreement for operating as a synchronous compensator and/or providing reactive
power capacity other than the capacity ensuring output at the nominal active power
level between 0.85 power factor of over-excited operation and 0.95 power factor of
underexcited operation as per the Electricity Market Ancillary Services Regulation
must participate in the reactive power control through the automatic voltage regulator
and/or in line with the instruction of RLDC and transmission or distribution system
operator, respectively.
(3) The reactive power control service shall be obtained from the Power
Generating Modules determined to be capable of providing reactive power control
233
service as a result of the performance tests related to provision of the reactive power
support indicated in the ANNEX-17.
(4) The instructions for supplying reactive power to the system or drawing
reactive power from the system by operation of the Power Generating Modules that
have entered into an ancillary service agreement with TEIAS for providing reactive
power control service as generator or synchronous compensator in order to regulate the
system voltage are notified by RLDC and/or the System Operator to the related Power
Generating Modules. The instructions to be given shall also include the details related
to the stage settings of the power transformers of the units. The Power Generating
Modules must response within minutes between the specified power factors and
provide the said response for unlimited number of times. The notifications for
termination of the instructions are also given by RLDC and/or the System Operator to
the related Power Generating Modules.
(5) In order to adjust the voltage value of the high voltage busbar connected by
the methods described in the paragraphs above, the Power Generating Modules within
the scope of this article shall install a control system which is able to control the high
voltage busbar by entering the required high voltage adjustment value in the related
control system and automatically receive the high voltage adjustment value if it is sent
by the System Operator via a remote control system, and which is capable of
controlling the high voltage busbar in line with such high voltage adjustment value.
ARTICLE 238
Restoration of system black out
[Previous Article 110]
(1) Restoration of system black out is executed as per the provisions set out in
the Section 7 of the Part 5 of this Regulation.
ARTICLE 239
Regional capacity leasing
[Previous Article 111]
(1) If it is considered necessary as a result of the technical studies conducted by
TEIAS, the capacities of new Power Generating Facilities and/or the capacities of
units added to the existing Power Generating Facilities may be leased by TEIAS
through the tenders made with approvals of the Ministry and Authority in accordance
with the provisions of the Electricity Market Ancillary Services Regulation. Possibility
of failure to meet the peak load as calculated during the technical studies conducted by
TEIAS for a year on the regional basis is compared with the possibility of failure to
meet the peak load given in the ARTICLE 170 [previous Article 48] of this
Regulation. The need for regional capacity leasing is determined for the regions
determined to have a possibility of failure to meet the peak load calculated by TEIAS
over the target value given in the ARTICLE 168 [previous Article 48].
(2) Tenders for regional capacity leasing are made, the Power Generating
Facilities that can provide regional capacity leasing service are selected, and the
ancillary service agreements for regional capacity leasing are entered into, and the
related financial transactions are made in accordance with the provisions of the
Electricity Market Ancillary Services Regulation.
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SECTION 3
Cross-border Processes for Load Frequency Control
ARTICLE 240
Imbalance Netting Process
[New Article, harmonization with ENTSO-E LFC&R code Article 42]
(1) TEIAS shall have the right to implement whenever needed Imbalance Netting
Process with adjacent TSO(s) member(s) of ENTSO-E, in compliance with the
provisions of LFC&R NC.
ARTICLE 241
Exchange or sharing of reserves
[New Article, harmonization with ENTSO-E code Article 49]
(1) TEIAS shall have the right to implement whenever needed Tertiary
Replacement Reserve Process, in compliance with the provisions of LFC&R NC.
(2) TEAIS shall have the right to implement whenever needed Exchange
or Sharing of Reserves with other TSO(s) members of RGCE, in compliance with the
provisions of LFC&R NC.
SECTION 4
Real-Time Balancing
ARTICLE 242
Definition of real-time balancing
[New article, harmonization with EB NC article 2 (definitions)]
(1) Real-time balancing means all actions and processes, on all timelines,
through which TEIAS ensure, in a continuous way, to maintain the system frequency
of the synchronous area within a predefined stability range as set forth in [Article 19
Frequency Quality Target Parameters of the European Network Code on LoadFrequency Control and Reserves], and to comply with the amount of reserves needed
per Frequency Containment Process, Frequency Restoration Process and Reserve
Replacement Process with respect to the required quality, as set forth in Chapter 6
Frequency Containment Reserves, Chapter 7 Frequency Restorations Reserves and
Chapter 8 Replacement Reserves of the European Network Code on Load-Frequency
Control and Reserves.
ARTICLE 243
Real-time balancing principles
[Previous Article 112 amended to be harmonised with EB NC Article 1]
(1) The real-time balancing principles include the principles related to the
activities carried out by NLDC in normal and alert state within the scope of the realtime market and/or ancillary services and the notification of technical and commercial
235
parameters by the real-time License Holders and/or ancillary service providing legal
entities to NLDC through MMS, and compliance with the instructions given by NLDC
in order to eliminate the supply and demand imbalances arising real-timely.
(2) Real-time balancing is performed as follows;
a) The Power Generating Modules that provide primary frequency
control service and/or secondary frequency control service automatically
increase or decrease their output power,
b) The balancing units within the scope of real-time market perform load
up and/or load down according to the instructions given by NLDC,
c) Activation of stand-by reserves in order to provide sufficient tertiary
reserve in real-time,
ç) Implementation of emergency measures pursuant to the article 63.
(3) Instructions given within the scope of real-time balancing and the
instructions stated in the first paragraph, which are given by NLDC when necessary
may be communicated to the relevant parties subject to the real-time balancing by
RLDC via communication means such as MMS, phone, fax or pax.
ARTICLE 244
Parties subject to real-time balancing
[Previous Article 113]
Real-time balancing principles apply to;
a) TEIAS,
b) Real-time License Holders,
c) Ancillary service providing legal entities,
d) System operators of interconnected countries, and
e) Distribution companies, and
f) Eligible consumers.
ARTICLE 245
balancing
Revision of regulations related to Real-time
[New Article, harmonisation with EB NC article 5,6 and 7]
(1) For all revision of the regulations on terms and conditions related to realtime balancing, TEIAS shall consult on a draft proposal for a period of not less than
four weeks.
(2) When establishing or revising an inter TSO agreement relative to real-time
balancing, TEIAS shall consult stakeholders on a draft proposal of the elements related
to real-time balancing for a period of not less than four weeks.
(3) TEIAS will establish by end of 2016 a procedure ensuring that the views of
stakeholders emerging from the consultations undertaken pursuant to previous articles
shall be duly considered by TEIAS prior to the submission of the documents for
regulatory approval, if required, or prior to publication in all other cases. In all cases, a
clear and robust justification of the reasons for including or not including the views
236
emerging from the consultation in the submission shall be developed and published in
a timely manner.
(4) All revisions of TEIAS terms and conditions related to real-time balancing,
and establishment and revision of inter TSO agreement involving TEIAS related to
real-time balancing shall be subject to the approval of EMRA.
(5) For all matters related to real-time balancing and subject to the approval of
EMRA, TEIAS shall propose a timeline for implementation to EMRA.
(6) TEIAS shall use reasonable endeavours to facilitate the consideration of
issues at the same point of time.
(7) In the event that EMRA requests an amendment to a proposal from TEIAS
related to real-time balancing, TEIAS shall resubmit an amended proposal for approval
within three months.
(8) TEIAS shall implement the decision of EMRA no later than at the date
specified in the decision.
(9) All documents related to real-time balancing and consulted by TEIAS shall
be made publically available by TEIAS after their approval, if approval of EMRA is
required, or after finalization in all other cases.
(10) TEIAS, DSOs, third parties to whom responsibilities have been delegated,
and Market Participants shall ensure that information is published at a time and in
format which does not create an actual or potential competitive advantage or
disadvantage to any individual or category of individuals.
(11) TEIAS shall publish the terms and conditions related to real–time
balancing at least one week before their application.
ARTICLE 246
Real-time balancing procedure
[Previous Article 114]
(1) If any of the following circumstances arises, real-time balancing procedure
shall be followed:
a) A generation and/or consumption facility in the system is
disabled,
b) Imbalance between supply and demand,
c) Deviation in the system frequency,
ç) Need for releasing the said reserves due to use of the primary
and/or secondary frequency control reserves,
d) Continuation of need for tertiary frequency control reserve
although the tertiary frequency control reserves are used,
e) Deviation in the cross-border electric program.
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(2) Real-time balancing procedure consists of the following steps:
a) The legal entities providing primary frequency control service
provide primary frequency control service according to the primary
frequency control reserve amount reported to NLDC and/or in
accordance with the instructions given by NLDC for providing reserve
in order to provide primary frequency control service. The units
providing primary frequency control service automatically increase their
output power as specified in the [previous Article 122] in the case of any
drop in the system frequency. In the case of an increase in the system
frequency, the said units automatically decrease their output power as
specified in the [previous Article 122].
b) The legal entities providing secondary frequency control
service provide secondary frequency control service according to the
instructions given by NLDC. The units providing secondary frequency
control service increase or decrease their output power in line with the
signals received from the automatic generation control program.
c) NLDC continuously monitors the secondary frequency control
reserve activated in the system. If a generation or consumption facility is
disabled so as to create a permanent supply-demand imbalance in the
system or it is observed that the secondary frequency control reserve is
used for a long time in the same direction, NLDC ensures a tertiary
frequency control reserve which is sufficient to release the activated
secondary frequency control reserve using the up and down regulation
instructions given under the real-time market. In addition, the tertiary
frequency control reserve may also be used in order to ensure that the
primary frequency control reserve is released as well as the secondary
frequency control reserve.
ç) NLDC may provide tertiary reserve by activating the stand-by
reserves, if any, in the event that it is detected that no sufficient amount
of tertiary control reserve is left in the system for the purpose of realtime balancing in order to eliminate a long-term supply-demand
imbalance in the system by means of tertiary control reserves.
d) Within the scope of real-time balancing, the emergency
measures given in the Article 63 of this Regulation may be
implemented.
(3) Interrelation of the steps given in the second paragraph within the scope of
the real-time balancing procedure is shown in the figure below.
238
Sistem
System
Frequency
Frekansı
Aktive
Activates
Eder
Frekans
Sapmasını
Balances
the
Frequency
Deviation
Dengeler
Primer
Primary
Frequency
Frekans
Control
Kontrol
TakesDevralır
Over
BringsOrtalamayı
the Average
to
the Nominal
Nominal
Değere
Value
Getirir
Nominal
BringsDeğere
to the
Nominal
GetirirValue
Rezervleri
Releases
the
Serbest
Reserves
Bırakır
Sekonder
Secondary
Frequency
Frekans
Control
Kontrol
Takes Devralır
Over
Rezervleri
Releases
the
Reserves
Serbest
Bırakır
Düzeltir
Corrects
Rezervleri
Releases
the
Serbest
Reserves
Bırakır
Tersiyer
Tertiary
Control
Kontrol
Takes Devralır
Over
Rezervleri
Releases
the
Reserves
Serbest
Bırakır
Bekleme
Standby
Reserve
Yedeği
Service
Hizmeti
Activates
in the
Uzun
Vadede
Long-Term
Aktive
Eder
Zaman
Time
Control
Kontrolü
(4) NLDC is entitled to re-optimize the generation-consumption plan when
necessary.
[New articlesitem, harmonization with ENTSO-E Network Code OS, 9.11
Frequency Control Management; EB NC Article 21]
(5)NLDC shall monitor close to real-time generation and exchange schedules,
power flows, node injections and withdrawals and other parameters within its LFC
Area relevant for anticipating a risk of a frequency deviation and when needed take
joint measures to limit their negative effects on the balance between generation and
demand in coordination with other TSOs of its Synchronous Area
(6) The activation of secondary frequency control reserve shall be made for
balancing purpose exclusively.
ARTICLE 247
Transmission system constraints
[Previous Article 115]
(1) Transmission system constrains include the case that the total demand for
transmission capacity is greater than the transmission capacity determined and put into
use after all security criteria and possible uncertainties in the transmission system are
taken into account.
(2) As a result of the following cases the transmission system may be affected
partially or totally as the overloading and / or voltage change transmission system
constraints may occur.
a)Disability of Power Generating Modules, transmission lines,
transformers/autotransformers, busbar, breaker and such devices due to
testing, maintenance, or revision, etc.,
239
b) Power fluctuations or inability to ensure the normal operation
conditions during normal operation of electricity system,
c) Existence of equipment with a lower capacity (conductor section,
current transformer ratio, disconnector, line trap, etc.), which may limit
loading of the transmission lines and/or transformers/autotransformers in
their respective nominal capacity.
ç) Consecutive failures due to simultaneous outage of plural equipment.
ARTICLE 248
Records related to the instructions
[Previous Article 116]
(1) Within the scope of real-time balancing, the instructions given by NLDC
and/or RLDC to the parties subject to real-time balancing are recorded using MMS
and/or sound recording and/or physical forms. The voice records within this scope are
maintained for five years, and other records for ten years.
ARTICLE 249
Electrical time error correction
[Previous Article 117]
(1) Electrical time error correction is performed by NLDC through balancing in
compliance with the nominal system frequency. NLDC is responsible for keeping the
electrical time error within the determined limits.
PART IX
Data Recording and Statistics Producing
SECTION 1
Principles Applicable to Data Recording and Subject Parties
ARTICLE 250
Principles applicable to data recording
[Previous Article 118]
(1) This section covers the procedures applicable to the preparation, updating
and recording of operational, planning, balancing and ancillary service data which
parties request from each other.
ARTICLE 251
Parties subject to data recording principles
[Previous Article 119]
(1) Data recording principles shall apply to;
TEIAS,
240
a) Legal entities performing generation activities as directly connected to the
transmission system,
b) Distribution companies,
c) Eligible consumers directly connected to the transmission system,
d) Legal entities performing generation activities with Power Generating Modules
of 50 MW and higher Maximum Capacity, connected at the distribution level,
or legal entities performing generation activities with Power Generating
Modules with significant impact on the transmission system,
e) Importing and/or exporting legal entities,
f) Supplier companies,
g) Legal entities providing any ancillary service.
SECTION 2
Data Groups, Procedures
ARTICLE 252
Data groups
[Previous Article 120]
(1) Data groups are divided into three categories;
a) Operational and balancing data,
b) Standard planning data, and
c) Detailed planning data.
ARTICLE 253
Preparation and presentation of data
[Previous Article 121]
(1) Users shall prepare and present to TEIAS the data sheets given in the
Annex-23 of this Regulation and listed in the Article 143 in line with the following
principles:
a) Data to be prepared pursuant to Sheet 1, 5 and 6 shall be sent to TEIAS,
b) In case of an agreement between TEIAS and the user regarding data
communication, the method to be pursued shall be specified through mutual
agreement,
c) Data to be prepared pursuant to Sheet 5 shall be prepared in line with the
instructions of TEIAS latest by April 30 every year,
241
ç) Users shall take all security measures to protect all data.
d) Data related to the ancillary services are provided in accordance with the
principles set out in the ancillary service agreements and in the specified
formats and periods. If any, the mathematical models of the control systems
of the Power Generating Module, which are related to the auxiliary services,
shall be submitted to TEIAS before testing.
ARTICLE 254
Data updating
[Previous Article 122]
(1) In case of any change in the data recorded at TEIAS, user shall notify
TEIAS thereof promptly.
ARTICLE 255
Missing Data
[Previous Article 123]
(1) In the event that data prepared by one of the parties does not reach the other
or reaches but is incomplete, estimated data shall be prepared and such data shall be
communicated to other party in writing.
ARTICLE 256
Data Sheets
[Previous Article 124]
(1) The data sheets to be prepared as per the Annex-23 are listed below:
a) Sheet 1 – Generation unit or combined cycle gas turbine block data,
b) Sheet 2 – Generation planning parameters,
c) Sheet 3 – Units’ outage programs, usable power and fixed capacity data,
ç) Sheet 4 – User systems data,
d) Sheet 5 – User outage data,
e) Sheet 6 – Load characteristics at connection points,
f) Sheet 7 – Data to be provided by TEIAS to users,
g) Sheet 8 – Demand profile and active power data,
ğ) Sheet 9 – Connection point data,
ı) Sheet 10 – Short circuit data,
i) Sheet 11 – Short circuit data, short circuit currents from Power
Generating Facility transformers.
(2) The data sheets applicable to user groups are given below:
a) Generation companies directly connected to the transmission system:
Sheets 1, 2, 3, 6, 7 and 11,
b) Legal entities performing generation activities with Power Generating
Modules of 50 MW and higher unit capacity or 100 MW and higher
Maximum Capacity, as connected at the distribution level, or legal
entities performing generation activities with Power Generating Modules
242
with significant impact on the transmission system: Sheets 1, 3, 7 and
11,
c) Legal entities performing generation activities other than those
covered by sub-paragraphs (a) and (b): Sheets 1, 7, 11,
ç) All distribution companies, wholesale companies, retail sale
companies, users directly connected to the transmission system and
international interconnection grid operators: Sheets 4, 5, 6, 7, 8, 19, 10
and 11.
SECTION 3
Statistical Data, Procedures, Obligations
ARTICLE 257
Statistical data
[Previous Article 125]
(1) TEIAS collects statistical data in order to generate the electric energy generation
and transmission statistics of Turkey in accordance with the provisions of the Law, and the
Turkish Statistics Law no 5429 and meet the statistics requests of the international
institutions and organizations, when necessary.
(2) TEIAS obtains the data needed for generating the statistics through the monthly
and annual questionnaires to be published by TEIAS on their website. When necessary,
such questionnaires are revised and updated by TEIAS.
(3) After the necessary infrastructure and hardware are provided, TEIAS collects all
data for the purpose of generating the statistics through its official website.
ARTICLE 258
Procedure and obligations
[Previous Article 126]
(1) In order to produce the electric energy generation and transmission statistics of
Turkey;
a) Legal entities engaged in generation activities,
b) Legal entities engage in distribution activities, and
c) (EPİAŞ) Enerji Piyasaları İşletme Anonim Şirketi ( Energy Market Operator
Corporation)
shall submit the data requested by TEIAS to TEIAS in the format and by the data to be
indicated by TEIAS.
243
(2) Legal entities engaged in generation activities shall submit to TEIAS their
generation data until twenty fifth day of the following month through the “Monthly
Questionnaires” published on the website of TEIAS, and their annual generation data until
15th February of the following year through the “Annual Questionnaires” published on the
website of TEIAS.
(2) Data obtained for generating the statistics may not be used for any other purpose.
PART X
Miscellaneous Provisions
SECTION 1
Other Provisions
ARTICLE 259
Settlement of disputes
[Previous Article 127]
(1) In the event that disputes arising from the implementation of this regulation
cannot be settled between TEIAS and relevant parties, the Authority shall be
competent in settling disputes. The decision to be taken by the Board shall be binding
on both parties.
ARTICLE 260
Attributions
[Previous Article 128]
ARTICLE 1 (1) The attributions made in Electricity Market Transmission
Regulation published in Official Gazette no:25001 dated 22/01/2003 and Electricity
Transmission System Supply Reliability and Quality Regulation published in Official
Gazette no:25639 dated 10/11/2004 are also applies to this Regulation.
ARTICLE 261
Annulled Regulations
[Previous Article 129]
244
ARTICLE 2 (1) Electricity Market Transmission Regulation published in
Official Gazette no:25001 dated 22/01/2003 and Electricity Transmission System
Supply Reliability and Quality Regulation published in Official Gazette no:25639
dated 10/11/2004
ARTICLE 262
Communication and notices
[Previous Article 130]
(1) Notifications shall be made in accordance with the provisions of the
Notification Law No. 7201.
SECTION 2
Provisional and Final Articles
TEMPORARY PROVISON 1
the Ancillary services
Use of Energy storage system within
[Previous Temporary provision 1]
(1)Procedures and principles for using the energy storage systems within the scope
of the ancillary services shall be prepared and submitted by TEIAS to the Authority for
approval by 31/12/2015.
TEMPORARY PROVISON 2
Failure Repair Periods
[Previous Temporary provision 2]
(1)The maximum failure repair period for phase-earth failures, as set out in the 6th
Paragraph of the Article 18 shall be determined with mutual agreement by 31/12/2015 by
taking into account the overcurrent and earth protection relay set values of the protection
relay which gives trip order to the line feeder Disconnector of TEIAS, short-circuit
withstanding time of the step-down transformers from transmission to distribution, Neutral
resistance/reactor nominal current withstanding time and relay coordination studies of the
user.
TEMPORARY PROVISON 3
Scada control centers
[Previous Temporary provision 3]
(1)SCADA control centers which should be established by the Electricity
Distribution Companies/Organized Industrial Zones (OIZ) having a Distribution License
pursuant to the Article 29 of this Regulation shall be put into operation by 31/12/ 2015.
TEMPORARY PROVISON 4
Park Modules
Connection Criteria for Wind Power
[Previous Temporary provision 4]
245
(1) Annex-18 which is current as of the signing date of the connection
agreement of the plan shall apply for the wind energy based Power Park Modules.
(2) the section “E.18.9- Monitoring of the Wind Power Park Modules”, which sets
out the infrastructure requirements for the Wind Power Monitoring and Forecast Center
(RITM), as included in the ANNEX-18 of this Regulation, shall apply to all wind energy
based Power Park Modules whether existing or to be newly installed, even if that section is
not included in the Annex-18 which is current as of the signing date of the connection
agreement. The Power Park Modules in this scope shall fulfil their tasks by 31/05/2015.
TEMPORARY PROVISON 5
control
Power values for the Reactive Power
[Previous Temporary provision 5]
(1)In respect of the Power Generating Facilities the project approval by the
Ministry is dated before 22/1/2003 or the Power Generating Facilities with a contract
effective date before 22/1/2003, the reactive power values with which they must participate
in the reactive power control is determined in accordance with the current legislation on
the project approval date or effective date of Power Generating Facility construction
contract, and included in the ancillary service agreements related to the reactive power
control.
TEMPORARY PROVISON 6
Participation Reactive Power support
[Previous Temporary provision 6]
(1)The Power Generating Modules of which connection agreement or project
approval has been concluded before the effective date of the regulation and which are not
capable of operating with a power factor of 0.85 at the alternator terminal in the case of
over-excited operation at the nominal active power according to the P-Q alternator loading
curve; and/or the units which are in the aforementioned situation, but also, increased their
Maximum Capacities subjecting to the generation license for the existing Power
Generating Facilities, and nominal active powers of the existing alternators in line with the
consent of the System Operator by amending the license shall agree and undertake that
they will decrease to the active power level at which they can generate the reactive power
amount corresponding to the power factor of 0.85 with over-excitation at the nominal
active output power level of the alternator at the request of the System Operator within the
scope of the Ancillary Service Agreements for Provision of Reactive Power Support, that
they will cover the extra cost of ancillary service reserve creation, which will be calculated
taking into account the market prices as a result of this instruction, under the Regulation on
Electricity Market Ancillary Services, and that they will fulfill all special obligations to be
determined by the System Operator.
TEMPORARY PROVISON 7
Reactive Energy Penalty
[Previous Temporary provision 7]
(1) With respect to the fact that the ratio of the monthly inductive reactive energy
power drawn from or monthly inductive reactive power supplied to the system by the
consumers directly connected to the transmission system and legal entities holding a
distribution license to the active power exceeds the ratios set out in the ARTICLE 28
[previous Article 14] of this Regulation; the reactive power usage ratio shall be evaluated
according to the ARTICLE 28 [previous Article 14] of this Regulation until the necessary
revisions are made by the Board Decision in the system use agreement, and in the event
246
that any breach is detected, a penalty equal to 20% of the sum calculated according to the
system use price of that month shall be imposed on the related users.
TEMPORARY PROVISON 8
Primary Control Services
Exemption
from
participation
in
[Previous Temporary provision 8]
(1) The Power Generating Modules operating for more than 30 years as of 1/1/2006
shall be exempted from requirement of installing the necessary systems and equipment for
participating in the primary frequency control, as well as the requirement of performance
tests.
ARTICLE 263
Effectiveness
[Previous Article 131]
(1) Enforcement dates of this Regulation are as follows:
(a) PART IV (ARTICLE 47 to ARTICLE 98), PART V (from
ARTICLE 105 to ARTICLE 158) shall apply as from the day of
expiration of a 3 year period following the date of publication of this
Regulation.
(b) The ARTICLE 34 (7) [previous article 20(7)], and ARTICLE 35 (8)
d,e,f,g and ğ [previous article 21(8) d,e,f,g and ğ], shall be effective on
the twentieth day following that of its publication and shall apply to
New and Existing Power Generating Modules as from the day of
expiration of a 3 year period following the date of publication of this
Regulation.
(c) With the exception of sub articles mentioned in ARTICLE
263ARTICLE 263(b), ARTICLE 34 [previous article 20], ARTICLE 35
[previous article 21] shall be effective on the twentieth day following
that of its publication and shall only apply to Existing Power Generating
Modules as from the day of expiration of a 3 year period following the
date of publication of this Regulation.
(d) Annex 18 shall be effective on the twentieth day following that of
its publication. Annex 18 shall only apply to Existing Power Park
Modules based on the wind energy connected to the distribution and
transmission system having Maximum Capacity of 10 MW and above as
from the day of expiration of a 3 year period following the date of
publication of this Regulation.
(e) Other Articles of this Regulation shall be effective on the twentieth
day following that of its publication.
247
ARTICLE 264
Enforcement
[Previous Article 132]
(1) The provisions of this Regulation shall be enforced by the President of
Energy Market Regulatory Authority.
248
ANNEX 1
CHARACTERISTICS OF THE STEP-DOWN POWER TRANSFORMERS TO BE USED IN THE TRANSMISSION SYSTEM
Operating
Voltage
(kV)
34.5
31.5
15.8
10.5
6.3
TRANSFORMER
POWER (MVA)
Impedance
Parallel Operation of
Secondary Side
Two
Transformers
Short
Circuit
Base
having
the
Same
Current (kA)
(Uk%) Power
Power
(MVA)
Idle Revolution and Voltage Adjustment
ONAN
ONAF
90
125
No
<16
15
125
400 kV±12x1.25%/33.25 kV
80
50
25
50
25
16
50
25
25
16
100
62.5
31.25
62.5
31.25
20
62.5
31.25
31.25
20
No*
Yes
Yes
No
No
Yes
No
No
No
No
<16
<16
<16
<16
<16
<16
<16
<16
<16
<16
12
12
12
16
12
12
17
12
15
12
100
62,5
31.25
50
25
16
50
25
25
16
154 kV±12x1.25%/33.6 kV
154 kV±12x1.25%/33.6 kV
154 kV±12x1.25%/33.6 kV
154 kV±12x1.25%/16.5 kV
154 kV±12x1.25%/16.5 kV
154 kV±12x1.25%/16.5 kV
154 kV±12x1.25%/11.1 kV
154 kV±12x1.25%/11.1 kV
154 kV±12x1.25%/6.6 kV
154 kV±12x1.25%/6.6 kV
* The power transformers of 154/33.6 kV, 100 MVA can be temporarily operated parallel in order to prevent disconnection during the maneuvers by
reaching to an agreement with the relevant distribution companies.
249
ANNEX 2
TRANSPOSITION IN THE TRANSMISSION LINES
TRANSPOSITION IN THE ELECTRICITY TRANSMISSION LINES OF 400 kV
A
C
B
B
A
C
C
B
A
approximately 40
0
approximately 80
approximately
120
TRANSPOSITION IN THE ELECTRICITY TRANSMISSION LINES OF 154 kV
A
C
B
B
A
C
C
B
A
approximately 15
approximately 30
0
250
approximately
45
ANNEX 3
TYPES AND CAPACITIES OF THE CONDUCTORS USED IN THE TRANSMISSION
SYSTEM
TYPES AND CAPACITIES OF THE CONDUCTORS USED IN THE OVERHEAD
TRANSMISSION LINES OF 400 kV
Total
Current
Summer
Spring/
Thermal
TYPE
Conductor
MCM
Carrying
Capacity
Autumn
Capacity
Area
Capacity
(MVA)* Capacity (MVA)***
(mm2)
(A)***
(MVA)**
2B, Rail
2x517
2x954
2x755
832
1360
995
2B, Cardinal
2x547
2x954
2x765
845
1360
1005
3B, Cardinal
3x547
3x954
3x765
1268
2070
1510
3B, Pheasant
3x726
3x1272
3x925
1524
2480
1825
* : Conductor Temperature: 80 °C, Air Temperature: 40 °C, Wind Velocity: 0,1 m/s
** : Conductor Temperature: 80 °C, Air Temperature: 25 °C, Wind Velocity: 0,5 m/s
*** : Conductor Temperature: 80 °C, Air Temperature: 40 °C, Wind Velocity: 0,25 m/s
2B and 3B represent the binary and triple conductor beams, respectively.
TYPES AND CAPACITIES OF THE CONDUCTORS USED IN THE OVERHEAD
TRANSMISSION LINES OF 154 kV
TYPE
Total
Conductor
Area
(mm2)
281
468,4
547
2x547
726
MCM
Current
Carrying
Capacity
(A)***
496
683
765
2x765
925
Summer
Capacity
(MVA)*
Spring/
Autumn
Capacity
(MVA)**
180
250
280
560
336
Thermal
Capacity
(MVA)***
Hawk
477
110
132
Drake
795
153
182
Cardinal
954
171
204
2B**** Cardinal
2x954
342
408
Pheasant
1272
206
247
0,1 m/s
** : Conductor Temperature: 80 °C, Air Temperature: 25 °C, Wind Velocity: 0,5 m/s
*** : Conductor Temperature: 80 °C, Air Temperature: 40 °C, Wind Velocity: 0,25 m/s
**** : 2B represents the binary conductor beam.
* :
Conductor
Temperatu
re: 80 °C,
Air
Temperatu
re: 40 °C,
Wind
Velocity:
TYPES AND CAPACITIES OF THE UNDERGROUND POWER CABLES USED IN THE
TRANSMISSION SYSTEM OF 154 Kv
Type
XLPE Cable (Copper)*
XLPE Cable (Copper)*
XLPE Cable (Copper)*
Total Conductor
Area (mm2)
630
1000
1600
Current Carrying
Capacity (A)
655
935
1350
Transmission
Capacity (MVA)
175
250
360
(*) or equivalent (aluminum) XLPE cable.”
251
TYPES AND CAPACITIES OF THE UNDERGROUND POWER CABLES USED IN THE
TRANSMISSION SYSTEM OF 400 kV
Type
XLPE Cable (Copper)
Total Conductor
Area (mm2)
2000
Current Carrying
Capacity (A)
1500
Transmission
Capacity (MVA)
987
400 kV AND 154 kV ISOLATION LEVELS
To the ground
For 400 kV For 154 kV
Lightning Impulse Voltage of 1.2/50
s (Isolation level for open switch
assembly)
Lightning Impulse Voltage (For
power transformers)
Switching Over Voltage (Isolation
level for open switch assembly )
Switching Over Voltage (For power
transformers)
Wet Resistance Voltage of 50 Hz – 1
Minute for open switch assembly
covering breakers and disconnectors
Along the open contacts
For 400 kV
For 154 kV
1550 kV
750 kV
1550(+300) kV*
860 kV*
1425 kV
650 kV
-
-
1175 kV
-
900(+430) kV
-
1050 kV
-
-
-
620 kVrms
325 kVrms
760 kVrms*
375 kVrms*
* Applied for Breakers and Disconnector switches.
252
ANNEX 4
AMBIENT CONDITIONS AND SYSTEM INFORMMATION
AMBIENT CONDITIONS:
Unless otherwise specified, the materials shall be operated under the service conditions indicated below.
1. Altitude Above Sea Level
2. Ambient Temperature
Internal type
External type
Maximum average in 24 hours
Average in a 1-year period
3. Wind pressure
4. Wind pressure
5. Maximum solar radiation
6. Icing
7. Openness to industrial pollution
Internal type
External type
8. Openness to lightning impulse
9. Exposure to earthquake
Horizontal acceleration
Vertical acceleration
10. Environmental pollution
Internal type
External type
11. Minimum leakage distance for isolators
Internal type
External type
: maximum 1000 meters
: -5°C/45°C
: -25°C/(*) 45°C
: 35°C
: 25°C
: 70 kg/m2 (on round surfaces)
: 120 kg/m2 (on flat surfaces)
: 500 W/m2
: 10 mm, class 10
: Little
: Available
: Yes
: 0.5g (at the ground level)
: 0.25 g
: Little
: Available
: 12 mm/kV (**)
: 25mm/kV
(*) –40°C at the centers located in the Eastern Anatolia Region
(**) This condition shall not be required for the internal type measurement transformer, but it shall be required
for the other equipment.
253
SYSTEM DATA:
1.Rated Values
a) Normal operating voltage kV rms
b) Max. system voltage kV rms
c) Rated frequency Hz
ç) System earth
d) Max. Radio interference level µV
(RIV) (in system voltage of 1.1 and
in 1 MHz)
e) 3-phase symmetric short circuit
thermal current kA (Ith)
-All primary equipment, busbars and
connections
-Short circuit duration (sec.)
-Dynamic short circuit current
f) Single phase-earth short circuit
current (kA)
2.Isolation Values
(Except for Power Transformer)
a) Lightning impulse resistance
voltage kV-peak
- Against Earth
- Between Open Ends
b) On-Of impulse resistance voltage
kV-peak
- Against Earth
- Between Open Ends
c) Resistance voltage (wet) in power
frequency of 1 min.
kV-rms
- Against Earth
- Between Open Ends
3.Isolation Values
(For Power Transformer)
-Lightning impulse resistance
voltage
kV-peak(phase-earth)
-On-Off impulse resistance voltage
kV-peak
-Resistance voltage (wet) in power
frequency of 1 min. kV-rms
4.Ancillary Service Supply
Voltage:
-3-phase-N AC system
-1-phase-N AC system
- DC system
400
420
50
154
170
50
33
36
50
Direct or over
resistance
10.5
12
50
Direct or over
resistance
Direct
Direct
2500
2500
-
-
50
31.5
25
25
1
2.5x(Ith)
1
2.5x(Ith)
1
2.5x(Ith)
1
2.5x(Ith)
35
20
15
15
400
154
33
10.5
1550
1550(+300)
750
860
170
75
-
-
-
620
760
325
375
70
28
1425
650
170
95 (YG
neutral)
1050
-
-
-
630
275
70
38 (YG
neutral)
1175
(900+430)
380 V + 10% - 15.50% Hz
220 V + 10% - 15.50% Hz
110 V (or 220 V) + 10% - 15%
254
ANNEX 5
SUBSTATION SWITCHYARD
SAMPLE SINGLE LINE DIAGRAMS
PRINCIPLE SINGLE LINE DIAGRAM OF LINE FEEDER OF 400kV FOR TEIAS (*2 MAIN BUSBAR+TRANSFER)
Line Feeder of 400 kV
Busbar 1
Primary Material List for Line Feeder of 400 kV
Busbar 2
No
Material
AP
Pantograph
Disconnector
Normal
Disconnector
Breaker
Current
Transformer
AN
K
C
Characteristic
420kV, 3150A, 50kA
420kV, 3150A, 50kA
D
G
Line Trap
Voltage
Transformer
TB
Ground Blade
420kV, 3150A, 50kA
420kV, 1500-3000/1-1-1-1A, 50kA,
Sn: 0.5+5P20+5P20+5P20
10+60+60+60VA
420kV, 3150A, 0.5 mH, 50kA
420kV, 380/V3:0.1/V3:0.1/V3:0.1/3,
10+50+50VA, Sn: 0.5+3P+3P,
4500pF
420kV, 50kA
Transfer Busbar
Secondary Material List for Line Feeder of 380 kV
Symbol
Name of the Device
DOCEF 67/67N
Directional Overcurrent and
Ground Protection Relay
FR
Z 21
R 79
Scheck 25
OV 59
BBP 87BB
BFB 50BF
Failure Recorder
Distance Protection Relay
Reclosing Relay
Synchronous Control Relay
Overvoltage Relay
Busbar Protection Relay
Breaker Failure Protection
Relay
Energy Analyzer
EA
*Overvoltage (OV 59) relay shall be placed in the lines longer than 100 km.
NOTE 1: The distance protection relay may include reclosing, synchrocheck and failure recorder functions.
NOTE 2: If the feeder has a measurement point, the characteristics of the current and voltage transformers shall comply with the meter communique issued by the EMRA.
NOTE 3: All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an independent laboratory and 2 (two) ea. fiber optic ports supporting
IEC 61850 communication protocol and should support SNTP (Simple Network Time Protocol) function with the sensitivity of 1 milliseconds.
PRINCIPLE SINGLE LINE DIAGRAM OF TRANSFORMER BANK FEEDER OF 400kV/154kV FOR TEIAS (DOUBLE BUSBAR+TRANSFER)
Primary Material List for Transformer Bank Feeder of 400/154 kV
No
Material
G
Voltage
Transformer
AP
Pantograph
Disconnector
Normal
Disconnector
Breaker
Current
Transformer
Current
Transformer
AN
K
C
CI
3A
3B
4P
4A
Current
Transformer
Current
Transformer
5
Pant. Dis.
Normal
Disconnector
Breaker
P
6
Surge Arrester
Surge Arrester
Characteristic
420kV,
380/V3:0.1/V3:0.1/V3:0.1/3,
10+50+50VA, Sn: 0.5+3P+3P,
4500pF
420kV, 2000A, 50kA
Secondary Material List for Transformer Bank
Feeder of 400/154 kV
Name of the Device
Symbol
DOC 50/51
Directional Overcurrent
Relay
EF 50/51N
Ground Relay
DEFP 67N
Directional Ground
Relay
Overload Relay
Differential Protection
Relay
Busbar Failure
Protection Relay
Breaker Failure
Protection Relay
Synchronous Control
Relay
Energy Analyzer
420kV, 2000A, 50kA
420kV, 3150A, 50kA
420kV, 500-1000/1-1A,
5P20+5P20, 60+60VA, 50kA
Bushing type: 420kv, 500/1-1-11A
Sn: 0.5Fs5+10P20,
10P20+10P20,
10+60+60+60VA
Bushing type: 154kv, 1200/1-1A
Sn: 0.5Fs5+10P20, 10+30VA
170kv, 1000-2000/1-1-1-1A,
31.5kA
Sn:0.5Fs5+5P20+5P20+5P10,
10+30+30+30VA
170kV, 2000A, 31.5kA
170kV, 2000A, 31.5kA, (Mot.
Kum.)
170kV, 2000A, 31.5kA, without
Tk
360kV, 10kA, ZnO, Sn: 3
144kV, 10kA, ZnO, Sn: 3
O/L 49
DIF 87
BFP 50BF
BBP 87BB
Scheck 25
EA
NOTE: All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an
independent laboratory and 2 (two) ea. fiber optic ports supporting IEC 61850 communication protocol and should support SNTP
(Simple Network Time Protocol) function with the sensitivity of 1 milliseconds.
255
PRINCIPLE SINGLE LINE DIAGRAM OF LINE FEEDER OF 154kV FOR TEIAS
(DOUBLE BUSBAR)
(BUSBAR+TRANSFER)
Line Feeder of 154 kV
Secondary Material List for Line Feeder of
154 kV
Name of the
Device
DOCEF 67/67 N
Directional
Overcurrent and
Ground Relay
Z 21
Distance
Protection Relay
Primary Material List for Line Feeder of 154 kV
(The rated currents of the feeder equipment shall be selected
higher in compliance with the characteristic of the line to which
they will be connected.)
No
Material
Characteristic
1
Voltage
Transformer
R 79
FR
EA
2
3 (*)
Line Trap
Current
Transformer
4
Disconnector
4T
Disconnector
with
Grounding
Blade
Breaker
Symbol
Reclosing Relay
Failure Recorder
Energy Analyzer
5
170kV,
154/V3:0.1/V3:0.1/V3:0.1/3,
10+10+10VA
Sn: 0.5+3P+3P, 4500pF
170kV, 1250A, 0.5mH
170kV, 400-800-1200-1600/11-1A
31.5kA, Sn: 0.5+5P20+5P20,
10+30+30 VA
170kV, 1250A, 31.5kA, without
Tk
170kV, 1250A, 31.5kA (Mot.
Kum.)
170kV, 2000A, 31.5kA, with
Tk
(*) Busbar and breaker failure protection system shall be installed at all
generation/consumption transformer centers of 400kV and 400/154kV and in the selfcontained generation switches of 154kV. Fort his reason, one more secondary winding shall
be added to the current transformer.
NOTE 1: The distance protection relay may include reclosing and failure recorder functions.
Directional overcurrent and ground relay can be supplied as a set.
NOTE 2: If the feeder has a measurement point, the characteristics of the current and
voltage transformers shall comply with the meter communique issued by the EMRA.
NOTE 3: All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an independent laboratory and 2 (two) ea. fiber optic ports supporting
IEC 61850 communication protocol and should support SNTP (Simple Network Time Protocol) function with the sensitivity of 1 milliseconds.
PRINCIPLE SINGLE LINE DIAGRAM OF TRANSFORMER FEEDER OF 154/34.5kV FOR TEIAS
(DOUBLE BUSBAR)
Transformer Feeder of 154 kV
(BUSBAR+TRANSFER)
Primary Material List for Line Feeder of 154/34.5 kV
No
Material
3
Current
Transformer
4
5
6
7
Disconnector
Breaker
Surge Arrester
Power
Transformer
Neutral
Resistance
r
3a
Current
Transformer
6a
5a
4t
8a
Surge Arrester
Breaker
Ground blade
Cable
To the
busbar
voltage
transformer
of 33 kV
To the
busbar
voltage
transformer
of 33 kV
Characteristic
170kV, 154/V3:0.1/V3:0.1/V3:0.1/3,
10+10+10VA
Sn: 0.5+3P+3P, 4500pF
170kV, 1250A, 31.5kA (Mot. Kum.)
170kV, 2000A, 31.5kA, without Tk
144kV, 10kA, ZnO, Sn: 3
154±8x1.25/34.5kV, 80(100)MVA
Uk:12%, YNyn0
36/V3kv, 1000A, 20ohm
Current Trans.; 36kV 200/5A, 30VA, Sn: 5P5,
25kA
Voltage Trans.; 33/V3:0.1/V3kV, Sn: 3P,
10VA (Single Phase, Internal)
36kv, 2000/1-1-1-1A
Sn:0.2sFs5+0.2sFs5+5P20+5P10
10+10+10+10VA
36kV, 10kA, ZnO, Sn:3
36kV, 2500A, 25kA, without Tk
36kV, 25kaA
36kV, 4x(1x240) mm2/phase XLPE
Secondary Material List for Line Feeder of
154/34.5 kV
Name of the
Device
O/C 50/51
Overcurrent Relay
EF 50/51N
Ground Relay
Symbol
DIF-87
59N
Metal Clad Busbar of 33 kV, 2500A
Metal Clad Busbar of 33 kV, 2500A
EA
Differential Relay
Residual Voltage
Protection Relay
Energy Analyzer
NOTE 1: All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an independent laboratory and 2 (two) ea. fiber optic ports supporting
IEC 61850 communication protocol and should support SNTP (Simple Network Time Protocol) function with the sensitivity of 1 milliseconds.
NOTE 2: If the measurement forming the basis of invoicing is made in the HV side of the transformer, 2 ea. measurement windigs should be added to the current transformer to be used and 3 ea.
voltage transformers of 170kV should be installed.
256
PRINCIPLE SINGLE LINE DIAGRAM OF COUPLING FEEDER OF 154kV FOR TEIAS (DOUBLE BUSBAR)
Coupling Feeder of 154 kV
Primary Material List for Coupling Feeder of 154 kV
No
Material
1
Voltage
Transformer
3
Current
Transformer
4
5
Disconnector
Breaker
Characteristic
170kV, 154/V3:0.1/V3:0.1/3,
10+10VA
Sn: 0.5+3P, 4500pF
170kV, 1000-2000/1-1-1A
31.5kA, Sn: 0.5+5P20+5P20,
10+30+30 VA
170kV, 2000A, 31.5kA (Mot. Kum.)
170kV, 2000A, 31.5kA, without Tk
Secondary Material List for Coupling Feeder of
154 kV
Name of the Device
Symbol
O/CEF 50/51N
Overcurrent and
Ground Relay
25
Synchronous Control
Relay
NOTE: All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an independent laboratory and 2 (two)
ea. fiber optic ports supporting IEC 61850 communication protocol and should support SNTP (Simple Network Time Protocol) function with the sensitivity of 1
milliseconds.
PRINCIPLE SINGLE LINE DIAGRAM OF LINE FEEDER OF 33kV FOR TEIAS SWITCH (METAL CLAD-SINGLE BUSBAR
Primary Material List for Metal Clad Line Feeder of 33 kV
2500A, 33kV, METAL CLAD BUSBAR
No
Material
3
Current
Transformer
Disconnector
with earthing
blade
Breaker
Voltage
Transformer
36kV, 300-600/1-1-1A, 10+10VA
25kA, Sn: 0.2sFs5+0.2sFs5+5P20
36kV, 25kA
Fuse
36kV, 2A
4t
5t
10
11
Characteristic
36kV, 1250A, 25kA with Tk
Secondary Material List for Metal Clad Line
Feeder of 34.5 kV
Name of the Device
Symbol
DOCEF 67/67N
Overcurrent Relay
EA
Energy Analyzer
NOTE: If the users are connected to the MV busbar of TEIAS switch by means of self-contained feeder, 2 ea. combined meters shall be installed.
All protection relays should support IEC 61850 standard, should have Level A type IEC 61850 certificate supplied from an independent laboratory and 2 (two) ea. fiber
optic ports supporting IEC 61850 communication protocol and should support SNTP (Simple Network Time Protocol) function with the sensitivity of 1 milliseconds.
All overcurrent + ground protection relays to be placed into the metal clad cells shall have 3-phase voltage input, reclosing, low voltage protection and low frequency
protection functions.
257
ANNEX 6
SYSTEM VOLTAGE LIMITS
Nominal
Voltage
KV
400 kV
154 kV
Planning
Maximum
KV
420 kV
162 kV
Operating
Minimum
KV
370 kV
146 kV
Maximum
kV
420 kV
170 kV
Minimum
kV
340 kV
140 kV
258
ANNEX 7
PLANNING LIMIT VALUES OF THE POWER QUALITY PARAMETERS
Table 1. Harmonic Voltage Planning Limit Values in the Transmission System of 400 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage
No.
Voltage (%)
(%)
5
2.0
3
1.5
2
1.0
7
1.5
9
0.5
4
0.8
11
1.0
15
0.3
6
0.5
13
1.0
21
0.2
8
0.4
17
0.5
>21
0.2
10
0.4
19
0.5
12
0.2
23
0.5
>12
0.2
25
0.5
>25
0.2+0.5 (25/h)
THBV: 2%
Table 2. Harmonic Voltage Planning Limit Values in the Transmission System of 154 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage (%)
No.
Voltage (%)
“h”
“h”
“h”
5
2.0
3
2.0
2
1.0
7
2.0
9
1.0
4
0.8
11
1.5
15
0.3
6
0.5
13
1.5
21
0.2
8
0.4
17
1.0
>21
0.2
10
0.4
19
1.0
12
0.2
23
0.7
>12
0.2
25
0.7
>25
0.2+0.5 (25/h)
THBV: 3%
Table 3. Harmonic Voltage Planning Limit Values in the Transmission System below 154 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage (%)
No.
Voltage (%)
“h”
“h”
“h”
5
3.0
3
3.0
2
1.5
7
3.0
9
1.2
4
1.0
11
2.0
15
0.3
6
0.5
13
2.0
21
0.2
8
0.4
17
1.6
>21
0.2
10
0.4
19
1.2
12
0.2
23
1.2
>12
0.2
25
0.7
>25
0.2+0.5 (25/h)
THBV: 4%
259
Table 4. Harmonic Voltage Compliance Limit Values in the Transmission System of 400 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage (%)
No.
Voltage (%)
5
7
11
13
17
19
23
25
>25
THBV: 3.5%
3,0
1,5
1,0
1,0
0,5
0,5
0,5
0,5
0,2+0,3 (25/h)
3
9
15
21
>21
1,7
0,5
0,3
0,2
0,2
2
4
6
8
10
12
>12
1,0
0,8
0,5
0,4
0,4
0,2
0,2
Table 5. Harmonic Voltage Compliance Limit Values in the Transmission System of 154 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage (%)
No.
Voltage (%)
“h”
“h”
“h”
5
4,0
3
2,0
2
1,0
7
2,0
9
1,0
4
0,8
11
1,5
15
0,3
6
0,5
13
1,5
21
0,2
8
0,4
17
1,0
>21
0,2
10
0,4
19
1,0
12
0,2
23
0,7
>12
0,2
25
0,7
>25
0,2+0,5 (25/h)
THBV: 5%
Tablo 6. Harmonic Voltage Compliance Limit Values in the Transmission System below 154 kV
Odd Harmonics
Odd Harmonics
Even Harmonics
(not being the multiples of 3)
(being the multiples of 3)
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
Harmonic
No.
Voltage (%)
No.
Voltage (%)
No.
Voltage (%)
“h”
“h”
“h”
5
5,0
3
3,0
2
1,9
7
4,0
9
1,3
4
1,0
11
3,0
15
0,5
≥6
0,5
≥13
2,5
21
0,5
THBV: 8%
Table 7. Flicker Planning Limit Values
Voltage Level (V)
V ≥ 154 kV
31.5 kV ≤ V < 154 kV
1 kV ≤ V < 31.5 kV
Flicker Intensity
Pst (Short Term)
Plt (Long Term)
0.85
0.63
0.97
0.72
1.0
0.8
260
ANNEX 8
HARMONIC LIMITS
Table 1. Allowable Current Harmonic Limits
Harmonic
Sequence
No
ODD HARMONICS
Group
1 kV<V≤34.5 kV
34.5 kV <V≤154 kV
Ik/IL
Ik/IL
20- 50- 100>
20- 50- 100>
<20
<20
<20
50 100 1000 1000
50 100 1000 1000
h<11
4
11≤h<17
2
7
10
12
15
2
3.5
5
6
7.5
1
1.8
2.5
3
3.8
3.5 4.5
5.5
7
1
1.8
2.3
2.8
3.5
0.5
0.9
1.2
1,4
1.8
4
5
6
0.8
1.25
2
2.5
3
0.4
0.6
1
1,25
1.3
1.5
2
2.5
0.3
0.5
0.75
1
0.4
0,5
0.6
0.3 0.5 0.7
1
1.4
0.15 0.25 0.35
0.75 0.12 0.17 0.25
0.35
17≤h<23
1.5 2.5
23≤h<35
0.6
h≥35
V>154 kV
Ik/IL
20- 50- 100>
50 100 1000 1000
1
0.5
1.25 0.15 0.25
0.7
The even harmonics are limited to 0.25 times of the odd harmonic before them.
TTB
5
8
12
15
20
2.5
4
6
7.5
10
1.3
2
3
3.75
5
These values are the average values of 10 minutes measured with 3-second resolution.
Ik: Maximum short circuit current at the common connection point
IL: Main component of the maximum load current at the common connection
point
Total Demand Distortion (TDD: The value which is the ratio of the square root of the total sum of the squares
of the effective values of the current harmonic components to the maximum load current (I L), and which
expresses the distortion in the waveform in percentage, and which is calculated using the following formula.
40
TTB 
 (I h )
h2
IL
2
x100
261
ANNEX 9
SITE RESPONSIBILITY SCHEDULES:
MAIN PRINCIPLES TO BE APPLIED IN THE PREPARATION OF THE SITE
RESPONSIBILITY SCHEDULES
E.9.1
Site responsibility schedules and their scope
For the connection agreements entered into between TEIAS and the user over the voltage
levels of 400 kV and/or 154 kV, site responsibility schedules shall be prepared. If any information
not included in the schedule is required, an additional arrangement is made between the parties.
The site responsibility schedules shall be drawn up under the title: Schedule for HV
equipment. Each page of the said schedule shall bear the schedule date and number.
In the schedule for HV equipment;
a) List of the HV installations and/or equipment,
b) Ownership of the HV installations and/or equipment,
c) Site supervisor (operating engineer of the user party)
ç) Matters related to the safety rules, and the person responsible for application of such rules
(operating engineer or other responsible engineer of the user party),
d) Matters related to the operating procedures to be applied,
e) Control engineer or other responsible engineer (engineer responsible for the facility during
construction of the facility),
f) Party responsible for the legal audits, short-circuit inspections and maintenance (Power Plant
supervisor), and
g) Contact phone number of the person who performed the short-circuit inspection and
maintenance
shall be indicated with the connection points open in the connection site field of the site
responsibility schedules.
E.9.2
Details
In the site responsibility schedule included in E.9.1.; with respect to the protection and
auxiliary service equipment, the management unit in-charge must be specified as well as the user
and TEIAS.
E.9.3
In the site responsibility schedule for HV equipment, the lines and cables entering into,
going out from and directly passing through the switchyard are indicated.
E.9.4
The site responsibility schedule is signed by the person responsible for the area where
the facility is located in on behalf of TEIAS and the authorized person on behalf of the
concerned user.
E.9.5
Distribution of the site responsibility schedule
After it is signed by the parties, the site responsibility schedule shall be made available in a
place visible to the facility staff. At the request of TEIAS, it shall be submitted by the relevant user to
TEIAS.
262
E.9.6
Modification of the site responsibility schedules
If TEIAS or the user requests for any modification or correction to be made in the site
responsibility schedules, the modified site responsibility schedules shall be prepared and notified to
TEIAS or the user.
E.9.7
Urgent changes
If a change is requested to be made in the site responsibility schedules, the parties notify each
other without no delay and confirm in written. In this case, the following considerations are
negotiated:
a) Changes requested to be made in the site responsibility schedule and reasons for such
changes,
b) Whether the change is permanent or temporary,
c) If the change is accepted by the parties, the distribution of the renewed site responsibility
schedule.
E.9.8
Authorized persons
TEIAS and the users submit the nomenclature list of the persons authorized to sign the site
responsibility schedules on behalf of them to each other. In case of a change in these lists, TEIAS and
the users notify each other without delay.
263
ANNEX 10
SAMPLE CONNECTION SINGLE LINE DIAGRAMS
FOR GENERATION AND CONSUMPTION PLANTS
Demand Connection
154 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
33 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
18 LINE FEEDERS (9
FEEDERS FOR EACH
TRANSFORMER)
DISCONNECTOR
POWER
TRANSFORMER
Demand Connection
(Designed as MV Shaft Metal-Clad Type)
154 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
BREAKER
DISCONNECTOR
POWER
TRANSFORMER
9 LINE FEEDERS
9 LINE FEEDERS
METAL-CLAD CELL
264
Demand Connection
154 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
18 LINE FEEDERS (9
FEEDERS FOR EACH
TRANSFORMER)
18 LINE FEEDERS (9
FEEDERS FOR EACH
TRANSFORMER)
BREAKER
DISCONNECTOR
POWER
TRANSFORMER
Demand Connection
154 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
9 LINE FEEDERS
9 LINE FEEDERS
9 LINE FEEDERS
BREAKER
DISCONNECTOR
POWER
TRANSFORMER
AUTOTRANSFORMER
REACTOR
9 LINE FEEDERS
METAL-CLAD CELL
265
Demand Connection
400
400
7 LINE FEEDERS
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
154 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
5 LINE FEEDERS
DISCONNECTOR
18 LINE FEEDERS (9
FEEDERS FOR EACH
TRANSFORMER)
POWER
TRANSFORMER
AUTOTRANSFORMER
REACTOR
Demand Connection
400
400
7 LINE FEEDERS
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
DISCONNECTOR
POWER
TRANSFORMER
5 LINE FEEDERS
AUTOTRANSFORMER
9 LINE FEEDERS
9 LINE FEEDERS
REACTOR
METAL-CLAD CELL
266
Demand Connection
400
7 LINE FEEDERS
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
DISCONNECTOR
10 LINE FEEDERS
AUTOTRANSFORMER
REACTOR
267
Demand Connection
400
7 LINE FEEDERS
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
10 LINE FEEDERS
DISCONNECTOR
AUTOTRANSFORMER
REACTOR
Demand Connection
400
7 LINE FEEDERS
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
DISCONNECTOR
10 LINE FEEDERS
AUTOTRANSFORMER
REACTOR
268
Generation Connection
400 kV
400 ≥ 1540 MW
2400 MW ≥ Generation
TOTAL GENERATION CAPACITY OF THE UNITS IS 1200 MW
TOTAL GENERATION CAPACITY OF THE UNITS IS 1200 MW
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
4 LINE FEEDERS
3 LINE FEEDERS
BREAKER
DISCONNECTOR
REACTOR
Generation Connection
400 kV
400≥ Generation
770 MW
400
KKK
MAIN BUSBAR-I
MAIN BUSBAR-II
KKK
TRANSFER
kV
v
kV
7 LINE FEEDERS
BREAKER
DISCONNECTOR
REACTOR
269
Generation Connection
154 kV
770 MW ≥ Generation
MAIN BUSBAR-I
MAIN BUSBAR-II
BREAKER
DISCONNECTOR
Generation Connection
400+ 154 kV
2400 MW ≥400
Generation ≥ 770 MW
400 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
7 LINE FEEDERS
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
10 LINE FEEDERS
DISCONNECTOR
AUTOTRANSFORMER
REACTOR
270
Generation Connection
33 kV
50 MW ≥ Generation
33 kV
MAIN BUSBAR-I
MAIN BUSBAR-II
TRANSFER
BREAKER
DISCONNECTOR
Generation Connection
33 kV
50 MW ≥ Generation
9 LINE FEEDERS
BREAKER
DISCONNECTOR
METAL-CLAD
CELL
271
ANNEX 11
PLANNING DATA
SECTION 1
E.11.1
STANDARD PLANNING DATA
E.11.1.1
Switchyard and user system data
.11.1.1.1
General
The user reports the data in relation to its system to TEIAS as described in E.11.1.1.2 and
E.11.1.1.3.
E.11.1.1.2
User system diagram
The user system single line diagram includes the current and recommended status, equipment
capacity and number of the connections and primary distribution systems.
E.11.1.1.3
Short circuit analysis data
a) (+), (-) and zero component impedances at the connection point between two systems
before and after the connection of the user system to the transmission system,
b) Contributions of synchronous generator, electrogen groups and/or synchronous/induction
motor and/or shunt capacitors included in the user system to the short circuit currents in
case of the occurrence of 3-phase earth and single-phase earth short circuit fault under
peak time load conditions in the transmission system.
E.11.1.2
Demand data
E.11.1.2.1
General
The users report the demand data of the previous year, which occurred at the connection
point, the estimated demand data of the current year and the following ten years to TEIAS as
specified in E.11.1.2.2, E.11.1.2.3 and E.11.1.4 by the end of January every year.
The annual peak time and minimum demand of the current year and the following ten
years are reported, including the days and times of the same, by TEIAS to the users by the end of
February every year.
The users report the additional demand estimations they made according to the operating
conditions at the connection point to TEIAS by the end of March every year. In the cases that
these estimations are not reported, it is considered that the final information available in TEIAS
is valid.
E.11.1.2.2
Active and reactive demand data
The active and reactive demand data concerning the internal needs of the power plants
supplying such needs from the distribution system, except for the losses in the distribution lines
and the generation of the units not included in the compensation based on the distribution
system, is provided by the distribution company.
User demand data is drawn up as follows;
a) The demand powers on the dates to be determined by TEIAS in connection with the
maximum summer and winter peak time and minimum loading of the system,
b) The highest demand power on and at the user’s own peak time day and time,
c) The highest demand power of the month on a monthly basis,
ç) The annual energy demand in MWh,
d) The net output powers of the units which are not subject to compensation and which are
directly connected to the user system,
e) The change of demand as per the voltage and frequency,
272
f) The harmonic components and amplitudes caused by the demand in the transmission
system,
g) The average and maximum phase instabilities caused by the demand in the transmission
system,
ğ) The daily, monthly and annual load curves,
h) The daily, monthly and annual load curves for the residence, place of business, state
office, school, hospital, industry, agricultural irrigation and non-tariff subscribers (Every
three months shall be considered as a season, beginning from January. In connection with
every season; the hourly peak time values for the sample day representing each of
Saturday, Sunday, Monday, Wednesday and the monthly energy consumption and the
daily, monthly and annual load curves of these consumer groups.).
E.11.1.2.3
Loads above 5 MVA
The users report the detailed load characteristics for the demands above 5MVA to TEIAS.
This group includes Arc Furnaces, steel processing workshops, subway and railways catenary supply
systems, flicker, voltage fluctuations and the loads that might affect the customers.
The data necessary for this type of loads:
a) The periodically changing active and reactive energy demands,
b) The period of the change,
c) The part of the demand remaining constant during periodical change,
ç) In the case that lack of supply occurs, the disconnection required to be made in active and
reactive demand in order to prevent the output voltage in the user busbar from dropping,
d) The maximum active and reactive power demands within a periodical time,
e) The highest energy demand within the periodical time.
E.11.1.3
Power plant data
E.11.1.3.1
General
The users report the data of the previous year, current year and the following ten years to
TEIAS as specified in E.11.1.3.2, E.11.1.3.3 and E.11.1.4.
The legal entities connected to the transmission system and engaged in generation activity
report the following information to TEIAS. The power plants not directly connected to the
transmission system, but connected to the user grid or to the distribution system report this
information to TEIAS, as well.
a) The power plant data for the case that the power plant or the unit is directly connected to
the transmission system via a busbar,
b) The power plant data for the case that the power plant or the unit is connected to the
transmission system over the user grid or the distribution system.
E.11.1.3.2
Power plant data
a) The geographical, electrical location and voltage of the point at which the power plant is
connected to the transmission system,
b) The installed capacity and minimum output power of the power plant,
c) The active and reactive internal consumption,
ç) The generation program.
While projecting the demand of the distribution system, the unit number of the power
plants directly connected to the distribution system and their total capacity are deducted from the
demand.
273
E.11.1.3.3
Unit data
a) Output power and voltage,
b) Power factor,
c) Annual operating period,
ç) Annual energy generation,
d) Generation capacity,
e) Contractual capacity,
f) Loading curve,
g) Active and reactive internal consumption,
ğ) Inertia constant,
h) Short circuit ratio,
ı) Vertical axis transient reactance (x’d),
i) Vertical axis sub-transient time constant (T”d),
j) Capacity, positive component reactance and step adjustments of the main power
transformer,
k) Availability schedule of the power plant,
l) Heat consumption (kcal/kwh),
m) Fuel consumption (gr/kwh, ton/year, m3/kwh, m3/year),
n) Fuel type,
o) Average thermal value of the fuel (kcal/kg),
ö) Auxiliary fuel type and amount,
p) Unit type and turbine revolution,
r) Unit investment ($/kW), overheads ($/kW-month), and variable operating costs
(cent/kwh),
s) Annual CO, CO2, CH4, NOx, SOx and dust emissions (gr/kwh),
ş) Emission properties determined before the establishment of the emission control plant
(CO, CO2, CH4, NOx, SOx and dust) (gr/kwh),
t) Efficiency of the emission control plants such as electro-filter, flue gas treatment plant
(%).
E.11.1.3.4
Hydroelectric power plant data
The data given above shall be prepared and notified to TEIAS for the hydroelectric power
plants as well.
E.11.1.4
Power plant data
E.11.1.4.1
Monthly power plant operating data (The data of the current month shall be
given by the end of the first week of the following month.)
E.11.1.4.1.1 Thermal power plant data
a) Gross generation (kWh)
b) Power plant internal consumption (kWh)
c) Net generation (kWh)
ç) Fuel quantity (Ton or sm³)
E.11.1.4.1.2 Hydraulic power plant data
a) Gross generation (kWh)
b) Power plant internal consumption (kWh)
c) Net generation (kWh)
ç) Incoming water quantity (m³)
274
E.11.1.4.1.3 Geothermal and Wind power plant data
a) Gross generation (kWh)
b) Internal consumption (kWh)
c) Net generation (kWh)
E.11.1.4.2 Short-term supply-demand projection power plant data (The data of the next
year shall be given by the end of March in the current year.)
a) Project generation (kWh)
b) Gross generation (kWh)
c) Internal consumption (kWh)
ç) Net generation (kWh)
E.11.1.4.3 Monthly power plant data of the previous year (shall be given by the end of
February in the current year.)
E.11.1.4.3.1 Monthly thermal power plant data of the previous year
a) Gross generation (kWh)
b) Internal consumption (kWh)
c) Net generation (kWh)
ç) Fuel quantity (Ton/sm³)
E.11.1.4.3.2 Monthly hydraulic power plant data of the previous year
a) Gross generation (kWh)
b) Internal consumption (kWh)
c) Net generation (kWh)
ç) Total incoming water quantity (m³)
d) Incoming flow rate (m³/sec)
e) Water used for energy (m³)
f) Vaporization (m³)
g) Water discharged from the spillway (m³)
ğ) Water used as drinking and potable water (m³)
h) Water used for bottom outlet and irrigation (m³)
ı) Leakage and losses (m³)
i) Total water quantity used (m³)
j) Lake level at the beginning of the month / at the end of the month (m)
k) Water quantity in the lake at the beginning of the month / at the end of the month (m³)
l) Water energy ratio (m³/kWh)
E.11.1.4.3.3 Monthly geothermal and wind power plant data of the previous year
a) Gross generation (kWh)
b) Internal consumption (kWh)
c) Net generation (kWh)
275
SECTION 2
E.11.2
DETAILED PLANNING DATA
E.11.2.1
Switchyard and user system data
E.11.2.1.1
General
The users report the detailed information concerning their systems to TEIAS as described
in E.11.2.1.2 and E.11.2.1.11.
E.11.2.1.2
User system diagram
a) Busbar architecture,
b) Lines, cables, transformers, circuit breakers, splitters and protection and measurement
system,
c) Phase sequence,
ç) Earthing mechanism,
d) Switching and locking mechanisms,
e) Operating voltages,
f) Procedures and principles for numbering and naming of the equipment.
E.11.2.1.3
Reactive compensation system data
The following information is prepared for the reactive compensation plants in the user system;
a) Whether the output of the reactive compensation system is constant or variable,
b) Operating range of the reactive compensation system in capacitive and/or inductive
zones,
c) Step adjustments of the reactive power output,
ç) Automatic control properties and adjustments of the reactive power output,
d) Connection point of the reactive compensation system to the user system.
E.11.2.1.4
The effect of the user system on the short circuit power of the transmission
system
The user reports the following information to TEIAS for the examination of the effect of its
system on the short circuit power of the transmission system;
a) Maximum 3-phase earth short circuit power at the connection point, including the units
connected to the user system,
b) Additional 3-phase earth short circuit power to be supplied from synchronous generators,
electrogen groups and/or synchronous/induction motor and/or shunt capacitors connected
to the user system,
c) (+), (-) and zero component impedances of the user system.
E.11.2.1.5
System susceptance
The user reports the information concerning the equivalent system susceptance at the
connection point between the user system at nominal frequency and the transmission system to
TEIAS. This information also include the data about the shunt reactors which are the integral part of
the wiring under normal conditions and which are not out of service independently from the cable.
This information does not include the following:
a) Independent reactive compensation plants in the user system,
b) User system susceptance in the active and reactive power additional demand data
specified in E.11.2.3.2.
276
E.11.2.1.6
Connection impedance
The users provide the values including equivalent resistance, reactance and shunt susceptances
in connection with their system to TEIAS. If TEIAS considers that these values are low, more
detailed information about the equivalent impedance or the resistance component of the user system
equivalent impedance may be requested from the user.
E.11.2.1.7
Demand transfer
If the demand is jointly supplied from more than one point in the transmission system, the
ratio of the demands at each of these points to the total demand is reported by the user to TEIAS.
Moreover, the demand transfer processes carried out manually or automatically on these demands
during troubleshooting and maintenance works and the periods necessary for these processes are
reported by the user to TEIAS.
If it is possible for the demand to be supplied from alternative points in the transmission
system, the possibilities for the demand to be transferred to these alternative points and the transfer
periods are reported by the user to TEIAS.
E.11.2.1.8
System data
The user provides the following data in relation to the high voltage system.
(a) System parameters:
-
Nominal voltage (kV),
Operating voltage (kV),
Positive component reactance,
Positive component resistance,
Positive component susceptance,
Zero component reactance,
Zero component resistance,
Zero component susceptance
(b) Transformers between the high voltage grid and the user grid:
-
MVA capacity,
Voltage ratio,
Connection manner of windings,
Positive component resistance projected by taking into consideration maximum,
minimum and nominal steps of windings,
Positive component resistance projected by taking into consideration maximum,
minimum and nominal steps of reactance,
Zero component reactance,
Step adjustment range,
Tap change step number,
Tap-changer type: on-load off-circuit,
Tap-changer type: analogue, numerical, BCD
(c) Primary feeder equipment connected to the connection point of the transmission system,
including the power plants;
-
Nominal voltage (kV),
Nominal current (A),
Nominal short circuit breaking current, 3-phase (kA),
277
-
Nominal short circuit breaking current, 1-phase (kA),
Nominal load breaking current, 3-phase (kA),
Nominal load breaking current, single-phase (kA),
Nominal short circuit closing current, 3-phase (kA),
Nominal short circuit closing current, single-phase (kA)
E.11.2.1.9
Protection system data
The user provides the following information concerning the protection systems at the
connection points and their adjustments to TEIAS.
a) Comprehensive information about the relays and protection systems in the user grid,
including their adjustments,
b) Comprehensive information about the reclosing assembly in the user grid,
c) Comprehensive information about the unit, unit transformers, start-up transformers,
internal needs transformers and the relays and protection systems on the connections in
relation to the same, including their adjustment,
ç) Removal periods of the electrical faults at the unit outputs with one circuit breaker,
d) Removal periods of the faults in the user grid.
E.11.2.1.10 Earthing data
The user provides the data of the earthing system on its grid, in relation to the projection
and measurements, including the impedances, to TEIAS.
E.11.2.1.11 Temporary over-voltage data
For the isolation coordination works, the over-voltage examination should be performed by
TEIAS. The user, if requested by TEIAS, provides the arc impedance values it projected for its own
system in relation to the connection point of the transmission system and the details of these
projections. TEIAS, if necessary, may request for more detailed information about the physical
dimensions of the plant and/or equipment and about the properties of the equipment and protection
tools directly connected to the transmission system.
E.11.2.2
Demand data
E.11.2.2.1
General
a) The users report, with respect to the demand, the information obtained the previous and
current year and expected for the following ten years to TEIAS as specified in E.11.2.2.3
and E.11.2.3.2.
b) The users provide the additional demand estimated data indicating the changes in the
demand estimations to TEIAS for the correct determination of the total demand in
different periods of the year.
E.11.2.2.2
Active and reactive power demand of the user
After deducting the generations of the power plants included in the user system and not being
subject to compensation, the remaining demand values are provided for every day on an hourly basis
as follows:
a) Date on which the active power peak time occurs in the user system,
b) Date on which the minimum active power occurs in the user system,
E.11.2.2.3
Customer demand management data
The demand drop made in active and reactive demand due to the reasons arising from the user,
the notifications made to the consumers before the demand drop in order to realize it, the periods of
278
the demand drops and the total number of the demand drops within the year are submitted to TEIAS.
The examination and evaluation about whether these demand drops are acceptable in terms of period
and number are carried out by TEIAS at the end of the year. The outcomes of this examination are
notified by TEIAS to the distribution company.
E.11.2.3
Power plant data
E.11.2.3.1
General
The generation companies having power plants with units of 50 MW and above or with
total installed capacity of 100 MW and above provide the information stated from E.11.2.3.2 to
E.11.2.3.9 to TEIAS.
E.11.2.3.2
Additional demand
a) Internal needs load of the unit under nominal load,
b) If the internal needs of the unit are supplied from the transmission or distribution system,
the additional internal needs of the unit should be indicated together with the unit power.
E.11.2.3.3
Unit parameters
a) Nominal output voltage (kV),
b) Nominal apparent power output (MVA),
c) Nominal active power output (MW),
ç) Minimum active power (MW),
d) Short circuit ratio,
e) Vertical axis synchronous reactance: (Xd),
f) Vertical axis transient reactance: (Xd),
g) Vertical axis sub-transient reactance: (Xd),
ğ) Vertical axis transient time constant: (Td),
h) Vertical axis sub-transient time constant: (Td),
ı) Horizontal axis synchronous reactance: (Xq),
i) Horizontal axis transient reactance: (Xq),
j) Horizontal axis sub-transient reactance: (Xq),
k) Horizontal axis transient time constant: (Tq),
l) Horizontal axis sub-transient time constant: (Tq),
m) Stator time constant: (Ts),
n) Stator resistance: (Rs),
o) Stator leakage reactance: (Xls),
ö) Turbogenerator inertia constant (MWsec/MVA) - (H),
p) Nominal excitation current: (If),
r)Unit terminal and voltage as well as the exciting current (I f) open circuit saturation curve by
using the values corresponding the range between 50 % and 120 % of the nominal voltage
taken by 10 % steps from the compliance certificates of the generation companies.
E.11.2.3.4
Step-up transformer parameters
a) Nominal apparent power (MVA),
b) Rate of voltage change,
c) Positive component resistance projected by taking into consideration maximum,
minimum and nominal steps of windings,
ç) Positive component reactance projected by taking into consideration maximum, minimum
and nominal steps of windings,
d) Zero component reactance,
e) Step adjustment range,
279
f)
g)
ğ)
h)
Tap change step number,
Tap-changer type: on-load or off-circuit,
Tap-changer type: analogue, numerical, BCD
Connection group.
E.11.2.3.5
Internal needs transformer parameters
a) Nominal apparent power (MVA),
b) Rate of voltage change,
c) Zero component reactance measured on the side of high voltage.
E.11.2.3.6
Excitation control system parameters
a) Excitation circuit DC gain,
b) Nominal excitation voltage,
c) Minimum excitation voltage,
ç)Maximum excitation voltage,
d) Maximum rate of change for the increased excitation voltage,
e) Minimum rate of change for the decreased excitation voltage,
f) Excitation circuit block diagram,
g) Dynamic properties of the over-excitation limiter,
ğ) Dynamic properties of the under-excitation limiter,
h) Power system stabilizer (PSS) parameters.
E.11.2.3.7
a)
b)
c)
ç)
d)
e)
f)
g)
ğ)
h)
ı)
i)
j)
Speed governor parameters for the gas turbine units of the resuperheater
system
HP (high pressure) speed governor average gain MW/Hz,
Booster engine adjustment range,
HP control valve time constant,
HP control valve opening limits,
HP control valve speed limits,
Resuperheater system time constant,
MP (medium pressure) speed governor average gain MW/Hz,
MP speed governor adjustment range,
MP control valve time constant,
MP control valve opening limits,
MP control valve speed limits,
Details of the parts sensitive to the acceleration in HP and MP speed governor circuit,
Speed governor block diagram.
E.11.2.3.8
Speed governor parameters for the gas turbine units without resuperheater
a) Speed governor average gain,
b) Booster engine adjustment range,
c) Steam or fuel control valve time constant,
ç) Control valve opening limits,
d) Control valve speed limits,
e) Turbine time constant,
f) Speed governor block diagram.
E.11. 2.3.9 Speed governor parameters for hydroelectric groups
a) Permanent speed-droop of the speed governor,
b) Temporary speed-droop of the speed governor,
c) Speed governor time constant,
280
ç)
d)
e)
f)
g)
ğ)
h)
ı)
i)
Filter time constant,
Servo time constant,
Inlet speed limit,
Maximum inlet limit,
Minimum inlet limit,
Water inlet time constant,
Turbine gain,
Turbine loss,
No-load flow.
E.11.2.3.10 Power plant flexibility performance
a) Cold starting rate of loading for the unit,
b) Warm starting rate of loading for the unit,
c) Block load following synchronization,
ç) Rate of load drop from the nominal capacity,
d) Control range,
e) Capability of load shedding.
E.11.2.4
Additional data
E.11.2.4.1
General
TEIAS, if necessary, may request additional data from the users for the system surveys.
281
ANNEX 12
ADJUSTMENT PROCEDURE FOR POWER SYSTEM STABILIZER (PSS)
E.12.1 PURPOSE AND SCOPE
The purpose of installing Power System Stabilizer (PSS) in the Synchronous
Power Generating Modules is to damp the oscillations arising in the transmission
system, and thus, contribute to the safe, reliable and stable operation of the
interconnected system and also to increase the transnational electric energy trade
volume.
Analysis based on the computer simulations included in the scope of this
Procedure are one of the most important processes, and the PSS which is an additional
control loop to the alternator, excitation system and automatic voltage regulator (AVR)
should be modelled and verified by means of the field tests.
For the PSS performance dynamic analyses to be able to be performed in the
computer environment, all data specified in the sections E.12.2, E.12.3. and E.12.4. of
this annex should be given to TEIAS. The PSS setting procedure consists of 3 stages:
a) Giving the data related to the alternator and excitation system (AVR+PSS) and
verified models to TEIAS,
b) Making the PSS settings,
c) Performing the PSS verification tests and submitting the related report to
TEIAS.
E.12.2 GENERATOR DATA TO BE REQUESTED
SYNCHRONOUS POWER GENERATING MODULES
FROM
THE
The generator data that is requested for each unit the Maximum Capacity per unit
of which is above 75 MW in the Synchronous Power Generating Module is given in
the Table-E.12.1.
Table-E.12.1- Generator Data Requested from the Generating unit
Parameter
Name
Producing Company
Type
Year of Connection
Nominal Apparent Power
Nominal Stator Voltage
Nominal Speed (corresponding to 50Hz)
Stator Leakage Reactance
Armature (stator) resistance
Reference Heat for excitation resistance
D-axis synchronous reactance (unsaturated)
Negative sequence impedance
Zero Sequence impedance and earthing type
D-axis temporary state synchronous reactance
(unsaturated)
D-axis sub-temporary synchronous reactance
(unsaturated)
Q-axis synchronous reactance (unsaturated)
282
Symbol
(Unit)
-
Year
Sn [MVA]
Un [kV]
fn [rpm]
Xl [pu]
ra [pu]
Tref [oC]
Xd [pu]
X- [pu]
X0 [pu]
Xd' [pu]
Xd'' [pu]
Xq [pu]
Value
Q-axis temporary state synchronous reactance
(unsaturated)
Q-axis sub-temporary synchronous reactance
(unsaturated)
D-axis no-load (open circuit) temporary state
time constant
D-axis no-load (open circuit) sub-temporary
state time constant
Q-axis no-load (open circuit) temporary state
time constant
Q-axis no-load (open circuit) sub-temporary
state time constant
D-axis short circuit temporary state time
constant
D-axis short circuit sub-temporary state time
constant
Q-axis short circuit temporary state time
constant
Q-axis short circuit sub-temporary state time
constant
Inertia Constant
Excitation resistance in Tref
Loading Curve
Open Circuit and Closed Circuit Curves
Earthing Type and Impedance
Xq' [pu]
Xq'' [pu]
Td'o [s]
Td''o [s]
Tq'o [s]
Tq''o [s]
Td' [s]
Td'' [s]
Tq' [s]
Tq'' [s]
H
[MWs/MVA]
Rf [Ohm]
[Ohm]
The data listed in the Table-E.12.1 is requested to form the sixth level
synchronous generator model on dq0 plane used in all dynamic analysis works related
to the alternator excitation systems, which will be performed by TEIAS. This data is
requested for each unit the unit power of which at the Synchronous Power Generating
Module is 75 MW or above. It is also possible to provide the values of the equivalent
circuit elements on dq0 plane (self-resistance, self-inductance and common inductance
values for the equivalent windings on dq0 plane) instead of the time constants and
reactance values given in the Table-E.12.1.
E.12.3 GROUP TRANSFORMER DATA TO BE REQUESTED FROM THE
SYNCHRONOUS POWER GENERATING MODULE
The Group Transformer Data requested for each unit the Maximum Capacity per
unit of which is above 75 MW in the Synchronous Power Generating Module is given
in the Table-E.12.2.
Table-E.12.2 – Group Transformer Data to be requested from the Power
Generating Modules
Parameter
Name
Producing Company
Type
Nominal Apparent Power
Nominal Primary Voltage
Nominal Secondary Voltage
Positive
Sequence
Serial
283
Symbol
(Unit)
-
Sn [MVA]
U1n [kV]
U2n [kV]
x1sc [%]
Value
Reactance
Negative
Sequence
serial
resistance
Zero Sequence serial reactance
and earthing type
Number of Taps
Tap change (total)
Earthing type
Connection Group (a.k.a. Vector
Group)
1. symmetry, upper-case letter:
HV
2. symmetry, lower-case letter:
LV
3.
symmetry,
number:
counterclockwise
phase
transposition (each internumber is
30 degree) (LV is behind HV)
%
%
+/%
E.12.4 EXCITATION SYSTEMS DATA TO BE REQUESTED FROM THE
SYNCHRONOUS POWER GENERATING MODULE
For the system stability analyses, the block diagrams corresponding to the IEEE
standard models of the Automatic Voltage Regulator (AVR) and the Power System
Stabilizer (PSS) in the Synchronous Power Generating Modules the pertinent values
corresponding to the parameters in these diagrams should be notified by the concerned
Power Generating Facility operator to TEIAS.
E.12.5 SETTING OF POWER SYSTEM STABILIZER (PSS)
Settings of the power system stabilizer are made by the user in accordance with this
Procedure when it is considered necessary by TEIAS. TEIAS will be informed of the date
of setting works at least 1 week before that date. TEIAS may have observers present during
the setting works if it considers it necessary.
The PSS settings shall be made so as to increase the absorption rate of all
electromechanical fluctuations in the frequency band of 0.1–3.0 Hz that might arise
during the operation. For this purpose, the PSS settings can be made in a way that the
inter-zone fluctuation, local fluctuation, inter-machine fluctuation and torsional shaft
fluctuation modes that might occur during the operation and by observing the
following setting recommendations a), b), c) and d).
The compliance of the results of the site test or the computer simulation
performed during the setting procedures with the following setting recommendations
a), b), c) and d) and to the performance requirements set out in this annex shall be
reported to TEIAS. It shall not be allowed to proceed to the performance stage of the
PSS verification tests without obtaining the approval of TEIAS. At the approval stage,
TEIAS may propose a parameter set that is different from the one reported to TEIAS.
The following recommendations a), b), c) and d) are not a detailed PSS setting
methodology. These recommendations are included in order to specify the minimum
criteria to the expert to carry out the PSS setting procedure. The local requirements of
the system may bring additional arrangements to the following recommendations.
284
a) The time constants of the cleaning filter that filters the PSS input signals shall
be drawn to an effective value for the pertinent modes. (It is recommended to
select time constants lower than 10 seconds.)
b) Upon completion of the aforementioned step; for the PSS, automatic voltage
regulator, excitation system and alternator, the phase characteristics of the
transfer function with the input signal defined as the rotor speed measurement
(PSS input) of the relevant unit and with the output signal defined as the active
power of the relevant unit shall be corrected with the PSS so as to be within the
range of ±30o within the frequency band of 0.1 – 3.0 Hz. (Grey shaded zone in
the FigureFigure-E.12.).
In the cases where there is a dangerous shaft fluctuation mode for the said unit, it
is under the responsibility of the excitation system producer that the phase
characteristics indicated in 1 have been adjusted with the PSS so as to be within the
range of ±30o within the frequency band of 0.1 – 4.0 Hz.
Phase (Degree)
Bode Diagram (Electrical Power / Rotor Speed)
Frequency (Hz)
Figure-E.12.1
–
Zone
recommended
for
PSS+AVR+Excitation
System+Alternator Phase Characteristic (For Electrical Power / Rotor Speed Transfer
Function)
c) After the settings suitable for the phase characteristics indicated in the FigureE.12. have been made, the PSS gain shall be adjusted so that the absorption rate
(ζ) will be 0,707 ≤ ζ < 1 for the most dominant (the one with the highest virtual
part/real part ratio) local fluctuation modes under the weakest transmission
system conditions. If noise amplification occurs or interaction is observed
between the excitation system, alternator and PSS due to the high PSS gain
during the site tests, the PSS gain value can be reduced to a safe value to be
determined by the excitation system producer (or the excitation system expert
approved by the excitation system producer), provided that it will be approved
by TEIAS.
285
ç) The PSS design should allow the PSS signal sent to the excitation system to be
limitable so as not to adversely affect the temporary stability of the unit. These
limit values shall be determined by the excitation system producer (or the
excitation system expert approved by the excitation system producer) as well.
While the PSS is on, the limit value in both the input signals and the output signals
should be higher than 0. (For the PSS output signal limit, the typical value is ±0.05
pu.)
E.12.6
POWER
PROCEDURE
SYSTEM
STABILIZER
VERIFICATION
TEST
After the reports regarding the setting works as indicated in the Section E.12.5 have
been submitted to and approved by TEIAS, the verification tests shall be performed in
accordance with the procedures set out in this section. TEIAS will be informed of the date
of verification testing at least 1 week before that date. TEIAS may have observers present
during the verification tests if it considers it necessary.
12.6.1 Preliminary Requirements
Before the power system stabilizer performance verification tests, the excitation
system expert to perform the tests should have the following equipment, software and
authorities:
a) Hardware and/or software sufficient to make change of step function type,
corresponding to adjustable voltage change, at the resolution of 0.001 pu,
within the range of 0 pu – 0.05 pu at the alternator terminals, at the AVR
voltage set value.
b) Hardware and/or software sufficient to make change, corresponding to
adjustable pure sinus or 1/fα type voltage change, at the resolution of 0.001 pu,
within the peak value range of 0 pu – 0.02 pu, at the alternator terminals, at the
AVR voltage set value.
c) In order to be able to perform the frequency response tests and to observe the
test results, a spectrum analyzer hardware and/or software that can run in the
frequency band of minimum 0.1 – 10 Hz.
ç) In order to store the test results in a digital environment, hardware and/software
that allows to record 8 different signals at the resolution of 0.001 pu and within
sampling time of maximum 10 milliseconds for each signal, as a minimum.
d) In order to be able to observe the changes in the relevant signals during the test,
stereophonic oscilloscope, in minimum.
e) In order to cancel the input of the PSS to the excitation system in emergency
cases that might occur during the test, adequate hardware and/or software.
f) In order to cancel the test signal (step function, pure sinus or 1/fα type test
signal) at the input of the automatic voltage regulator in emergency cases that
might occur during the test, adequate hardware and/or software.
g) All auxiliary equipment of the PSS (measurement transducers, alarm and alert
systems) is in complete and operational.
ğ) The excitation system expert to perform the test should have the authority and
responsibility to make change,
-
on the excitation system hardware
on the excitation system software
on the alternator protection system
on the AVR and PSS parameters.
286
12.6.2 Test Method
The PSS performance verification tests shall be performed by the excitation
system producer of the relevant unit or an excitation system expert approved by the
excitation system producer. The personnel of the Power Generating Facility and/or the
excitation system experts to perform the test must have completed all preliminary
preparations for the test-related software and hardware and must be ready for the test.
The following signals should be recorded in all tests for the analysis works to be
carried out subsequently.
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
Active power of the unit
Reactive power of the unit
Excitation voltage
Excitation current
Output signal of the PSS
Terminal voltage of the alternator
Armature current of the alternator (optional)
Grid frequency
Rotor speed (optional, if appropriate)
Voltage reference value (together with the change signal applied)
At the end of the tests, the Performance Verification Report shall be submitted to
TEIAS as specified in the section E.12.7.
12.6.2.1 Step Response Tests
In order to observe that whether the PSS contributes to the absorption of the local
fluctuations, the signals set out in the Article 12.6.2 of this Procedure shall be
observed and recorded by making step function type change of ±2% (or ±3%) in the
voltage reference value of the excitation system.
The procedure indicated below shall be followed during the tests:
a) The necessary permissions should be obtained from the RLDC and NLDC.
Since the unit should not participate in the frequency control during the tests,
the necessary arrangements shall be made in the speed governor.
b) The PSS set values approved by TEIAS shall be loaded to the PSS.
c) Furthermore, if requested by TEIAS, while the unit is turning at the rated
speed without being synchronous to the grid (when the generator circuit
breaker is on) and when it is in excited condition at the rated voltage, in
order to verify the alternator and the excitation model used during the PSS
setting procedures, the signals stated above shall be observed and recorded
by making step function type change of 2% (or 3%) in the voltage reference
value of the excitation system. During this test, the PSS should be in off
position.
ç) When the PSS is in off position, the unit shall be brought to between 90%
and 100% of its nominal power.
d) In order to determine the gain value to be used during the tests before
starting the step function response tests, the PSS gain shall be drawn to 0 and
the PSS shall be switched to on position. Afterwards, the PSS gain shall be
brought to the value that had been previously reported to TEIAS by
287
increasing at 5 equal steps by observing the behavior of the unit. For each
gain step, it shall be ensured that there is no noise amplification or no
interaction between the excitation system and the PSS by observing the
signals indicated in the Article 12.6.2 of this document and the behavior of
the unit for 1 minute. If noise amplification occurs or interaction is observed
between the excitation system and the PSS due to high PSS gain during the
test, the PSS gain value may not be increased more. In these cases, the PSS
gain can be decreased to a safe value to be determined by the excitation
system producer (or the excitation system expert approved by the excitation
system producer).
e) If no adverse condition is encountered during the gain tests, the test
procedure shall continue with the step function response test. The purpose of
this test is to obverse the contribution of the PSS in the absorption of the
local oscillation of the relevant unit. For this reason, the step function
response tests shall be performed separately when the PSS is in off position
and when the PSS is in on position.
First of all, when the PSS is off position, the signals set out in the Article 12.6.2
of this document shall be observed and recorded by making step change of 2% (or 3%)
in the voltage reference value of the excitation system.
Afterwards, the PSS shall be switched to on position and the PSS gain shall be
brought to the maximum safe value by increasing at 5 equal steps. For each gain step,
the signals set out in the Article 12.6.2 of this document shall be observed and
recorded by making step function type change of 2% (or 3%) in the voltage reference
value of the excitation system. If noise amplification occurs or interaction is observed
between the excitation system and the PSS due to high PSS gain during the test, the
PSS gain value may not be increased to the safe value. In these cases, the PSS gain can
be decreased to a safe value to be determined by the excitation system producer (or the
excitation system expert approved by the excitation system producer).
At the evaluation stage of the results, the results of the step response tests
performed when the PSS is off and when the PSS is on shall be drawn at the same
scale. Although it is the most fundamental expectation that the fluctuations in the
active power of the unit are absorbed with a higher absorption rate when the PSS is in
on position in comparison with the results obtained when the PSS is in off position, it
is a satisfactory result that the active power fluctuations are absorbed within 2-3
fluctuation period. While the test results are evaluated, the requirement for the absence
of periodical fluctuations which are not absorbed in the reactive power of the unit, in
the excitation voltage or in the excitation current or of noise component should be also
taken into consideration even if the active power fluctuations are absorbed well.
12.6.2.2 Frequency Response Tests
In order to observe that the PSS is adjusted so as to increase the absorption rate
of the fluctuations within the range of 0.1–3.0 Hz, the signals indicated in the Article
12.6.2 of this document shall be observed and recorded by applying white noise or
pure sinusoidal test signal at frequencies varying within the frequency band of 0.1 – 4
Hz to the voltage reference value of the excitation system so as to make peak value
change of 0.001 pu in minimum and of 0.002 pu in maximum in the terminal voltage.
Similar tests can be performed also by applying test signals of 1/fα type (white noise
or pink noise) that includes all frequency components instead of the tests repeated by
applying pure sinus test signal at frequencies varying within the frequency band of 0.1
– 3.0 Hz.
During the evaluation of the test results, Fast Fourier Transform (FFT) shall be
applied to the terminal voltage signal for the fluctuations in the frequency band of 0.1
– 0.5 Hz and to the active power signal of the unit for the fluctuations in the frequency
band of 0.5 – 3.0 Hz. The success criterion is the intensity of the fluctuations is
288
reduced in the test results obtained when the PSS is in on position for the relevant
fluctuations (voltage or active power) in comparison with the test results obtained
when the PSS is in off position.
During the tests, the procedure stated below shall be followed:
a) The necessary permissions shall be obtained from the Regional Load
Dispatch Center and the National Load Dispatch Operation Directorate.
When the PSS is off, the unit shall be synchronized to the grid and brought
to between 90% and 100% of the Maximum Capacity. During this test, the
unit should not participate in the primary frequency control under any
circumstances in order to be able to evaluate the test results exactly.
b) The signals set out in the Article 19.6.2 oof this annex shall be observed and
recorded by applying either test signals of 1/fα type (white noise or pink
noise) or pure sinus test signal at frequencies varying within the frequency
band of 0.1 – 3.0 Hz (in this case, the tests shall be repeated for pure sinus
test signal at the frequencies of 0.1 Hz, 0.2 Hz, 0.3 Hz, 0.4 Hz, 0.5 Hz, 0.6
Hz, 0.7 Hz, 0.8 Hz, 0.9 Hz, 1 Hz, 1.25 Hz, 1.5 Hz, 2 Hz, 2.5 Hz, 3 Hz, 3.5
Hz and 4 Hz) to the voltage reference value of the excitation system so as to
make peak value change of 0.001 pu in minimum and of 0.02 pu in
maximum in the terminal voltage. During the test, the amplitude of the test
signal applied should be increased slowly so as to make peak value change
of 0.001 pu in minimum and of 0.02 pu in maximum in the terminal voltage
by beginning from zero. The recording procedure should start after the
adjustment of the value of the terminal voltage changes. At each step, first of
all, the test shall be performed when the PSS is off. Afterwards, the PSS
shall be switched to on position without changing the amplitude of the signal
applied when the PSS is off. Especially in the cases where the pure sinus test
signal is applied, maximum care should be taken to the intensity of the
fluctuations in the active power of the unit while increasing the amplitude of
the signal between 0.8 – 2 Hz that includes the local fluctuation modes. In
any unforeseen condition, it is recommended to stop the application of the
test signal urgently and to switch the PSS to off position.
c) After completing the tests and ensuring that the data is recorded properly,
during the evaluation of the test results, FFT shall be applied to the terminal
voltage signal for the fluctuations in the frequency band of 0.1 – 0.5 Hz and
to the active power of the unit for the fluctuations in the frequency band of
0.5-4 Hz. The success criterion is that the intensity of the fluctuations is
reduced when the PSS is on for the relevant fluctuations (voltage or active
power).
12.6.2.3 Rapid Loading Tests
During the tests, the procedure stated above shall be followed:
a) The necessary permissions shall be obtained from the Regional Load
Dispatch Center and the National Load Dispatch Center. Since the unit will
not participate in the primary or secondary frequency control during the
tests, the necessary arrangements shall be made in the speed governor. While
the PSS is on, the unit shall be brought to the minimum stable generation
level.
b) The unit shall be loaded at the maximum rate of MW/second determined by
the generators until it reaches to its nominal active power. The signals
specified in the section 12.6.2 of this annex shall be observed and recorded.
c) The unit shall perform load shedding at the maximum rate of MW/second
until it reaches to the minimum stable generation level. The signals specified
in the section 12.6.2 of this annex shall be observed and recorded.
289
ç) After completing the tests and ensuring that the data have been recorded
properly, it shall be expected that reactive power fluctuations at large scale are not
observed while the unit performs loading and load shedding during the assessment of
the test results. Otherwise, the PSS design should be reviewed. This frequently occurs
when a PSS with single input (delta P type) is used especially at the hydroelectric
Power Generating Modules. For this reason, it is important to use a PSS design with
double input (with active power and frequency inputs) and having the integral of
accelerating power philosophy.
E.12.7 MINIMUM PERFORMANCE REQUIREMENTS
The success criterion of the Power System Stabilizers of the Power Generating
Module is that each one of the said units will meet the performance requirements set
out in the section E.12.6 as a result of the tests to be performed by the relevant
excitation system producer (or an excitation system expert approved by the relevant
excitation system producer) according to the Test procedure given in the same section.
During the tests performed on the said units, in order to meet the designated
performance requirements, the power system stabilizer set values which had been
previously reported to TEIAS can be changed. The set values forming the basis of the
success criterion of the Power Generating Module are the values that are verified with
the site tests.
The performance verification reports should include the following analysis and
test results in minimum.
a) The data that is related to the Power Generating Module (data specified in
the 2nd, 3rd and 4th parts of this annex)
Note: The parameter values finalized as a result of the performance verification
tests for the PSS and excitation system should be given in the performance verification
reports.
b) The Bode Diagrams that are described in the following items;
-
-
While the PSS is disconnected (in off position), for the automatic
voltage regulator, excitation system and alternator, the gain and phase
characteristics for the transfer function with the input signal defined as
the voltage reference value (AVR input) of the relevant unit and with the
output signal defined as the terminal voltage of the relevant unit.
While the PSS is connected (in on position), for the PSS, automatic
voltage regulator, excitation system and alternator, the gain and phase
characteristics for the transfer function with the input signal defined as
the rotor speed measurement (PSS input) of the relevant unit and with
the output signal defined as the active power of the relevant unit.
c) The results of the step response, frequency response and rapid loading tests
performed in compliance with the methodology specified in the 6th part of this annex.
ç) The Results of validation of compatibility of the computer and field
measurements.
d) Using the validated model with the results of the modal analysis performed
between the regions of oscillation modes (~ 0:15 Hz) damping ratio (ζ), PSS
change in on and off situations.
e) The chart showing the 1 hour frequency spectrum of active power signal
measures and voltage realized under PSS on and off conditions.
290
ANNEX 13
ALTERNATOR LOADING CURVE
ANNEX
LOADING CURVE
Rotor Winding Limit
Overexcitation
Over-excited power
factor of 0.85
Stator Winding Limit
Underexcitation
Nominal Active
Power (Turbine Limit)
Excitation Loss Limit
Under-excited power
factor of 0.95
Stability Limit
291
ANNEX 14
GENERATION PLANNING PARAMETERS
The following data is prepared for the units and/or blocks party to compensation
and conciliation:
1)
Minimum period necessary for resynchronization of a unit and/or block being out
of synchronization,
2)
Minimum synchronization period between different units in the Power Generating
Module or between a gas turbine and a cycle unit in the combined cycle gas turbine
block or between two blocks,
3)
Minimum generation identified as block load in the combined cycle gas turbine
block during synchronization,
4)
For the following conditions, maximum loading ratios in the synchronization of the
unit and/or block;
a) Hot
b) Warm
c) Cold
5)
The least no-load operating period,
6)
For the following conditions, maximum load drop ratios of the unit and/or block;
a) Hot
b) Warm
c) Cold
7)
For the following conditions, maximum allowable annual operating conditions;
a) Hot
b) Warm
c) Cold
292
ANNEX 15
OUTPUT POWER REQUIREMENT AGAINST FREQUENCY
Frequency
(Hz)
Frekans
(Hz)
47.5
49.5
50.5
%100
Aktif
100% Active
Power
Output
Güç Çıkışı
96% Active
%96 Output
Aktif
Power
Güç Çıkışı
(1) In the case that the grid frequency is in the range of 49.5 Hz – 50.5 Hz, the
output power should maintain 100% constant value and no more than 1 % output power
drop should occur against every additional 1 % frequency drop. This requirement applies
to any ambient temperature under 25 0C (77 0F) for the gas turbines.
(2) Necessary measures should be taken in order that the drop in the active power
output of the gas turbines due to a turbine speed reduced by decrease in the system
frequency will not drop below the linear characteristic shown in the chart”.
293
ANNEX 16
CRITICAL EVENT NOTIFICATION FORMAT
1.
2.
3.
4.
5.
6.
7.
Time and date of the critical event,
Place of the critical event,
Facility and/or equipment in and/or on which the critical event occurred,
Brief description of the critical event,
Estimated or actual time and date of return to service/recovery,
Disconnected faulty units and disconnection period,
Reduction arising in the availability status of the units in operation/grid due to the
critical event.
294
ANNEX 17
ANCILLARY SERVICES PERFORMANCE TEST PROCEDURES
E.17.A. PRIMARY
PROCEDURES
FREQUENCY
CONTROL
PERFORMANCE
TEST
(1) The Primary Frequency Control Performance Tests consist of three stages.
These stages are the Primary Frequency Control Reserve Test, Primary Frequency Control
Sensitivity Test and Verification Test as described in the sections E.17.A.1, E.17.A.2 and
E.17.A.3 below.
These tests shall be performed in all of the Power Generating Modules that are to involve
in the Primary Frequency Control. If there is more than one unit at the relevant Power
Generating Module, the primary frequency control performance tests shall be performed
for each unit that is liable to participate in this service and the primary frequency control
performance test certificate concerning these tests shall be prepared separately for each
unit. The test report to be issued shall include the tests that are performed for all units.
(2) Besides the documents requested during the tests, the simplified block diagrams
of the unit control systems, and especially the functioning between the turbine governor
and the boiler control system should be provided by the Power Generating Facility
personnel in order to demonstrate the functions of primary frequency control. The block
diagrams obtained and the application points of the test signal shall be indicated in the test
report.
(3) During the Primary Frequency Control Performance Tests, the records of the
following signals shall be taken over the connection indicated next to them according to
the type of the unit. The records of the other signals considered necessary by the expert
performing the test shall be taken as well as the aforementioned signals. The source,
accuracy and reliability of the data recorded shall be under the responsibility of the
authorized test company performing the test.
i.
ii.
iii.
iv.
v.
vi.
vii.
viii.
Active Power Reference of the Unit
Active Power Output (over the Current-Voltage Transformer/Transducer)
Grid Frequency (over the Voltage Transformer/Transducer)
Applied Test Frequency (over the Transducer/PLC/DCS)
Valve Positions or Fuel Flow/Quantity (over the Transducer/PLC/DCS)
Turbine by-pass valve position for the steam turbines (clearance %) (over the
Transducer/PLC/DCS)
Steam pressure for the steam turbines (over the Transducer/PLC/DCS)
Steam temperature for the steam turbines (over the Transducer/PLC/DCS)
The signals recorded during the tests shall be added to the test record and the test
report as text formatted (ASCII/Text) data recording file in CD/DVD environment as
determined by TEIAS and shall be delivered to the supervisor of TEIAS.
(4) The sampling rate for each value that is measured during the tests should be 10
data in a second (1 data in 100 milliseconds). The recording equipment supplied by the
authorized company performing the test and capable of measuring the relevant signals over
the connection points stated above in the form of current and/or voltage by means of
external connection must be used for the records to be taken during the tests, and no record
files obtained for the Power Generating Facility’s own systems or data recording methods
based on communication should not be used. The accuracy class of each data recording
295
equipment to be externally connected should be minimum 0.2% and the data recording
equipment should have the ability to record the measured values with the time information.
The calibration certificate of the test equipment should be for three years at most. It shall
be submitted to the supervisor of TEIAS that the data recording equipment meets the
necessary requirements along with its certificates prior to the test.
(5) During the tests, the unit parameters (pressure, temperature etc.) should remain
within the normal operating values and it shall be stated in the test report that the unit
parameters remain within the normal operating values. During the tests, the unit parameters
should not exceed the limits in the existing normal operating conditions and should not
have a restrictive impact. Any additional protection mechanism that might cause the test or
the unit to step should not be used.
(6) The Primary Frequency Control Performance Tests shall be performed by
applying the directly simulated speed information instead of the measured speed
information by the principle seen in the Figure E.17.A.1 so that the turbine speed governor
of the unit tested will not sense the grid frequency by using any software and/or hardware
simulation method.
It is the responsibility of the relevant Power Generating Module to take all kinds of
measures related to the equipment and personnel safety against the unforeseen
circumstances that might occur during the application of the test signal and during the
performance of the test.
fref
Speed
Governor
fgrid
Simulation
fsimulated
Method *
Test Signal
* : Any software and/or hardware simulation method which the speed
regulator cannot sense the grid frequency
Figure E.17.A.1 - Principle Diagram for Frequency Simulation Application Method
(7) The primary frequency control performance tests shall be performed within the
framework of the steps specified below and shall be reported according to the report
template included in the attachment of the primary frequency control service agreement
and published on the website of TEIAS.
E.17.A.1.
Primary Frequency Control Reserve Test
Test Objective
(1) The objective of the Primary Frequency Control Reserve Test is to verify that
the unit has the ability to provide the maximum primary reserve amount that it can allocate
296
for the primary frequency control, when required, in compliance with the criteria
designated in line with the grid frequency control.
Test Phases
(2) The following procedures are carried out on the unit while performing the
Primary Frequency Control Reserve test:
a) The unit is brought to the position to provide the function of Primary Frequency
Control.
b) Dead band value is set to 0 (zero) mHz.
c) Speed droop and other relevant parameters must be set so as to be consistent with
the speed droop values given in the following table and that can vary between 4%
and 8% according to the requirement i.e. “50% of the primary frequency control
reserve must be activated within no later than 15 seconds and the entire primary
frequency control reserve must be activated within no later than 30 seconds in the
event of frequency deviation of 200 mHz”.
If the Maximum Primary Reserve Capacity is less than 5% of the nominal active
power of the unit, the pertinent parameters for the tests and the normal operation after the
tests shall be adjusted so as to be parallel with speed droop of maximum 8%. In the
relevant unit, the power change limitation corresponding to the designated Maximum
Primary Reserve Capacity shall be applied in the test for the step frequency deviation of 200 mHz. In the test for the tap change of +200 mHz, any primary response limitation
should not be used. The Maximum Primary Reserve Capacity may not be less than 2% and
more than 10% of the nominal power of the unit. If it is deemed appropriate by TEIAS, a
test may be performed for a maximum primary frequency control reserve capacity above
10%. In this case, the test shall be performed using a speed gradient value calculated by the
speed gradient formula.
Table E.17.A.1 –Speed gradient value
Maximum Primary Frequency Control Reserve Capacity 5
(RPmax), %
Speed gradient (sg), %
8
10
4
The speed droop, dead band and other relevant parameter settings made for the tests
shall be remain the same at all phases of the primary frequency control performance tests
and shall not be changed.
(3) The Primary Frequency Control Reserve Tests shall be performed in two stages
at minimum and maximum output power levels as follows:
a.
For the test to be performed at the maximum output power level, the output
power set point value of the unit shall be adjusted to a Pset value that is below
the nominal output power of the unit or the maximum output power that the
unit can provide under the existing operating conditions as much as “RPmax +
(3% x PGN)” value after the speed droop value of the unit and other relevant
parameters are adjusted as specified above.
b.
For the test to be performed at the minimum output power level, the output
power set point value of the unit shall be adjusted to a Pset value that is above
the minimum active output power with which the unit can provide stable and
297
safe operation as much as “RPmax + (3% x PGN)” value after the speed droop
value of the unit and other relevant parameters are adjusted as specified above.
If the difference between the maximum and minimum output power levels of
the unit, which are determined for the tests, is less than two times the "RPmax"
value, it will not be necessary to perform the tests at the minimum output
power level.
c.
During the both steps above, the frequency deviation of f=-200 mHz or the
simulated test signal of f=49.8 Hz shall be applied at the input of turbine
governor in a way that it does not receive speed information from the grid and
in the form of tap change and this value shall be maintained for minimum 15
minutes. At the end of this period, the nominal frequency value shall return to
50 Hz and it shall be waited that the unit remains stable at the same Pset value
and the same procedure shall be repeated for the frequency deviation of
f=+200 mHz or the simulated frequency value of f=50.2 Hz. The application
concerning these test steps shall be performed as seen in the following FigureE.17.A.2 and Figure-E.17.A.3.
simulated frequency (Hz)
15 min.
time
15 min.
active output power (MW)
time
Figure-E.17.A.2. Application of Simulated Frequency in Primary Frequency Control
Reserve Test for maximum output power level
298
simulated frequency (Hz)
15 min.
time
15 min.
active output power (MW)
time
Figure-E.17.A.3. Application of Simulated Frequency in Primary Frequency Control
Reserve Test for minimum output power level
Test Results
(4) During the Primary Frequency Control Reserve Tests, the active power output
of the unit, the simulated frequency and the other relevant signals shall be recorded.
Test Acceptance Criteria
(5) Graphics shall be created separately for two separate simulated frequency step
of f=-200 mHz and of f=+200 mHz; and the success of the test shall be evaluated
separately according to the following rules by using these graphics created separately with
the data obtained from the tests performed at maximum and minimum levels:
a.
50% of the Maximum Primary Frequency Control Reserve Capacity should be
able to be activated within maximum 15 seconds, and the entire of it within
maximum 30 seconds as shown in the Figure E.17.A.4 and Figure E.17.A.5.
b.
The Maximum Primary Frequency Control Reserve Capacity should be able to
be maintained for at least 15 minutes within the tolerances given in the Figure
E.17.A.6. When evaluating this criterion, it will be considered satisfactory if at
least 99% of the data recording points in the graphic are within the tolerance
limits.
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Active Output Power
Simulated Frequency
P (MW)
f (Hz)
Pset + RPmax
RPmax
Pset + RPmax
Pset
50.0
f
49.8
t0
time
th
(15sec.)
t1
(30 sec.)
t2
(min.)
Figure E.17.A.4 - Response Expected from Unit in Application of Simulated
Frequency of f=49.8 Hz
300
Active Output Power
Simulated Frequency
P (MW)
f (Hz)
50.2
f
Pset
50.0
RPmax
Pset - RPmax
Pset - RPmax
t0
time
th
(15sec.)
t2
t1
(30sec.)
(min.)
Figure E.17.A.5 - Response Expected from Unit in Application of Simulated Frequency of
f=50.2 Hz
c.
The response expected from the unit in the Primary Reserve Tests should be
within the tolerances as indicated in the Figure.E.17.A.6. When evaluating this
criterion, it will be considered satisfactory if at least 99% of the data recording
points in the graphic are within the tolerance limits
d.
The units, as seen in the Figure-E.17.A.6, should start to response within no later
than “the Delay Time” specified as "Δtd" (4 seconds for hydroelectric units and 2
seconds for other units).
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Primary Reserve Amount
Response Limits / Tolerances
Expected Response
 td
Response Delay Time
Δtd= 4 seconds, for Hydroelectric Units
Δtd= 2 seconds, for Other Units
Nominal Output Power of Unit
PGN
Figure-E.17.A.6- Assessment of Primary Frequency Control Reserve Test
E.17.A.2.
Primary Frequency Control Sensitivity Test
Test Objective
(1) The objective of the Primary Frequency Control Sensitivity Test is to verify that
the sensitivity of the unit tested to the frequency deviations at sufficient and required level.
Test Phases
(2) The Primary Frequency Control Sensitivity Tests shall be performed as follows
at the maximum output power level at which there is no consistent operational obstacle in
the ability to provide the primary response constantly:
The test signal or the frequency deviation amount shall be applied at the input of
turbine governor increasingly in the increments of 5 mHz in plus and minus direction
starting from f=-5 mHz until a response related to the test signal on the check valves of
the unit is observed in line with the application principle shown in the Figure E.17.A.6 in
order to determine the sensitivity of unit. Valve action and/or variations in the other
pertinent signals are assumed as the criteria for the response of unit. The frequency
deviation of f=-5 mHz or the simulated frequency value of f=49.995 Hz shall be applied
in the form of step variations as shown in the Figure E.17.A.5 below and it shall be
maintained at this value for minimum one minute. At the end of this period, the nominal
frequency value shall return to 50 Hz and it shall be waited that the unit remains stable at
the same Pset value, and this time, the frequency deviation of f=+5 mHz or the simulated
frequency value of f=50.005 Hz shall be applied in the same manner. If the unit does not
302
react to the frequency deviations of ±5 mHz, the same procedures shall be repeated for the
frequency deviations of ±10 mHz.
simulated frequency (Hz)
1 min.
1 min.
time
1 min.
1 min.
Figure.E.17.A.6- Application of Primary Frequency Control Sensitivity Test
Test Results
(3) During the test, the valve position and the other signals shall be recorded.
Test Acceptance Criteria
(4) The Primary Frequency Control Sensitivity Test shall be assessed according to
the following criteria;
a.
b.
The variation at the valve position and/or other pertinent signals at the moment
when the frequency deviation is applied should be observed during the Primary
Frequency Control Sensitivity Tests,
The unit insensitivity must not exceed ±10 mHz.
E.17.A.3
Verification Test
Test Objective
(1) The objective of the Verification Test is to verify that the unit tested can
continually run under the normal operating conditions as well as the test conditions in
compliance with the primary frequency control.
Test Phases
(2) The Verification Test shall be performed if it is observed as a result of the
Primary Frequency Reserve and Sensitivity tests that the unit renders this service. The
normal operation of the unit with actual frequency shall be recorded for 24 hours by
connecting the unit so that the turbine speed governor will obtain the speed information
from the grid without changing the adjustments made on the unit. If the units are
disconnected due to the reasons arising from the transmission system or instructions given
by the system operator, the disconnection period shall be added to the end of the test. In the
cases of disconnection not arising from the transmission system or instructions given by
the system operator, 24-hour test shall be restarted. For the verification tests, the output
power set point value of the unit shall be adjusted as a Pset value at which the maximum
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primary frequency control reserve amount can be provided and which is not below the
minimum output power level. Operation schedule of the unit during the verification test
shall be determined so as to make the Pset value possible.
(3) The verification test for the gas engines shall be performed in groups so as to
include at least three units.
Test Results
(4) For the highest frequency deviation in positive and negative directions, which
occurred during the tests, the graphics that include the frequency and output power values
shall be added to the test report.
Test Acceptance Criteria
(5) The assessment of the verification test for all units tested shall be carried out as
specified in the Figure.E.17.A.7. While carrying out the assessment of the verification test
for the gas engines, the total output power value of the groups tested shall be taken into
account, but the measurements shall be recorded on a unit basis.
At least 90% of the Output Power values that are measured for the Unit/Gas engine group
should be within the range of “Pset + PG ± %1 x PGN”.
PG: Primary response expected to be given to the realized frequency deviation.
Expected Output Power Limits
Expected Output Power
Realized Output Power
Figure.E.17.A.7- Assessment of Primary Frequency Control Verification Test
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E.17.B. SECONDARY FREQUENCY CONTROL PERFORMANCE TEST
PROCEDURES
(1) Prior to the secondary frequency control performance tests, the Power
Generating Module/ block/ unit should be included in TEIAS SCADA unit, and the
interface has to be made in the Power Generating Facility for involvement of the Power
Generating Module in the secondary frequency control/ system design document has to be
submitted to TEIAS and approved by TEIAS, and this system has to be realized in full
compatibility with the requirements of Automatic Generation Control (AGC) Program
located at the National Load Distribution Center of TEIAS as per the design document that
is approved by TEIAS.
(2) The Secondary Frequency Control Performance Tests shall be performed
separately for each unit (Power Generating Module/block/unit) to which "Remote Power
Demand Set Value (Pset RPD)" is sent.
(3) For the Secondary Frequency Control Performance Tests, the maximum
capacity (MAXC) and the minimum capacity (MINC) values of the relevant unit (Power
Generating Module/block/unit) shall be calculated in consideration of the limits within
which each unit can run for the secondary frequency control, except for the reserve which
the units will use for the primary frequency control. Accordingly, the minimum and
maximum limits which are designed in such a manner that they can be adjusted and
manually entered for each unit of the relevant unit (Power Generating Module/block/unit)
planned to participate in the Secondary Frequency Control must have been identified
separately. The maximum capacity (MAXC) and the minimum capacity (MINC) values of
the relevant unit (Power Generating Module/block/unit) shall be adjusted so as to provide
the highest range planned for the participation in the secondary frequency control. This
range adjusted for the relevant unit (Power Generating Module/block/unit) shall be defined
as “Maximum Secondary Frequency Control Reserve Capacity (RSA)”.
(4) For the Secondary Frequency Control Performance Tests, the maximum
capacity (MAXC) value of the relevant unit (Power Generating Module/block/unit) shall
be calculated by taking the total of the adjusted maximum limit values of the units the
secondary frequency control operating conditions of which are in “Auto” position and the
instantaneous active output power values of the units in “Manual” position. For the
Secondary Frequency Control Performance Tests, the minimum capacity value (MINC) of
the relevant unit (Power Generating Module/block/unit), however, shall be calculated by
taking the total of the adjusted minimum limit values of the units the secondary frequency
control operating conditions of which are in “Auto” position and the instantaneous active
output power values of the units in “Manual” position. If there is a steam turbine
generating as connected to the units in the relevant unit planned to participate in the
Secondary Frequency Control, the minimum and maximum capacity values of the steam
turbine estimated as specified below shall be included into the relevant total capacity
values as well.
(5) For the steam turbines (for instance; natural gas combined cycle blocks)
generating as connected to the units in the relevant unit planned to participate in the
Secondary Frequency Control, however, the approximately estimated value that the steam
turbine can generate from the units to which it is connected as a result of the addition of the
adjusted maximum limit values of the units the secondary frequency control operating
conditions of which are in “Auto” position and the instantaneous active output power
values of the units in “Manual” position shall be considered as the maximum limit value of
the steam turbine, and the approximately estimated value that the steam turbine can
generate from the units to which it connected as a result of the addition of the adjusted
minimum limit values of the units the secondary frequency control operating conditions of
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which are in “Auto” position and the instantaneous active output power values of the units
in “Manual” position shall be considered as the minimum limit value of the steam turbine.
(6) It shall be checked by means of the tests to be performed that whether the
maximum capacity (MAXC) and the minimum capacity (MINC) values of the relevant unit
(Power Generating Module/block/unit) planned to participate in the Secondary Frequency
Control, which are determined for the secondary frequency control, are calculated
accurately by using the minimum and maximum limit values which are manually entered
for each unit and in consideration of the secondary frequency control operating conditions
(Auto/Manual) of the units.
(7) It is principle also for the steam turbines generating as connected to the units in
the relevant unit planned to participate in the Secondary Frequency Control (for instance;
natural gas combined cycle blocks) to be connected and recorded during the tests.
Accordingly, it is principle to distribute Remote Power Demand Set Value sent to the
relevant unit to the units accurately by taking into account the generation values of the
steam turbines. It shall be checked that this distribution is performed accurately by means
of the tests to be performed.
(8) The Maximum Secondary Frequency Control Reserve Capacity (the difference
between MAXC and MINC, RSA) of the relevant unit (Power Generating
Module/block/unit) planned to participate in the Secondary Frequency Control should be
adjusted so that it will not exceed the maximum Loading Speed Ratio and the reserve
amount which the unit can provide within 5 minutes. The relevant unit (Power Generating
Module/block/unit) should have a suitable ramp or inclination functionality by which it can
run with the loading speed ratio set out in the Article-123 and the loading speed ratio
should be adjustable.
(9) During the tests, the unit parameters should remain within the normal operating
values. Due to the tests, the unit parameters (pressure, temperature, voltage etc.) should not
exceed the limits in the existing normal operating conditions for the safe use of the
equipment and should not have restrictive impact. Any additional protection mechanism
which might cause the test or the Power Generating Module/block/unit tested to stop
should not be used.
(10) At the Power Generating Modules where the Secondary Frequency Control
performance tests are performed, in the cases such as environmental conditions that do not
allow the unit to reach to the nominal active power (Pn), lake elevation and similar factors,
the test shall be performed in consideration of the maximum active output power that can
be achieved according to the conditions during the tests.
(11) The Secondary Frequency Control Performance Tests shall be performed
within the framework of the steps indicated below and shall be reported according to the
report template included in the attachment of the secondary frequency control service
agreement and published on the website of TEIAS.
Test Objective
(12) It shall be found out that whether the Secondary Frequency Control
System/Interface installed at the Power Generating Module which will participate in the
Secondary Frequency Control and to which the set value will be sent over the SCADA
System via the Automatic Generation Control (AGC) Program at the National Load
Dispatch Center of TEIAS provides the required functions and designated performance
criteria.
Test Phases
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(13) The basic test steps to be followed in the secondary frequency control
performance tests are as follows.
a) Check of the Calculation of Power Generating Module/Block/Unit Limits
During the tests, it shall be checked that the Power Generating Module/block/unit
limits (MAXC, MINC, MAXCpr and MINCpr) are calculated by considering the limits,
actual generation, operating positions and PFCO conditions of the unit.
b) Loading Speed Tests
The loading speed tests shall be performed in loading and load shedding direction
in two separate operating conditions, namely while the Power Generating
Module/block/unit is participating into the primary frequency control and without the
participation of this Power Generating Module/block/unit into the primary frequency
control.
The basic test steps to be followed in these operating conditions are given below:
b.1. Load Shedding Speed Test While the Primary Frequency Control Operation is Off
(PFCO = OFF)
Before the commencement of the tests, the maximum capacity (MAXC) and the
minimum capacity (MINC) values at which the pertinent Power Generating
Module/block/unit can render the service shall be set without separating the primary
frequency control reserve amounts of the units, so as to provide the maximum secondary
frequency control reserve capacity (RSA) and by manually entering the limits at which
each unit can operate for the secondary frequency control. These MAXC and MINC values
designated shall also be used in the loading speed ratio test while the primary frequency
control operation is off.
i.
The total active power output of the pertinent Power Generating
Module/block/unit on which the Performance Tests will be performed shall
be set to MAXC value and the Power Generating Module/block/unit shall
be left to steady-state operation at this level.
ii.
The amount of “Remote Power Demand Set Value” to be sent to the
pertinent Power Generating Module/block/unit via AGC program existing at
the National Load Dispatch Center shall be set to MAXC value of the
pertinent Power Generating Module/block/unit and it shall be observed that
“Remote Power Demand Validity Signal (PD Validity)” is active.
iii.
It shall be checked that the value of Remote Power Demand set as MAXC is
received and displayed accurately in the Power Generating Module control
system.
iv.
It shall be checked that the signal of “Remote Power Demand Feedback
Value” sent from the Power Generating Module control system is displayed
accurately at the National Load Dispatch Center.
v.
It shall be checked that the signal of “Remote Power Demand Feedback
Value” sent from the Power Generating Module control system is displayed
accurately at the National Load Dispatch Center.
vi.
After the completion of the mutual verification procedures, the operating
condition of all units of the pertinent unit tested shall be switched to “Auto”
position and the secondary frequency control operating condition of the
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pertinent Power Generating Module/block/unit shall be switched to
“Remote” position.
vii.
While the pertinent Power Generating Module/block/unit tested carries on
running in MAXC, MINC which is the minimum capacity value shall be
sent as “Remote Power Demand Set Value” to the Power Generating
Module/block/unit via AGC program existing at the National Load Dispatch
Center.
viii.
It shall be waited that the total active power output value of the pertinent
Power Generating Module/block/unit reach to the target output power level
sent via AGC program existing at the National Load Dispatch Center and is
able to maintain this output power level for minimum 3 minutes in a steadystate condition.
b.2. Loading Speed Ratio Test While the Primary Frequency Control Operation is Off
(PFCO = OFF)
During this test, the maximum capacity (MAXC) and the minimum capacity
(MINC) values of the pertinent Power Generating Module/block/unit should be set to the
values used in the Load Shedding Speed Test while the primary frequency control
operation is off.
i.
The total active power output of the pertinent Power Generating
Module/block/unit shall be set to MINC value and the Power Generating
Module/block/unit shall be left to steady-state operation at this level.
ii.
The amount of “Remote Power Demand Set Value” to be sent to the
pertinent Power Generating Module/block/unit via AGC program existing at
the National Load Dispatch Center shall be set to MINC value of the
pertinent Power Generating Module/block/unit and it shall be observed that
“Remote Power Demand Validity Signal (PD Validity)” is active.
iii.
It shall be checked that the value of Remote Power Demand set as MINC is
received and displayed accurately in the Power Generating Module control
system.
iv.
It shall be checked that the signal of “Remote Power Demand Feedback
Value” sent from the Power Generating Module control system is displayed
accurately at the National Load Dispatch Center.
v.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” sent from the SCADA System of TEIAS is displayed accurately
in the Power Generating Module control system (LRPD=OK).
vi.
After the completion of the mutual verification procedures, the operating
condition of all units of the pertinent unit tested shall be switched to “Auto”
position and the secondary frequency control operating condition of the
pertinent Power Generating Module/block/unit shall be switched to
“Remote” position.
vii.
While the pertinent Power Generating Module/block/unit tested carries on
running in MINC, MAXC which is the maximum capacity value shall be
sent as “Remote Power Demand Set Value” to the Power Generating
Module/block/unit via AGC program existing at the National Load Dispatch
Center.
308
viii.
It shall be waited that the total active power output value of the pertinent
Power Generating Module/block/unit reach to the target output power level
sent via AGC program existing at the National Load Dispatch Center and is
able to maintain this output power level for minimum 3 minutes in a steadystate condition.
b.3. Load Shedding Speed Ratio Test While the Primary Frequency Control Operation is
On (PFCO = ON)
Before the commencement of this test, the primary frequency control operation
shall be turned on at the pertinent Power Generating Module/block/unit. The Primary
Frequency Control Reserve Amount (RP) shall be set so as to correspond to minimum
2.5% of the nominal active power (PGN) of the Power Generating Module/block/unit. The
speed droop set value of the units shall be set as 4% for the hydroelectric units and the
natural gas fired units and as 8% for the other units. If it is required to apply a different
speed droop set value, the relevant parameters shall be set to the suitable values at which
the specified primary frequency control reserve amount can be provided. The dead band set
value, however, shall be set as 0 (zero) mHz.
The maximum capacity value MAXCpr while the pertinent Power Generating
Module/block/unit tested is primary frequency controlled and the minimum capacity value
MINCpr while it is primary frequency controlled shall be calculated according to the
following formula in consideration of the primary frequency control reserve amounts of the
Power Generating Module/block/unit:
MAXCpr = MAXC + RP
MINCpr = MINC - RP
These values calculated shall be set so as to provide the secondary frequency
control reserve range RSApr while the Power Generating Module/block/unit is primary
frequenncy controlled and by manually entering the limits at which each unit can operate
for the secondary frequency control.
i.
The total active power output of the pertinent Power Generating
Module/block/unit on which the Performance Tests will be performed shall
be set to MAXC value and the Power Generating Module/block/unit shall
be left to steady-state operation at this level.
ii.
The amount of “Remote Power Demand Set Value” to be sent to the
pertinent Power Generating Module/block/unit via AGC program existing at
the National Load Dispatch Center shall be set to MAXC value of the
pertinent Power Generating Module/block/unit and it shall be observed that
“Remote Power Demand Validity Signal (PD Validity)” is active.
iii.
It shall be checked that the value of Remote Power Demand set as MAXC is
received and displayed accurately in the Power Generating Module control
system.
iv.
It shall be checked that the signal of “Remote Power Demand Feedback
Value” sent from the Power Generating Module control system is displayed
accurately at the National Load Dispatch Center.
v.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” sent from the SCADA System of TEIAS is displayed accurately
in the Power Generating Module control system (LRPD=OK).
309
vi.
After the completion of the mutual verification procedures, the operating
condition of all units of the pertinent unit tested shall be switched to “Auto”
position and the secondary frequency control operating condition of the
pertinent Power Generating Module/block/unit shall be switched to
“Remote” position.
vii.
While the pertinent Power Generating Module/block/unit tested carries on
running in MAXC, MINC which is the minimum capacity value shall be
sent as “Remote Power Demand Set Value” to the Power Generating
Module/block/unit via AGC program existing at the National Load Dispatch
Center.
viii.
It shall be waited that the total active power output value of the pertinent
Power Generating Module/block/unit reach to the target output power level
sent via AGC program existing at the National Load Dispatch Center and is
able to maintain this output power level for minimum 3 minutes in a steadystate condition.
b.4. Loading Speed Ratio Test While the Primary Frequency Control Operation is On
(PFCO = ON)
Before the commencement of this test, the primary frequency control operation of
the pertinent Power Generating Module/block/unit shall be turned on. The Primary
Frequency Control Reserve Amount (RP) shall be set so as to correspond to minimum
2.5% of the nominal active power (PGN) of the Power Generating Module/block/unit. The
speed droop set value of the units shall be set as 4% for the hydroelectric units and the
natural gas fired units and as 8% for the other units. If it is required to apply a different
speed droop set value, the relevant parameters shall be set to the suitable values at which
the specified primary frequency control reserve amount can be provided. The dead band
set value, however, shall be set as 0 (zero) mHz.
During this test, the maximum capacity MAXCpr and the minimum capacity
MINCpr values of the pertinent Power Generating Module/block/unit should be set to the
values used in the Load Shedding Speed Test while the primary frequency control
operation is on.
i.
The total active power output of the pertinent Power Generating
Module/block/unit shall be set to MINC value and the Power Generating
Module/block/unit shall be left to steady-state operation at this level.
ii.
The amount of “Remote Power Demand Set Value” to be sent to the
pertinent Power Generating Module/block/unit via AGC program existing at
the National Load Dispatch Center shall be set to MINC value of the
pertinent Power Generating Module/block/unit and it shall be observed that
“Remote Power Demand Validity Signal (PD Validity)” is active.
iii.
It shall be checked that the value of Remote Power Demand set as MINC is
received and displayed accurately in the Power Generating Module control
system.
iv.
It shall be checked that the signal of “Remote Power Demand Feedback
Value” sent from the Power Generating Module control system is displayed
accurately at the National Load Dispatch Center.
310
v.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” sent from the SCADA System of TEIAS is displayed accurately
in the Power Generating Module control system (LRPD=OK).
vi.
After the completion of the mutual verification procedures, the operating
condition of all units of the pertinent unit tested shall be switched to “Auto”
position and the secondary frequency control operating condition of the
pertinent Power Generating Module/block/unit shall be switched to
“Remote” position.
vii.
While the pertinent Power Generating Module/block/unit tested carries on
running in MINC, MAXC which is the maximum capacity value shall be
sent as “Remote Power Demand Set Value” to the Power Generating
Module/block/unit via AGC program existing at the National Load Dispatch
Center.
viii.
It shall be waited that the total active power output value of the pertinent
Power Generating Module/block/unit reach to the target output power level
sent via AGC program existing at the National Load Dispatch Center and is
able to maintain this output power level for minimum 3 minutes in a steadystate condition.
c) Alarm and Status Information Tests
It shall be tested that the alarm and status information of the pertinent Power
Generating Module/block/unit at which the Secondary Frequency Control Performance
Tests will be performed are created accurately at the Power Generating Module as
indicated in the following table and that this information is sent to the Load Dispatch
Center of TEIAS.
Minimum Capacity Alarm
(LMIN)
0= MIN
1= OK
(LMAX)
0= MAX
1= OK
1= LOCAL
0 = LOCAL OFF
1= REMOTE
0 = REMOTE OFF
1= MANUAL
0 = MANUAL OFF
1= FAILURE
0 = OK
(Plant at Minimum Limit)
Maximum Capacity Alarm
(Plant at Maximum Limit )
Power Generating Module/block/unit (LLOC)
SFK Local Operating Condition
(Plant in Local Control)
Power Generating Module/block/unit (LREM)
SFK Remote Operating Condition
(Plant in Remote Control)
Power Generating Module/block/unit (LMAN)
SFK Manual Operating Condition
(Plant in Manual Control)
LFC System Micro-Processor Failure (LMIC)
Alarm
311
(LFC Micro Processor Failure Alarm)
(LPWR)
1= OK
0 = MISMATCH
Demand (LRPD)
1= OK
0 = INVALID
1= AUTO
0= MANUAL
1= OFF
0= ON
Power Mismatch Alarm
(Local Power Mismatch)
Invalid Remote
Information Alarm
Power
(Invalid Remote Power Demand)
Unit
SFK
Condition
Operating (AUTO / MANUAL)
(Generator Unit Mode)
Unit Primary Frequency
Operating Condition
Control (PFCO)
(Primary Frequency Control in Operation)
Table E.17.B.1 - Alarm and status information
c.1. Invalid Remote Power Demand Alarm Test (LRPD)
MAXC and MINC values of the pertinent Power Generating Module/block/unit
shall be set so as to provide the maximum secondary frequency control range (RSA)
without separating the primary frequency control reserve amounts of the units.
The steps to be applied at this test phase are as follows:
i. It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block/unit.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position.
iv.
It shall be checked that “MAXC” and “MINC” values sent for the Power
Generating Module/block/unit from the Power Generating Module control
system are displayed accurately at the National Load Dispatch Center.
v.
The average of MAXC and MINC ((MAXC + MINC) / 2) of the Power
Generating Module/block/unit shall be sent as the set value via AGC
program existing at the National Load Dispatch Center and it shall be
waited that the output power becomes steady-state at this level.
vi.
While the Power Generating Module/block/unit carries on operating at the
set output power value, it shall be checked that “Remote Power Demand
Validity Signal (PD Signal)” sent to the pertinent Power Generating
Module/block/unit from the National Load Dispatch Center is cut, the
Power Generating Module control system generates LRPD signal as
“INVALID” due to the reason that it could not receive this signal for
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minimum 60 seconds, and afterwards, the secondary frequency control
operating condition of the Power Generating Module/block/unit is switched
to “LOCAL” position and this information is displayed accurately at the
National Load Dispatch Center.
vii.
While the Power Generating Module/block/unit is in this condition, the
Power Generating Module operator shall be requested to switch the
secondary frequency control operating condition of the Power Generating
Module/block/unit to “REMOTE” position. It shall be checked that the
Power Generating Module/block/unit can not be switched to “REMOTE”
operating condition and carries on operating in “LOCAL” operating
position because “Remote Power Demand Validity Signal (PD Validity)” is
inactive.
viii.
“Remote Power Demand Validity Signal (PD Validity)” sent to the pertinent
Power Generating Module/block/unit from the National Load Dispatch
Center shall be reactivated. It shall be checked that the Power Generating
Module control system generates LRPD signal as “OK”, and at the same
time, the Power Generating Module/block/unit is automatically switched to
“REMOTE” operating position and carries on operating in “LOCAL”
operating position, and this information is displayed accurately at the
National Load Dispatch Center.
ix.
While the Power Generating Module/block/unit is in this condition, the
Power Generating Module operator shall be requested to switch the
secondary frequency control operating condition of the Power Generating
Module/block/unit to “REMOTE” position. It shall be checked that the
Power Generating Module/block/unit is switched to “REMOTE” operating
position and this information is displayed accurately at the National Load
Dispatch Center.
c.2. Power Generating Module/block/unit SFK Remote Operating Condition Test
(LREM)
The steps to be applied at this test phase are as follows:
i.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block/unit.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position. It shall be checked that this information is displayed accurately at
the National Load Dispatch Center.
iv.
It shall be checked that the secondary frequency control operating condition
of the pertinent Power Generating Module/block cannot be switched to
“REMOTE” position without switching the operating condition of at least
one of the other units, except for the steam turbine inside the Power
Generating Module/block, to “AUTO” position.
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c.3. Power Generating Module/block/unit SFK Local Operating Condition Test (LLOC)
The steps to be applied at this test phase are as follows:
i.
The secondary frequency control operating condition of the pertinent Power
Generating Module/block/unit shall be switched to “LOCAL” position and
it shall be checked that this information is displayed accurately at the
National Load Dispatch Center.
c.4. Power Generating Module/block/unit SFK Manual Operating Condition Test
(LMAN)
The steps to be applied at this test phase are as follows:
i.
The secondary frequency control operating condition of the pertinent Power
Generating Module/block/unit shall be switched to “MANUAL” position
and it shall be checked that this information is displayed accurately at the
National Load Dispatch Center.
c.5. Maximum Capacity Alarm Test (LMAX)
The test steps to be applied for the Maximum Capacity Alarm Test are as follows:
i.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block/unit.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position.
iv.
It shall be checked that “MAXC” value sent for the Power Generating
Module/block/unit from the Power Generating Module control system is
displayed accurately at the National Load Dispatch Center.
v.
The current generation value of the Power Generating Module/block/unit
shall be sent as the set value via AGC program existing at the National Load
Dispatch Center. It shall be checked that this value is displayed accurately
in the Power Generating Module control system, and similarly, “Remote
Power Demand Feedback Value” of the Power Generating
Module/block/unit sent from the Power Generating Module control system
is displayed accurately at the National Load Dispatch Center.
vi.
While the Power Generating Module/block/unit carries on operating under
normal conditions, “MAXC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block/unit via AGC
program existing at the National Load Dispatch Center.
vii.
When the generation value of the Power Generating Module/block/unit
reaches to “MAXC + (1% x RSA)” value and is above this value, it shall be
314
checked that LMAX signal is generated as “MAXIMUM” in the Power
Generating Module control system and it is displayed in this manner at the
National Load Dispatch Center.
viii.
“MAXC + (50% x RSA)” value shall be sent to the relevant Power
Generating Module/block/unit as “Remote Power Demand Set Value” via
AGC program existing at the National Load Dispatch Center. When the
generation value of the Power Generating Module/block/unit drops below
“MAXC + (1% x RSA)” value, it shall be checked that LMAX signal is
generated as “OK” in the Power Generating Module control system and it is
displayed in this manner at the National Load Dispatch Center.
c.6. Minimum Capacity Alarm Test (LMIN)
The test steps to be applied for the Minimum Capacity Alarm Test are as follows:
i.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block/unit.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position.
iv.
It shall be checked that “MINC” value sent for the Power Generating
Module/block/unit from the Power Generating Module control system is
displayed accurately at the National Load Dispatch Center.
v.
The current generation value of the Power Generating Module/block/unit
shall be sent as the set value via AGC program existing at the National Load
Dispatch Center. It shall be checked that this value is displayed accurately
in the Power Generating Module control system, and similarly, “Remote
Power Demand Feedback Value” of the Power Generating
Module/block/unit sent from the Power Generating Module control system
is displayed accurately at the National Load Dispatch Center.
vi.
While the Power Generating Module/block/unit carries on operating under
normal conditions, “MINC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block/unit via AGC
program existing at the National Load Dispatch Center.
vii.
When the generation value of the Power Generating Module/block/unit
reaches to “MINC + (1% x RSA)” value and is below this value, it shall be
checked that LMIN signal is generated as “MINIMUM” in the Power
Generating Module control system and it is displayed in this manner at the
National Load Dispatch Center.
viii.
“MINC + (50% x RSA)” value shall be sent to the relevant Power
Generating Module/block/unit as “Remote Power Demand Set Value” via
AGC program existing at the National Load Dispatch Center. When the
generation value of the Power Generating Module/block/unit is above
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“MINC + (1% x RSA)” value, it shall be checked that LMIN signal is
generated as “OK” in the Power Generating Module control system and it is
displayed in this manner at the National Load Dispatch Center.
c.7. Power Mismatch Alarm Test (LPWR)
MAXC and MINC values of the pertinent Power Generating Module/block/unit
shall be adjusted so as to provide the maximum secondary frequency control range (RSA)
without separating the primary frequency control reserve amounts of the units.
The test steps to be applied for the Power Mismatch Alarm Test are as follows:
i. It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block/unit.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position.
iv.
It shall be checked that “MAXC” and “MINC” values sent for the Power
Generating Module/block/unit from the Power Generating Module control
system are displayed accuratey at the National Load Dispatch Center.
v.
The average of MAXC and MINC ((MAXC + MINC) / 2) of the Power
Generating Module/block/unit shall be sent as the set value via AGC
program existing at the National Load Dispatch Center and it shall be
waited that the output power becomes steady-state at this level.
vi.
While the Power Generating Module/block/unit carries on operating in this
condition, it shall be ensured that there arises a difference higher than (10%
x RSA) value between the generation value of the Power Generating
Module/block/unit and “Remote Power Demand Set Value” sent by sending
the suitable “Remote Power Demand Set Value” from the National Load
Dispatch Center. In this case, it shall be checked that LPWR signal is
generated as “MISMATCH” in the Power Generating Module control
system and it is displayed in this manner at the National Load Dispatch
Center.
vii.
It shall be ensured that there arises a difference lower than (10% x RSA)
value between the generation value of the Power Generating
Module/block/unit and “Remote Power Demand Set Value” sent by sending
the suitable “Remote Power Demand Set Value” from the National Load
Dispatch Center. In this case, it shall be checked that LPWR signal is
generated as “OK” in the Power Generating Module control system and it is
displayed in this manner at the National Load Dispatch Center.
c.8. Micro-Processor Failure Alarm Test (LMIC)
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“LFC Microprocessor Failure (LMIC)” signal of the relevant Power Generating
Module/block/unit to be tested shall be checked by simulation method since actual failure
cannot be created.
The steps to be applied at this test phase are as follows:
i.
As a result of the failure simulation performed, it shall be checked that the
Power Generating Module control system generates “LMIC” signal as
“FAILURE” and this information is displayed accurately at the National
Load Dispatch Center.
ii.
If the failure simulation performed is ended, however, it shall be checked
that the Power Generating Module control system generates “LMIC” signal
as “OK” and this information is displayed accurately at the National Load
Dispatch Center.
d) Power Distribution Test
The Power Distribution shall be applied for the Power Generating Modules/units in
which the number of units is 2 and above.
Before the power distribution test, the necessary adjustments shall be made so that
the primary frequency control operation of the units will be disconnected. MAXC and
MINC values of the relevant Power Generating Module/unit shall be adjusted so as to
provide the maximum secondary frequency control range (RSA) without separating the
primary frequency control reserve amounts of the units.
In this part of the Secondary Frequency Control Performance Tests, first of all, the
units that can participate in the secondary frequency control operation shall be separated
into two groups so that each group will has equal number of units. The tests shall be
performed in 2 phases by switching the secondary frequency control operating conditions
of the units to “AUTO” position by turns as a group. In other words, it shall be checked
that whether the distribution of “Remote Power Demand Set Value” only to the units in the
first group is performed accurately by switching the secondary frequency control operating
conditions of the units in the second group to “MANUAL” position while the secondary
frequency control operating conditions of the units in the first group is in “AUTO”
position. In the second phase of the test, however, it shall be checked that whether the
distribution of “Remote Power Demand Set Value” only to the units in the second group is
performed accurately by switching the secondary frequency control operating conditions of
the units in the first group to “MANUAL” position while the secondary frequency control
operating conditions of the units in the second group is in “AUTO” position.
The steps to be applied in the first phase of this test are as follows:
i.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
317
iii.
After the completion of the mutual verification procedures, the operating
condition of the pertinent unit/units shall be switched to “AUTO” position
and the secondary frequency control operating condition of the pertinent
Power Generating Module/block/unit shall be switched to “REMOTE”
position.
iv.
It shall be checked that “MAXC” and “MINC” values sent for the Power
Generating Module/block from the Power Generating Module control
system are displayed accurately at the National Load Dispatch Center.
v.
The generation value of the unit/units the operating condition of which is
“AUTO” shall be set to its own secondary minimum capacity value for each
unit and it shall be waited that the generation becomes steady-state at this
level. The generation value of the unit/units the operating condition of
which is “MANUAL”, however, shall be set to the value which is the
arithmetical average of its minimum and maximum capacity values for each
unit and it shall be waited that the unit becomes steady-state at this level.
vi.
The current generation value of the Power Generating Module/block shall
be sent as the set value via AGC program existing at the National Load
Dispatch Center. It shall be checked that this value is displayed accurately
in the Power Generating Module control system.
vii.
While the Power Generating Module/block carries on operating under
normal conditions, “MAXC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block via AGC
program existing at the National Load Dispatch Center.
viii.
It shall be checked that the units the operating condition of which is
“AUTO” increase their generation in order to reach to “Remote Power
Demand Set Value” sent and there is no change in the generation of the
units the operating condition of which is “MANUAL”.
ix.
While the Power Generating Module/block carries on operating under
normal conditions, “MINC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block via AGC
program existing at the National Load Dispatch Center.
x.
It shall be checked that the units the operating condition of which is
“AUTO” decrease their generation in order to reach to “Remote Power
Demand Set Value” sent and there is no change in the generation of the
units the operating condition of which is “MANUAL”.
Before the commencement of the second phase of this test, the following steps shall
be applied by switching the units operating condition of which is in “AUTO” position to
“MANUAL” position and the units the operating condition of which is in “MANUAL”
position to “AUTO” position:
i.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is active for the pertinent Power Generating Module/block.
ii.
It shall be checked that “Remote Power Demand Validity Signal (PD
Validity)” is displayed accurately in the Power Generating Module control
system and that LRPD signal is sent as “OK” to the National Load Dispatch
Center.
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iii.
After the completion of the mutual verification procedures, it shall be
checked that the operating conditions of the pertinent unit/units are in
“AUTO” position and the secondary frequency control operating condition
of the pertinent Power Generating Module/block/unit is in “REMOTE”
position.
iv.
It shall be checked that “MAXC” and “MINC” values sent for the Power
Generating Module/block from the Power Generating Module control
system are displayed accurately at the National Load Dispatch Center.
v.
The generation value of the unit/units the operating condition of which is
“AUTO” shall be set to its own secondary minimum capacity value for each
unit and it shall be waited that the generation becomes steady-state at this
level. The generation value of the unit/units the operating condition of
which is “MANUAL”, however, shall be set to the value which is the
arithmetical average of its minimum and maximum capacity values for each
unit and it shall be waited that the unit becomes steady-state at this level.
vi.
The current generation value of the Power Generating Module/block shall
be sent as the set value via AGC program existing at the National Load
Dispatch Center. It shall be checked that this value is displayed accurately
in the Power Generating Module control system.
vii.
While the Power Generating Module/block carries on operating under
normal conditions, “MAXC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block via AGC
program existing at the National Load Dispatch Center.
viii.
It shall be checked that the units the operating condition of which is
“AUTO” increase their generation in order to reach to “Remote Power
Demand Set Value” sent and there is no change in the generation of the
units the operating condition of which is “MANUAL”.
ix.
While the Power Generating Module/block carries on operating under
normal conditions, “MINC” value shall be sent as “Remote Power Demand
Set Value” to the pertinent Power Generating Module/block via AGC
program existing at the National Load Dispatch Center.
x.
It shall be checked that the units the operating condition of which is
“AUTO” decrease their generation in order to reach to “Remote Power
Demand Set Value” sent and there is no change in the generation of the
units the operating condition of which is “MANUAL”.
In order to verify that the generation changes in the units the operating condition of
which is “MANUAL” do not affect the tracing of “Remote Power Demand Set Value” sent
via AGC program at the National Load Dispatch Center by the generation of the Power
Generating Module/block, the following test shall be performed:
i.
One or several of the units the operating condition of which is in “AUTO”
position shall be switched to “MANUAL” position and it shall be checked
that whether the other units in “AUTO” position compensate the load
change caused by these units in “MANUAL” position by having loading
and/or load shedding procedures performed up to the limit values of the unit
by means of operator interference. If required, the same procedures shall be
repeated for the other units.
Test Results
319
(16) During the Secondary Frequency Control Performance Tests, the records of the
other signals that may be considered necessary shall be taken as well as the following
signals according to the test step to be performed;
i.
Active Power Output Gross Values
ii.
Remote Power Demand Set Value (Pset RPD)
iii.
Remote Power Demand Feedback Value (Pset Feedback)
iv.
Grid/Simulated Frequency
v.
Speed Droop Set Values
vi.
Maximum Capacity Value (MAXC)
vii.
Minimum Capacity Value (MINC)
viii.
Remote Power Demand Validity Signal (PD Validity)
ix.
Alarm and Status Information;
- Invalid Remote Power Demand Information Alarm (LRPD)
- Maximum Capacity Alarm (LMAX)
- Minimum Capacity Alarm (LMIN)
- Micro-Processor Failure Alarm (LMIC)
- Power Mismatch Alarm (LPWR)
- Unit Operating Condition (Auto/Manual)
- Secondary Frequency Control Operating Condition (LREM, LMAN,
LLOC)
- Primary Frequency Control Operating Condition (PFCO)
(17) It is principle that the test report to be drawn up as a result of the secondary
frequency control performance tests will include at least the following test results:
i.
In accordance with the set value (Pset RPD) sent to the Power Generating
Module/block/unit tested, the graphic of the response that occurs in the
Power Generating Module/block/unit (it shall be formed for each one of the
loading speed tests set out in the test phases section for both operating
conditions, namely while the Power Generating Module/block/unit is
participating in the primary frequency control and without the participation
of this Power Generating Module/block/unit in the primary frequency
control)
ii. "Loading Speed and Ratio",
The loading speed is the proportion of the load change occurring within the period
from the moment when the total active power output of the Power Generating
Module/block/unit starts to change in line with “Pset RPD” signal until the moment when
it reaches to the target output power to such period.
iii.
The loading speed (MW/min.) calculated above shall be converted into the
loading speed ratio by using the following formula.
iv.
Loading speed ratio (%/min) = 100*(loading speed/Pnom)
v.
Pnom= nominal active power of the Power Generating Module/block/unit
vi.
“Delay Time” which is the period from the moment when “Remote Power
Demand Set Value (Pset RPD)” is sent to the pertinent Power Generating
Module/block/unit until the moment when the total active power output of the
320
Power Generating Module/block/unit starts to change in line with “Pset RPD”
signal.
vii.
The Response Time is the period from the moment when the relevant Power
Generating Module/block/unit starts to response until the moment when the
total active power output reaches to the target output power.
viii.
The following tables should be filled in separately according to the results
obtained in the Loading and Load Shedding tests in "PFK ON" and "PFK
OFF" positions.
Name of the Unit
Loading Speed
(MW/minute)
Load Shedding Speed Droop
Speed
Set Value (%)
(MW/minute)
Unit–1
Unit–2
Unit- …
Unit-n
Table E.17.B.2 - Loading and Load shedding speeds
Unit/Block/Power Generating Module
Minimum
Limit (MW)
SFK Maximum SFK Limit
(MW)
Unit–1
Unit–2
Unit- …
Unit-n
Total Secondary Frequency Control Range
(MINC and MAXC)
Tablo E.17.B.3 - Secondary Frequency Control Range
ix.
It shall be checked that the following information are displayed on the
Automatic Generation Control System/ Interface Human-Machine Interface
(HMI) installed at the Power Generating Module:
-
AGC control block diagram,
Operation mode of the AGC system,
Set value and distribution to the units,
Local set value (It can be entered manually by the operators),
Secondary frequency control limits on unit basis (It can be entered manually
by the operators),
- Secondary and primary frequency control maximum and minimum capacity
values (MAXC, MINC, MAXCpr and MINCpr) of the Power Generating
Module/block/unit,
- Secondary frequency control band of the Power Generating
Module/block/unit,
321
-
Status of “PD Validity” signal,
Alarms concerning the AGC System/ Interface,
Total primary frequency control reserve allocated,
Status signals of participation of the units in the primary frequency control
(PFCO),
Unit loading / load shedding speeds,
Speed governor droop settings,
Total Power Generating Module generation,
Control error (difference between set value and Power Generating Module
generation).
Test Acceptance Criteria
(18) In accordance with the set value sent by TEIAS to the Power Generating
Module/block/unit tested over the Automatic Generation Control (AGC) system located at
the National Load Dispatch Center, the graphic of the response that occurs in the Power
Generating Module/block/unit, which is created according to the date obtained during the
loading speed ratio test (section b.2.) while the primary frequency control operation is
disabled should be within the tolerances indicated in the following figure.
Ts= 120 sec.
Tp=t2-t1=t6-t5= 30 sec.
Tt=t4-t1=t8-t5 <= 300 sec.
Td=t5-t4=t9-t8=180 sec.
ε = 1%*Pnom. Relevant generation fac.
Şekil E.17.B.1 – Test Acceptance Criteria
(19) After having been generated accurately at the Power Generating Module, the
alarm tested and the position information should be sent to the Load Dispatch Center of TEIAS
accurately. The communication infrastructure of the Power Generating Module/block/unit
tested, which will participate in the Secondary Frequency Control, should be sufficient to
render this service.
(20) In the power distribution test, the loading speed ratios that occurred in the
applied output power changes of the relevant Power Generating Module/block/unit should
322
be compatible with the calculated loading speed ratio within the tolerances of ±10% so as
to be directly proportional to the number of the units in “Auto” position.
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E.17.C.1 REACTIVE POWER SUPPORT SERVICE PERFORMANCE TEST
PROCEDURES
(1)
If there is more than one unit at the Power Generating Module, the reactive
power support service performance tests shall be performed and the reactive power support
service performance test certificate concerning these tests shall be drawn up separately for
each unit. The test report to be prepared shall include the tests performed for all units.
Before the Reactive Power Support Service Performance Tests, the following conditions
should be met:
a.
For the purpose of testing the unit to be tested under the operating conditions
under which the unit is expected to function all the time, the relevant unit,
independent from all kinds of external control cycles, shall be capable of
running in the Alternator Terminal Voltage Regulation Mode (AVR Auto
Mode) and ensuring reactive power loading by increasing/decreasing the
alternator terminal voltage set value. In the step-up transformer, it can be
ensured that the unit is loaded with reactive power by changing the tap for the
units having load tap changers and, when required, by changing the alternator
terminal voltage set value.
b.
For the purpose of preventing the voltage changes that might occur during the
test from threatening the system safety and bringing the system voltage to more
suitable levels for the test, the necessary coordination shall be ensured by
communicating with the RLDC prior to the test. At the relevant Power
Generating Module, the other units that are not subject to the test shall be
operated in order to minimize the voltage changes for such purpose and to
improve the test conditions.
c.
The performance tests shall be performed under the operating conditions which
the unit to be tested is exposed to during the normal operation.
d.
Before the test, the alternator loading curve and all pertinent protection values
(V/f limitation, V/f trip, Over-excitation Limitation, Over-excitation Trip,
Stator Current Limitation, High Voltage Trip, Under-excitation Limiter,
Excitation Loss trip and Low Voltage Trip etc.) of the unit to be tested shall be
provided by the Power Generating Module officials to those authorized to
perform the test. The tests shall be started after this information has been
provided. This information shall also be added to the test report.
e.
Before the test, the nominal active power value specified in the acceptance
certificates or generation license of the unit to be tested, the nominal power
factor and nominal apparent power (MVA) value of the alternator connected to
that unit, the cooling type, the main transformer information (whether or not
there is a load tap changer, rate and number of taps), the control structure block
diagram that is used to regulate the busbar voltage shall be provided by the
Power Generating Module officials to those authorized to perform the test. The
tests shall be started after this information has been provided. This information
shall also be added to the test report.
f.
The sampling rate for each value that is measured during the tests should be
minimum 1 data in a second. For the records to be taken during the tests, it is
principle to use recording equipment which is supplied by the authorized
company performing the test and which can measure the relevant signals by
external connection over the connection points specified. The recording files
belonging to the Power Generating Module control system should not be used.
324
The accuracy class of the data recording equipment to be externally connected
should be minimum 0.2%. The data recording equipment should have the
ability to record the values that are measured during the test with the time
information. The calibration certificate of the test equipment should be for
three years at most. It shall be submitted to the supervisor of TEIAS that the
data recording equipment meets the necessary requirements along with its
certificates prior to the test.
(2)
For the alternator to allow that the forced reactive power values can be
completely reached during the tests, care should be taken to start the relevant test with
over-excited operation or under-excited operation in consideration of the status of the
busbar voltage. The other units, if any, at the concerned Power Generating Module or the
pertinent zone facilities under the coordination of the RLDC should be used to provide the
optimum busbar voltage conditions for the unit tested.
(3)
For the units which have the ability to function as synchronous
compensator, the tests shall be performed both in generator condition and synchronous
compensator condition. For the synchronous compensation service, the tests shall be
performed in line with the verification that the forced MVAR values different from the
values determined according to the generator condition have been achieved.
(4)
The signals recorded during the tests shall be added to the test report as text
formatted (ASCII/Text) data recording file in CD/DVD environment as determined by
TEIAS and shall be delivered to the supervisor of TEIAS.
E.17.C.1.1 Reactive Power Capacity Tests
Test Objective
(5)
For the tests to be performed in generator condition, the main purpose is to
verify that the units can reach to the forced MVAR values (Figure E.4.C.1) determined in
order to be able to control the busbar voltage at the active power levels between the
nominal active power and the minimum stable generation levels (MSGL).
(6)
For the tests to be performed in Synchronous Compensator condition, the
main purpose is to verify that the units, when required, can reach to the forced reactive
power values defined in the Article 20 of this Regulation within the tolerance determined
(Figure E.4.C.2).
Generator Nom.
Figure E.17.C.1.1 – Conditions in which
the Test Objectives are achieved (Generator)
Figure E.17.C.1.2 – Conditions in which the
Test Objectives are achieved (Synchronous Comp.)
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Test Phases
(7)
The Reactive Power Support Service Performance Test to be performed in
generator condition shall be performed at three active power levels in total, namely at the
nominal level of the active power output of the unit to be tested, at the minimum stable
generation level and at the average value between the nominal level and the minimum
stable generation level. If the available capacity of the unit is below the nominal level, the
tests can be performed at the available capacity level. The Reactive Power Support Service
Performance Test to be performed in synchronous compensator condition, however, shall
be performed in over and under-excited condition while the unit is running as synchronous
compensator.
(8)
The basic test steps to be performed separately at each of the designated
operating points are specified below.
a.
The performance test with regard to the provision of reactive power support
service in synchronous compensator condition shall be performed as follows in
over and under-excited condition while the unit is running as synchronous
compensator.
b.
Over-Excited Reactive Power Support Test
The active power output of the unit shall be fixed to the relevant power in the
aforementioned phases and the frequency control operations shall be disconnected. As the
beginning phase of the test, the reactive output power of the unit shall be adjusted to the
value which is closest to zero and it shall be waited for minimum 2 minutes in this
condition. Afterwards, the reactive output power amount of the unit shall be gradually
increased until one of the following conditions occurs. In addition to this, the position of
the load tap changer, if any, shall be changed in line with the test purpose (In order to
prevent unwanted disconnections, the adjustment coordination of the protection functions
should be verified prior to the test). The application regarding this test step shall be carried
out as seen in the Figure-E.17.C.1.3 below.
i.
ii.
iii.
iv.
v.
vi.
Until the alternator reaches to the loading curve limit,
Until V/f limiter is activated or reaches to the maximum operable terminal
voltage, (The maximum operable alternator terminal voltage must not be less
than 105% of the nominal alternator terminal voltage.)
Until the Over-excitation Limiter is activated,
Until the Stator Current Limiter is activated,
Until it reaches to the continuous operable alternator temperature limits,
Until it reaches to the maximum internal demand voltage level, (If the unit
tested has connection and if the internal demand is not regulated in a different
manner)
The reason which does not allow the unit to be loaded with more MVAR as overexcited while the reactive output power amount is being gradually increased shall be
determined and this value shall be specified in the test results. After carrying on for
minimum 10 minutes at the achievable reactive power level, the Table-E.17.C.1.1 in the
Test Results section shall be filled in according to the average values.
For the synchronous compensator condition, the process shall be concluded upon
reaching to the Over-Excited Forced MVAR value defined for this condition, not upon
reaching to the alternator loading curve limit.
326
P/Q Limit
2
min.
10
min.
Figure E.17.C.1.3 – Application of the Over-Excited Reactive Power Support Test
c.
Under-Excited Reactive Power Support Test
The active power output of the unit shall be fixed to the relevant power in the
aforementioned phases and the frequency control operations shall be disconnected. As the
beginning phase of the test, the reactive output power of the unit shall be adjusted to the
value which is closest to zero and it shall be waited for minimum 2 minutes in this
condition. Afterwards, the reactive output power amount of the unit shall be gradually
decreased until one of the following conditions occurs. In addition to this, the position of
the load tap changer, if any, shall be changed in line with the test purpose (In order to
prevent unwanted disconnections, the adjustment coordination of the protection functions
should be verified prior to the test). The application regarding this test step shall be carried
out as seen in the Figure-E.17.C.1.4 below.
i.
ii.
iii.
iv.
v.
vi.
Until it reaches to the alternator loading curve limit,
Until the minimum operable terminal voltage is reached (The minimum
operable alternator terminal voltage must not be more than 95% of the
nominal alternator terminal voltage)
Until the under-excitation limiter is activated,
Until the Stator Current Limiter is activated,
Until it reaches to the continuous operable alternator temperature limits,
Until it reaches to the minimum internal demand voltage level, (If the unit
tested has connection and if the internal demand is not regulated in a different
manner)
The reason which does not allow the unit to be loaded with more MVAR as underexcited while the reactive output power amount is being gradually decreased shall be
determined and this value shall be specified in the test results. After carrying on for
minimum 10 minutes at the achievable reactive power level, the Table-E.17.C.1.2 in the
Test Results section shall be filled in according to the average values.
For the synchronous compensator condition, the process shall be concluded upon
reaching to the Under-Excited Forced MVAR value defined for this condition, not upon
reaching to the alternator loading curve limit.
327
P/Q Limit
2
min.
10
min.
Figure E.17.C.1.4 – Application of the Under-Excited Reactive Power Support Test
Test Results
(9)
During the Reactive Power Support Service Performance Tests, the records
of the signals indicated below shall be taken over the connection specified next to them.
The records belonging to the other signals considered necessary by the expert performing
the test shall be taken as well as the aforementioned signals. The source, accuracy and
reliability of the data recorded shall be under the responsibility of the authorized test
company performing the test.
i.
ii.
iii.
iv.
v.
vi.
vii.
viii.
Active Power (over Current-Voltage Transformer/Transducer/PLC/DCS)
Reactive Power (over Current-Voltage Transformer/Transducer)
Busbar Voltage (over Voltage Transformer/Transducer)
Alternator
Terminal
Voltage
(over
Voltage
Transformer/Transducer/PLC/DCS)
Excitation
Current
or
Voltage
(Current-Voltage
Transformer/PLC/DCS/Transducer/Calculation)
Stator Current (Current Transformer/PLC/DCS/Transducer/)
Internal Demand Voltage (over Voltage Transformer/Transducer/PLC/DCS)
Power Factor (PLC/DCS/Transducer/Calculation)
The signals recorded during the tests shall be added to the test record and report as
text formatted (ASCII/Text) data recording file in CD/DVD environment as determined by
TEIAS.
(10) In the test report to be drawn up as a result of the Reactive Power Support
Service Performance Test to be performed in line with the steps set out in the Test Phases
section, it is principle to fill in the Table-E.17.C.1.1 and the Table.E.17.C.1.2 given below
separately for each test phase starting by fixing the active power output of the unit to be
tested at the nominal level, at the minimum stable generation level and at the average value
between the nominal level and the minimum stable generation level.
Likewise, it is principle to fill in the designated tables also for the unit tested as
synchronous compensator.
Time
Transformer Generator
Step
MW
Generator
MVAR
Alternator
Busbar
Terminal
Voltage
Voltage
(kV)
(kV)
Beginning
of
the
328
Excitation
Current
Stator
(A)
Current
or
(kA)
Voltage
(V)
Internal
Demand
Voltage
(kV)
Power
Factor
(cos φ)
Test
(average
values of 2
min.)
End of the
Test
(average
values of
10 min.)
The condition which does not allow the unit to be loaded with more MVAR as over-excited:
Table E.17.C.1.1 - Data to be recorded during the over-excited operation
Transforme Generator
r Step
MW
Time
Generator
MVAR
Alternator
Busbar
Terminal
Voltage
Voltage
(kV)
(kV)
Excitation
Current
Stator
(A)
Current
or
(kA)
Voltage
(V)
Internal
Demand
Voltage
(kV)
Beginning
of
the
Test
(average
values of 2
min.)
End of the
Test
(average
values of
10 min.)
The condition which does not allow the unit to be loaded with more MVAR as under-excited:
Table E.17.C.1.2 - Data to be recorded during the under-excited operation
d.
i.
ii.
iii.
iv.
v.
vi.
vii.
viii.
ix.
x.
xi.
In addition to the tables that are filled in separately for each of three phases, the
following information and certificates supplied by the manufacturer shall be
added to the test report as well:
Alternator Loading Curve
Control structure block diagram that is used to regulate the busbar voltage
Nominal active power of the unit specified in the acceptance certificates or
the Generation License (Pnom)
Turbine type (Hydroelectric, Gas, Steam)
Minimum Stable Generation Level of the unit (MW)
Nominal apparent power value of the alternator (MVA)
Nominal terminal voltage of the alternator (kV)
Rated rotor (field) current/voltage of the alternator
Rated current/voltage of the exciter
Nominal voltage of the high voltage busbar to which the alternator is
connected (voltage after the step-up main transformer)
Nominal power factor value of the alternator
329
Power
Factor
(cos φ)
xii.
xiii.
xiv.
xv.
xvi.
xvii.
Cooling type of the alternator (directly air / water-air / water-hydrogen)
Forced Reactive Power Capacity expected to be reached in the Overexcitation
Zone (Qmax +)
Forced Reactive Power Capacity expected to be reached in the Underexcitation Zone (Qmax -)
Nominal Primary and Secondary Voltage of the Step-up Transformer
Existing tap value of the Step-up Transformer during the test
Protection and Limitation Information (Value/Time) (V/f limitation, V/f trip,
Over-excitation Limitation, Over-excitation Trip, Stator Current Limitation,
High Voltage Trip, Under-excitation Limiter, Excitation Loss trip, Low
Voltage Trip)
Test Acceptance Criteria
(11) The acceptance criteria of the Reactive Power Support Service Performance
Test are as follows:
a.
b.
The unit tested must reach to the over and under-excited forced MVAR values
determined as generator and synchronous compensator within the 10%
tolerance of these values.
The unit tested must provide the over and under-excited forced MVAR values
determined as generator and synchronous compensator for minimum 10
minutes.
330
E.17.C.2. REACTIVE POWER SUPPORT SERVICE PERFORMANCE TEST
PROCEDURES FOR THE POWER PARK MODULES BASED ON THE WIND
ENERGY
(1)
The Reactive Power Support Service Performance Tests for the Power Park
Modules Based on the Wind Energy shall be performed on a Power Park Module basis at
the connection point(s) of the Power Park Module to the system and the reactive power
support service performance test certificate and test report regarding these tests shall be
prepared on a Power Park Module basis. The following conditions should be met prior to
the reactive power support service performance test.
(2)
Before the reactive power support service performance tests, the legal entity
that is engaged in generation activity must have obtained approval from the concerned
Regional Load Dispatch Center and/or National Load Dispatch Center of TEIAS.
(3)
The reactive power support service performance tests for the Power Park
Modules based on the wind energy consist of two parts, namely the Reactive Power
Capacity Tests and the Voltage Control Test.
(4)
During these tests, all units should be connected; if this is not possible, at
least 80% of the units should be connected. Furthermore, the Power Park Module voltage
controller should be connected, and the system voltage and the voltage transmitted by
TEIAS should be functioning in line with the reference and droop values.
(5)
For the purpose of preventing the voltage changes to occur during the tests
from threatening the system safety and bringing the system voltage to more suitable levels
(0.95pu – 1.05pu) for the test, the necessary coordination shall be ensured by
communicating with the RLDC prior to the test.
(6)
For the Power Park Module to allow that the forced reactive power values
defined in the relevant ancillary service agreement texts can be completely reached during
the tests, special care should be taken to start the relevant test with over-excited operation
or under-excited operation in consideration of the status of the busbar voltage. The
pertinent zone facilities under the coordination of the RLDC shall be used to provide the
optimum busbar voltage conditions for the unit tested.
(7)
The nominal active power value specified in the acceptance certificates or
generation license of the Power Park Module to be tested, the unit technologies used at the
Power Park Module, the main transformer information (whether or not there is a load tap
changer, rate and number of taps), the control structure block diagram that is used to
regulate the busbar voltage and the parameters of all relevant protection systems shall be
obtained prior to the test and this information shall be added to the test report.
(8)
The data recorder shall have the capability to record the measured values
with the time information.
(9)
The accuracy class of the data recording equipment used in the Reactive
Power Capacity Tests should be minimum 0.2%. The calibration certificate of the test
equipment should be for three years at most. It shall be submitted to the supervisor of
TEIAS that the data recording equipment meets the necessary requirements along with its
certificates prior to the test.
(10) After the completion of the performance tests, the Reactive Power Support
Service Performance Test Report should be filled in and signed by the parties taking part in
the test.
331
E.17.C.2.1 Reactive Power Capacity Tests
Test Objective
(11) The objective of this test is to verify that the reactive power capacity of the
Power Park Module based on the wind energy is provided within the limits set out in the
Annex-18 of the Grid Regulation.
Test Phases
(12) This test shall be performed for three different active output power values,
namely 20%, 50% and, depending on the wind conditions, a value between 60% and 100%
of the Maximum Capacity of the Power Park Module, at the connection point to the
system.
(13) The basic test steps to be performed separately on each of the operating
points specified are indicated below.
a. Over-Excited Reactive Power Capacity Test
i.
The busbar voltage reference value shall be applied to the voltage controller so
that the total reactive output power will be 0 (zero) MVAr. If the units have
reached to the voltage limits, the tests shall be carried on by returning the units
to the normal operating conditions via the transformer load tap changers, if
any.
ii.
The voltage reference value shall be increased by 1% at most until the total
reactive output power, after it has become steady-state, reaches to the overexcited forced reactive power value that is updated according to the system
voltage of the Power Park Module within the tolerance determined by TEIAS.
iii.
If the units have reached to the voltage limits before the total reactive output
power reaches to the over-excited forced reactive power value that is updated
according to the system voltage, the tests shall be carried on by returning the
units to the normal operating conditions via the transformer load tap changers,
if any. (If there is a no-load tap changer, the necessary arrangements shall be
made by using the no-load tap changer under the initiative of the company
authorized to perform the test. If considered inappropriate by the company
authorized to perform the test, the tests shall be ended).
iv.
After the total reactive output power has reached to the over-excited forced
reactive power value that is updated according to the system voltage within the
tolerance determined by TEIAS, the over-excited reactive power capacity test
shall be ended after it has been observed that the total reactive output power
has functioned as steady-state for 10 minutes at this value.
b. Under-Excited Reactive Power Capacity Test
i. The busbar voltage reference value shall be applied to the voltage controller so
that the total reactive output power will be 0 (zero) MVAr. If the units have
reached to the voltage limits, the tests shall be carried on by returning the units
to the normal operating conditions via the load tap changers of the transformer,
if any.
ii. The voltage reference value shall be increased by 1% at most until the total
reactive output power, after it has become steady-state, reaches to the underexcited forced reactive power value that is updated according to the system
voltage of the Power Park Module within the tolerance determined by TEIAS.
iii. If the units have reached to the voltage limits before the total reactive output
power reaches to the under-excited forced reactive power value that is updated
332
according to the system voltage, the tests shall be carried on by returning the
units to the normal operating conditions via the transformer load tap changers,
if any. (If there is a no-load tap changer, the necessary arrangements shall be
made by using the no-load tap changer under the initiative of the company
authorized to perform the test. If considered inappropriate by the company
authorized to perform the test, the tests shall be ended).
iv. After the total reactive output power has reached to the under-excited forced
reactive power value that is updated according to the system voltage within the
tolerance determined by TEIAS, the under-excited reactive power capacity test
shall be ended after it has been observed that the total reactive output power
has functioned as steady-state for 10 minutes at this value.
Test Results
(14) During the Reactive Power Capacity Tests, the signals indicated below shall
be recorded. The records belonging to the other signals considered necessary shall be taken
as well as the aforementioned signals.
-
Total Active Output Power of the Power Park Module (MW) (At the
Connection Point)
-
Total Reactive Output Power of the Power Park Module (MVAr) (At the
Connection Point)
-
System Voltage (kV) (At the Connection Point)
-
Voltage Reference Value of the Power Park Module (kV)
(15) The variables described above shall be named as specified and shall be
added to the test report in CD/DVD environment in line with the data format (ASCII/Text,
csv) determined by TEIAS.
(16) The sampling frequency for the signals measured during the Reactive Power
Capacity Tests shall be minimum 1 data (minimum 1 data in 1 second or in a shorter time)
in a second.
(17) At the conclusion part of the test report to be prepared as a result of the
tests, it is principle to fill in the Table E.17.C.2.1 and the Table E.17.C.2.2 given below
separately for three different active output power values, namely 20%, 50% and,
depending on the wind conditions, a value between 60% and 100% of the Maximum
Capacity of the Power Park Module to be tested.
Name of the Power Park Module:
Nominal Voltage of the System (kV):
Maximum Capacity MW:
Over-Excited Forced MVAR value (MVAR):
Voltage Drop (Droop) (%):
Total Number of the Units:
Maximum power achievable depending on the
wind conditions (MW):
Time
Main
Transform
er
Tap
Position
Forced MVAR
Updated
according to the
System Voltage
Total
Active
Output
Power
(MW)
333
Total
Reactive
Output
Power
(MVAR)
System
Voltage
(kV)
Voltage
Reference
Value
(kV)
Beginning
of the Test
End of the
Test
The condition which does not allow the Power Park Module to be loaded with more MVAR as
over-excited:
Table E.17.C.2.1 - Data to be recorded during the over-excited operation
Name of the Power Park Module:
Nominal Voltage of the System (kV):
Maximum Capacity MW:
Under-Excited Forced MVAR value (MVAR):
Voltage Drop (Droop) (%):
Total Number of the Units:
Maximum power achievable depending on the
wind conditions (MW):
Time
Main
Transformer
Tap
Position
Forced MVAR
Updated
according to the
System Voltage
Total
Active
Output
Power
(MW)
Total
Reactive
Output
Power
(MVAR)
System
Voltage
(kV)
Voltage
Reference
Value
(kV)
Beginning
of the Test
End of the
Test
The condition which does not allow the Power Park Module to be loaded with more MVAR as
under-excited:
Table E.17.C.2.2 - Data to be recorded during the under-excited operation
(18) In addition to the tables that are filled in separately for each of three phases,
the following information shall be added to the test report:
i.
Control structure block diagram that is used in order to regulate the busbar
voltage
ii.
Maximum Capacity of the Power Park Module that is specified in the
acceptance certificates or the Generation License (MW)
iii.
Unit Technologies
iv.
Nominal voltage of the system (Connection Point) (kV)
v.
Forced Reactive Power Capacity that is defined in the Reactive Power Support
Ancillary Service Agreement and that is expected to be reached in the Overexcitation Zone (Qmax +)
vi.
Forced Reactive Power Capacity that is defined in the Reactive Power Support
Ancillary Service Agreement and that is expected to be reached in the Underexcitation Zone (Qmax -)
vii.
Nominal Primary and Secondary Voltage of the Main Transformer
334
viii.
Impedance (%), X/R Ratio and nominal apparent value (MVA) of the Main
Transformer
ix.
Tap information of the main transformer (Load/no-load, change percentages)
x.
Protection and Limitation Information (Value/Time)
Test Acceptance Criteria
(19) The unit tested should reach at least 90% of the over and under-excited
forced reactive power values.
(20) If the Power Park Module tested could not reach the over and under-excited
forced reactive power values due to the system conditions even though the units have
reached to the voltage limits, the tests shall be considered successful. Apart from this, if the
Power Park Module could not reach the over and under-excited forced reactive power
values, the tests shall be considered unsuccessful. In both cases, the reason for the Power
Park Module not to be able to reach the forced reactive power values should be
documented and specified in the test report.
E.17.C.2.2 Power Park Module Voltage Controller Performance Test
Test Objective
(21) The objective of this test is to verify that the Power Park Module based on
the wind energy has performed the voltage control in line with the busbar reference value
and droop value determined by TEIAS and within the limits set out in the Annex-18 of the
Grid Regulation.
Test Phases
(22) This test shall be performed by adjusting the voltage drop (droop) to a value
between 2% and 7% while the active output power of the Power Park Module is at a value
between 60% and 100% of its Maximum Capacity depending on the wind conditions at the
connection point to the system.
(23) This test shall be performed by applying the simulated busbar voltage
instead of the connection point busbar voltage measured so that the voltage controller
cannot sense the system voltage. It is the responsibility of the relevant Power Park Module
to take all kinds of measures related to the equipment and personnel safety against the
unforeseen circumstances that might occur during the application of the test signal and
during the performance of the test.
(24) It shall be ensured that the total reactive output power of the Power Park
Module is 0 (zero) MVAr by adjusting the voltage reference value and the busbar voltage
test signal to the same value.
(25) After the total reactive output power has reached to 0 (zero) MVAr value,
tap changes up to ±1% of the nominal voltage of the connection point to the test signal
shall be applied. The tap changes shall be applied for minimum 1 minute.
Test Results
(26) During the Voltage Controller Performance Test, the signals indicated
below shall be recorded. The records belonging to the other signals considered necessary
by the expert performing the test shall be taken as well as the signals mentioned above.
335
-
Total Active Output Power of the Power Park Module (MW) (At the
Connection Point)
-
Total Reactive Output Power of the Power Park Module (MVAr) (At the
Connection Point)
-
System Voltage (kV) (At the Connection Point)
-
Voltage Reference Value of the Power Park Module (kV)
(27) The variables described above shall be named as specified and shall be
added to the test report in CD/DVD environment in line with the data format determined
by TEIAS (ASCII/Text, csv).
Test Acceptance Criteria
(28) The total reactive output power of the Power Park Module should reach to
the values indicated in the Table E.17.C.2.3 within the tolerance indicated with red lines in
the Figure E.17.C.2.1 as a result of the voltage reference value changes of ±1% depending
on the voltage drop (droop).
Tap change
+1%
Voltage
(Droop) 2%
Drop
Voltage
(Droop) 4%
Drop
Voltage
(Droop) 7%
Drop
of
Tap change of -1%
Qmax+ / 2
Qmax- / 2
Qmax+ / 4
Qmax- / 4
Qmax+ / 7
Qmax- / 7
Table E.17.C.2.3 - Reactive output power values expected to be reached as a result of the voltage
drop change
336
Total Reactive Output
Power (MVAr)
Qfinal: Total reactive output power expected to be
achieved (MVAr)
Time (hr)
Figure E.17.C.2.1 – Voltage Controller Performance Criteria
E.17.D. RESTORATION OF SYSTEM BLACK OUT SERVICE PERFORMANCE
TEST PROCEDURES
(1)
The Restoration of System Black Out Service Performance Tests consist of
two stages, namely the Unit Restoration Test and the Power Generating Module
Restoration Test. TEIAS, when it considers necessary, can perform a Power Generating
Module restoration test as the system test by isolating the Power Generating Module that
will render this service and a zone to which the Power Generating Module is connected
from the interconnected system in such a manner that the same test steps indicated below
will be followed, but the actual grid conditions will be reflected exactly (energization of
idle lines, island mode stability).
(2)
The Unit Restoration Test shall be performed by activating only the unit to
be tested by deenergizing the internal demand busbar and feeding it via the emergency
generator while the relevant Power Generating Module is connected to the transmission
system. It is principle to perform the Unit Restoration Test on all units of the relevant
Power Generating Module, which will render this service.
(3)
The Power Generating Module Restoration Test, however, shall be
performed by activating the unit to be tested by feeding the internal demand busbar via the
emergency generator while the relevant Power Generating Module is completely
disconnected from the transmission system by isolating all output feeders or internal
demand busbars of the Power Generating Module. The Power Generating Module
Restoration Test shall be performed by selecting one unit in the case where the relevant
Power Generating Module is not connected to the transmission system.
337
Output feeders
Power Generating
Module High
Voltage Busbar
Unit 1
Power Generating
Module High
Voltage Busbar
Unit 1
Unit 1
Internal
demand
busbar of
Unit 1
Configuration 1
Internal
demand
busbar of
Unit 2
Emergency
Generator
Configuration 2
Emergency
Generator
Figure E.17.D.1: General electrical connection configurations of internal demand busbar
and emergency generator
(4)
These tests shall be performed at all of the Power Generating Modules that
will render the Restoration of System Black Out service. The sampling rate for each value
that is measured during the tests should be 1 data in a second. Recording equipment
capable of measuring the relevant signals by means of external connection must be used
for the records during the tests, and no record files of the Power Generating Module’s
control system should be used. The accuracy class of the recording equipment should be
minimum 0.2% and the values that are measured during the test should be recorded with
the time information. The signals recorded during the tests shall be added to the test report
as text formatted (ASCII/Text) data recording file in CD/DVD environment as determined
by TEIAS and shall be delivered to the supervisor of TEIAS. It shall be submitted to the
supervisor of TEIAS that the data recording equipment to be externally used meets the
necessary requirements along with its certificates prior to the test.
E.17.D.1 Unit Restoration Test
Test Objective
(1)
The purpose of the Unit Restoration Test is to verify the restoration
capability of the unit tested and the activation of the relevant unit via the emergency
generator.
338
Test Phases
(2)
The unit restoration test shall be performed as follows while the unit to be
tested is connected and loaded in line with the relevant generation program.
a) After informing the NLDC/RLDC, the unit to be tested shall be disconnected by
gradually reducing its load in line with the relevant instructions. During this
process, all emergency generators must be disconnected.
b) The internal demand busbar of the unit to be tested shall be isolated from the
system. (For example, opening of CB1 and CB3 breakers in two configurations
given in the Figure E.17.D.1) According to the existing Power Generating Module
electrical connection configuration, if feeding cannot be ensured via the emergency
generator by isolating the internal demand of only one unit, the test steps for the
mentioned unit restoration test should be revised and submitted to TEIAS for
approval prior to the test by indicating the maneuvers to be made in the existing
Power Generating Module configuration on the single line diagram.
c) The internal demand busbar of the unit to be tested shall be energized by activating
the emergency generator.
d) It shall be ensured that the auxiliary equipment of the unit to be tested are energized
and supplied by the emergency generator.
e) While the internal demand of the relevant unit is being fed by the emergency
generator, the unit shall be connected and loaded in line with the instructions of the
NLDC/RLDC after the necessary conditions have been met.
f) The internal demand of the relevant unit shall be transferred to the unit auxiliary
transformer (sample Configuration 1) or to the Power Generating Module service
transformer (sample Configuration 2) according to the configuration of the relevant
Power Generating Module, without leading to any interruption in the output power
of the unit, at the output power level determined in line with the operating
procedures. In this case, care should be taken to automatically disconnect the
emergency generator or to provide the synchronization conditions of the grid and
the emergency generator in order not to lead to any interruption or disconnection in
the internal demand and, indirectly, in the output power of the unit.
g) After feeding the internal demand with normal configuration and disconnecting the
emergency generator, the relevant unit and other units shall be loaded in line with
the designated generation program or the loading instructions in consideration of
the instructions of the NLDC/RLDC.
Test Results
(3) During the Unit Restoration Test, the records belonging to other signals
considered necessary by the expert performing the test shall be taken as well as the signals
indicated below. The authorized test company performing the test shall be responsible for
the source, accuracy and reliability of the recorded data.
i.
ii.
iii.
iv.
Active power output of the emergency generator (MW)
Active power output of the alternator terminal of the unit to be tested (MW)
Voltage of the internal demand busbar of the unit to be tested (kV)
Voltage of the alternator terminal of the unit to be tested (kV)
339
Test Acceptance Criteria
(4) The time elapsed from the moment when the planned disconnection of the unit
to be tested is performed, the internal demand busbar is deenergized and the “connect”
instruction is given to the unit that will render this service to the moment when the internal
demand of the relevant unit is transferred to the grid should not exceed 15 minutes.
E.17.D.2. Power Generating Module Restoration Test
Test Objective
(1)
The purpose of the Power Generating Module Restoration Test is to verify
the activation of the relevant unit that is located in the relevant Power Generating Module
and that will render this service via the emergency generator in case of a real system black
out.
Test Phases
(2)
The Power Generating Module restoration test shall be performed as follows
while all other units are disconnected, except for the unit to be tested.
a) After informing the NLDC/RLDC, the unit to be tested shall be disconnected by
gradually reducing its load in line with the relevant instructions. During this
process, all emergency generators must be disconnected.
b) All internal demand busbars, internal demand busbar breakers or all output feeders
at the relevant Power Generating Module shall be opened and isolated.
c) The necessary internal demand busbars of the Power Generating Module and the
internal demand busbar of the unit to be tested shall be energized by activating the
emergency generator.
d) It shall be ensured that the auxiliary equipment of the unit to be tested are energized
and supplied by the emergency generator.
e) While the internal demand of the relevant unit is being fed by the emergency
generator, the unit shall be connected and loaded in line with the instructions of the
NLDC/RLDC after the necessary conditions have been met.
f) The internal demand of the relevant unit shall be transferred to the unit auxiliary
transformer (sample Configuration 1) or to the Power Generating Module service
transformer (sample Configuration 2) according to the configuration of the relevant
Power Generating Module, without leading to any interruption in the output power
of the unit, at the output power level determined in line with the operating
procedures. In this case, care should be taken to automatically disconnect the
emergency generator or to provide the synchronization conditions of the grid and
the emergency generator in order not to lead to any interruption or disconnection in
the internal demand and, indirectly, in the output power of the unit.
g) After feeding the internal demand with normal configuration and disconnecting the
emergency generator, the relevant unit and other units shall be connected and
loaded in line with the designated generation program or the loading instructions in
consideration of the instructions of the NLDC/RLDC.
340
Test Results
(3)
During the Power Generating Module Restoration Test, the records
belonging to other signals considered necessary by the expert performing the test shall be
taken as well as the signals indicated below. The authorized test company performing the
test shall be responsible for the source, accuracy and reliability of the recorded data.
i.
ii.
iii.
iv.
Active power output of the emergency generator (MW)
Active power output of the alternator terminal of the unit to be tested (MW)
Voltage of the internal demand busbar of the unit to be tested (kV)
Voltage of the alternator terminal of the unit to be tested (kV)
Test Acceptance Criteria
(4)
The time elapsed from the moment when the planned disconnection of the
unit to be tested is performed, the internal demand busbar is deenergized and the “connect”
instruction is given to the unit that will render this service to the moment when the internal
demand of the relevant unit is transferred to the grid should not exceed 15 minutes.
341
E.17.E. INSTANTANEOUS DEMAND CONTROL SERVICE PERFORMANCE
TEST PROCEDURES
(1)
The Instantaneous Demand Control Service Performance Tests shall be
performed in order to ensure the determination of the technical characteristics required to
be provided at the consumption points connected to the instantaneous demand control relay
of the consumption facilities of the legal entity that will render the service. These tests
shall be performed at all of the consumption facilities that will render the Instantaneous
Demand Control service. If there is more than one consumption point to participate in this
service at the consumption facility, the Instantaneous Demand Control Service
Performance Tests shall be performed separately for each consumption point to participate
in this service, and the instantaneous demand control performance test report and
certificate concerning these tests shall be drawn up separately for each consumption point.
(2)
Before the Instantaneous Demand Control Service Performance Tests, the
legal entity that will render the service must have completed the necessary arrangements at
the relevant consumption facilities, the investment regarding the relay that meets the
technical criteria determined by TEIAS and the investments regarding the meter,
installation and other necessary equipment.
(3)
The Instantaneous Demand Control Service Performance Tests shall be
performed by applying the test frequency signal to the instantaneous demand control
relays. It is the responsibility of the relevant consumption facility to take all kinds of
measures related to the equipment and personnel safety against the unforeseen
circumstances that might occur during the application of the test signal and during the
performance of the test.
(4)
The sampling rate for each value that is measured during the tests should be
minimum 10 data (one data per 100 milliseconds) in a second. For the records to be taken
during the tests, it is principle to use the recording equipment that is supplied by the
authorized company performing the test and that can measure the pertinent signals by
external connection. The accuracy class of the data recording equipment to be externally
connected should be minimum 0.2% and should have the capability to record the measured
values with the time information. The calibration certificate of the data recording
equipment should be for three years at most.
Test Objective
(1)
The purpose of the Instantaneous Demand Control Service Performance
Tests is to verify that the demand of the consumption points that are located at the tested
consumption facilities and that will participate in this service can be automatically
disconnected via the instantaneous demand control relays if the system frequency drops to
the frequency level determined by TEIAS.
Test Phases
(1)
During the performance of the Instantaneous Demand Control Service
Performance Tests, the following procedures shall be carried out. Before the
commencement of the tests, the consumption facility must have consumption amount as
much as the instantaneous demand control reserve amount that it commits to supply in
order to participate in the instantaneous demand control service.
a. Simulated test frequency signal shall be applied to the instantaneous demand
control relay at the consumption point to be tested instead of the grid frequency
information, and the frequency shall be reduced at the speed of 0.1 Hz/s.
342
b. After the simulated test frequency signal applied has reached to the frequency
level at which the service will be rendered, it shall be checked that whether or
not the instantaneous demand control relays have disconnected the total demand
at the relevant consumption point.
Test Results
(1)
During the Instantaneous Demand Control Service Performance Tests, the
records belonging to the other signals considered necessary by the expert performing the
test shall be taken as well as the signals indicated below.
i.
Simulated test frequency signal (Hz) applied to the instantaneous demand
control relay
ii.
Delay time of the instantaneous demand control relay (s)
iii.
Load amount measured at the relevant consumption point (MW)
iv.
Relay on off signal
(2)
The signals recorded during the tests shall be added to the test record and
the test report as text formatted (ASCII/Text) data recording file in CD/DVD environment
as determined by TEIAS and shall be delivered to the supervisor of TEIAS. It shall be
submitted to the supervisor of TEIAS that the data recording equipment meets the
necessary requirements along with its certificates prior to the test.
(3)
The simulated test frequency signal applied to the instantaneous demand
control relay and the load amount measured at the pertinent consumption point shall be
shown in the graphic as specified in the Figure E.17.E.1 and this graphic shall be added to
the test report.
Test Frequency Signal to be applied to
the Relay (Hz)
Rate of Change
df/dt
Load (MW)
df/dt = 0.1 Hz/second
Load
Change
Figure E.17.E.1 – Test Frequency Signal and Demand Curves
343
Test Acceptance Criteria
(1)
The acceptance criteria of the Instantaneous Demand Control Service
Performance Tests to be performed by the company authorized to perform the test are as
follows:
The demand must have been completely disconnected at the pertinent
consumption point within a period shorter than 400 milliseconds (including the statistical
delay time as well) after the simulated test frequency signal applied to the instantaneous
demand control relay has reached to the frequency level determined by TEIAS. (Tg ≤ 400
milliseconds)
344
ANNEX 18
GRID CONNECTION CRITERIA OF THE POWER PARK MODULES BASED
ON THE WIND ENERGY
E.18.1 SCOPE
These criteria are applied to the Power Park Modules based on the wind energy
connected to the transmission system and the Power Park Modules based on the wind
energy connected to the distribution system, having Maximum Capacity of 10 MW and
above. For the issues not included in this annex, the relevant provisions of this Regulation
are valid.
E.18.2 CONTRIBUTION OF THE POWER PARK MODULES BASED ON
THE WIND ENERGY TO THE SYSTEM AFTER FAILURE
Grid Phase-Phase voltage (p,u)
During the period in which the grid phase-phase voltage at the connection point of
the transmission or distribution system remains in the zone no 1 and zone no 2 shown in
the Figure E.18.2.1., the wind turbines should remain connected to the grid in case of
voltage drops arising in any phase or all phases.
Time, millisecond
Figure E.18.1 – grid phase-phase voltage at the connection point of the transmission
or distribution system
In the cases that the voltage drop remains in the zone no 1 during failure, the active
power of the wind turbine should achieve the maximum active power value that can be
generated by being increased at least 20 % of the nominal active power in a second
immediately after the removal of the failure.
In the cases that the voltage drop remains in the zone no 2 during failure, the active
power of the wind turbine should achieve the maximum active power value that can be
generated by being increased at least 5 % of the nominal active power in a second
immediately after the removal of the failure.
345
The voltage fluctuations up to ±10% (0.9pu – 1.1pu) that occur at the grid connection
point are the normal operating conditions and the wind energy-based Power Park Modules
should comply with the principles set out in the Article E.18.6 Reactive Power Support.
In the voltage fluctuations higher than ±10% that will occur in the mentioned failure
cases at the grid connection point, each wind turbine generator should provide maximum
reactive current support in inductive or capacitive direction without exceeding the designed
transient rated values, at the levels to reach 100% of the nominal current if required. This
transient state should reach to the maximum reactive current support value within 60
milliseconds with 10% error margin and should be sustainable for 1.5 seconds.
E.18.3 ACTIVE POWER CONTROL
In the emergency cases identified in the Article 61 of the Regulation, active power
control shall be able to be performed in the Power Park Modules based on the wind energy
connected to the transmission system. The active power output of the wind energy-based
Power Park Module should be automatically controllable between 20% and 100% of the
available power of the Power Park Module under the conditions of that time by means of
the signals to be sent by TEIAS, when necessary. In this context;
a) For the Power Park Modules based on the wind energy having Maximum Capacity
of 100 MW and below, loading speed should not exceed 5% of the Maximum Capacity of
the Power Park Module in a minute, and load shedding speed should not be less than 5% of
the Maximum Capacity of the Power Park Module in a minute.
b) For the Power Park Modules based on the wind energy having Maximum Capacity
above 100 MW, loading speed should not exceed 4% of the Maximum Capacity of the
Power Park Module in a minute, and load shedding speed should not be less than 4% of the
Maximum Capacity of the Power Park Module in a minute.
Users who fully comply with the TEIAS SCADA System shall install the necessary
system for reducing the generation amounts according to the set-point values to be sent by
TEIAS Load Distribution Center for certain periods for the purpose of decreasing
generation in the wind Power Park Modules due to grid constraints, etc.
E.18.4 FREQUENCY RESPONSE
The wind turbines should provide the frequency ranges and operating periods
specified in the ARTICLE 34 of this Regulation.
In addition to these operating conditions, the additional wind turbine should not be
commissioned in the cases that the grid frequency is above 50.2 Hz at the relevant Power
Park Module.
The wind turbine frequency response should be as to remain within the limits of the
power-frequency curve given in the Figure E.18.4.1.
346
Wind Turbine Available Active Power [%]
Frequency, Hertz
Figure E.18.4.1 – Wind Turbine Power-Frequency Curve
The wind turbine should have the capacity to generate all of the available power as
long as the grid frequency is within the range of 47.5-50.3 Hz. If the grid frequency
increases above 50.3 Hz, the wind Power Park Modules should perform load shedding so
as to provide 4% speed drop value by following the active power-frequency characteristics
given in the Figure E.18.4.1 and should be completely decommissioned at 51.5 Hz.
E.18.5 REACTIVE POWER CAPACITY
At the connection point of the transmission or distribution system, the wind energybased Power Park Module can constantly operate at every point for the reactive power
factor values within the limits specified with dark lines in the Figure E.18.5.1.
Total Active Power of the Facility (pu)
Wind Power Generating Module Reactive Power Capacity
Curve
Power Factor: 0.95 capacitive
Power Factor: 0.95 inductive
Power Factor: 0.835 capacitive
Power Factor: 0.835 inductive
Reactive power support below output power of 0.1 pu (total
power of the facility, active power) shall not be required.
Underexcitation Zone
Total Reactive Power of the Power Park
Module
(pu)
347
Overexcitation Zone
Figure E.18.5.1 – Wind Power Park Module Reactive Power Capacity Curve
These forced reactive power values determined and recorded by the ancillary
service agreements should be achieved when required depending on voltage as specified in
the Figure E.18.5.2.
U, Grid Voltage (p.u)
Underexcitation
Zone
Overexcitation
Zone
Reactive Output Power
Measured at the Grid
Connection Point
Q max - = Qmax_Under_Excited
Q max + = Qmax_Over_Excited
Figure E.18.5.2 Change of Forced Reactive Power Values depending on the Voltage of the
Connection Point
E.18.6 PROVISION OF REACTIVE POWER SUPPORT
The Power Park Modules based on the wind energy should constantly respond to
the balance state changes of the voltage of the connection point under the normal operating
conditions defined between the values of 0.9 pu and 1.1 pu of the voltage the connection
point in line with the characteristics designated in the Figure E.18.6.1.
348
U, Grid Voltage (p.u)
Voltage Set Value
This value is the % vaue of the voltage that will occur as
per the given voltage set value in the grid voltage for the
reactive output power of the Power Park Module to
increase from 0 to over-excited maximum reactive power
value or from 0 to under-excited maximum reactive
power value.
Reactive Output Power
Measured at the Grid
Connection Point (MVAr)
Reactive power factor corresponding to the
power factor of 0.95 as under-excited as per the
installed capacity of the generation facility
Qmax - = Under-excited Forced Reactive Power Value
Reactive power factor corresponding to the
power factor of 0.95 as over-excited as per the
installed capacity of the generation facility
Qmax + = Over-excited Forced Reactive Power Value
Figure E.18.6.1 – Curve of Reactive Power Support to be given to the System by the
Power Park Modules based on the wind energy
The voltage set value shall be given by TEIAS for the voltage of the grid
connection point. The Power Park Modules based on the wind energy should give
proportional response to the changes in the voltage of the grid connection point as seen in
the Figure E.18.6.1.
In the graphic given in the Figure E.18.6.1, “droop” value is a value between 2%
and 7% and shall be determined by TEIAS. (“Droop” (voltage drop) value is the % voltage
change that will occur as per the given voltage set value in the grid voltage for the reactive
output power of the Power Park Module to increase from 0 to over-excited maximum
reactive power value or from 0 to under-excited maximum reactive power value.)
The relevant Power Park Module should start to respond to a sudden tap change
that might occur under the normal operating conditions in the voltage of the grid
connection point within no later than 200 milliseconds, the reactive output power should
reach 90% of the required balance value within no later than 1 second and should be
balanced within no later than 2 seconds. In the balance state, the peak value of the
fluctuations that might occur in the reactive output power should not exceed 2% of the
change occurred.
E.18.7 GRID CONNECTION TRANSFORMER OF WIND ENERGY-BASED
POWER PARK MODULE
The grid connection transformers of the Power Park Modules based on the wind
energy directly connected to the transmission system should have the capacity of automatic
on-load tap-change. The other properties the transformers are required to have are
described in this Regulation.
349
E.18.8 INFORMATION TO BE PROVIDED BY THE POWER PARK
MODULES BASED ON THE WIND ENERGY TO TEIAS
At the stage of application for the connection agreement to TEIAS for the wind
energy-based Power Park Module, the following information is submitted to TEIAS:
1. Total Maximum Capacity capacity of the wind energy-based Power Park Module
in MWe.
2. Number of the wind turbines and nominal active power and type (asynchronous,
synchronous, type 3, type 4, etc.) of each wind turbine in MWe.
3. Connection manner of the turbines to the grid (directly connected; asynchronous
generator with dual excitation, synchronous generator with AC/DC/AC converters).
4. Operating status of the wind turbines in minimum and maximum wind speed
values (graphics displaying the generation deviation in the wind turbines as per the wind
speed).
5. Type and label values of the systems to be established in order to limit the voltage
and current harmonics and flicker impact.
6. Power quality impact assessment report prepared by an institution having ISO/IEC
17025 accreditation in compliance with IEC 61400-21 standard based on the
measurements performed as per the norms of IEC 61400-12 standard.
7. Static and dynamic models of the wind turbines to be established in order to be
used in the system surveys. Within this scope, static data details (voltage level, section,
length, etc.) of the wiring system in the wind farm in addition to the static and dynamic
data of the turbines.
8. Functional diagrams and mathematical models and set parameters of the master
controller of the wind farms.
9. Geographical coordinates of the wind energy-based Power Park Module and wind
turbines to be established on the regional 1/25.000 scale geographical map.
10. Other data that might be required by TEIAS.
Pursuant to the provisions of the Electricity Market Ancillary Services Regulation,
in order to put a new Power Park Module which is required to participate in the relevant
ancillary service into commercial operation, the legal entity registered in the name of the
facilities should submit the parameters and variables to be identified for “recording,
monitoring and control” of the ancillary services to be rendered and for the wind power
forecast and monitoring system to TEIAS according to the data format designated and
within the data transmission process following the signature of the relevant ancillary
service agreement with TEIAS or the inclusion of the mentioned Power Park Module into
the scope of the relevant ancillary services agreement that had been previously signed by
the relevant legal entity engaged in the generation activity as required by the item four of
the Article 36 of this Regulation.
350
E.18.9 MONITORING OF THE WIND POWER PARK MODULES
All licensed wind Power Park Modules shall establish the necessary infrastructure
in order to ensure that they are monitored from the Wind Power Monitoring and Forecast
Center (RITM) the center of which is in the General Directorate of Renewable Energy and
accordingly from the Load Dispatch Centers of TEIAS. The properties which the technical
equipment will have shall be published on the web page of the General Directorate of
Renewable Power.
351
ANNEX 19
WORK PERMIT REQUEST FORM
TEIAS
……...TRANSMISSION FACILITY AND OPERATION GROUP
DIRECTORATE
……..… DIRECTORATE/GROUP CHIEF ENGINEERING
Annex-1
YTİM.1
………LOAD DISPATCH OPERATION DIRECTORATE
1
WORK PERMIT REQUEST
1
2
Equipment to be taken out of service
3
Work to be performed
4
5
6
No : ……./…...
Date:
Center or E.T.Line at and on which the
work will be performed
Authorized Person requesting for the
permit
Crew Chief or Coordination Supervisor
to perform the work
T.M. Operation Technician to request
for energy disconnection and connection
from RLDOC
Date and time on and at which the work
Date
will be started
Date and time on and at which the work
8
Date
will be ended
Decommissioning
period
of
the
9
equipment
10 Users to be disconnected
Manner and period of taking into
11
service in emergency cases
7
Time
Time
Communication manner of T.M.
Operation Technician with RLDOC
NOTE:
12
2
REQUESTED MANEUVER PROPERTIES
1
Manner of starting maneuver
2
Delivery manner of the equipment
Manner of
available
NOTE:
3
making
the
equipment
Personnel authorized to request for work
permit
Name
Signature
Remark: The requests other than opening-closing routine maneuvers from the requested maneuver properties shall be
specified in this section.
352
ANNEX 20
WORK PERMIT REQUEST CANCELLATION FORM
TEIAS
……………..LOAD
DIRECTORATE
Appendix-2
DISPATCH
OPERATION
Form YTİM-2
1
WORK PERMIT
Date:
No :
Work Permit Request No :...……………..
1- Personnel filling in the form in RLDOC : …………………………………………………………………………
2-Work to be performed:………………………………………………………………………………………………
………………………………………………………………………………………………………….........................
3-Crew Chief or Coordination Supervisor to perform the work : …………………………………………………….
4-Departments informed :
………………………………………………………………………………………………………….........................
…………………………………………………………………………………………………………........................
5- Departments to perform the work:
OPERATION:………………………………………………………………………………………………………………
………………………………………………………………………………………………………………………….
RELAY :…………………………………………………………………………………………………………………
…………………………………………………………………………………………………………………………
ELECTRONIC :………………………………………………………………………………………………………
…………………………………………………………………………………………………………………………
TEST :…………………………………………………………………………………………………………………
…………………………………………………………………………………………………………………………
PLANT :………………………..………….………………………………………………………………………
…………………………………………………………………………………………………………………………
6-Users to be disconnected :…………………………………………………………………………………….
……………………...…………………………………………………………………………………………………
7-Person making an agreement with the user :……………………...……………………………………………………
…………………………………………………………………………………………………………………………
8- Reason for not granting work permit :……………………………………………………………………………...
………………………………………………………………………………………………………………………….
NOTE: This Form YTİM-2 shall be sent to the concerned departments even in the case that work permit has not been
granted.
RLDOC Engineer
Name
Signature
RLDOC Chief Engineer
Name
Signature
CANCELLATION OF WORK PERMIT
1- Official who requests for the cancellation :…………………………...…………………………….……………
2- Reason for the cancellation :…………………………………………………………………………………….
…………………………………………………………………………………………………………………….
3- Accepted by :……………………………………………………………………………………………………….
4- Services informed :……………………………..…………………………………………………………..
…………………………………………………………………………………………………………………….
5- Customers informed and Informant :……………………………………………………………………..
RLDOC Engineer
RLDOC Chief Engineer
Name
Signature
Name
Signature
353
2
Remark: Single signature is sufficient whenever it is compulsory.
354
ANNEX 21
MANEUVER FORM
TEIAS
…. LOAD DISPATCH DIRECTORATE
Appendix-3
Form YTİM-3
MANEUVER FORM
Person who made the Start Manouevre at
:…………………………………….Date: …../…../20….
RLDOC
Person who made the End Manouevre at
:…………………………………….Date: …../…../20….
RLDOC
:…………………………………………….…………
1- Maneuver No
2- Work Permit No
:…………………………………………….…………
3- Person requesting for the permit
:…………………………………………….…………
:…………………………………………….…………
4- Reason
:…………………………………………….…………………
…………………………………………….…………………
:……………………………………………………………….
…………………………………………….………………….
5- TM Operation Technician
6- Equipment to be taken out of service
7- Decommissioning period of the
:…………………………………………….…………
equipment
8- Other Works in the Center
:…………………………………………….…………
…………………………………………………...…………………………………………….
…………………………….……………………..…………………………………………….
……………………………….…………………..…………………………………………….
…………………SUBSTATION
Maneuverd by:
Maneuverd by:
Person who prepared the Maneuver Form:
Verified by:
355
MIN.
HOUR
DESCRIPTION
NO
MIN.
NO
DESCRIPTION
CLOSING MANEUVER
HOUR
OPENING MANEUVER
ANNEX 22
EQUIPMENT NUMBERING AND NAMING
Standard maneuver diagram for numbering and naming the equipment
Standardized numbering and naming of the equipment
E.N.H
…0
…1
…6
…9
…2
…3
…7
…5
Transfer
Busbar
Main Busba
...5
...5
...9
…6
…6
…7
...9
…7
G
MV
FEEDERS
Legend:
1.
2.
3.
5.
6.
7.
9.
0.
Line feeder splitter,
Line feeder circuit breaker,
Line feeder busbar separator, busbar 1 separator in a system with dual main busbar,
Transformer, unit, transfer feeder separator on the main busbar side, busbar 2
separator in a system with dual main busbar,
Transformer, unit, transfer and connection feeder circuit breaker,
Transfer feeder separator on the transfer busbar side, transformer feeder separator
on the transformer side, unit feeder separator on the transformer side,
By-pass or transfer separator,
Feeder earth separator.
356
ANNEX-23
DATA SHEETS
DATA RECORD SECTION
Page 1/9
SCHEDULE 1
DATA OF THE GENERATION UNIT OR COMBINED CYCLE GAS TURBINE BLOCK
: _________________________
DATE: _____________
DATA
UNIT
DATA
CATEGO
RY
DATA OF THE GENERATION
GENERATING MODULE
YEAR
0
YEAR
1
YEAR
2
YEAR
3
YEAR
4
YEAR
5
GR
3
GR
4
GR
5
GR
6
UNIT
OR
POWER
YEAR YEAR YEAR YEAR
6
7
8
9
US
DEMANDS OF THE POWER
PLANT:
Demand in relation to the power plant
supplied from the transmission
system of TEIAS or the user system
of the generation company
Maximum demand
MW
MVAr
Annual peak time value of the MW
demand of TEIAS within the certain MVAr
period of half an hour
Minimum annual value of the MW
demand of TEIAS within the certain MVAr
period of half an hour
APV(*)
APV
APV
APV
APV
APV
(The additional demand supplied by
the unit transformers should be
specified below)
GR GR
1
2
(***
)
UNIT OR COMBINED CYCLE
GAS TURBINE BLOCK DATA
AS PER THE STATUS
If the combined cycle gas turbine
block of the unit is excluded or if the
combined cycle gas turbine block is
connected to the transmission system
or the distribution system of TEIAS
according to the geographical and
electrical location and system
voltage, the connection point with the
system
The data SPV(**)
shall be
given
with
a
separate
writing.
If there is more than one connection Busbar
SPV
points, the connection point of the section
combined cycle gas turbine block
number,
the number
of
the
busbar to
which it is
connected
357
US
Type of the unit; steam, gas turbine
combined cycle gas turbine unit,
wind, etc.
List of the units within the combined
cycle gas turbine block (specifying
that which unit is part of which
combined cycle gas turbine block), in
case of combined cycle gas turbine
block in order, the details of the
possible configurations should be
given separately.
(*) Detailed Planning Data
(**) Standard Planning Data
SPV
(***) Generation group no 1
358
DATA RECORD SECTION
Page 2/9
DATA
UNIT
SCHEDULE 1
DATA
CATEGORY
GENERATION UNIT (OR COMBINED
CYCLE GAS TURBINE BLOCK AS
THE CASE MAY BE)
GR GR GR GR GR GR UT
1
2
3
4
5
6
(**
*)
Estimated operating order; e.g. 7 days
3 shifts
Nominal apparent power
Nominal active power
Nominal output voltage
*Unit Loading curve
*Available Capacity (monthly)
MVA
MW
kV
Inertia constant for synchronous units
MW
second
/MVA
Short circuit ratio for synchronous units
Normal auxiliary load supplied by the
unit at the nominal MW output
Nominal excitation current at the
nominal MW and MVAr output and
in nominal output voltage
Open circuit saturation curve of the
excitation current obtained from the test
certificated of the generation companies
120 % nominal output voltage
110 % nominal output voltage
100 % nominal output voltage
90 % nominal output voltage
80 % nominal output voltage
70 % nominal output voltage
60 % nominal output voltage
50 % nominal output voltage
IMPEDANCES: (Unsaturated)
Vertical axis synchronous reactance
Vertical axis transient reactance
Vertical axis subtransient reactance
Horizontal axis synchronous reactance
Horizontal axis transient reactance
Stator leakage reactance
Coil winding direct current resistance
MW
SPV(*)
SPV+
APV(**)
SPV
SPV
SPV+
MW
MVAr
A
SPV+
APV
APV
APV
A
A
A
A
A
A
A
A
APV
APV
APV
APV
APV
APV
APV
APV
% MVA
% MVA
% MVA
% MVA
% MVA
% MVA
% MVA
APV
SPV+
APV
APV
APV
APV
APV
(*)Detailed Planning Data,
(**)Standard Planning Data
(***) Power Generating Module
359
Block
DATA RECORD SECTION
Page 3/9
DATA
Time constants
Short circuit and unsaturated
Vertical axis transient time constant
Vertical axis subtransient time constant
Horizontal axis subtransient time constant
Stator time constant
Generation unit step-up transformer
SCHEDULE 1
UNIT
DATA
CATEGORY
Second
Second
Second
Second
APV
SPV
APV
APV
DATA OF THE GENERATION UNIT OR
POWER GENERATING MODULE
GR 1 GR
GR
GR GR 5 GR 6 ÜT
2
3
4
Nominal apparent power
MVA
SPV+
Voltage ratio
APV
Positive component reactance:
For maximum step
MVA %
SPV+
For minimum step
MVA %
SPV+
For nominal step
MVA %
SPV+
Positive component resistance:
For maximum step
MVA %
APV
For minimum step
MVA %
APV
For nominal step
MVA %
APV
Zero component reactance
MVA %
APV
Tap change range
+%/-%
APV
Tap change step size
%
APV
Tap-changer type of on-load or off-circuit OnAPV
Maximum Capacity
load/Offcircuit
Step type
Digital
Analogue
BCD
Connection group
EXCITATION SYSTEM PARAMETERS
Note:
The data requested under the Option 1 below must be provided. If this data is in relation to the small Power Generating
Modules or autoproducers not having significant effect on the transmission system of TEIAS, it is not necessary to provide such data.
Unless a contrary agreement is entered into with TEIAS, the generation companies must provide the data included in the Option 2. The
generation companies must provide the data under the Option 2 for the excitation control systems of the unit commissioned after 1st
January of 1997 and for the excitation control systems of the unit recommissioned for any reason such as replacement after 1st January
of 1997 and for the excitation control systems of the unit for which the generation company found out that the data items specified under
the Option 2 is in relation to the unit concerned as a result of testing or other processes.
Option 1
Excitation circuit dc gain
APV
Maximum excitation voltage
V
APV
Minimum excitation voltage
V
APV
Nominal excitation voltage
V
APV
Rate of change for maximum excitation
voltage:
Increased
V/Second
APV
Decreased
V/Second
APV
Details of the excitation circuit
Diagram
As identified in the form of a block
diagram displaying the transfer functions
of various parts
APV
Dynamic properties of the overexcitation
limiter
Dynamic properties of the underexcitation
limiter
APV
APV
360
(please insert)
DATA RECORD SECTION
Page 4/9
DATA
SCHEDULE 1
UNIT
DATA
CATEGORY
EXCITATION SYSTEM PARAMETERS (continued)
Option 2
Excitation mechanism class, for example
rotating excitation mechanism or static
excitation mechanism, etc.
Nominal reaction of the excitation system
ve
Nominal excitation voltage
ufn
No-load excitation voltage
ufo
On-load excitation system
Positive ceiling voltage
upl+
No-load excitation system
Positive ceiling voltage
upo+
No-load excitation system
Negative ceiling voltage
upoElectrical system equalizing signal
With
a SPV
separate
writing
Second-1
APV
V
APV
V
APV
V
APV
V
APV
V
APV
Yes/No
SPV
Details of the excitation system
As identified in the form of a block
diagram displaying the transfer functions of
various parts, including PSS, if any
Diagram
APV
Details of the overexcitation limiter
In the form of a block diagram displaying
the transfer functions of various parts
Diagram
APV
Details of the underexcitation limiter
In the form of a block diagram displaying
the transfer functions of various parts
Diagram
APV
361
DATA OF THE GENERATION UNIT
OR POWER GENERATING MODULE
GR GR GR GR GR GR ÜT
1
2
3
4
5
6
DATA RECORD SECTION
SCHEDULE 1
Page 5/9
DATA
UNIT
DATA
CATEGORY
SPEED GOVERNOR AND RELATED EXCITER
PARAMETERS
Option 1
SPEED GOVERNOR PARAMETERS
(RESUPERHEATER UNITS)
HP (*) speed governor average gain
MW/Hz
APV
Booster engine adjustment range
Hz
APV
HP speed governor valve time constant
Second
APV
HP speed governor valve opening limits
APV
HP speed governor valve speed limits
APV
Resuperheating time constant; active power
kept in the resuperheater system
Second
APV
MP (**) speed regulator average gain
MW/Hz
APV
MP speed regulator adjustment range
Hz
APV
MP speed governor time constant
Second
APV
MP speed governor valve opening limits
APV
MP speed governor valve speed limits
APV
In HP and MP speed governor circuit
APV
Details of the parts sensitive to acceleration
Speed governor block diagram
APV
Displaying the transfer functions of various Diagram
parts
SPEED GOVERNOR PARAMETERS
FOR STEAM AND GAS TURBINES
WITHOUT RESUPERHEATER
Speed governor average gain
MW/Hz
APV
Booster engine adjustment range
APV
Steam or fuel speed governor time constant
Second
APV
Speed governor valve opening limits
APV
Speed governor valve speed limits
APV
Turbine time constant
Second
APV
Speed governor block diagram
APV
SPEED GOVERNOR PARAMETERS
FOR HYDROELECTRIC UNITS
Adjustment blade activator
Second
APV
Adjustment blade opening limit
(%)
APV
Adjustment blade opening speed limits
%
APV
/Second
Adjustment blade closing speed limits
%
APV
/Second
Water time constant
Second
APV
DATA OF THE GENERATION UNIT OR POWER
GENERATING MODULE
GR 1 GR 2 GR 3 GR 4 GR 5 GR 6 ÜT
COMPONENT
(please insert)
(please insert)
(please insert)
Notes:
1. (*) High Pressure
2. (**) Medium Pressure
3. The data items requested under the Option 1 above must be provided. If this data is in
relation to the small Power Generating Modules or autoproducers not having significant
effect on the transmission system of TEIAS, it is not necessary to provide such data.
4. Unless a contrary agreement is entered into with TEIAS, the generation companies must
provide the data items included in the Option 2.
5. The generation companies must provide the data under the Option 2 for the excitation
control systems of the unit commissioned after 1st January of 1997 and for the excitation
control systems of the unit recommissioned for any reason such as replacement after 1st
362
January of 1997 and for the excitation control systems of the unit for which the generation
company found out that the data items specified under the Option 2 is in relation to the unit
concerned as a result of testing or other processes.
6. TEIAS must also check the dates included in the connections terms.
363
DATA RECORD SECTION
Page 6/9
DATA
SCHEDULE 1
UNIT
DATA DATA OF THE GENERATION UNIT
CAT. OR POWER GENERATING MODULE
GR 1
SPEED GOVERNOR AND RELATED EXCITER COMPONENT PARAMETERS
GR 2
GR 3
GR 4
GR 5
GR 6
ÜT
(continued)
GRADIENT PROPERTIES OF THE SPEED
GOVERNOR OF THE GENERATION UNIT
Speed-droop in minimum generation
Intermediate load 1
Speed-droop under intermediate load 1
Intermediate load 2
Speed-droop under intermediate load 2
Speed-droop in recorded capacity
(%)
MW
(%)
MW
(%)
(%)
İB4
İB4
İB4
İB4
İB4
İB4
Note: In the steam units, the intermediate load 1 and the intermediate load 2 in nominal steam pressure should be in the
nominal power range of 80 % - 100 %. For the directly connected or autoproducer Power Generating Modules, unless it
is agreed that the data shall be given on the basis of the block for each unit within the block, such data is given either for
each unit within the block or on the basis of the block. If it is not specified that the data is given on the basis of the block,
such data is considered to be given separately for each unit within the block.
BOILER AND STEAM TURBINE DATA (*)
Boiler time constant (active power kept)
Second
HP turbine reaction ratio:
(%)
(the ratio of the primary prevention control arising from
HP turbine)
364
İB4
İB4
DATA RECORD SECTION
Page 7/9
DATA
SCHEDULE 1
UNIT
DATA
CATEGORY
DATA OF THE GENERATION UNIT
OR POWER GENERATING MODULE
GR GR GR GR GR GR ÜT
1
2
3
4
5
6
SPEED GOVERNOR AND RELATED EXCITER COMPONENT PARAMETERS (continued)
Option 2
All Generation Units
Speed governor block diagram displaying
the transfer functions of various parts
including the parts sensitive to
acceleration
APV
Speed governor time constant
Speed governor dead band ()
- maximum adjustment
- normal adjustment
- minimum adjustment
Second
APV
Hz
Hz
Hz
İB4
İB4
İB4
Booster engine adjustment range
(%)
APV
Speed governor average gain
MW/
Hz
APV
(%)
(%)
(%)
(%)
(%)
(%)
İB4
İB4
İB4
İB4
İB4
İB4
Speed-droop of the speed governor (##)
Increased speed-droop in MLP1
Increased speed-droop in MLP2
Increased speed-droop in MLP3
Increased speed-droop in MLP4
Increased speed-droop in MLP5
Increased speed-droop in MLP6
If the speed governor of the unit has no selectable dead band equipment, only the
actual value of the dead band should be given.
The data submitted under İB4 is not intended to obstacle the ancillary services
agreement.
365
DATA RECORD SECTION
Page 8/9
SCHEDULE 1
UNIT
DATA
CATEGORY
HP valve time constant
HP valve opening limits
HP valve opening speed limits
HP valve closing speed limits
HP turbine time constant
Second
(%)
% / Second
% / Second
Second
APV
APV
APV
APV
APV
MP valve time constant
MP valve opening limits
MP valve opening speed limits
MP valve closing speed limits
MP turbine time constant
Second
(%)
% / Second
% / Second
Second
APV
APV
APV
APV
APV
LP valve time constant
LP valve opening limits
LP valve opening speed limits
LP valve closing speed limits
LP turbine time constant
Second
(%)
% / Second
% / Second
Second
APV
APV
APV
APV
APV
Resuperheating system time constant
Boiler time constant
HP energy ratio
MP energy ratio
Gas Turbine Units
Inlet valve opening time constant
Inlet valve opening limits
Inlet valve opening speed limits
Inlet valve closing speed limits
Second
Second
(%)
(%)
APV
APV
APV
APV
Second
(%)
% / Second
% / Second
APV
APV
APV
APV
Fuel valve time constant
Fuel valve opening limits
Fuel valve opening speed limits
Fuel valve closing speed limits
Second
(%)
% / Second
% / Second
APV
APV
APV
APV
(%)
APV
(%)
APV
DATA
Steam turbines
Waste heat recovery boiler time constant
Hydroelectric Turbine Units
Permanent speed-droop of the speed
governor
Temporary speed-droop of the speed
governor
Speed governor time constant
Filter time constant
Servo time constant
Adjustment duct opening speed
Adjustment duct closing speed
Minimum adjustment duct opening
Maximum adjustment duct opening
Turbine gain
Turbine time constant
Water time constant
No-load flow
Second
APV
Second
APV
Second
% / Second
% / Second
(%)
Per unit
Second
Second
Per unit
APV
366
DATA OF THE GENERATION UNIT OR
POWER GENERATING MODULE
GR 1 GR 2 GR 3 GR 4 GR 5 GR 6 ÜT
DATA RECORD SECTION
Page 9/9
DATA
SCHEDULE 1
UNIT
DATA DATA OF THE GENERATION UNIT
CATE OR POWER GENERATING MODULE
GR 1 GR GR 3 GR 4 GR GR 6 Ü
2
5
T
UNIT CONTROL OPTIONS*
Maximum speed-droop
Normal speed-droop
Minimum speed-droop
(%)
(%)
(%)
İB4
İB4
İB4
Maximum frequency dead band
Normal frequency dead band
Frequency dead band
±Hz
±Hz
±Hz
İB4
İB4
İB4
Maximum output dead band
Normal output dead band
Minimum output dead band
±MW
±MW
±MW
İB4
İB4
İB4
Hz
Hz
Hz
İB4
İB4
İB4
Yes/No
İB4
Frequency adjustment for which the speed-droop of the
load controller of the unit is valid:
Maximum
Normal
Minimum
Continuous control normally selected
CONTROL CAPACITY
Note: The following data may be similar with the data included in the relevant Ancillary Services Agreement, but the data
submitted under İB4 is not intended to obstruct the Ancillary Services Agreement.
Designed minimum output level
MW
MW loading points requiring control data:
MLP1 (MYN1)
MLP2 (MYN2)
MLP3 (MYN3)
MLP4 (MYN4)
MLP5 (MYN5)
MLP6 (MYN6)
MW
MW
MW
MW
MW
MW
İB4
İB4
İB4
İB4
İB4
İB4
NOTE:
The users should refer to the Schedule 4 and the Schedule 11 displaying the data necessary
for the users directly connected to the transmission system of TEIAS including the Power
Generating Modules.
367
DATA RECORD SECTION
Page 1/3
GENERATION PLANNING PARAMETERS
SCHEDULE 2
This Schedule includes the generation planning parameters of the Power Generating Facilities
necessary for drawing up the time schedules of business planning for TEIAS.
Unless otherwise is stated, the data for a unit in a Power Generating Module directly connected to
the transmission system or in an autoproducer Power Generating Module shall be given according
to the units and the data for a combined cycle gas turbine block in a Power Generating Module
directly connected to the transmission system or in an autoproducer Power Generating Module
shall be given according to the blocks.
When KÇGT blocks in a Power Generating Module directly connected to the transmission system
or in an autoproducer Power Generating Module are referred to, where applicable, “GR1” column
and others should be modified as “A,B,C,D” when reading.
Power Generating Module: _________________________
Generation Planning Parameters
DATA
UNIT
OUTPUT CAPACITY
In case of a combined cycle gas turbine
block in a Power Generating Module, as MW
based on thegeneration
block
Minimum
(in case of a
combined cycle gas turbine block in a MW
Power Generating Module, as based on the
block)
Available
MW above the recorded
capacity in the generation units
MW
NON-AVAILABILITY OF THE SYSTEM
This data is for recording the nonavailability periods.
Earliest commissioning period:
Monday
hour/minute
Tuesday – Friday
hour/minute
Saturday – Sunday
hour/minute
Latest decommissioning period:
Monday – Thursday
hour/minute
Friday
hour/minute
Saturday – Sunday
hour/minute
SYNCHRONIZATION PARAMETERS
Period of deviation from zero after the minute
decommissioning of 48 hours
Synchronization periods of the Power minute
Generating
Module
after
the
decommissioninggroup,
of 48 hours
Synchronization
if any
from 1 to 4
DATA
CATEGORY
DATA OF THE GENERATION UNIT OR
POWER GENERATING MODULE
GR 1 GR 2 GR 3 GR 4 GR 5 GR 6 ÜT
SPV
SPV
SPV
İB2
İB2
İB2
-
İB2
İB2
İB2
-
İB2
-İ
-
B
2
İB2
368
-
-
-
DATA RECORD SECTION
Page 2/3
DATA
SCHEDULE 2
UNIT
Synchronous generation after the MW
decommissioning of 48 hours
Decommissioning period
DATA
CATEGORY
DATA OF THE GENERATION UNIT OR
POWER GENERATING MODULE
GR GR 2 GR 3 GR 4 GR 5 GR 6 ÜT
1
-
APV
İB2
Minute İB2
-
-
-
-
-
-
RESTRICTIONS
OF
THE
DECOMMISSIONING PERIOD:
Minimum non-zero period after the minute
decommissioning of 48 hours
İB2
Minimum zero period
minute
İB2
Limit of two shifts (maximum for day)
No.
İB2
ACCELERATION PARAMETERS
Rate of loading after decommissioning of
48 hours
(see the Note 2 on Page 3)
MW Level 1
MW
MW Level 2
MW
İB2
İB2
APV
Ve
Rate of loading from synchronous MW/min İB2
generation to MW Level 1
Rate of loading from MW Level 1 to MW/min İB2
MW Level 2
Rate of loading from MW Level 2 to MW/min İB2
Maximum Capacity
-
Rates of load drop:
MW Level 2
Rate of load drop from Maximum
Capacity to MW Level 2
MW Level 1
Rate of load drop from MW Level 2 to
MW Level 1
Rate of load drop from MW Level 1 to
desynchronization
MW
İB2
MW/min APV
İB2
MW
İB2
MW/min İB2
MW/min İB2
369
DATA RECORD SECTION
Page 3/3
DATA
SCHEDULE 2
UNIT
DATA
CATEGORY
DATA OF THE GENERATION UNIT OR
POWER GENERATING MODULE
GR 1 GR 2 GR 3 GR 4 GR 5 GR 6 ÜT
REGULATION PARAMETERS
Regulation range
MW
Load drop capacity in synchronous status MW
and loaded status
GAS
TURBINE
PARAMETERS:
APV
APV
LOADING
MW/min İB2
MW/min İB2
Rapid loading
Slow loading
COMBINED CYCLE GAS TURBINE
BLOCK PLANNING MATRIX
İB2
(please insert)
NOTES:
1.
The generation units of which the enterprisers are the same should be allocated to one of the
synchronous groups, each of which consists of no more than four, for allowing different
generation units within a Power Generating Module directly connected or an autoproducer
Power Generating Module. Only one synchronous period shall be valid within one
synchronous group, but it shall be assumed that there is zero synchronous period between
the synchronous groups.
2.
The three-step change of a generation group’s rate of loading from Maximum Capacity to
synchronous block load from two intermediate load shown as MW level 1 and MW level 2 is
shown as characteristic. MW level 1 and MW level 2 values may be different for the
generation groups.
370
DATA RECORD SECTION
SCHEDULE 3
Page 1/3
DECOMMISSIONING PROGRAMS, AVAILABLE POWER AND FIRM CAPACITY
DATA OF THE UNITS
Unless otherwise is stated, the data for a unit in a Power Generating Module directly connected to
the transmission system or in an autoproducer Power Generating Module shall be given according
to the units and the data for a combined cycle gas turbine block in a Power Generating Module
directly connected to the transmission system or in an autoproducer Power Generating Module
shall be given according to the blocks. The agreements in relation to the external interconnections
cover the data.
DATA
UNIT
PERIOD
UPDATE
PERIOD
DATA
CATEGORY
Power Generating Module:...........................
Number of the combined cycle gas turbine block in the unit or Power
Generating Module:...
Maximum Capacity:..........................
Decommissioning program of the Power Maximum Capacity of the
Generating Module
Power Generating Module
PLANNING FOR THE NEXT 3 – 10 YEARS
Monthly
available power
Temporary
commissioning
including the following:
Period
Preferred start
Earliest start
Commissioning date
YEAR 5 – Week 24
10
SPV
Week 2
İB2
Week
Date
Date
Date
Calendar
year 3 – 5
"
"
"
"
"
"
"
"
"
"
"
"
MW
"
"
"
average MW
program
Weekly available power
Response of TEIAS, of which the details are given in İB2
Calendar
year 3 – 5
possible Calendar
year 3 – 5
Week 12
Calendar
year 3 – 5
Week 25
İB2
"
"
"
"
"
"
"
"
"
"
"
"
"
"
"
Response of TEIAS for the period in the next box, of which the details
are given in İB2
Response of the users for the changes and possible decommissioning recommended
by TEIAS
Calendar
year 3 – 5
Calendar
year 3 – 5
Week 28
Response of TEIAS for the period in the next box, of which such
details as the changes recommended by it in addition are given in İB2
Calendar
year 3 – 5
Ensuring
agreement
on
the
decommissioning program of the final
power
Calendar
year 3 – 5
Week 45
İB2
Calendar
year 1 – 2
Week 10
İB2
"
"
"
Response of the users for the changes
decommissioning recommended by TEIAS
and
Updated, temporary decommissioning
program including the following:
Period
Preferred start
Earliest start
Commissioning date
Week
Date
Date
Date
Weekly updated available MW
power
Week 14
Week 31
Week 42
PLANNING FOR THE NEXT 1 – 2 YEARS
Updating the decommissioning program of
the previous final power agreed on
Weekly
power
available MW
371
DATA RECORD SECTION
Page 2/3
DATA
SCHEDULE 3
UNIT
PERIOD
UPDATE
PERIOD
Week 12
Response of TEIAS for the period in the next box, of which
Calendar
the details are given in İB2
year 1 – 2
Response of the users for the update of the changes or possible Calendar
Week 14
decommissioning recommended by TEIAS
year 1 – 2
Revised weekly
Calendar
Week 34
available power
year 1 – 2
Response of TEIAS for the period in the next box, of which
Calendar
Week 39
the details are given in İB2
year 1 – 2
Response of the users for the update of the changes or possible Calendar
Week 46
decommissioning recommended by TEIAS
year 1 – 2
Ensuring agreement on the decommissioning
Calendar
Week 48
program of the final power
year 1 – 2
PLANNING FOR THE CURRENT YEAR
Decommissioning program of the updated
Current year 1600
final power
From
the Wednesday
next week 2
to the year
end
Available
MW
"
"
power
at
weekly
peak
time
Response of TEIAS for the period in the next box, of which the details are given Current year 1700
in İB2
From
the Friday
next week 8
to week 52
Response of TEIAS for the period in the next box, of which the details are given Next 2 - 7 1600
in İB2
weeks
Thursday
Estimated recommissioning
DATE
From
the 0900
Planned decommissioning or error
next 2 days daily
to 14 days
Available
MW
"
"
power at all
hours
Response of TEIAS for the period in the next box, of which the details are given From
the 1600
in İB2
next 2 days daily
to 14 days
INFLEXIBILITY
Firm capacity Minimum MW Next 2 - 8 1600 Tuesday
of
the (Weekly)
weeks
generation
group
"
Firm capacity Minimum MW Next 2 -14 0900 daily
of
the (daily)
days
generation
group
"
372
DATA
CATEGORY
İB2
İB2
İB2
"
İB2
İB2
İB2
İB2
DATA RECORD SECTION
Page 3/3
SCHEDULE 3
DATA
UNIT
PERIOD
UPDATE
PERIOD
DATA
CATEGORY
GENERATION PROFILES
Information necessary for the understanding of the MW
possible profile of the large Power Generating Modules
such as stream, wind of which the generation is unreliable
or cannot be programmed or shows alteration according
to another method
YEAR 1 - Week 24
7
SPV
AGREEMENT DATA
The following information is required for the Power
Generating Modules which have entered into agreement
on the use of an external interconnection
Power agreed on
MW
YEAR 1 - Week 24
7
SPV
Which external interconnection will be used
With
a YEAR 1 - Week 24
separate 7
writing
SPV
Note: 1. The numbers of week given in the update time column indicate the Standard weeks of the
current year.
373
DATA RECORD SECTION
Page 1/7
DATA RELATED TO THE USER SYSTEMS
DATA
SCHEDULE 4
UNIT
DATA
CATEGORY
DESIGN OF THE USER SYSTEMS
A single line diagram showing the whole or a part of the user system
should be provided. This diagram should include the following
information:
(a)
Existing or planned parts of the user system operating are 380
kV, 154 kV and 66 kV,
(b)
Parts of the user system operating at the medium voltage level
and interconnecting the connection points or separating the
busbars at a single connection point,
(c)
Parts of the user system between the Power Generating Modules
above or below 50 MW connected to the transmission system of
the user and the relevant connection point,
(d)
Parts of the user system at a site of TEIAS
Furthermore, the single line diagram may include the transmission system
of the user and the transformers connected to the transmission system of
the user at low voltage in more detailed, also the details of the system at
the voltage lower than that of the transmission system of the user may be
included in the single line diagram upon the agreement of TEIAS.
In the single line diagram or on the detail drawing, electrical circuits,
overhead lines, ground cables, power transformers and similar equipment
and operating voltages, including the adjustment of the equipment bearing
existing and planned load current in relation to the existing and planned
connection points, should be indicated. Moreover, the circuit breakers and
the phase sequence for the equipment operating at the transmission
system voltage should be indicated.
374
APV
DATA RECORD SECTION
Page 2/7
DATA RELATED TO THE USER SYSTEMS
DATA
SCHEDULE 4
UNIT
DATA
CATEGORY
REACTIVE COMPENSATION
For the reactive compensation equipment independently switched which
is connected to the user system at medium voltage level, which is not
owned by TEIAS and which is excluded from the power factor
correction equipment in relation to the facility or installation of a
customer:
Type, constant or variant of the equipment
With
separate
writing
MVAr
MVAr
MVAr
Capacitive power
Inductive power
Operating range
a SPV
SPV
SPV
SPV
Details of the automatic control principles in order to ensure the With
determination of the operating characteristics
separate
writing
and/or
diagrams
a SPV
Connection point to the user system by the electrical location and system With
voltage
separate
writing
a SPV
TRANSFORMER CENTER INFRASTRUCTURE
For the infrastructure with respect to the equipment of a user at a
transformer center owned, operated or managed by TEIAS:
Nominal three-phase (rms) short circuit resistance current
Nominal single-phase (rms) short circuit resistance current
Nominal short circuit resistance period
Nominal (rms) continuous current
375
(kA)
(kA)
Second
A
SPV
SPV
SPV
SPV
Years
for
which
the data
is valid
Connec
tion
point 1
Connec Nominal Operating
tion
Voltage voltage
point 2
kV
kV
R
X
Y
Positive Component
Percentage (%) of 100 MVA
R
X
Y
R
X
Y
Zero Component (single)
Zero Component (mutual)
Percentage (%) of 100 Percentage (%) of 100 MVA
MVA
All of the following data is the Standard planning data. The details of the circuits indicated in the single line diagram should be given.
Circuit Parameters
DATA RELATED TO THE USER SYSTEMS
DATA RECORD SECTION
Page 3/7
SCHEDULE 4
Notes
1. The
data
should
be
given for the
current
year
and financial
year and for
every
seven
financial years
following.
This can be
possible
by
indicating the
years
for
which the data
is valid in the
first column of
the schedule.
376
377
Name
of the
connec
tion of
the
connec
tion
point
N
a
m
e
of
th
e
tr
an
sf
or
m
er
No
m.
MV
A
YG A1
AG
2
Voltage Ratio
Positive
Component
Reactance
having
Nominal Power
As %
Maxi Minim
Nomin
mum um
al Step
Step
Step
Maxim
um
Step
Open/Clos Correct/Di
ed
r/Rea
Open/Clos Correct/Di
ed
r/Rea
Open/Clos Correct/Di
ed
r/Rea
Type
(delete
the
unappr
Open/Clos
opriate Correct/Di
edone)
r/Rea
Earthin
g
details
(delete
the
unappr
opriate
one)
Açık/Kap
alı
Open/Clos Doğru/
ed
Dir/Rea
Açık/Kap
alı
Open/Clos Correct/Di
ed
1. The data should be given for the current year and financial year and for every seven financial years following. This can be possible by indicating
the r/Rea
years for which the data is valid in the first column of the Sschedule.
Open/Clos
Doğru/Dir
2. For a transformer with two secondary windings, the positive and zero component leakage impedances between HV and LV1, HV and LV2
and LV1
ed
/Rea
and LV2 windings are required.
Minim
um
Step
Zero
Con Tap-changer
Compone necti
nt
on
Reactanc Grou
e
p
%
of
Nomin
Range
Step
Nomin
al Step
From
size %
al
+%
to -%
Positive
Component
Resistance having Nominal
Power
As %
Notes: * In case of Resistance or Reactance, please write the impedance value next to it.
.
Years
for
whic
h the
data
is
valid
All of the following data is th standard planning data and the details of the transformers indicated in the single line diagram should be given. The details of
winding adjustments, ta-change and earthing are necessary only for the transformers connecting the user system to the primary voltage system and higher
voltage system.
DATA RELATED TO THE USER SYSTEMS
Transformer Data
DATA RECORD SECTION
Page 4/7
SCHEDULE 4
378
Connect
ion
point
Assembl
y No.
Nominal
Voltage
kV (rms)
Operating
Voltage
kV (rms)
3-phase
kA
(rms)
Initial
Current
Single-phase 3-phase
kA (rms)
kA puant
Short circuit breaking
current
Circuit Nominal
(rms)
continuous
current
(A)
Single-phase
kA puant
Short
DC
time
constant
in
asymmetrical
breaking capacity
testing (Second)
Notes:
1.
Nominal Voltage should be given as identified in IEC 694.
2. The data should be given for the current year and financial year and for every seven financial years following. This can be possible by indicating the
years for which the data is valid in the first column of the Sschedule.
Y
ea
rs
fo
r
w
hi
ch
th
e
da
ta
is
va
lid
All of the following data is the Standard planning data and should be given for the circuit breakers, load separators and splitters for the switch
assembly operating at high voltage. Moreover, this data should be given for the circuit breakers in a swithcyard owned, operated and managed
by TEIAS tarafından regardless of the voltages of the circuit breakers.
Switch Assembly Data
DATA RELATED TO THE USER SYSTEMS
DATA RECORD SECTION
Page 5/7
SCHEDULE 4
DATA RECORD SECTION
Page 6/7
DATA RELATED TO THE USER SYSTEMS
DATA
SCHEDULE 4
UNIT
PROTECTION SYSTEMS
The following information is related to the protection equipment which
switches on, remotely switches on or switches off the connection point
circuit breaker or the circuit breaker TEIAS. The information should be
given only once unless there a change occurs according to the timing
requirements specified in E.5.19 (b).
(a)
Complete definition of the existing relays and protection
systems on the user system including their adjustment;
DATA
CATEGORY
APV
(b)
Complete definition of the automatic reclosing assembly on the
user system including their types and delay periods;
APV
(c)
Complete definition of the unit transformer, start-up
transformer, internal requirement transformer and the relays and
protections systems installed on the connections related to the
same including their adjustment;
APV
(d)
Voltage reset periods for the faults in the generation units having
a circuit breaker at its output
APV
(e)
Removal period of the fault:
Troubleshooting period for the electrical faults in a part of the Millisecond APV
user systems directly connected to the transmission system of
TEIAS.
379
DATA RECORD SECTION
Page 7/7
DATA RELATED TO THE USER SYSTEMS
SCHEDULE 4
Information Necessary for Transient Over-Voltage Evaluation APV
The following information may be requested by TEIAS from the users with respect to a switchyard
between TEIAS and the relevant user. The influence of a third person in the user systems on the
system operation should be included in this information, as well.
(a)
Layout plans of the current and voltage transformers’ bushings, post insulators, splitters,
circuit breakers, surge arrestors and similar equipment shall be provided along with their
dimensions and physical drawings of the switchyard. The electrical parameters of this
equipment shall be provided, as well.
(b)
Electrical parameters and installation details of the lines and cables connected to the
busbar. Electrical parameters of the transformers (including neutral earthing impedance or
earthing transformers, if any), serial reactors and shunt compensation equipment directly
connected to the busbar or connected to the tertiary winding of a transformer or connected
to the relevant busbar through cables and lines,
(c)
Main isolation levels of the equipment connected to the busbar directly or through lines or
cables,
(d)
Properties of the protection devices for over-voltage at the busbar and the output points of
the lines and cables connected to the busbar,
(e)
Number of faults at the medium voltage outputs of each transformer, directly without an
inter-stage transformer or indirectly, connected to the transmission system of TEIAS,
(f)
For the transformers operating at 400 kV, 154 kV and 66 kV; peak value for operating in
magnetic flux density at three or five-core or single-phase and nominal voltage,
(g)
Planned decommissioning conditions and equipment that might be decommissioned
synchronously.
Harmonic Works (APV)
For the examination of the harmonic distortion on the transmission and user systems, the
following information not given within the scope of the Schedule 4 may be requested by TEIAS.
(a)
The circuit of the overhead lines and ground cables of the transmission system of the user
should be separated and the following data should be given separately for each type:
Positive component resistance
Positive component reactance
Positive component susceptance
(b)
For the transformers connected to the transmission system of the user on the low
voltage side, the following data should be given:
Nominal apparent power (MVA),
Rate of voltage change,
Positive component resistance
Positive component reactance
380
(c) For the low voltage points of the connection transformers, the following data should
be given:
Equivalent positive component susceptance,
Nominal voltage, MVAr capacity of the capacitor benches and, if not connected as filter,
design parameters of the parts constituting the bench,
Positive component of the user system impedance,
Minimum and maximum demand MW and Mvar,
Details of the harmonic current resources, impact arc furnaces and inductive loads at the
connection points
(ç) Planned decommissioning conditions and equipment that might be decommissioned
synchronously,
381
Voltage Evaluation Studies APV
TEIAS may request information other than those included in the Schedule 4 for the detailed study
on voltage. TEIAS may also request the information concerning the synchronous/asynchronous
motor and generation units affecting the system operation of the third parties.
The information that might be requested by TEIAS for the detailed study on voltage is as follows;
(a)
For the circuits connected by the user to the transmission system, the following data should be
given:
Positive component resistance,
Positive component reactance,
Positive component susceptance,
MVAr capacity of reactive compensation equipment
(b) For the transformers connected to the transmission system of the user on the low voltage side,
the following data should be given:
Nominal apparent power (MVA),
Rate of voltage transformation,
Positive component resistance,
Positive component reactance,
Tap change range in Volt,
Tap change step number,
Tap-changer type: on-load or off-circuit,
AVC automatic voltage control/tap-changer delay period,
AVC automatic voltage control/tap-changer inter-stage delay period,
(c)
At the points on the low voltage side of the transformers specified in (b), the following data
should be given:
Stable positive component susceptance,
MVAr capacity of reactive compensation equipment,
Equivalent positive component of the user system impedance,
Minimum and maximum demand (MW and MVAr),
Estimated value of the reactive load in 75 % of the load conditions at peak time and out of
peak time
Short Circuit Analysis: APV
With respect to the switchyard, if the short circuit current of any equipment owned, operated or
managed by TEIAS is close to its nominal value, TEIAS may request information other than those
included in the Schedule 4 for the detailed study on voltage. TEIAS may also request the
information concerning the synchronous/asynchronous motor and generation units affecting the
system operation of the third parties.
(a)
For the circuits of the transmission system of the user, the following data should be given:
Positive component resistance,
Positive component reactance,
Positive component susceptance,
Zero component resistance,
Zero component reactance,
Zero component susceptance
382
(b) For the transformers connected to the transmission system of the user on the low voltage side,
the following data should be given:
Nominal MVA,
Rate of voltage transformation,
Positive component resistance at maximum, minimum and nominal step,
Positive component reactance at maximum, minimum and nominal step,
Zero component reactance at nominal step,
Tap-changer range,
Earthing method: directly through resistance or earthing transformer and, if not directly
earthed, earthing impedance
383
DATA RECORD SECTION
Page 1/1
DATA RELATED TO THE DECOMMISSIONING OF THE USERS
DATA
UNIT
Detailed information in relation to the
decommissioning that might affect the system
performance; the decommissioning of the Power
Generating Modules above 50 MW connected to
the
distribution
system,
the
planned
decommissioning of the equipment in the user
systems, the decommissioning of the units
belonging to the generation companies.
TEIAS
informs
the
users
about
the
decommissioning that might affect them
The user informs TEIAS, if it is adversely affected
by the notified decommissioning.
TEIAS draws up its plan concerning the
decommissioning in the transmission system and
informs the users about these decommissioning and
their possible effects.
The generation companies and customers directly
connected to the transmission system, except for the
generation groups, submit the details concerning
the equipment owned by them ata the grid
connection points.
TEIAS
informs
the
users
about
the
decommissioning that might affect them.
TEIAS submits the details of the relevant
decommissioning affecting the user system.
TEIAS informs the users about the generation
restrictions or the other effects on their systems.
The user informs TEIAS, if it is adversely affected
by the notified restrictions or the other effects.
TEIAS informs the users about the final status of
the decommissioning plan of the transmission
system and its opinions on the effects of this plan
on the user system.
The generation companies, users and customers
directly connected to the transmission system
inform TEIAS about the changes which occurred in
time in the decommissioning plan they previously
declared.
TEIAS clarifies the details of the load transfer
capacity of 5 MW between the grid connection
points.
SCHEDULE 5
TIME
UPDATE TIME DATA CATEGORY
Year 3-5
Week 8
Users etc.
Week 13
Generation
companies
İB2
İB2
Year 3-5
Week 28
"
Week 30
"
Week 34
Year 1-2
Week 13
Year 1-2
Week 28
Year 1-2
Week 32
Year 1-2
Week 34
Year 1-2
Week 36
İB2
Year 1-2
Week 49
İB2)
From the When occurred
next week
8 to the
year end
Current
year
İB2
İB2
İB2
İB2
When requested İB2
by TEIAS
Note: The users should refer to İB2 for the information to be provided by TEIAS at the
programming stage through the procedure above.
384
DATA RECORD SECTION
SCHEDULE 6
Page 1/1
LOAD CHARACTERISTICS AT THE CONNECTION POINTS
The data included in the Schedule 6 is the standard planning data and should be given for the
existing and possible connections agreed on. This data should be updated only if demanded by
TEIAS.
DATA
UNIT
DATA FOR THE NEXT YEARS
Year Year Year Year Year Year Year Year Year Year
1
2
3
4
5
6
7
8
9
10
FOR THE DEMANDS AT THE
CONNECTION POINT
The following information should be
given only when requested by
TEIAS;
Details of the loads of which the
(Please insert)
characteristics are different from the
standard range of the domestic or
commercial and industrial load:
Sensitivity of the demand to the
voltage and frequency fluctuations
on the transmission system of
TEIAS during the peak time
connection point demand
Active power
Sensitivity of the load or demand as MW/kV
per the voltage
MVAr/k
V
Sensitivity of the load or demand as MW/Hz
per the frequency
MVAr/Hz
Sensitivity of the reactive power as
per the frequency is related to the
power factor given in the Schedule
10 or Schedule 1 and the Note 6
concerning the reactive power in the
Schedule 10.
Phase instability on the transmission
system of TEIAS
- maximum
(%)
- average
(%)
Maximum harmonic content on the (%)
transmission system of TEIAS
Details of the loads that might lead
higher demand fluctuation than the
allowed demand fluctuation under
the connection terms at the common
connection point including the shortterm flicker severity and long-term
flicker severity
385
DATA RECORD SECTION
Page 1/1
DATA TO BE PROVIDED BY TEIAS TO THE USERS
SCHEDULE 7
1.
TEIAS, in accordance with its obligation included in the transmission license, shall issue the
report on connection opportunities (the notification on connection possibilities) annually,
which was drawn up in order to inform the users about the usage opportunities of the
transmission system.
2.
If the user requires some highly detailed additional information about the connection
opportunities for the region on which the user intends to make investment, the user can
contact with TEIAS. TEIAS may arrange a negotiation for the additional information to be
requested by the user in relation to the site and provide this information.
3.
In the transmission license, TEIAS is authorized to lay down agreement terms for the
transmission system connection and the system use. In accordance with the transmission
license, TEIAS is liable for providing additional information to the user during the
negotiations in regard to the terms of this agreement.
DATA TO BE PROVIDED BY TEIAS TO THE USERS
REGULATION
DEFINITION
BŞ
Maneuver diagram
BŞ
Site responsibility schedules
PB
Date and time on and at which the system peak time occurs
Date and time on and at which the system minimum consumption occurs
İB2
Power Generating Module demand reserves and available power requirements for
the generation companies in various time schedules
Equivalent grids necessary for the decommissioning planning
İB4
Weekly operating program
DB1
Demand estimations, notified reserve and instability, sample synchronization and
desynchronization periods of the Power Generating Modules connected to the
distribution systems.
DB2
Purchase-sale acceptances, ancillary service instructions for the relevant users,
emergency instructions
DB3
Location, number and adjustment of the low frequency relay performing the demand
control for the demands connected to the distribution system.
386
DATA RECORD SECTION
SCHEDULE 8
Page 1/2
DEMAND PROFILE AND ACTIVE POWER DATA
The following information should be given by the users and the customers directly connected to the
transmission system within the 24th week of every calendar year.
DATA
YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR UPDATE TIME
0
1
2
3
4
5
6
7
8
9
10
Demand
Profile
System
Day on which the maximum annual demand of the user occurs (MW)
profile of the Day on which the annual peak time demand of TEIAS occurs (MW)
user
Day on which the minimum annual demand of TEIAS occurs (MW)
0000: 0100
0100:0200
0200: 0300
0300: 0400
0400: 0500
0500: 0600
0600: 0700
0700: 0800
0800: 0900
0900: 1000
1000: 1100
1100: 1200
1200: 1300
1300: 1400
1400: 1500
1500: 1600
1600: 1700
1700: 1800
1800: 1900
1900: 2000
2000: 2100
2100:2200
2200:2300
2300:0000
387
Week 24
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
DATA CATEGORY
SPV
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
:
DATA RECORD SECTION
Page 2/2
DATA
SCHEDULE 8
YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR
0
1
2
3
4
5
6
7
Results
Actual Corrected
according
the air
YEAR YEAR YEAR
8
9
10
to
Active Power Data
Total annual average
active powers of the
users and the customers
directly connected to
the
transmission
system:
Domestic
Agricultural
Commercial
Industrial
Rail
System
Transportation
Impact Arc Furnaces
Lightning
User system
Losses
Below Peak Time:
Domestic
Commercial
NOTES:
1.
“YEAR” means “Financial Year of TEIAS”.
2.
The demand and active power data should be measured at the point connected to the
transmission system of TEIAS and the net value of the generation of the small Power
Generating Modules and the customer Power Generating Module should be deducted from
this demand. The demand met by the suppliers supplying the customers in the user system
should be included in this data. The internal consumption of the small Power Generating
Modules should be included in the demand data at the connection point given by the user.
3.
The demand profile and active power data should be for the grid operator’s system and every
customer directly connected to the transmission system, including all connection points. For
the users, the demand profile should indicate the maximum numerical demand that might
occur on the transmission system of TEIAS.
4.
Moreover, the demand profile should be given for the certain days to be defined by TEIAS,
but TEIAS should not make this kind of demand more than once in a calendar year.
388
DATA RECORD SECTION
SCHEDULE 9
Page 1/3
CONNECTION POINT DATA
The following information should be given by the users and the customers directly connected to the
transmission system to TEIAS until the 24th calendar week of every year.
YEAR YEAR
0
1
DATA
YEAR
2
YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR
3
4
5
6
7
8
9
10
UPDATE
TIME
DATA
CATEGORY
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
Week 24
SPV
HOURLY DEMANDS AND POWER
FACTORS
(see the Notes 2, 3 and 5)
Demands and power factor at the point
indicated in the next box:
Name of the grid connection point
Annual hourly peak time at the MW
connection point
Cos

-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Load drop for the small Power
Generating Modules and customer
Power Generating Modules (MW)
Time of the annual half an hour MW
peak time of the demand of
TEIAS
Cos

Disconnection made for the small Power Generating Modules and
customer Power Generating Modules
(MW)
Time of the minimum annual MW
hourly value of the demand of
TEIAS
Cos
.
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
Load drop for the small Power
Generating Modules and customer
Power Generating Modules (MW)
For the other times that might be MW
specified by TEIAS
Cos
.
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
389
Once
year
Once
year
a SPV
a
SPV
Load drop for the small Power Generating Modules and customer
Power Generating Modules (MW)
-
-
-
-
390
-
-
-
-
-
-
Once
year
a
DATA RECORD SECTION
Page 2/3
YEAR
0
DATA
SCHEDULE 9
YEAR YEAR
1
2
YEAR YEAR YEAR YEAR
3
4
5
6
YEAR YEAR YEAR YEAR
7
8
9
10
UPDATE
TIME
DATA CAT.
Week 24
SPV
Week 24
Week 24
SPV
SPV
Week 24
SPV
Week 24
SPV
Week 24
Week 24
Week 24
SPV
SPV
SPV
Week 24
SPV
DEMAND
TRANSFER
CAPACITY MAIN SYSTEM
The following information should be
given in case of a user demand or in
such cases that the demand group
will be supplied from an alternative
connection point.
In case of decommissioning of the
first circuit due to an error;
Name of the alternative connection
point
Demand to be transferred
(MW)
(MVAr)
Transfer method;
Manual (E)
Automatic (O)
Time when the transfer occurs
(hour)
In case of planned decommissioning
of the second circuit
Name of the alternative connection
point
Demand transferred
(MW)
(MVAr)
Transfer method
Manual (E)
Automatic (O)
Time when the transfer occurs
(hour)
Note: The information concerning the demand transfer capacity for the netwrok connection points
above should be updated within the current year – see the Schedule 5.
391
DATA RECORD SECTION
SCHEDULE 9
Page 3/3
YEAR YEAR YEAR YEAR YEAR YEAR YEAR
0
1
2
3
4
5
6
DATA
YEAR YEAR
7
8
SMALL
POWER
GENERATING
MODULES
AND
CUSTOMER
GENERATION
SUMMARY
The following information
is
required
for
the
connection point covering
small Power Generating
Modules
or
customer
generation units:
Number of the small Power
Generating Modules and
customer generation units
Number of the units
Total capacity of the units
In the cases that the user
system restricts the capacity
of a Power Generating
Module connected to the
distribution system above
50 MW;
Name of the Power
Generating Module
Number of the unit
Restricted capacity of the
system
The
connection point
demands, power factors for
each single line diagram to
be submitted under the
Schedule 4 should be given
for the specified value of
the annual half an hour
peak time of the demand of
TEIAS:
YEAR
9
YEAR
10
UPDATE
TIME
DATA
CATEGORY
Week 24 SPV
Week 24 SPV
Week 24 SPV
Week 24 SPV
Week 24 SPV
Week 24 SPV
Connectio
n point
Yıl
Connectio Demand
n point
Power Factor
Week 24 SPV
NOTES:
1.
2.
3.
4.
“YEAR” means “Financial Year of TEIAS”. YEAR0 corresponds to the current financial year.
The demand data should be the net generation of the small Power Generating Modules and the
customer Power Generating Modules. The demand met by the suppliers supplying the customers
within the user system should be included in the data. The internal consumption of the Power
Generating Modules connected to the distribution system should not be included in the demand data
given by the user.
The peak time demands should be diversely related to a connection point and indicate the maximum
demand of the user on the transmission system of TEIAS. If it is planned for the busbars at a
connection point to operate in separate sections, separate demand data should be given for each
section of the busbar.
While projecting the demands, the generation of the small Power Generating Modules and customer
generation units should be taken into consideration and deducted from the demand as specified in
the Note 2 and the Schedule above by the user.
392
5.
6.
7.
TEIAS may demand the necessary information for the determination of the possible generation
profile of the small Power Generating Modules such as wind, stream of which the generation is
unreliable or cannot be programmed or show alteration according to another method.
If more than 95 % of the total demand at a connection point belongs to the synchronous motors, the
power factor values in maximum and minimum continuous excitation can be given.
The power factor data should include the serial reactive losses in the user system, but not the
reactive compensation values (these values area also included in the Schedule 4).
DATA RECORD SECTION
Page 1/1
SHORT CIRCUIT DATA
SCHEDULE 10
The data included in the Schedule 11 is the standard planning data and should be given by the users
connected or to be connected to the transmission system of TEIAS through a connection point. The
data should be given within the 24th week of every year. The following information should be
given for each connection point in the single line diagram in the Schedule 4.
DATA
UNIT
Name of the connection point
Short circuit current flowing
to the transmission system
from the user system at the
connection points
Symmetrical three-phase short
circuit current;
At the moment of short circuit
After the end of the
subtransient short circuit
current
X/R ratio of the positive
component at the moment of
short circuit
Voltage at the short circuit
point before the short circuit
(if different from 1.0 p.u.) (see
Note 1)
Negative
component
impedances at the connection
point (**):
Resistance
-
Reactance
Zero component impedances
at the connection point:
Resistance
-
Reactance
YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR
0
1
2
3
4
5
6
7
8
9
10
(kA)
(kA)
(kA)
(p.u.)
(%)
100 MVA
(%)
100 MVA
(%)
100 MVA
(%)
100 MVA
(*) p.u. is the ratio of the voltage to the nominal value of the operating value.
(**) If the negative component impedances at the connection point are not given, they shall be
considered as the same with the positive component impedances.
393
DATA RECORD SECTION
Page 1/2
SHORT CIRCUIT DATA
SCHEDULE 11
The data included in the Schedule 12 are the standard planning data and should be given by the
generation companies directly connected to the transmission system or connected to the distribution
system. The data should be given within the 24th week of every year.
Short circuit currents flowing from the unit transformers
The following information should be given for the unit power transformers. If there is more than
one transformer connected to a unit, the total short circuit current can be given. It should be
accepted that the maximum number of unit is in operation under normal operating conditions and
also the contribution of the synchronous and/or asynchronous motors and auxiliary generation units
connected to the unit panel, for instance auxiliary gas turbines, to the short circuit current should be
taken into consideration.
DATA
UNIT
Power Generating Module
Number of the unit transformer
Symmetrical three-phase short
circuit current for a short circuit
in the unit transformer output;
At the moment of short circuit
After
the
end
of
the
subtransient
short
circuit
current
X/R ratio of the positive
component at the moment of
short circuit
Subtransient time constant (if
different from 40 milliseconds)
Voltage at the short circuit
point before the short circuit (if
different from 1.0 p.u.) (see
Note 1)
Zero component impedances at
the connection point:
Resistance
-
Reactance
Note 1.
Note 2.
Note 3.
Note 4.
YEAR YEAR YEAR YEARYEAR YEARYEAR YEARYEAR YEARYEAR
0
1
2
3
4
5
6
7
8
9
10
(kA)
(kA)
Millisecond
(p.u.)
(%)
100 MVA
(%)
100 MVA
The voltage before the short circuit given above should indicate the voltage between 0.95
and 1.05 giving the highest short circuit current.
% 100 MVA is the abbreviation of the percentage (%) of 100 MVA.
The zero component resistance and reactance should be given in case of the zero
component short circuit current flow to the transmission system from the Power
Generating Module transformer.
p.u. is the ratio of the voltage to the nominal value of the operating value.
394
DATA RECORD SECTION
Page 2/2
SCHEDULE 11
SHORT CIRCUIT CURRENTS FLOWING FROM THE POWER GENERATING
MODULE TRANSFORMERS
The following information should be given for the Power Generating Module transformers directly
connected to the transmission system of TEIAS. It should be accepted that the maximum number of
generation unit is in operation under normal operating conditions and also the contribution of the
synchronous and/or asynchronous motors and auxiliary generation units connected to the Power
Generating Module panel, for instance auxiliary gas turbines, to the short circuit current should be
taken into consideration. The short circuit current should be expressed as the current flowing from
the transformer for a short circuit in HV output busbar of the transformer. As the short circuit type,
three-phase earth fault should be accepted. In order to determine the effect of X/R ratio of the
system on the short circuit current, also the following information should be given.
DATA
UNIT
Power Generating Module
Number of the Power
Generating
Module
transformer
Symmetrical
three-phase
short circuit current for a
short
circuit
in
the
transformer output;
At the moment of short
circuit
After the end of the
subtransient short circuit
current
X/R ratio of the positive
component at the moment of
short circuit
Subtransient time constant (if
different
from
40
milliseconds)
Voltage at the short circuit
point before the short circuit
(if different from 1.0 p.u.)
(see Note 1)
Zero component impedances
at the connection point:
Resistance
-
Reactance
Note 1.
Note 2.
Note 3.
YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR YEAR
0
1
2
3
4
5
6
7
8
9
10
(kA)
(kA)
Millisecond
(p.u.)
(%)
100 MVA
(%)
100 MVA
The voltage before the short circuit given above should indicate the voltage between 0.95
and 1.05 giving the highest short circuit current.
% 100 MVA is the abbreviation of the percentage (%) of 100 MVA.
The zero component resistance and reactance should be given in case of the zero
component short circuit current flow to the transmission system from the Power
Generating Module transformer.
395