Registra
č
ní
č
íslo:
Úrove
ň
zpracování
:Revision 11
January 2011
Datum:
1.1. 2011
Soubor: part_I_II_III_an_rev11.docRevision 11/January 2011
RULES FOR TRANSMISSION SYSTEM OPERATION
EXTRACT FROM
THE GRID CODE
(in compliance with the Czech Energy Act (Act No. 458/2000), Article 24, Paragraph 10)
Part I.
Basic conditions for the use of the Czech
Transmission System
Part II.
Ancillary services
Part III.
Providing system and transmission services
The following provisions of the ČEPS Grid Code have been translated into English. This text is for instructive purposes only.
The translation has not been approved by the Energy Regulation Office. The Czech version predominates.
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CONTENT
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CONTENT
CONTENT ... 2
Glossary... 5
1 About the Grid Code ... 9
2 Introductory provisions ... 13
2.1 Main principles employed in the creation of the Grid Code ... 13
2.2 ČEPS’s basic responsibilities ... 13
2.3 ČEPS’s main activities ... 13
2.4 Activities of the ČEPS Dispatch Centre ... 13
2.5 Basic rules for connection and use ... 14
2.6 Observation of requirements and verification ... 14
3 Information on the Damas and eTrace ePortals ... 14
4 System services ... 15
4.1 Technical-organisational tools for ensuring SyS... 15
4.1.1 The maintenence of the summary power reserve for frequency primary control ... 15
4.1.2 Secondary f/P control ... 16
4.1.3 Tertiary active power control ... 16
4.1.4 Use of the dispatcher reserve ... 16
4.1.5 Secondary voltage and reactive power control (SVC) ... 16
4.1.6 Tertiary voltage control ... 17
4.1.7 Ensuring transmission stability ... 17
4.1.8 Restoration of operation after full or partial blackout (loss of supply) ... 18
4.1.9 Ensuring the quality of the voltage sine wave ... 18
4.2 The relationship between System and Ancillary services ... 18
5 Conditions applicable to plant unit operation ... 19
5.1 Requirements applicable to plant unit operation ... 19
5.1.1 Allowed values of voltage and frequency ... 19
5.1.2 Transition and operation under internal consumption ... 19
5.1.3 Unit island operation capability ... 19
5.1.4 Unit operation under grid failure conditions ... 20
5.1.5 Generator stability loss protection ... 20
5.1.6 Frequency relay ... 20
5.1.7 Automated devices ... 20
5.2 Control requirements applicable to U and Q ... 21
5.2.1 Requirements applicable to unit control range ... 21
5.2.2 Requirements applicable to unit primary regulation U ... 21
5.3 Measurements and transferred signals ... 21
5.4 Ensuring transmission stability ... 21
6 TS requirements of electricity users ... 22
6.1 TS electricity user ... 22
6.1.1 Direct users of the TS – IIB catogory ... 22
6.1.2 Distribution licence-holders –IIA category ... 22
6.2 Connection site... 22
6.3 Active power consumption ... 23
6.4 Reactive power consumption ... 23
6.5 Coordination of TSO and user transformer control ... 23
6.6 Requirements concerning higher harmonic content, size of flicker and asymmetry ... 23
6.7 Measurements and transmitted signals ... 23
7 Connection site requirements ... 24
7.1 Requirements for measurement facilities at the connection site ... 24
7.1.1 General requirements for commercial measurement ... 24
7.1.2 General requirements for dispatch measurement ... 24
8 Information to be exchanged between ČEPS and transmission system users ... 25
8.1 Content of information between ČEPS and the producer – AnS provider ... 25
8.1.1 System information ... 25
8.1.2 Measurement ... 26
8.1.3 Additional information for unit control ... 26
8.1.4 Signalling ... 26 8.1.5 Quantities transmitted from the ČEPS central dispatch centre to the power station or group of power stations
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8.1.6 Information and data exchanged between ČEPS technical dispatching and RES sources connected to thetransmission system ... 27
8.1.7 Information and data exchanged between ČEPS technical dispatching and DR dispatching centers ... 28
8.2 Exchange of information between ČEPS and the load changing AnS (ZZ30) provider ... 28
8.2.1 Information on the system ... 28
8.2.2 Measurement ... 28
8.2.3 Signalling ... 28
8.3 Information flow between the generating unit and AVC ... 29
8.4 Information flow between the transmission system substation control system and the user ... 29
9 Technical calculations ... 30
9.1 Classification of calculations ... 30
9.2 Content of calculations... 31
9.2.1 Load flow calculations ... 31
9.2.2 Calculation of symmetrical and non-symmetrical short-circuit currents ... 31
9.2.3 Transient stability calculations ... 31
9.2.4 Mid-term dynamics calculations ... 31
9.2.5 Long-term dynamics calculations ... 31
9.2.6 Power system operational planning calculations regarding AnS ... 31
9.2.7 Static stability calculations ... 32
9.2.8 Reliability calculations ... 32
9.3 Input data required for calculations ... 32
10 Terminology ... 34
10.1 References ... 42
11 Appendices ... 43
Appendix 1 Report about PSS parameters setting ... 43
Appendix 2 Verification of PSS function by measurement ... 44
Extract from Part II ... 47
List of Variables and Coefficients: ... 48
1 Ancillary services AnS ... 51
1.1 General requirements applicable to AnS ... 51
1.2 AnS providers ... 51
1.2.1 Power plant unit ... 51
1.2.2 Conditions for the creation of virtual units ... 52
1.2.3 Market participant – subject to deviation settlement ... 53
1.3 Definition of ancillary services ... 53
1.3.1 Unit primary f control (PR) ... 54
1.3.2 Unit secondary P control (SR) ... 54
1.3.3 Unit tertiary P control (TR) ... 55
1.3.4 Quick-start 10 minute reserve (QS10) ... 56
1.3.5 Quick-start 15 minute reserve (QS15) ... 56
1.3.6 Dispatch reserve available within t-minutes (DZt) ... 56
1.3.7 Load change (ZZ30) ... 56
1.3.8 Generation shedding (SV30) ... 57
1.3.9 The Vltava (VSR) ... 57
1.3.10 Secondary U/Q control (SRUQ) ... 57
1.3.11 Island operation capability (IO) ... 57
1.3.12 Black start capability (BS) ... 58
1.4 EregZG and EregZ ... 59
1.5 Classification of Regulation Reserves and Energy ... 61
3 Purchase of AnS ... 62
3.1 Trade in AnS – general rules for AnS purchase ... 62
3.1.1 Legal directives for the purchase of AnS ... 62
3.1.2 Principles governing the choice of AnS providers ... 62
3.1.3 Aims of AnS purchase ... 63
3.1.4 Methods for ensuring AnS and operative electricity supplies from/to abroad on TS level ... 63
3.1.5 Published information on AnS trading ... 63
3.1.6 Announcement of the maximum acceptable price for particular AnS ... 64
3.1.7 Publication of weight coefficients for AnS selection ... 64
3.2 AnS Providers ... 64
3.2.1 Commitments from AnS providers ... 64
3.2.2 Conditions for new applicants for AnS provision ... 64
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3.3 Tender proceedings for long-term supplies of AnS ... 65
3.3.1 Announcement of tender proceedings ... 65
3.3.2 Submitting bids ... 65
3.3.3 Bid structuring requirements ... 65
3.3.4 Tender Results ... 66
3.4 Direct contract with the AnS provider ... 66
3.4.1 Non-daily market, non-tender purchase of (PR, SR, TR, SV30, QS10, QS15, DZt) ... 66
3.4.2 Secondary U/Q control (SRUQ) ... 66
3.4.3 The Vltava (VSR) ... 67
3.4.4 Black start capability (BS) ... 67
3.4.5 Island operation capability (IO) ... 67
3.4.6 Load change (ZZ30) ... 67
3.5 Contracts of operative electricity supplies from/to abroad... 67
3.5.1 Emergency aid ... 67
3.5.2 Operative electricity supplies from/to abroad (EregZG, EregZ ... 67
3.5.3 Electricity operative supplies from/to abroad, in context of co-operation on TSO level [EregZGCC] ... 67
3.6 AnS daily market ... 67
3.6.1 Demand for AnS purchase in context of AnS DM ... 68
3.6.2 Bids for provision of AnS on the AnS DM ... 68
3.6.3 Acceptance of AnS offers ... 68
3.6.4 Trade cancellation ... 68
3.7 Tender and DM bid evaluation characteristics ... 68
3.7.1 Unit primary f control (PR) ... 68
3.7.2 Unit secondary P control (SR) ... 68
3.7.3 Unit tertiary P control - (TR+) ... 68
3.7.4 Unit tertiary P control - (TR-)... 68
3.7.5 Quick start 10-minute reserve (QS10) ... 69
3.7.6 Quick-start 15 minute reserve (QS15) ... 69
3.7.7 Dispatcher reserve (RZDZt) ... 69
3.8 Terms of payment ... 69
3.8.1 Payment for AnS regulation reserve ... 69
3.8.2 Payment for regulation energy ... 69
1 Providing system and transmission services ... 72
1.1 Legal regulations relating to the provision of System and Transmission Services ... 72
2 Trading of System Services ... 72
2.1 Submission of data relating to payment for System Services, RES, CHP, secondary sources (DZ), and EMO activities ... 72
2.2 TS service provision pricing ... 73
2.3 Terms of payment ... 73
3 Trading of Transmission Services at the Czech TS level ... 73
3.1 General conditions ... 73
3.2 Connection site... 73
3.3 Technical conditions for electricity transfer ... 73
3.4 Terms of payment ... 74
4 Cross-border trading of Transmission Services ... 74
4.1 General conditions ... 74
4.2 Methodology for the calculation of available transmission capacity on interfaces ... 75
4.3 Allocation of transmission capacity for cross-border transfer ... 77
4.4 Long-term cross-border transfers ... 77
4.5 Cross-border transfers at ČEPS/SEPS profile - nomination through an implicit auction ... 78
4.6 Intra-day cross-border transfers - Intra-day at the ČEPS/TPS, ČEPS/50HzT, ČEPS/PSEO, ČEPS/SEPS, and ČEPS/APG profile ... 78
4.7 Control power for TSO needs ... 79
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Glossary
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Glossary
Nomenclature of the Ancillary Services and their reserves on the provider appliances
symbol meaning
PR
Primary regulation
SR
Secondary regulation
TR
Tertiary regulation
QS
10Quick start reserve
DZ
tDispatch reserve
ZZ
30Load change
SV
30Generation shedding
VSR
Vltava river
SRUQ
Secondary U/Q regulation
IO
Island Operation
BS
Black start
RZPR, RZSR, RZ
15, RZN
15,
RZQS
10, RZQS
10V, RZVSR,
RZ
30+, RZN
30+,RZN+ ,
RZDZ
30, RZZZ
30+, RZTR+,
RZ
30-, RZN
30-,RZN- RZZZ
30-,
RZSV
30, RZTR-, RZN
>30,
RZDZt,
EregZ
30+, EregZG
30+,
EregZG
30-, Ereg
30-, Ereg,
EregZ
see GC part II., 1.5.
RRPR
Regulation range of (PR)
RRSR
Regulation range of (SR)
RRTR+
Regulation range of TR+
RRTR-
Regulation range of TR-
RRQS
Regulation range of (QS)
RRDZt
Regulation range of (DZt)
RRPR RZPR 2 1 = RRSR RZSR 2 1 = RZTR+=RRTR+ RZTR-=RRTR- RZQS=RRQS RZTDZt=RRDZtPage 6/ 80
Glossary
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Names of Authorities and
Organizations
symbol
CENTREL
nameČ
EPS
name of regional group of TSOs consisting of ČEPS, a.s. (ČR), SEPS, a.s. (SR), Polskie Sieci Elektroenergetyczne SA (PL) and MAVIR Rt (H).
DSO
name of Czech Transmission System Operator
EMO
distribution system operator
ERO
Electicity Market Operator
ETSO
Energy Regulatory Office
MIT
European Transmission System Operators
TSO
Ministry of Industry and Trade of the Czech Republic
Other abbrevations
symbol
AnS
meaningAVC
Ancillary Services
ASVR
Automatic Voltage Controller
BM
Automatic System of Voltage Regulation
DM
Balance Market
DS
Daily Market
Ereg
Distribution System
NTC
Regulation Energy
TTC
Net Transmission Capacity
TRM
Total Transmission Capacity
ATC
Transmission Reliability Margin
SyS
Available Transfer Capacity
TC
System Services
TS
Transmission Capacity (Transfer Capacity)
EHV
(Czech) Transmission System
HV
Extra High Voltage
RES
High Voltage
CHP
Renewable Energy Sources
OP
Combined Heating and Power
ROPD
Operational Planning
COPD
Regional Operational Planning Department
PSS
Central Operational Planning Department
TG
Power System Stabilizer
Turbogenerátor
Documents issued by CEPS
Shortened title
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Glossary
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Transmission Services
Agreement
Agreement on Services Provided by the Czech
Transmission System
Contract for Electricity
Transfer
Agreement concerning the Accession to Trading Terms and
Conditions for Cross-border Transmission through the
Transmission System in the Czech Republic
Regulation Energy Preliminary
Agreement
Contract for Electricity Transfer
Regulation Energy Contract
Agreement on Conditions for Giving Consent to the
Real-Time Exchange of Regulation Energy during a Trading Day
Operational Instructions
Contract for Real-Time Exchanges of Regulation Energy
during a Trading Day
Rules
Symbols used for variables
and parameters
symbol
C
unit meaningf
MW/min Rate of loading of TG
∆
f
Hz
Frequency
P
Hz
Frequency deviation from nominal value (50 Hz)
∆
P
MW
Active power
Q
MW
Deviation of active power from basic point
U
MVAr
Reactive power
kV
Voltage
Subscripts of variables and
parameters:
index
base
meaningdg
Basic point
n
Diagram point
max/min
Nominal value
S or skut
Maximum/minimum value
Z or zad
Actual value
Basic conditions for the use of the Czech
Transmission System
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Glossary
Datum:
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Soubor: part_I_II_III_an_rev11.docRevision 11/January 2011
RULES FOR TRANSMISSION SYSTEM OPERATION
THE GRID CODE
Part I.
Basic conditions for the use of the Czech
Transmission System
(in compliance with the Czech Energy Act (Act No. 458/2000 Coll. on conditions of trading and state supervision in the power industry and on amending selected acts (the Energy Act), as amended, Article 24, Paragraph 10)
Contents:
1. About the grid code 2. Introductory provisions
3. Information on the Damas and eTrace ePortal 4. System services
5. Conditions for the Damas and eTrace ePortal 6. TS requirements of elektricity users
7. Connection site requirements
8. Information to be exchanged between ČEPS and transmission system users 9. Technical calculations
10. Terminology
The following provisions of the ČEPS Grid Code have been translated into English. This text is for instructive purposes only.
The translation has not been approved by the Energy Regulation Office. The Czech version predominates.
Basic conditions for the use of the Czech
Transmission System
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About the Grid Code
Datum:
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Soubor: part_I_II_III_an_rev11.docRevision 11/January 2011
1 About the Grid Code
The Grid code is an integral set of documents consisting of the following parts:
Part I. Basic conditions for the utilisation of the transmission system
The basic Grid Code document specifying its mission, the principles of its creation and the updating process. The competences of the TSO regarding UCTE interconnection are defined including a description of system services. The reader will find important information from various EU directives, the Energy Act, certain implementing regulations and network connection conditions. In addition, specification necessary data for TS operation and development is provided as well as a description of principal technical calculations and the relevant input data and a definition of the terminology employed in the Grid Code.
Part II. Ancillary services (AnS)
A description of the methodology employed for the determination of the total value of ancillary services required so as to ensure the reliable and secure operation of the Czech power system. Ancillary services are described (including details of their function and conditions for their provision). This part sets out the conditions for the granting and
revocation of metering certification. A description of the methodology for the measurement and evaluation of particular AnS is provided and the conditions for tendering for AnS procurement and subsequent evaluation are defined. The concept of the electronic on-line operation of the Daily Market in AnS on the internet is outlined. A description is provided of how to obtain permission for performing different tests within the power system and the rules for the preparation and approval of such tests.
Part III. Provision of system and transmission services
A description of the transmission services market at both the national and international levels including the methodology employed for the determination of available marketable capacity and the organisation of auctions. An examination is made of the verification of the import, export and transit of power on interconnectors carried out in order to provide the technical verification of the feasibility of reliable transmission of all commercial transactions. This part concludes with a definition of the rules for providing documentation for the preparation of transmission system operation.
Part IV. Development planning of the transmission system
Sets out the development trends, intentions and goals of the TSO with regard to the further development of the transmission system and the measures to be employed in accomplishing them. This part contains an outline of the application procedure for the connection of new equipment to the transmission system.
Part V. Operational security and quality at the transmission level
Describes the principles of the defence plan including the frequency plan, frequency load shedding and other measures to ensure against voltage and frequency deviations, overloading, cascade spreading after a failure and oscillation and loss of synchronism. The restoration plan is outlined here setting out strategy, priorities and responsibilities during the restoration of the power system after a black-out situation as well as the parameters for the quality of electricity delivered.
Part VI. Dispatch control
The aim here is to familiarise transmission system users, especially those subordinated to control from the ČEPS Dispatch Centre, with the relevant operational procedures. In addition, this part describes the communication of information concerning accidents.
Part VII. Transmission system facilities
Concerns the basic technical requirements for high voltage equipment and the principles of operation and maintenance and provides a definition of control systems, trade metering and protection requirements.
Part VIII. Transmission system standards A definition of the relevant standards.
Basic conditions for the use of the Czech
Transmission System
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About the Grid Code
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Preface
The aim of the Grid Code is to provide information for market participants as well as rules which establish:
• the minimum technical, design and operational requirements for connection to and utilisation of the transmission system,
• the conditions for the provision of ancillary and transmission services.
These conditions are influenced by a large number of transmission system technical requirements including the rules for international cooperation within the UCTE interconnected area. The transmission system operator, the TSO, must take into account all these circumstances when creating the conditions for the connection and operation of transmission system users. Naturally, UCTE cooperation rules are constantly developing and could well be changed in the future and be subject to modification based on operational experience and the level of openness of the electricity market.
The fulfilment of the conditions defined by the Grid Code is not sufficient however to guarantee the safe and efficient operation of the transmission system. The Operating Instructions of the ČEPS Dispatch Centre represent a further stage in the formalisation of relations between the TSO and the user. The validity of the Operating Instructions is defined by the Czech power system dispatch order. This set of documents – the Grid Code together with the Operating Instructions is considered to be the minimum set of rules necessary for ensuring the secure and reliable operation of the transmission system.
The Transmission System Operator and the rules for TS operation – the
Grid Code
The Transmission System Operator, established by Czech legislation and operated in the public interest, is ČEPS a.s. The company fully adheres to Czech legislation as well as to those obligations arising from various international agreements and contracts to which it is a party.
Since only one licence is issued to operate the Czech Republic’s transmission system, the system forms a natural monopoly which is regulated by the Energy Regulatory Office as well as by stiff competition rules. The TSO’s long-term goals and strategic decisions follow the relevant decisions of the Ministry of Industry and Trade, i.e. the State energy concept.
The users of the transmission system consist primarily of holders of licenses issued in compliance with the Czech Energy Act (Act No. 458/2000 Coll. on conditions of trading and state supervision in the power industry and on amending selected acts (the Energy Act), as amended, hereinafter only referred to as the Energy Act), as well as wider European electricity market users.
ČEPS’s cross border lines connect the Czech power system with the transmission systems of neighbouring countries thus creating a trans-European electricity infrastructure.
The transmission system consists of a sophisticated technological complex of EHV lines, substations, control and information systems and measurement equipment, the smooth functioning and reliability of which is the responsibility of the TSOs of those EU and other countries whose transmission systems are interconnected as members of the UCTE organisation. In addition, various regional impacts on consumption and generation have to be considered.
Power flows within the transmission system depend on physical laws, grid construction and the configuration of other interconnected transmission systems. Conditions within this complex system can change rapidly due to a wide range of factors, not all of which are under the TSO’s control. It is not possible to accurately define such conditions nor is it possible to fully guarantee their stability and invariability.
The necessary reserves of grid components and transmission capacity should be pre-planned according to repair, reconstruction and maintenance requirements and with regards to physical/natural connections and the potential occurrence of force majeure emergency situations.
Basic reliability criteria are set out jointly at the national and international levels. Therefore, any decision relating to the required amount of technical reserves should be made in consultation, and be defined and subsequently adopted with other, particularly neighbouring, operators of the interconnected grid.
Nevertheless, transmission system users, when making business decisions, need a knowledge of reference parameters, technical conditions and rules for connection to or use of the transmission system before they can begin to negotiate trade agreements.
Those transmission system users satisfying the requirements for connection and transmission have the right to connection to the grid and to non-discriminatory conditions for electricity transmission provided that sufficient transmission capacity is available and secure operation with the necessary reserves is possible.
Basic conditions for the use of the Czech
Transmission System
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About the Grid Code
Datum:
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Soubor: part_I_II_III_an_rev11.docRevision 11/January 2011
The rules for transmission system operation outlined in the Grid Code provide an important source of publicly
available technical information.
The following figure depicts the relevant legislative relationships:
Fig. 1 Grid Code - Legislative framework
The Energy Act requires the TSO to include into the Grid Code certain information, which must also be publicly available. Ministry decrees supplementary to the Energy Act (implementation regulations) refer to other recommended information.
ČEPS decides whether it is necessary to incorporate any other information into the Grid Code e.g. with respect to EU Decisions, EU Regulations or other commitments pertaining to international agreements and contracts.
The Grid Code is published on ČEPS’s web site (http://www.ČEPS.cz/) following Energy Regulation Office approval.
The rules for transmission system operation i.e. the Grid Code do not constitute a separate source of law. They provide, together with other publicly available documents, information for transmission system users. It is neither a unilateral declaration nor source of legal obligation on the part of ČEPS, a.s.
The rights and obligations of transmission system users and ČEPS, a.s. result from legislation and their mutual rights and obligations result from negotiated commercial agreements.
Reasons for creating the Grid Code
With the adoption of market rules in the electricity industry, it is necessary to ensure both the transparency of the natural monopoly of the TS and a non-discriminatory approach to all its users. This principle results from the Directive (see [1]). However, the power system, from a technical-physical point of view, remains a unified and complex system controlled by physical laws. It is becoming increasingly important to secure the safe and reliable operation of the power system as a whole regardless of its organisational structure and ownership. Therefore certain basic rules must be laid down, from the
Ministry decree Ministry decree Transmission System Operator ČEPS Energy Regulation Office EU Directive Energy Act EU Regulation EU Decisions Grid Code
Commercial conditions for connection Conditions for providing ancillary services
Metering details
Specification of ancillary services facilities Data provision for operation and development
Quality parameters of delivered electricity Commercial conditions of transmission
Operational directions Rules for operational planning
Rules for development Mi nistry decree ApprovesDevelops Information Obligations from other Agreements Transmission system users Contracts Commercial Agreements Agreement on providing ancillary services Agreement on providing transmission services Transmission system users
Basic conditions for the use of the Czech
Transmission System
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About the Grid Code
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technical point of view, which ensure the necessary co-operation and co-ordination between individual transmission system users.This approach follows Chapter IV of the Directive 2003/54/EC, – Operation of the transmission system, article 8, in which it is specified that organisations which own transmission systems shall designate a transmission system operator (which shall be, according to the relevant definition, responsible for operating, maintaining and, if necessary, developing the transmission system in any given area and its interconnection with other systems). Chapter II – General rules for the organisation of the sector, article 5 specifies an obligation to develop and publish technical rules specifying the minimum design and operational requirements for the connection of generating installations, distribution systems, directly connected consumer equipment, interconnector circuits and direct lines. These rules shall ensure the inter-operability of transmission systems and they shall be impartial and non-discriminatory.
A further reason for drawing up the Grid Code is that, in order to ensure reliable operation, the TSO needs a rigid set of rules to prevent possible conflict between transmission system users. The Grid Code provides a general knowledge of the conditions pertaining to the use of the transmission system and sets out identical conditions for all transmission system users of a similar category.
The mission of the Grid Code
Transmission systems, together with distribution systems, constitute specific network subsystems of individual power systems and, by definition, take the form of natural monopolies. The Directive introduces terms and conditions relevant to the transmission system operator or distribution system operator for those organisations operating such subsystems. The activities of such operators and the corresponding business conditions are not exposed to the direct effects of market mechanisms based on the existence of competition and thus are subject to regulatory supervision. Consequently, the rules for the operators of natural monopolies are set out, in an open and transparent manner, in a document generally referred to as the Grid Code.
The mission of the transmission system Grid Code is to explain, as transparently as possible, the following issues to all its users:
• the principles, rules and standards pertaining to the transmission system operator regarding the operation, maintenance and development of the transmission system, which, by their nature, set the quality of the relevant system, ancillary and transmission services,
• the conditions which must be met by applicants wishing to be connected to the transmission system,
• the requirements in terms of data, information and co-operation that users of transmission services are obliged to provide to the transmission system operator as a condition for the proper operation of the transmission system at the required quality level,
• the conditions under which users of the transmission system can offer ancillary services and the rules and conditions that the operator of the transmission system must observe during the tendering process,
• the conditions for the provision of ancillary and transmission services.
The Grid Code thus provides information that serves not only TS users as a list of the technical conditions necessary for reliable co-operation with the TSO but which also serves as the basis for verifying the competence of the TSO itself.
Updating the Grid Code
The Grid Code is written and updated by the TSO, or stipulated by the ERO. It comes into effect after approval from the Energy Regulation Office (§17 and § 97a of the Energy Act). Such an approval process is required for any subsequent changes in the Grid Code.
Consequently, a one year regular time interval for revisions to the Grid Code has been established. The deadline for the inclusion of suggestions and other material requiring a change in the existing wording of the Grid Code is the end of November, the updated version being published in December. The Grid Code is then valid for the following calendar year. The TSO may submit changes to the Grid Code at any time during the year should it judge that developments in general legislation and requirements for power system operation require it.
General provisions
New users of the TS must meet the requirements of the Grid Code in full in order to be connected to the TS. Existing (already connected) users must adapt their equipment to meet any new requirements of the Grid Code at the earliest possible opportunity in order to satisfy the conditions relevant to new users. This means the partial or complete reconstruction of that equipment or part of which does not meet the respective requirements.
Basic conditions for the use of the Czech
Transmission System
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Introductory provisions
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The Grid Code covers a broad area of transmission and power system operation and establishes rules for both. The enforcement of requirements for reliable transmission system operation for existing users facing new conditions might be solved by the negotiation of mutually agreeable transition periods.2
Introductory provisions
2.1
Main principles employed in the creation of the Grid Code
The following principles have been applied in the creation of the Grid Code:
1. Relevance – the updating of the Grid Code reflects progress in both the technical and legislative environments. 2. Unambiguousness – the text of the Grid Code should be unambiguous and redundancy minimised.
3. Modularity - each part of the Grid Code forms a separate document that may be revised independently of the other parts.
4. Transparency – the rules are understandable and do not contradict each other.
5. Liability for users – all the standards, rules and recommendations presented in the Grid Code are binding for all transmission system users and certification authorities. This liability results from the Energy Act.
2.2
Č
EPS’s basic responsibilities
ČEPS, as the licensee, is responsible both for the development and refurbishment, and the secure and reliable operation of the transmission system. This is achieved through its dispatch centre and its operational and development departments.
ČEPS’s basic responsibility is to provide transmission services for transmission system users. This responsibility is described in detail in Part III of the Grid Code ( III).
In addition, ČEPS as the TSO ensures the system services necessary for the secure and reliable operation of the Czech power system. System services are covered in Chapter 4.
2.3
Č
EPS’s main activities
According to § 24 par. (1) of the Energy Act, ČEPS is responsible for the following:
1. ensuring the reliable operation, refurbishment, and development of the transmission system, including interconnections, and for system maintenance
2. providing electricity transmission on the basis of concluded agreements
3. controlling power flows within the transmission system taking into account transits between the interconnected systems of other countries and in co-operation with distribution system operators within the power system
4. ensuring system services for the power system at the transmission system level
2.4
Activities of the
Č
EPS Dispatch Centre
The activities of the ČEPS dispatch centre during dispatcher control differ according to the situation pertaining within the transmission system.
1. In the normal state
dispatchers monitor the state of the system and react to deviating operating values by the activation of ancillary services, by manipulation within the grid and with the cooperation of neighbouring transmission and distribution system operators.
2. In the alert state:
dispatchers adopt operating measures to restore the system to its normal state
3. In the emergency state:
a) Dispatchers apply special procedures relevant to the TSO’s responsibility for restoring the system to its normal state as quickly as possible. These special procedures include e.g. load shedding, reduction of export/import, black start of generation units and the re-synchronisation of islands (isolated parts of the interconnected grid). The same procedure applies for emergency state prevention.
b) In the case of an emergency situation at the main dispatch centre (e.g. outage, terrorist attack) a backup dispatch centre takes over control of the Czech power system.
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2.5
Basic rules for connection and use
In addition to the requirements of common regulations it is necessary to satisfy further technical requirements as specified in the relevant parts of the Grid Code. The requirements placed on particular category users are set out in chapters 5 and 6; the requirements relevant to the connecting site are provided in chapter 7.
2.6
Observation of requirements and verification
ČEPS shall publish specific procedures for the verification of the adherence to the technical rules and requirements for connection of a user to the transmission system. During operation, ČEPS reserves the right to carry out operational screening and monitoring, to take measurements and to verify the fulfillment of the relevant connection requirements. In addition, ČEPS is entitled to verify the fulfillment of the relevant requirements pertaining to the quality and quantity of ancillary services provided by the user.
Transmission system users shall be informed on the operational characteristics, valid standards and results of any operational evaluation carried out. ČEPS shall specify the rules for the verification of its own operational procedures and thus shall submit proof to users that the various procedures are applied correctly and in a non-discriminatory manner.
The user is responsible for the observation of the standards and technical requirements set out in this Grid Code.
3
Information on the Damas and eTrace ePortals
The Damas and eTrace ePortals consist of a hardware infrastructure connected to the internet and a software application available on the following web sites:
http://market.ČEPS.cz/– Damas ePortal
http://market.e/trace.biz/ – eTrace. ePortal
The Damas and eTrace ePortals assist in the collection of technical-commercial data (bids and offers), its verification, processing and communication as described in the Rules for DAMAS ePortal operation between ČEPS and users (the current version of this document can be found at: http://www.ČEPS.cz/ and the current version of the ‘Operational Instructions’ can be found at: http://www.e-trace.biz/ ).
The security of any commercial data transmitted by users to the Damas and/or eTrace ePortals through the internet is guaranteed by the use of SSL encryption which prevents third parties from reading such data. Identification and authorisation elements are used at the PKI standard level – all data is electronically signed.
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4
System services
This chapter contains a definition of system services (SyS) which are both managed and coordinated by ČEPS.
ČEPS is, according to the Energy Act, responsible for ensuring system services for the power system at the transmission system level. The system services provided by ČEPS serve to ensure both the secure and reliable operation of the power system and the quality of electricity transmission and satisfy the various international obligations set out by the UCTE.
ČEPS provides the following system services: 1) Maintaining the quality of electricity
This service entails the use of the following technical-organisational tools: o Management of the summary power reserve for primary frequency control o Secondary f/P control
o Secondary voltage control o Tertiary voltage control
o Ensuring the quality of the voltage sine wave o Ensuring transmission stability
The criteria for the quality of electricity follow current technical standards V.3. 2) Real time active power balancing
This service requires the use of the following technical-organisational tools: o Load frequency control
o Tertiary active power control o Dispatcher reserve
The criteria for evaluating the quality of active power balancing (the control of power interchange at the planned level) are contained in recommendations provided by the UCTE (Ground rules concerning primary and secondary control of frequency and active power within the UCPTE) and in the Catalogue of requirements for connection to the UCPTE. 3) System restoration
System restoration is based on the so-called Restoration plan (V.2) which employs both the Island operation and Black start ability ancillary services.
The criteria for evaluating the quality of system restoration are set out in the rules of both ČEPS and the UCTE. 4) Dispatch control
In addition to the tools outlined above this service includes the following:
o ensuring the security of operation based on the Defence plan (V.1) and Operational instructions
o congestion management (the control of power flows) involving grid reconfiguration, re-dispatching and counter trading V.1
The criteria for evaluating the quality of dispatch control are set out in the rules of both ČEPS and the UCTE.
4.1
Technical-organisational tools for ensuring SyS
4.1.1 The maintenence of the summary power reserve for frequency primary control
The maintenance of the summary power reserve for frequency primary control involves the procurement of this reserve at a determined value and quality (with the required static and dynamics).
Primary frequency control in any interconnected power system is based on the so-called solidarity principle. This means that in the case of imbalance between the load and the power source (e.g. caused by unit outage or load change) all the sources within the interconnected system involved in primary frequency control in each control area are responsible for restoring power balance.
The purpose of primary frequency control is to correct frequency deviation within a period of a few seconds by increasing or decreasing the power supply. The power response ∆P depends on the stationary frequency deviation and can
be represented mathematically as follows:
f
P
=
−
∆
∆
λ
[MW, MW/Hz, Hz] (1)λ represents the so-called power frequency characteristic of the control area. The summary of power reserves for the primary control of all the control areas is specified as a standard determined by the value of the maximum power outage to be covered by the primary frequency control. Ensuring this power reserve (mutually agreed within the UCTE) constitutes a basic TSO obligation i.e. it is a condition for the synchronous operation of systems belonging to companies which agree to
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such interconnection. Consequently, every control area maintains a specified summary power reserve for primary frequency control with a given summary static.II.2.Units participating in primary frequency control provide primary control AnS (See II.1). Primary frequency control is supplemented by secondary f/P control.
4.1.2 Secondary f/P control
Secondary f/P control automatically maintains both frequency at a nominal value and power balance within the control area (exchange of power with neighbouring systems at a scheduled value).
Secondary f/P control is provided automatically by the central controller located at the ČEPS Dispatch Centre. Power station terminals providing the unit secondary active power AnS (II.1) and terminals at border substations measuring the amount of power exchanged are connected to the central controller. The central controller itself works according to the network characteristics method which guarantees the so-called non-intervention principle. That means that the control area directly affected (in which the power imbalance has arisen) restores the power balance and returns the frequency to the nominal value. The area control error (represented by G according to [2]) is calculated as follows:
f
K
P
G
=
∆
+
∆
[MW, MW, MW/Hz, Hz] (2)∆P is the deviation of exchanged power from the scheduled value and K is the adjusted parameter, the so-called
K-factor (frequency bias), which should be equal to the power factor λ to ensure the smooth functioning of the
non-intervention principle.
The instant area control error must not be mistaken for the so-called system deviation which represents the energy deviation of market participants – subjects to deviations settlement during a defined trade interval.
When restoring the power balance, secondary f/P control supplements primary frequency control in such a way as to gradually replace all the power provided by the interconnected system according to the solidarity principle. Secondary f/P control is implemented by sending the required value of power from the central controller to units providing secondary active power control AnS.
Secondary f/P control should restore the set frequency and exchanged power values within 15 minutes of the commencement of the imbalance. Secondary f/P control is further supplemented by tertiary active power control.
4.1.3 Tertiary active power control
Tertiary active power control maintains the necessary secondary power reserve.
Tertiary control serves to replace the spent secondary power reserve, i.e. that power consumed by secondary f/P control. It is possible to employ quick starts when necessary along with the spinning reserve (on units providing tertiary control AnS).
The quick start reserve QS10 is used for covering large unit outages in cases where it is necessary to comply with
the criterion of restoring the power balance within 15 minutes of an outage occurring. The QS10 reserve is replaced upon the
activation of tertiary P control AnS or by dispatcher reserve start up after recovery of the power balance.
4.1.4 Use of the dispatcher reserve
The dispatcher reserve covers power imbalances caused by market participants unable to comply with the scheduled load diagram or base points over an extended period of time (more than two hours).
The dispatcher reserve covers power deficiencies caused by unit outages or larger consumption than was originally agreed. Generators or consumers are unable or unwilling to cover such eventualities by their own means (e.g. by purchasing electricity on the balancing market).
4.1.5 Secondary voltage and reactive power control (SVC)
Secondary voltage and reactive power control automatically maintains the reference voltage at the transmission system pilot nodes. Reference voltages are determined by tertiary voltage control.
The purpose of SVC is to maintain reference voltages specified by tertiary voltage control at the pilot nodes. The SVC system is initiated using the automatic voltage controller (AVC) which reacts to deviations in actual voltage from the reference value voltage at the pilot node and determines the amount of active power required to eliminate such deviations. The required power is sent to those power stations the units of which provide secondary U/Q control AnS.
If a power station has more than one unit then it must be equipped with a reactive power group controller which allocates the required reactive power from the AVC to individual units according to predetermined rules. In principle, the following arrangements are possible :
1. The AVC is located at the power station (as part of the power station control system). The so-called group excitation controller determines the reactive power of individual units (using pulsed or analogous reactive power control). 2. The AVC is located outside the power station (e.g. at a very high voltage substation) but includes a power station group
controller which directly controls the reactive power of individual units (using pulsed or analogous reactive power control).
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3. The AVC is located outside the power station (e.g. at a very high voltage substation) but sends the required reactivepower summary value to the power station. The group controller located at the power station subsequently distributes this value between the individual units.
Individual arrangements must be agreed between the ancillary service provider and the TSO. The AVC system comprises compensation reactors employed when the appropriate generator regulation reserves are exhausted. Regulation by means of compensation reactors should commence before the technical potential of the alternators is fully exhausted. A permanent emergency reactive power reserve should be maintained on alternators. The control system includes network transformer tap changing (on-load tap changer control – OLTC). The AVC must allow communication with tertiary voltage control as well as the performance of basic diagnostics and control quality assessment.
The following figure shows the hierarchic U/Q control links within the power system.
Tertiary U/Q control
Secondary Q controller
(located at units)
AVC system of secondary voltage control
+ group controller
Unit U/Q control Voltage control
in pilot node
Tertiary controller
(Located at the TSO dispatch centre)
skupinový regulátor Q
(located at power station)
Secondary Q controller (located at units) Secondary Q controller (located at units) Secondary Q controller (located at units) Secondary Q controller
(located at power station)
AVC automatic voltage controller
(located at pilot node)
AVC automatic voltage controller
(located at pilot node)
AVC automatic voltage controller
(located at pilot node)
AVC automatic voltage controller
Fig. 2 U and Q control structure in the transmission system
During the transition from pilot node to island operation the AVC automatically disconnects from tertiary control (remote voltage control) and switches over the local mode of the voltage settings. The impulse is derived from the output of the so-called island operation controller of the appropriate generator which controls the voltage in the pilot node. When there is no output available, a signal is received from the frequency relay which indicates the commencement of island operation in a given part of the transmission system.
4.1.6 Tertiary voltage control
Tertiary voltage control coordinates the reference values of voltages in the pilot nodes to ensure the secure and economically efficient operation of the power system as a whole.
Tertiary voltage control is provided by optimisation software located at the ČEPS Dispatch Centre. It can be seen in
Fig. 2 that tertiary control is positioned at the top of the power system voltage and reactive power control hierarchy.
4.1.7 Ensuring transmission stability
This is a supervisory and co-ordinating activity which assures the stability of active power transmission and dampens oscillations within the system.
The operation of interconnected transmission systems requires the verification of the static and dynamic stability of power transmission. Consequently, inspections are carried out by ČEPS, which monitor and evaluate the measured phenomena in real time1, and stability calculations are made which suggest the measures to be put in place for the setting of under excitation limiters, the increasing of excitation controllers and the setting of power system stabilisers (PSS) in the excitation controllers. These issues are addressed in the Defence Plan by measures which are designed to prevent oscillations and loss of synchronisation V.1.
1
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4.1.8 Restoration of operation after full or partial blackout (loss of supply)
A process consisting of unit start up without support from the network (black start), subsequent network voltage recovery and supply to predetermined priority consumers and release from island operation of parts of the network and their gradual synchronisation and reconnection.
In the case of a large system failure which cannot be managed by the normal safeguards in place to prevent the spread of such a failure (the Defence Plan), full or partial blackout of the system may occur. In such cases it is ČEPS’s responsibility to restore the system to normal operational conditions. With this purpose in mind, ČEPS has drawn up its so-called Restoration plan V.2, which is included in the dispatch centre operational instructions of distribution system operators. Regular training is carried out on the content of the Restoration plan and certain parts of the plan are subject to regular testing for example the start-up of units without an external voltage and power supply (black start) and the testing of the ability of units to work in island operation.
4.1.9 Ensuring the quality of the voltage sine wave
Containing both passive (monitoring and checking) and active (filters) elements.
With the development of semiconductor technology the amount of equipment based on such technology and supplied at higher voltage levels is on the increase. This may cause harmonic course distortion of the voltage level (impulses, higher harmonic volume etc.), which may negatively affect other consumers. Hence ČEPS reserves the right to monitor and measure the ‘correctness’ of the sine curve, identify the source of the failure and suggest the measures to be taken in order to rectify the situation.
4.2
The relationship between System and Ancillary services
ČEPS uses so-called ancillary services (AnS), provided by particular transmission system users, to ensure its system services. By so doing, ČEPS is able to operate the transmission system in a reliable way and to the high level required of UCTE standards. The list of ancillary services is as follows:
1. Unit primary f control (PR) 2. Unit secondary P control (SR) 3. Unit tertiary P control (TR) 4. Quick start reserve (QS10)
5. Dispatcher reserves (DZt)
6. Load changing (ZZ30)
7. Generation shedding (SV30)
8. Vltava (VSR)
9. Secondary U/Q control (SRUQ) 10. Island operation capability (IO) 11. Black start capability (BS)
More detailed information is provided in part II of the Grid Code. II.
The following table outlines the relationships between system (SyS) and ancillary (AnS) services. For any particular SyS it shows the corresponding AnS through which transmission system users can participate in ensuring system unit m Primary frequency control services:
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SYSTEMSERVICE
Technical-
organisational instrument Producers -unit operators
Other users Maintenance
of electricity quality
Primary frequency control Unit primary f control Secondary voltage control Secondary U/Q control Secondary f/P control Unit secondary P control
Vltava cascade Active power
balancing in real time
Tertiary active power control
Quick start reserve Unit tertiary P control Dispatcher 30-minute reserve Generation shedding
Vltava cascade
Load changing
Dispatcher reserve use Dispatcher reserves Load changing System
restoration Island operation capability Black start capability
Table 1 Overview of system services and corresponding ancillary services
5
Conditions applicable to plant unit operation
In this chapter, a summary of requirements is provided, applicable to plant units connected or operated in the transmission system (TS). Technical requirements concerning power equipment of units connected to the transmission system must comply with requirements stated in Part VII. 1. Technical requirements concerning protection are stated in Part VII.2.
5.1 Requirements applicable to plant unit operation
The safe operation of the power system requires a clear specification of requirement applicable to plant units, closely related to the needs of the transmission system. Such requirements are particularly related to the ability of units to operate in TS even under extreme U and f values.
5.1.1 Allowed values of voltage and frequency
The plant unit as a whole (i.e., including internal consumption) must be capable of permanent operation with the nominal active power, as well as with the nominal apparent power, of the generator within the frequency range of 48.5 and 50.5 Hz, and the unit alternator terminal voltage within the range of 95% and 105% Un (assigned upper limit freguency for
CCG – 51,5 Hz). In justified cases (particularly, when the technology used is uncapable of meeting the operation requirement with the nominal active power for frequency values under 49.5 Hz), operation conditions shall be arranged, on a basis of a written requirement, in an agreement between ČEPS and the power plant operator. For PPC, the frequency upper limit is determined at the value of 51.5 Hz. For each unit, the unit supplier must define two frequency limit values fmin and
fmax, for which the unit operation is impermissible.
The minimum and the maximum values fmin and fmax are defined in the frequency plan (V.1). For the frequency
range between fmin up to 48.5 Hz and from 50.5 Hz to fmax, and concurrently for the terminal voltage range from 80% Un to
95% Un and from 105% Un to 110% Un, the unit supplier must define values of the unit alternator active and apparent
power, possibly with their time limitations. ČEPS must have these values available in a format of a set of tables or diagrams.
5.1.2 Transition and operation under internal consumption
A thermal power plant unit (with steam or gas turbine) must be capable of an instant and a safe transition from the full load to an internal consumption operation mode. It must be capable to operate in this mode for the period of 2 hours, as the minimum.
5.1.3 Unit island operation capability
In case island operation occurs (as a symptom, the frequency deviates from 49.8-50.2 Hz limits - see Frequency Plan V.1), the unit must be capable of changing its power output automatically, depending on the frequency deviation
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Apart from it, units providing the Island Operation Capability auxiliary service must be able, on TS Dispatcher demand, to change their power output so that it participates at the island frequency control to a value appropriate for the island synchronization. The power output change can be either manual (in case of a power change command) or automated - in case of a transition to an astatic - proportionally integral control of revolutions (in case of a TS dispatcher command for a transition to this particular control mode). For details please see II.1.An operator of a unit with the installed power exceeding 50 MW evaluates the actual unit behaviour after each change of the turbine control structure associated with the system frequency deviation from the limits 50 ± 0.20 Hz and
sends them in an electronic format to TS operator. This Unit island operation report provides a necessary feedback between the TS operator and plant unit operators and serves particularly the purposes of safety enhancement in the electrical power system operation (prevention of serious system failures, such as blackouts). For details of the Report please see
Appendix 3.
5.1.4 Unit operation under grid failure conditions
The unit must comply with conditions of resistance against grid failure effects, when the following is at risk:
• dynamic stability with "short-circuit" type failures
• static stability (in the meaning of lost abilities to transmit the active power over a compromised transfer interface)
• static stability (in the meaning of undamped fluctuations (double amplitudes), i.e. "self-excited oscillations").
In case the dynamic stability is at risk, as identified by calculations, units must be provided with relevant safety features according to chapter 5.1.7 – „Automated devices“. The static stability loss is primarily prevented by correct settings of underexcitation limit controls. The basic measure preventing an occurrence of spontaneous fluctuations is provided by a magnetic-field stabilizer system (PSS) and a suitable magnitude of a control loop amplification in the voltage primary control.
5.1.5 Generator stability loss protection
If ČEPS calculations prove the probability of alternator stability loss in a specific power system location substantial, alternators with apparent power of 100 MVA and higher must be provided (subject to an agreement with the manufacturer) with protection features disconnecting the alternator from the grid in case of stability loss. It is recommended for the protection to include optional settings of the number of slips after which the alternator is disconnected. The number of the generator slips is set in respect of the design endurance against such a state, i. e., subject to an agreement with the alternator manufacturer and respecting slip effects on TS operation. The setting shall be determined on a basis of calculations described in chapter 9 and subject to an agreement between the power plant and ČEPS.
5.1.6 Frequency relay
Units must be provided with suitable frequency relays responding to ES frequency and ensuring automated tasks in case of frequency failure changes according to Frequency plan. Specific tasks derived from frequency relay operation depend on the location of a unit connection to TS, on the unit size, and results of calculations described in chapter9. Having being discussed with ČEPS, these tasks are realized in particular power plants, with settings of particular limits and parameters included.
5.1.7 Automated devices
In some locations of a power plant connection to TS, risks may occur of stable run loss when the grid function is degraded due to a failure or from other reasons. Such fact is identified on a basis of calculations. In order to reduce risks of the entire power plant loss after an occurrence of such situations, system automated devices are installed in TS, capable of switching off selected plant units. In such a situation, it becomes necessary to ensure a transfer of a relevant signal from the automated device to the power plant, corresponding to switching off and a transition of operated power plant units to the internal consumption operation. This measure is designed to maintain, in a failure situation, a stable operation of the rest of the plant units.
The design of this automatics system part is arranged for by ČEPS, and of the related part in the power plant by the power plant itself. The automated devices are set on a basis of above mentioned calculations, in a process coordinated between the power plant and ČEPS. Other automated functions are arranged for subject to an agreement between the power plant and ČEPS. E. g., a signal transmission from TS station to the power plant when the unit line in TS station is switched off. The impulse affects turbine valve boosters2, reduces the rise of turbine revolutions, thus making easier the transition to the internal consumption.
2
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5.2 Control requirements applicable to U and Q
The chapter includes general requirements applicable to all units. For specific requirements applicable to the provider (AnS) please see II.1.
5.2.1 Requirements applicable to unit control range
The generator must be able to produce the nominal active power within the range of the power factors cosϕIND = 0.85 (generator running in overexcited state) and cosϕKAP = 0.95 (generator running in underexcited state) with
frequency between 48.5 to 50.5 Hz and within an allowed voltage range either ±5 % Un on generator terminals or 400 kV±5
%, 220 kV ±10 % and 110 kV ±10 % on VHV of the unit transformer. In justified cases (particularly, when the technology used is uncapable of meeting the operation requirement with the nominal active power for frequency values under 49.5 Hz), operation conditions shall be arranged, subject to a written requirement, in an agreement between ČEPS and the power plant operator.
With lower active power values, allowed values of the reactive power can be identified according to unit operation diagrams, which must be included in the unit operation-technical documentation. The internal consumption technology of a power plant and ensuring the internal consumption power supply will make possible to use the above stated allowed range, e. g., using a tap-changing transformer of the internal consumption supply with a control under load.
The basic required regulation range of the reactive power, as stated here, may be modified, i. e., it may be reduced or enlarged. Reasons for possible modifications may include, e. g., a different (lower/higher) needs for the controlling reactive power in a particular TS location, or special needs of technology. Such a modification would require a conclusion of a special agreement between the operator and the user of TS.
5.2.2 Requirements applicable to unit primary regulation U
The primary voltage control is ensured by the primary controller, which is a standard part of the field regulator and makes possible an involvement on the higher level secondary controlU/Q (SRUQ).
Primary voltage controller:
a) may not display insensitivity during a voltage control
b) must be provided with circuits for voltage drop compensation on the unit transformer, using "statics
from idle current"
c) must enable impulse control of a desired value of generator terminal voltage
d) must enable transfer of measured, controlled, and controlling signals (variables) to other devices
through digital communication
Apart from the primary voltage controller mentioned already, the field regulator is supplemented by the following, auxiliary, automatics:
1. stator & rotor current reducer (alternator safety circuits) 2. underexcitement limit sensor (HMP)
3. stabilizing circuits for grid fluctuation dampening (system stabilizers)
The HMP must be set in order to protect the alternator according to manufacturer's requirements (defined in the operation diagram P-Q). In case of a unit not included into ASRU, the HMP setting shall ensure, additionally, the static stability of the unit connected to the system. The HMP setting from the viewpoint of the static stability is determined, subject to an agreement with ČEPS, on a basis of relevant calculations.
5.3 Measurements and transferred signals
The point of the plant unit connection to TS must be provided with adequate dispatching and commercial measuring facilities. A detail specification is provided in chapter 7.1 - "Requirements applicable to connection point measuring facilities" A list of signals and information, necessary for a reliable control of ES operation is provided in chapter 8 "Information exchanged between TS operator and its users".
5.4 Ensuring transmission stability
The transmission stability is ensured by an installation of system stabilizers and sensors of the underexcitement limit, into the unit field regulator. With the increasing level of interconnection of particular electrical power systems into extensive systems, the tendency grows to fluctuations of system variables, such as local frequency, voltage, and power transmission values. Such fluctuations reduce the quality of electricity and additionally, they may cause serious system failures. Therefore, such fluctuations must be damped.
Efficient methods include a setting of amplification of the field regulator
