Operation Handbook
Transcription
Operation Handbook
Operation Handbook June 2004 union for the co-ordination of transmission of electricity INTRODUCTION I – Introduction to the UCTE Operation Handbook (OH) [E] Chapters A. B. C. D. E. F. G. H. I. J. UCTE’s basic needs for the Operation Handbook Target audience for the Operation Handbook Main characteristics of the Operation Handbook Main scope of the Operation Handbook Basic structure of the Operation Handbook Guide for handbook readers Procedure for handbook development Table of handbook policies and appendices UCTE system overview Contacts and links History of changes v2.5 draft 24.06.2004 UCTE Secretariat v2.4 draft 01.03.2004 OH Team minor changes, OH development procedure update minor changes Current status The "Union for the Co-ordination of Transmission of Electricity" (UCTE) is the association of transmission system operators in continental Europe, providing a reliable market base by efficient and secure electric "power highways". The UCTE (up to the 30th of June 1999 named UCPTE) has created a “Survey of essential UCPTE recommendations for the interconnected operation” (dated 31st of December 1991) and important additional rules and recommendations on specific subjects after that date. Up to now (and if not already replaced by the Operation Handbook) these documents have been in force in the UCTE. The “UCTE Operation Handbook” (OH) is an up-to-date collection of operation principles and rules for the transmission system operators in continental Europe. Additional references to UCTE operation and security rules and recommendations as well as a list of publications, public statistics and information about the members, organisation, structure and activities of the UCTE in general can be found on the UCTE Web site: !http://www.ucte.org This introduction is the cover paper for the operation handbook policies and appendices. It includes a general overview, the main characteristics and scopes of the handbook, a description of the handbook structure with the table of contents as well as guides and descriptions for readers. The glossary of terms is provided in a separate paper. This version of the document (version 2.5, level E, dated 24.06.2004) has “final ” status1. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. 1 : The version numbers of handbook documents currently reflect the developments only. As soon as a document is approved and enforced for the first time, the version number may change. UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) A. "I–2 UCTE’s basic needs for the Operation Handbook [Union for the Co-ordination of Transmission of Electricity – Articles of Association, 2000] The “Union for the Co-ordination of Transmission of Electricity” (UCTE) co-ordinates the operational activities of transmission system operators in 22 European countries. Their common objective is the security of operation of the interconnected power system. 50 years of joint activities laid the basis for a leading position in the world which the UCTE holds in terms of the quality of synchronous operation of interconnected power systems. Through the networks of the UCTE, 450 million people are supplied with electric energy; annual electricity consumption totals approx. 2100 TWh. Close co-operation of member companies is required to make the best possible use of benefits offered by interconnected operation. For this reason, the UCTE has developed a number of technical and organisational rules and recommendations in the past that constitute a common reference for smooth operation of the power system. The “UCTE Operation Handbook” is the successor to these sets of rules and recommendations, that have been continually developed during the decades of construction and extension of the power system since 1950, reflecting the changes in the technical and political framework. Only the consistent maintenance of the high demands on quality will permit in the future to set standards in terms of security and reliability as in the past. Moreover, the strong interconnections in the UCTE grid require common understandings for grid operation, control and security in terms of fixed technical standards and procedures. They are comprised in this “UCTE Operation Handbook” in an organised form to make consultation easier for members and the general public. UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) C. "I–3 UCTE System Overview For the sake of general information and orientation, the following figures show maps of the UCTE system in the overview: • the map of the complete UCTE interconnected network / transmission system of 2003 (available from UCTE at !http://www.ucte.org/), !I–4 UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) • the political map (by countries, membership, connection status) of the UCTE SYNCHRONOUS ZONES as of 2004, • the structure and organisation of the CONTROL BLOCKS /AREAS of the UCTE SYNCHRONOUS AREA by countries/companies NL D CENTREL RWE E.ON D VE-T BEWAG EnBW TIRAG B CEGEDEL PL Acc. CZ VKW Acc. Area SK FEP CH F UCTE VEAG A H E RO BG UKR 7 P MOR JIEL I SLO HR BIH CG EKC SR MK UCTE South AL GR UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) B. "I–5 Target audience for the Operation Handbook The “UCTE Operation Handbook” shall support consultation and provide assistance to different parties in issues of system operation, such as to • Transmission System Operators (TSOs) / Grid Operators, Co-ordination Centres. Every TSO in the UCTE interconnected network (SYNCHRONOUS AREAS) has declared to follow the technical standards and procedures that are comprised in this “UCTE Operation Handbook” (main focus of the handbook). This Operation Handbook therefore serves as the reference (“legislation”) for the grid operation by the TSOs and guarantees the UCTE’s quality and reliability standards. • Generation Companies (GENCOs). Every party operating a generating unit in the UCTE interconnected network (SYNCHRONOUS AREAS) makes use of the transmission network and may have to deliver products for the provision of system services that are indispensable for secure and stable grid operation. The Operation Handbook sets standards for the essential requirements and capabilities regarding generation that contribute to the operation of the grid by the TSOs. • Other associations, traders, customers, politicians and decision makers. Operation of an interconnected transmission system is bound to physical principles and technical constraints, that differ significantly from other well-known technical or financial systems. This Operation Handbook explains these differences and characteristics in a transparent manner to the public for a better understanding. It can also serve as a general reference document. UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) D. "I–6 Main characteristics of the Operation Handbook The following main characteristics of the “UCTE Operation Handbook” serve as a guideline for the development and set-up of the handbook: • Transparency. Technical and physical principles of transmission grid operation in the UCTE are clearly described and published in the Operation Handbook also for nonexperts. • Liability. Following the Articles of Association of the UCTE, as they have been signed by all members, the standards and recommendations of the Operation Handbook were developed as binding for all members (including associated members) of the UCTE and their operation of the grid. • Unambiguousness. All standards and recommendations of the Operation Handbook are written to be straightforward and unmistakable for the processes of secure operation of the UCTE SYNCHRONOUS AREA(S). All terms used in the handbook are defined only once. • Relevance to the present. Standards and recommendations included in the Operation Handbook are continually adapted to the changed technical and legislative environment. A version history clearly shows the status of each part of the handbook. • Minor Redundancy. The Operation Handbook is written to have only the minimum of redundancy that is required. For this purpose, references to other chapters within the handbook are used instead. • Modularity. Each chapter, policy, rule and guideline of the Operation Handbook can be seen as a separate document that may be revised independently of the other parts. All chapters use a similar layout and internal structure. UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) E. "I–7 Main scope of the Operation Handbook The main objective of the “UCTE Operation Handbook” as a comprehensive collection of all relevant technical standards and recommendations is to provide support to the technical operation of the UCTE interconnected grid (SYNCHRONOUS AREAS), including operation policies for generation control, performance monitoring and reporting, reserves, security criteria and special operational measures. The basic subject of the Operation Handbook is to ensure the interoperability among all TSOs connected to the SYNCHRONOUS AREAS. Standards for network access of customers, network tariffs, accounting, the commercial part of unintentional deviations, billing procedures and market rules as well as other standards that may be set by national GridCodes, laws or contracts are not within the scope of this Operation Handbook (see next figure). UCTE Interconnected Network Transmission and Distribution Network UCTE Operation Handbook ! Rules for Interconnection GridCodes / Laws / Contracts ! Rules for Grid Access ... "I–8 UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) F. Basic structure of the Operation Handbook The “UCTE Operation Handbook” clearly differentiates between policies, technical appendices, training documents and data collections (in independent documents) and is basically structured as follows: • Preface, general information (UCTE history, organisation,...) • Introduction, overview, table of contents, versions, basics, operational framework, procedures • Glossary of terms, acronyms • Operating policies (common structure, list of policies for transmission and ANCILLARY SERVICES) • Technical appendices (technical criteria, definitions) • Training documents (calculation methods, theory) • Collections of data The formal structure of the operation handbook into policies and appendices, each document with chapters and sections, is shown in the following figure. UCTE Operation Handbook Policy x • Chapter y • Sections z • ... • ... Appendix x • Chapter y • Sections w • ... • ... ... ... The policies themselves have a clear policy-internal structure of standards, rules, criteria, requirements, rights and obligations. The table of all policies can be found in section #I. The policies of the operation handbook themselves are organised in the following main sections: • Criteria (C). Criteria introduce or define specific values or a specific naming as given facts, that may be used or cited within the policy. • Requirements (R). Requirements are (technical or organisational) prerequisites that are used within a policy. They have to be fulfilled in total before any standard can be applied. • Standards (S). Standards define rules that are fixed and binding for the addressees, subject to the specific situation. Standards are usually the core part of a policy. • Guidelines (G). Guidelines describe practical ways for typical operation or usage as recommendations, as they may be used by the addressees. • Procedures (P). Procedures introduce fixed methods and alternatives for operation or usage as common practice. • Measures (M). Measures name the actions to be taken, e.g. if a requirement is not fulfilled, a standard is violated by an addressee or a procedure is not used. UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) G. "I–9 Guide for handbook readers The operation handbook makes use of the following internal reference schemes: $document [-chapter [-section]] #chapter [-section] "document – page The following examples show how to read the references in the documents: • “$P1” and “$A1” are used as references to the policy or appendix with number 1. Other documents are usually referred to by a single letter, e.g. the introduction by $I. • “$P1-A” is used as reference to the chapter A of Policy 1 (within Policy 1 the reference can also be “#A” only). • “$P1-A-C1” is used as reference to the first criterion of section A in policy 1. The same scheme is used for requirements, standards, guidelines, procedures and measures. • Pages are numbered by the document identifier (“P1” for Policy 1) followed by the page number, e.g. “"P1-8” is the reference to page 8 of Policy 1. According to the basic structure of the UCTE Operation Handbook, the following rough guide for readers can be given: • As a good starting point, it is recommended to start reading with this introduction document ($I). Basic principles and frameworks for the complete handbook are described here in detail. Moreover, the introduction includes the full table of operation policies that are part of the handbook. • The glossary of terms ($G) needs to be consulted as a reference only. All terms that are formatted in CAPITALISED letters can be found in the glossary of terms. In case of unknown terms, acronyms or units please refer here for definitions and explanations. • For reading a policy (policies are numbered by #) it is recommended to start with the introduction of the policy and to consult the corresponding appendices ($A#), before reading the requirements, standards and guidelines. The appendices usually give a general motivation and technical description of the subjects, that is required for reading the policies. • The policies themselves ($P#) are organised in independent chapters (starting with A), each of them in sections (identified by letters C, R, S, G, P and M, see above) with numbered paragraphs. Before reading and understanding a policy it is necessary to have background knowledge on the subjects. There is no definite way how to read a policy, usually it is best to start at the beginning. Internal references may point to other paragraphs of this policy before or after the current paragraph, external references may point to other policies or appendices as well. For easy reading, the first pages of policies and appendices are commonly organised in the following layout: UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) P# – Policy #: Title [Level] Chapters A. B. C. Chapter A Chapter B Chapter C Introduction Introduction … History of changes v#.# draft 01.12.2003 Current Status Status information … General notices … developer changes… "I–10 UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) H. "I–11 Procedure for handbook development Following is the description of the development process procedure with the flow chart showing the procedure. The Operation Handbook development process involves following steps: 1. Process initiation 2. Drafting stage 3. Internal consultation 4. Decisions on external consultation 5. External consultation 6. Final approval 7. Policy implementation STEP 1 Process initiation Requests to revise or develop the Policy are submitted to the Steering Committee by the Working Group Operations and Security (WG OS) with a short description of the Policy to be revised or drafted newly. Alternatively, the process is initiated by the Steering Committee. The Steering Committee approves the Policy for development or revision or rejects the request. For each Policy Steering Committee sets a clear deadline for the drafting and revision stage of the process. STEP 2 Drafting stage Once the Policy is accepted for development or revision the WG OS then assigns the request to a Drafting Team which prepares the table of contents and a 1st draft of new or revised Policy. Then the Drafting Team presents the 1st draft for internal consultation. STEP 3 Internal consultation Comments on the 1st draft will be solicited only from UCTE Members (TSOs). Comments can be sent only by using consultation forum on the UCTE website till the date announced by UCTE Secretariat. The minimum period for internal consultation is 1 month. Based on the comments, the Drafting Team prepares the 2nd draft of the Policy. STEP 4 Decisions on external consultation The 2nd draft is the subject of WG OS and corresponding Steering Committee approval for presenting it for external consultation. The bodies can approve the draft Policy for the external consultation or return it for further work to the Drafting Team with a clear statement on how to proceed and what to adapt. STEP 5 External consultation Once the Policy is approved by the Steering Committee for the external consultation, it is published on the UCTE website and the external consultation process starts. The consultation period lasts 4 - 8 weeks with respect to the extent of the Policy. Duration of the consultation process will be determined by the WG OS or UCTE Secretariat. Comments on the 2nd draft will be actively solicited from all registered participants. Comments will be accepted only on-line using an internet-based consultation forum. All UCTE members will have to substantiate their position, i.e. that also those who do not want to comment will have UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) "I–12 to state it. Based on its own review, the Drafting Team revises the draft Policy as needed and presents it to the WG OS. STEP 6 Final approval WG OS approves the Policy and sends the final draft including change marks and for information list of rejected comments to the Steering Committee for final approval. If the WG OS does not approve the Policy, it may return the draft to the Drafting Team for further work with a clear statement on how to proceed and what to adapt. As a rule, the Steering Committee will put the proposed Policy at its next meeting’s agenda. If the Policy is not approved, the Steering Committee may return the Policy to the Drafting Team for further work with a clear statement on what to adapt or it may terminate the Policy development. STEP 7 Policy implementation Once the Steering Committee approves a new or modified Policy all members are expected to implement and follow the Policy in accordance with all accepted UCTE rule. "I–13 UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) Requests, modifications WG “Operations & Security” Decision STEP 1 Requests, modifications UCTE Steering Committee Decision Rejection For development STEP 2 Table of contents / topics [A] Development 1st Draft of new Standard [B] Drafting Team STEP 3 Internal consultation UCTE Secretariat&Drafting Team 2nd Draft of new Standard [C] WG “Operations & Security” Revision STEP 4 Decision 2nd Draft of new Standard [C] UCTE Steering Committee Revision Decision Rejection For external consultation STEP 5 External consultation UCTE Secretariat&Drafting Team Final Draft of new Standard [D] WG “Operations & Security” STEP 6 Decision Final Draft of new Standard [D] UCTE Steering Committee Revision Decision For implementation STEP 7 Final new UCTE Standard [E] UCTE Operation Handbook UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) "I–14 The status of policies and appendices during procedure is rated according to the following legend: Level A B C D E Description Table of contents Preliminary internal draft Consultation draft Final draft ready for approval by the WG and SC Approved new UCTE Standard. Process roles: Steering Committee is the executive directing body of UCTE: It: • • • approves the Policy for development approves the 2nd draft for external consultation makes a final approval of the Policy Working Group Operations&Security is the body responsible for overseeing the Operation Handbook development process. It: • • • • • • initiates the process of Policies development or revision assigns the Drafting Team and nominates the DT leader sets deadlines for development, revision and consultation periods actively participate in the internal and external consultation process approves and presents the 2nd draft to SC for approval for external consultation approves the final draft and presents it for SC final approval Drafting Team is a team of technical experts that develops the detail of the Policy. It: • • • • • • prepares the table of contents and first draft of the Policy presents the draft for internal consultation considers and responds to comments (with UCTE Secretariat support) revise the draft after internal consultation presents the draft to WG OS for approval for external consultation revise the draft after external consultation UCTE Secretariat administers the OH development process. It: " ensures the integrity of the development process " ensures consistency of quality and completeness of the OH " structures the consultation process " monitors and guide the web-based consultation forum " publish documents (including layouting according to corporate identity) " supports the Drafting Teams " reports to WG OS on the development progress UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) I. "I–15 Table of Handbook Policies and Appendices The following tables of contents list all existing and planned policies /appendices / documents of the UCTE Operation Handbook with their individual table of contents. General part: ID Title, contents I Introduction A. UCTE’s basic needs for the Operation Handbook B. Target audience for the Operation Handbook C. Main characteristics of the Operation Handbook D. Main scope of the Operation Handbook E. Basic structure of the Operation Handbook F. Guide for handbook readers G. Procedure for handbook development H. Table of handbook policies and appendices I. UCTE system overview J. Contacts and links G Glossary A. Glossary of Terms B. List of Acronyms C. List of Units Policies: ID Title, contents P1 Load-Frequency-Control and Performance A. Primary Control B. Secondary Control C. Tertiary Control D. Time Control E. Measures for Emergency Conditions P2 Scheduling and Accounting A. Scheduling B. Online Observation C. Accounting P3 Operational Security A. N-1 Security (operational planning and real-time operation) B. Voltage control and reactive power management C. Network faults clearing and short circuit currents D. Stability E. Outages scheduling F. Information exchanges between TSOs for security of system operation P4 Co-ordinated Operational Planning A. Outage Scheduling UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) B. C. D. E. Capacity Assessment Capacity Allocation Day Ahead Congestion Forecast Congestion Management P5 Emergency Procedures P6 Communication Infrastructure A. The EH Network, Architecture and Operation B. Real Time Data Collection and Exchange C. File Transfer data Exchange D. E-Mail on the Electronic Highway E. Information Publication in Hyptertext on EH F. Procedures for future Services on EH G. Non-EH communication among TSOs P7 Data Exchanges A. Code of conduct and generic rules to handle the data P8 Operational Training Appendixes: ID Title, contents A1 Load-Frequency-Control and Performance A. Primary Control B. Secondary Control C. Tertiary Control D. Time Control E. Measures for Emergency Conditions A2 Scheduling and Accounting A. Scheduling of Power Exchange B. Online Observation of Power Exchange C. Accounting of Unintentional Deviations "I–16 UCTE Operation Handbook – Introduction (final v2.5 E, 24.06.2004) J. Contacts and Links For questions concerning Operation Handbook development process and consultation process please contact Jakub Fijalkowski at [email protected]. For all other information, please contact the UCTE-Secretariat: 15 Boulevard Saint-Michel 1040 Brussels Belgium Tel: +32 2 741 69 40 Fax: +32 2 741 69 49 E-mail: [email protected] "I–17 GLOSSARY G – Glossary [E] Chapters A. B. C. Glossary of terms List of acronyms List of units History of changes v2.2 v2.1 v2.0 draft draft draft 24.06.2004 12.05.2004 01.03.2004 UCTE Secreteriat UCTE Secretariat OpHB-Team glossary update new terms added minor changes, linguistic review Current status This glossary is a growing list of terms1, acronyms and units commonly used in the policies and appendices of the Operation Handbook. In order to identify common terms of this glossary when used in any document, all terms listed in this glossary shall be formatted in a “CAPITALISED” manner (but not written in capital letters). This version of the document (version 2.2, level E, dated 24.06.2004) has “final ” status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. 1 : Additional terms to be included shall be submitted to the UCTE secretariat ([email protected]) or to the secretary of the UCTE WG Operations & Security ([email protected]). !G–2 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) A. Glossary of terms [UCTE ground rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] [Articles of association of the UCTE, 2001] [NERC glossary of terms, 08.1996, ETSO Definitions of Transfer Capacities in liberalised Electricity Markets, 2001] Term (Acronym) {Synonym} ("References) Definition / explanation, CROSS-REFERENCE. Accounting {Energy ~, ~ of Unintentional Deviations} ("P2) After the EXCHANGE PROGRAMS have been validated during the scheduling phase, and taking into account the real-time observation of UNINTENTIONAL DEVIATIONS across a set of OBSERVATION LINES, ACCOUNTING is the organisational process implemented in order to: • collect the provisional and the final values of the exchanged energy for each time interval; • determine the UNINTENTIONAL DEVIATIONS of energy and set-up the corresponding COMPENSATION PROGRAMS for their offsetting during the following week. Accounting Co-ordination ("P2) ACCOUNTING CO-ORDINATION means a co-ordination service provided to the CONTROL BLOCKS, by the sites in charge of performing the ACCOUNTING CO-ORDINATION for the purpose of carrying out the ACCOUNTING. It consists of the following phases: • acquisition and validation of the EXCHANGE PROGRAMS between the CONTROL BLOCKS during the scheduling phase; • acquisition of the EMRs’ values of TIE-LINES2 among CONTROL BLOCKS to compute the provisional energy exchanges; • real-time observation across the previously defined OBSERVATION LINES; • computation of the provisional and final UNINTENTIONAL DEVIATIONS; • computation of the COMPENSATION PROGRAMS for each CONTROL BLOCK. If these tasks are performed at different locations, a very close co-operation must be ensured among the centres responsible for these activities. Responsibility for correct ACCOUNTING remains with the co-ordinators of the individual CONTROL BLOCKS and CONTROL AREAS. Responsibility for this matter cannot be delegated to the ACCOUNTING COORDINATION. The CONTROL BLOCKS and CONTROL AREAS are responsible for the resources required to provide the results of the ACCOUNTING. In order to be able to monitor and supervise the operation of their CONTROL BLOCK or CONTROL AREA, they all need to be equipped with a real-time data acquisition system. The ACCOUNTING CO-ORDINATION is provided with the necessary data to enable some checking at a global level and to give extra confirmation to the co-ordinators of the CONTROL BLOCKS and CONTROL AREAS that no major mistake has gone undetected or that, if such an error should occur, it would not stay undetected for a long time. Active Power ACTIVE POWER is a real component of the apparent power, usually expressed in kilowatts (kW) or megawatts (MW), in contrast to REACTIVE POWER. 2 Including virtual TIE-LINES that may exist for the operation of jointly owned power plants. !G–3 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Adjacent Control Area {Adjacent System} ("P1-B) An ADJACENT CONTROL AREA (or ADJACENT SYSTEM) is any CONTROL AREA (or system) either directly interconnected with or electrically close to (so as to be significantly affected by the existence of) another CONTROL AREA (or system). ("P1) Ancillary Services ANCILLARY SERVICES are Interconnected Operations Services identified as necessary to effect a transfer of electricity between purchasing and selling entities (TRANSMISSION) and which a provider of TRANSMISSION services must include in an open access transmission tariff. Apparent Power APPARENT POWER is the product of voltage (in volts) and current (in amperes). It consists of a real component (ACTIVE POWER) and an imaginary component (REACTIVE POWER), usually expressed in kilovolt-amperes (kVA) or megavolt-amperes (MVA). Already Allocated Capacity (AAC) The ALREADY ALLOCATED CAPACITY is the total amount of allocated transmission rights, whether they are capacity or EXCHANGE PROGRAMS depending on the allocation method. Area Control Error (ACE) ("P1-B) The AREA CONTROL ERROR is the instantaneous difference between the actual and the reference value (measured total power value and scheduled CONTROL PROGRAM) for the power interchange of a CONTROL AREA (UNINTENTIONAL DEVIATION), taking into account the effect of the FREQUENCY BIAS for that CONTROL AREA according to the NETWORK POWER FREQUENCY CHARACTERISTIC of that CONTROL AREA and the overall FREQUENCY DEVIATION. Automatic Generation Control (AGC) ("P1-B) AUTOMATIC GENERATION CONTROL is an equipment that automatically adjusts the generation to maintain its generation dispatch, interchange schedule plus its share of frequency regulation. AGC is a combination of SECONDARY CONTROL for a CONTROL AREA / BLOCK and real-time operation of the generation dispatch function (based on generation scheduling). SECONDARY CONTROL is operated by the TSO, generation scheduling is operated by the respective generation companies (GENCOs). Availability AVAILABILITY is a measure of time during which a generating unit, transmission line, ANCILLARY SERVICE or another facility is capable of providing service, whether or not it actually is in service. Typically, this measure is expressed as a percentage available for the period under consideration. Available Transfer Capacity (ATC) AVAILABLE TRANSFER CAPACITY is a measure of the transfer capability remaining in the physical TRANSMISSION network for further commercial activity over and above already committed uses. AVAILABLE TRANSMISSION CAPACITY is the part of NTC that remains available after each phase of the allocation procedure for further commercial activity. ATC is defined by the following equation: ATC = NTC- AAC !G–4 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Black-start Capability ("P3, "P5) BLACK-START CAPABILITY is the ability of a generating unit to go from a shutdown condition to an operating condition and start delivering power without assistance from the electric system. Capacity CAPACITY is the rated continuous load-carrying ability of generation, transmission, or other electrical equipment, expressed in megawatts (MW) for ACTIVE POWER or megavolt-amperes (MVA) for APPARENT POWER. Compensation program Compensation of UNINTENTIONAL DEVIATIONS is performed by exporting to / importing from the interconnected system during the compensation period by means of schedules of constant power within the same tariff periods as when they occurred (COMP). Consumption See: DEMAND Contingency ("P3) CONTINGENCY is the unexpected failure or outage of a system component, such as a generator, transmission line, circuit breaker, switch, or other electrical element. A CONTINGENCY also may include multiple components, which are related by situations leading to simultaneous component outages. Control Area (CA) ("P1-B) A CONTROL AREA is a coherent part of the UCTE INTERCONNECTED SYSTEM (usually coincident with the territory of a company, a country or a geographical area, physically demarcated by the position of points for measurement of the interchanged power and energy to the remaining interconnected network), operated by a single TSO, with physical loads and controllable generation units connected within the CONTROL AREA. A CONTROL AREA may be a coherent part of a CONTROL BLOCK that has its own subordinate control in the hierarchy of SECONDARY CONTROL. Control Block (CB) ("P1-B) A CONTROL BLOCK comprises one or more CONTROL AREAS, working together in the SECONDARY CONTROL function, with respect to the other CONTROL BLOCKS of the SYNCHRONOUS AREA it belongs to. Control Area Operator ("P2) A CONTROL AREA OPERATOR is the operator of a CONTROL AREA usually a TSO. Control Block Operator ("P2) The BLOCK OPERATOR is a single TSO that is responsible for SECONDARY CONTROL of the whole CONTROL BLOCK towards its interconnected neighbours / blocks, for ACCOUNTING of all CONTROL AREAS of that block, for organisation of the internal SECONDARY CONTROL within the block, and that operates the overall control of that block. !G–5 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Control Program (CP) ("P1-B, "P2) A CONTROL PROGRAM constitutes the SCHEDULE of the total programmed exchange of a CONTROL AREA / BLOCK, the sum of all EXCHANGE PROGRAMS and the COMPENSATION PROGRAM, that is used for SECONDARY CONTROL. Co-ordination centre (CC) The CO-ORDINATION CENTRE is responsible for acquiring and validating the EXCHANGE PROGRAMMES among the CONTROL BLOCKS during the scheduling phase, acquiring the energy meter readings values of TIE-LINES among the CONTROL BLOCKS to compute the UNINTENTIONAL DEVIATIONS and the COMPENSATION PROGRAM to be carried out the following week in order to offset said UNINTENTIONAL DEVIATIONS. This task is shared among the CO-ORDINATION CENTRES UCTE North in Brauweiler and UCTE South in Laufenburg. Curtailment CURTAILMENT means a reduction in the scheduled capacity or energy delivery. ("P5) Defence Plan The DEFENCE PLAN summarises all technical and organisational measures taken to prevent the propagation or deterioration of a power system incident in order to avoid a collapse. Demand {Consumption} is the rate at which electric power is delivered to or by a system or part of a system, generally expressed in kilowatts (kW) or megawatts (MW), at a given instant or averaged over any designated interval of time. DEMAND should not be confused with LOAD (a LOAD is usually a device). DEMAND Disturbance DISTURBANCE is an unplanned event that produces an abnormal system condition. Droop of a Generator ("P1-A, "A1-A) The DROOP OF A GENERATOR is one of the parameters set on the primary speed controller of a GENERATING SET (generator and turbine). It is equal to the quotient of the relative quasi-steady-state FREQUENCY OFFSET on the network and the relative variation in power output from the generator associated with the action of the PRIMARY CONTROLLER. This ratio without dimension is generally expressed as a percentage. Electrical Energy ELECTRICAL ENERGY is a measure of the generation or use of electric power by a device integrated over a period of time; it is expressed in kilowatt-hours (kWh), megawatt-hours (MWh), or gigawatt-hours (GWh). Electric System Losses ELECTRIC SYSTEM LOSSES are total electric energy losses in the electric system. The losses consist of TRANSMISSION, transformation, and distribution losses between supply sources and delivery points. Electric energy is lost primarily due to heating of transmission and distribution elements. !G–6 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) ("P6) Electronic Highway (EH) The ELECTRONIC HIGHWAY represents a secure, fast, reliable and highly available communication infrastructure for real-time and non-real-time data exchanges between TSOs. ("P2) Energy Meter Readings (EMRs) ENERGY METER READINGS are performed (in addition to those for internal lines, transformers, generators and LOADS) for actual energy exchanges on TIE-LINES3 between CONTROL BLOCKS (of CONTROL AREAS) to carry out the ACCOUNTING function (e.g.: to compute, together with scheduled exchanges, the UNINTENTIONAL DEVIATIONS for each time interval). ("P2) Exchange Program (CAX, CBX) An EXCHANGE PROGRAM represents the total scheduled energy interchange between two CONTROL AREAS (CAX) OR BETWEEN CONTROL BLOCKS (CBX). ("P2) Exchange Schedule (CAS, CBS) An EXCHANGE SCHEDULE defines an agreed transaction with regard to its size (megawatts), start and end time, RAMP PERIOD and type (e.g. firmness); it is required for delivery and receipt of power and energy between the contracting parties and the CONTROL AREA(S) (CAS) or between control areas and control blocks (CBS) involved in the transaction. Frequency see: SYSTEM FREQUENCY Frequency Bias see: NETWORK POWER FREQUENCY CHARACTERISTIC Frequency Control See: PRIMARY CONTROL. ("P1) Frequency Deviation FREQUENCY DEVIATION means a departure of the actual SYSTEM FREQUENCY from the set value frequency. Frequency Offset ("P1-D) FREQUENCY OFFSET is the difference between the actual and the nominal value of the SYSTEM FREQUENCY in order to correct the SYNCHRONOUS TIME (TIME CONTROL); it is not identical with FREQUENCY DEVIATION. Generation is the rate at which a GENERATION SET delivers electric power to a system or part of a system, generally expressed in kilowatts (kW) or megawatts (MW), at a given instant or averaged over any designated interval of time, see also: DEMAND. GENERATION 3 Including virtual tie-lines that may exist for the operation of jointly owned power plants. !G–7 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) ("P1) Generation Set A GENERATION SET is a set of machines consisting of a generator (and its driving apparatus) and a turbine of a generation unit. Inadvertent Deviation see UNINTENTIONAL DEVIATION. Interconnected System An INTERCONNECTED SYSTEM is a system consisting of two or more individual electric systems that normally operate in synchronism and are physically connected via TIE-LINES, see also: SYNCHRONOUS AREA. Interconnection An INTERCONNECTION is a transmission link (e.g. TIE-LINE or transformer) which connects two CONTROL AREAS. Intra-Control-Area Transaction An INTRA-CONTROL-AREA TRANSACTION is a transaction carried out from one or more generating sources to one or more delivery points where all the sources and delivery points are entirely located within the metered boundaries of the same CONTROL AREA. Island ("P1) An ISLAND represents a portion of a power system or of several power systems that is electrically separated from the main INTERCONNECTED SYSTEM (separation resulting e.g. from the disconnection / failure of transmission system elements). K-Factor ("P1-B) The K-FACTOR is a value, usually given in megawatts per Hertz (MW/Hz), which is normally determined for a (single) CONTROL AREA / BLOCK; it defines the FREQUENCY BIAS of that CONTROL AREA for SECONDARY CONTROL (especially to assure the functionality of the NETWORK CHARACTERISTIC METHOD); it is not to be confused with the NETWORK POWER FREQUENCY CHARACTERISTIC. Load LOAD means an end-use device or customer that receives power from the electric system. LOAD should not be confused with DEMAND, which is the measure of power that a load receives or requires. LOAD is often wrongly used as a synonym for DEMAND. Load-Frequency Control (LFC) See: SECONDARY CONTROL Load-Shedding ("P1, "P3) LOAD-SHEDDING is the disconnection of LOAD from the synchronous electric system, usually performed automatically, to control the SYSTEM FREQUENCY in emergency situations. UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) !G–8 Loop Flows See: PARALLEL PATH FLOWS. Metering METERING describes the methods of applying devices that measure and register the amount and direction of electrical quantities with respect to time. Minute Reserve {15 Minute Reserve} See: TERTIARY CONTROL RESERVE N-1 Criterion ("P3) The N-1 CRITERION is a rule according to which elements remaining in operation after failure of a single network element (such as transmission line / transformer or generating unit, or in certain instances a busbar) must be capable of accommodating the change of flows in the network caused by that single failure. Net Transfer Capacity (NTC) The NET TRANSFER CAPACITY is defined as: NTC = TTC-TRM The NET TRANSFER CAPACITY is the maximum total EXCHANGE PROGRAM between two ADJACENT CONTROL AREAS compatible with security standards applicable in all CONTROL AREAS of the SYNCHRONOUS AREA, and taking into account the technical uncertainties on future network conditions. Network Characteristic Method ("P1-B) The properties required for SECONDARY CONTROL are produced by the NETWORK CHARACTERISTIC METHOD. The purpose of SECONDARY CONTROL is to move the overall FREQUENCY DEVIATION and POWER DEVIATION of the CONTROL AREA / BLOCK considered towards zero. The NETWORK CHARACTERISTIC METHOD (to be applied to all CONTROL AREAS in the same way and at the same time) assures the control of two variables at the same time with one set-point value, as long as the NETWORK POWER FREQUENCY CHARACTERISTIC is used. Network Power Frequency Characteristic ("P1-B, "A1-A) The NETWORK POWER FREQUENCY CHARACTERISTIC defines the sensitivity, given in megawatts per Hertz (MW/Hz), usually associated with a (single) CONTROL AREA / BLOCK or the entire SYNCHRONOUS AREA, that relates the difference between scheduled and actual SYSTEM FREQUENCY to the amount of generation required to correct the power imbalance for that CONTROL AREA / BLOCK (or, vice versa, the stationary change of the SYSTEM FREQUENCY in case of a disturbance of the generation-load equilibrium in the CONTROL AREA without being connected to other CONTROL AREAS); it is not to be confused with the K-FACTOR. The NETWORK POWER FREQUENCY CHARACTERISTIC includes all active PRIMARY CONTROL and SELF-REGULATION OF LOAD and changes due to modifications in the generation pattern and the DEMAND. Observation Line ("P2) An OBSERVATION LINE is a conventional border line separating a part of the SYNCHRONOUS ZONE from the rest of the system for the purpose of real-time error detection and preliminary calculation of UNINTENTIONAL DEVIATIONS. It must run along the borders of CONTROL BLOCKS and must not split any CONTROL BLOCK. !G–9 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Offsetting of Unintentional Deviations ("P2) OFFSETTING OF UNINTENTIONAL DEVIATIONS describes a procedure applied to carry out the compensation in energy of UNINTENTIONAL DEVIATIONS through a corresponding energy EXCHANGE SCHEDULE; the energy is to be delivered to (or imported from) the rest of the system during the following week according to the standards. Observation of Unintentional Deviations The on-line OBSERVATION OF UNINTENTIONAL DEVIATIONS is performed in an autonomous and independent way by each CONTROL BLOCK according to the standards established. A second level exists through real-time observation of UNINTENTIONAL DEVIATIONS across previously defined OBSERVATION LINES. This function allows to improve the detection, as early as possible, of any error concerning on-line telemeasurements (TMs), any misunderstanding which may occur in setting the EXCHANGE PROGRAMS, etc., in order to implement without delay the appropriate corrective actions. This function may be performed in one or more locations which must then closely co-operate . Operating Policies OPERATING POLICIES constitute the doctrine developed for INTERCONNECTED SYSTEMS operation; they form the main part of the Operation Handbook. Each doctrine consists of criteria, standards, requirements, guides, and instructions, and applies to all CONTROL AREAS / BLOCKS / TSOS. Operating Procedures OPERATING PROCEDURES are a set of policies, practices, or system adjustments that may be automatically or manually implemented by the system operator within a specified time frame to maintain the operational integrity of the INTERCONNECTED SYSTEMS. Parallel Path Flows {loop flows, circulating power flows, unscheduled power flows} PARALLEL PATH FLOWS describe the difference between the scheduled and actual power flow, assuming zero inadvertent interchange, on a given transmission path in a meshed grid. Power System The POWER SYSTEM comprises all generation, consumption and network installations interconnected through the network. Power Deviation ("P1) A POWER DEVIATION is a power deficit (negative value) or a surplus (positive value) in a CONTROL AREA / BLOCK of the SYNCHRONOUS AREA4, usually measured at the borders of the area, with respect to the CONTROL PROGRAM. Primary Control {Frequency Control, Primary Frequency Control} ("P1-A, "A1-A) PRIMARY CONTROL maintains the balance between GENERATION and DEMAND in the network using turbine speed governors. PRIMARY CONTROL is an automatic decentralised function of the turbine 4 Power exchanges over DC-connections are not included in the calculation of the power deviation, they are considered to be either an injection or a load in the CONTROL AREA connected. !G–10 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) governor to adjust the generator output of a unit as a consequence of a FREQUENCY DEVIATION / OFFSET in the SYNCHRONOUS AREA: • PRIMARY CONTROL should be distributed as SYNCHRONOUS AREA; evenly as possible over units in operation in the • the global PRIMARY CONTROL behaviour of an interconnection partner (CONTROL AREA / BLOCK), may be assessed by the calculation of the equivalent droop of the area (basically resulting from the DROOP OF ALL GENERATORS and the SELF-REGULATION OF THE TOTAL DEMAND). By the joint action of all interconnected undertakings, PRIMARY CONTROL ensures the operational reliability for the power system of the SYNCHRONOUS AREA. Primary Control Power ("P1-A) PRIMARY CONTROL POWER is the power output of a GENERATION SET due to PRIMARY CONTROL. Primary Control Range ("P1-A) The PRIMARY CONTROL RANGE is the range of adjustment of PRIMARY CONTROL POWER, within which PRIMARY CONTROLLERS can provide automatic control, in both directions, in response to a FREQUENCY DEVIATION. The concept of the PRIMARY CONTROL RANGE applies to each generator, each CONTROL AREA / BLOCK, and the entire SYNCHRONOUS AREA. Primary Control Reserve ("P1-A) The PRIMARY CONTROL RESERVE is the (positive / negative) part of the PRIMARY CONTROL RANGE measured from the working point prior to the disturbance up to the maximum PRIMARY CONTROL POWER (taking account of a limiter). The concept of the PRIMARY CONTROL RESERVE applies to each generator, each CONTROL AREA / BLOCK, and the entire SYNCHRONOUS AREA. Primary Controller ("P1-A) The PRIMARY CONTROLLER is a decentralised / locally installed control equipment for a GENERATION SET to control the valves of the turbine based on the speed of the generator (for synchronous generators directly coupled to the electric SYSTEM FREQUENCY); see PRIMARY CONTROL. The insensitivity of the PRIMARY CONTROLLER is defined by the limit frequencies between which the controller does not respond. This concept applies to the complete primary controller-generator unit. A distinction is drawn between unintentional insensitivity associated with structural inaccuracies in the unit and a dead band set intentionally on the controller of a generator. Primary Frequency Control See: PRIMARY CONTROL Pseudo-Tie-Line See: VIRTUAL TIE-LINE. Reactive Power REACTIVE POWER is an imaginary component of the apparent power. It is usually expressed in kilo-vars (kVAr) or mega-vars (MVAr). REACTIVE POWER is the portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment. REACTIVE POWER must be supplied to most types of magnetic equipment, such as motors and transformers and causes reactive losses on transmission facilities. REACTIVE POWER is provided by generators, synchronous condensers, or electrostatic equipment such as capacitors, and directly influences the electric system voltage. The REACTIVE POWER is the imaginary part of the complex product of voltage and current. UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Ramp Period !G–11 ("P1-B) The RAMP PERIOD is the time between ramp start and end times, usually expressed in minutes and applied to SCHEDULES. Reliability5 ("P3) RELIABILITY describes the degree of performance of the elements of the bulk electric system that results in electricity being delivered to customers within accepted standards and in the amount desired. RELIABILITY on the transmission level may be measured by the frequency, duration, and magnitude (or the probability) of adverse effects on the electric supply / transport / generation. Electric system RELIABILITY can be addressed by considering two basic and functional aspects of the electric system: • Adequacy — The ability of the electric system to supply the aggregate electrical demand and energy requirements of the customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. • Security — The ability of the electric system to withstand sudden disturbances such as electric short circuits or unanticipated loss of system elements. Secondary Control {Load-Frequency-Control} ("P1-B, "A1-B) SECONDARY CONTROL is a centralised automatic function to regulate the generation in a CONTROL AREA based on SECONDARY CONTROL RESERVES in order • to maintain its interchange power flow at the CONTROL PROGRAM with all other CONTROL AREAS (and to correct the loss of capacity in a CONTROL AREA affected by a loss of production) and, at the same time, • (in case of a major FREQUENCY DEVIATION originating from the CONTROL AREA, particularly after the loss of a large generation unit) to restore the frequency in case of a FREQUENCY DEVIATION originating from the CONTROL AREA to its set value in order to free the capacity engaged by the PRIMARY CONTROL (and to restore the PRIMARY CONTROL RESERVES). In order to fulfil these functions, SECONDARY CONTROL operates by the NETWORK CHARACTERISTIC METHOD. SECONDARY CONTROL is applied to selected generator sets in the power plants comprising this control loop. SECONDARY CONTROL operates for periods of several minutes, and is therefore dissociated from PRIMARY CONTROL. This behaviour over time is associated with the PI (proportional-integral) characteristic of the SECONDARY CONTROLLER. Secondary Control Range ("P1-B) The SECONDARY CONTROL RANGE is the range of adjustment of the secondary control power, within which the SECONDARY CONTROLLER can operate automatically, in both directions at the time concerned, from the working point of the secondary control power. Secondary Control Reserve ("P1-B) The positive / negative SECONDARY CONTROL RESERVE is the part of the SECONDARY CONTROL RANGE between the working point and the maximum / minimum value. The portion of the SECONDARY CONTROL RANGE already activated at the working point is the SECONDARY CONTROL POWER. Secondary Controller ("P1-B) A SECONDARY CONTROLLER is the single centralised TSO-equipment per CONTROL AREA / BLOCK for operation of SECONDARY CONTROL. 5 To a great extent, the overall RELIABILITY of the electric power supply (for customers being connected to the distribution grid), that is usually measured, is defined by the RELIABILITY of the power distribution instead of the transmission or generation. !G–12 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) ("P3) Security Limits {Operating Security Limits} SECURITY LIMITS define the acceptable operating boundaries (thermal, voltage and stability limits). The TSO must have defined SECURITY LIMITS for its own network. The TSO shall ensure adherence to these SECURITY LIMITS. Violation of SECURITY LIMITS for prolonged time could cause damage and/or an outage of another element that can cause further deterioration of system operating conditions. Self-Regulation of Load ("P1-A) The SELF-REGULATION OF LOAD is defined as the sensitivity of consumers’ demand to variations in the SYSTEM FREQUENCY (a decrease of the SYSTEM FREQUENCY results in a decrease of the LOAD), generally expressed in % / Hz. ("P3) Stability STABILITY is the ability of an electric system to maintain a state of equilibrium during normal and abnormal system conditions or disturbances. • Small-Signal Stability — The ability of the electric system to withstand small changes or disturbances without the loss of synchronism among the synchronous machines in the system while having a sufficient damping of system oscillations (sufficient margin to the border of stability). • Transient Stability — The ability of an electric system to maintain synchronism between its parts when subjected to a disturbance of specified severity and to regain a state of equilibrium following that disturbance. Supervisory Control and Data Acquisition (SCADA) SUPERVISORY CONTROL AND DATA ACQUISITION is a system of remote control and telemetry used to monitor and control the electric system. Synchronous Area ("P1) A SYNCHRONOUS AREA is an area covered by INTERCONNECTED SYSTEMS whose CONTROL AREAS are synchronously interconnected with CONTROL AREAS of members of the association. Within a SYNCHRONOUS AREA the SYSTEM FREQUENCY is common on a steady state. A certain number of SYNCHRONOUS AREAS may exist in parallel on a temporal or permanent basis. A SYNCHRONOUS AREA is a set of synchronously INTERCONNECTED SYSTEMS that has no synchronous interconnections to any other INTERCONNECTED SYSTEMS, see also: UCTE SYNCHRONOUS AREA. Synchronous Time ("P1-D) SYNCHRONOUS TIME is the fictive time based on the SYSTEM FREQUENCY in the SYNCHRONOUS AREA, once initialised on UTC time and with the clock frequency being 60/50 of the SYSTEM FREQUENCY. If the SYNCHRONOUS TIME is ahead / behind of the UTC time (TIME DEVIATION), the SYSTEM FREQUENCY has on average been higher / lower than the nominal frequency of 50 Hz. TIME CONTROL action will return a TIME DEVIATION to zero again. System Frequency {Frequency} ("P1, "A1-A) SYSTEM FREQUENCY is the electric frequency of the system that can be measured in all network areas of the SYNCHRONOUS AREA under the assumption of a coherent value for the system in the time frame of seconds (with minor differences between different measurement locations only). !G–13 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) Tertiary Control ("P1-C, "A1-C) TERTIARY CONTROL is any (automatic or) manual change in the working points of generators (mainly by re-scheduling), in order to restore an adequate SECONDARY CONTROL RESERVE at the right time. ("P1-C) Tertiary Control Reserve {Minute Reserve} The power which can be connected (automatically or) manually under TERTIARY CONTROL, in order to provide an adequate SECONDARY CONTROL RESERVE, is known as the TERTIARY CONTROL RESERVE or MINUTE RESERVE. This reserve must be used in such a way that it will contribute to the restoration of the SECONDARY CONTROL RANGE when required. The restoration of an adequate SECONDARY CONTROL RANGE may take, for example, up to 15 minutes, whereas TERTIARY CONTROL for the optimisation of the network and generating system will not necessarily be complete after this time. ("P1) Tie-Line A TIE-LINE is a circuit (e.g. a transmission line) connecting two or more CONTROL AREAS or systems of an electric system. ("P1-D) Time Deviation The TIME DEVIATION normally is the time integral of the FREQUENCY DEVIATION. In practice, an electrical clock that follows the SYSTEM FREQUENCY is compared with the astronomical time (UTC). Time Control ("P1-D, "A1-D) TIME CONTROL is a control action carried out to return an existing TIME DEVIATION between SYNCHRONOUS TIME and UTC time to zero. Total Transfer Capacity (TTC) TOTAL TRANSFER CAPACITY is the maximum EXCHANGE PROGRAM between two ADJACENT CONTROL AREAS that is compatible with operational security standards applied in each system (e.g. GridCodes) if future network conditions, generation and load patterns are perfectly known in advance. Transmission TRANSMISSION is the transport of electricity on the extra-high or high-voltage network (transmission system) for delivery to final customers or distributors. Operation of TRANSMISSION includes as well the tasks of system operation concerning the management of energy flows, reliability of the system and availability of all necessary system services / ANCILLARY SERVICES. Transmission Reliability Margin (TRM) The TRANSMISSION RELIABILITY MARGIN is a security margin that copes with uncertainties on the computed TTC values arising from: • UNINTENTIONAL DEVIATIONS of physical flows during operation due to the physical functioning of SECONDARY CONTROL • Emergency exchanges between TSOs to cope with unexpected unbalanced situations in real-time • Inaccuracies, e. g. in data collection and measurements UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) !G–14 Transmission System Operator (TSO) A TRANSMISSION SYSTEM OPERATOR is an company that is responsible for operating, maintaining and developing the transmission system for a CONTROL AREA and its INTERCONNECTIONS. UCTE Synchronous Area ("P1) A UCTE synchronous area is a part of a SYNCHRONOUS AREA covered by INTERCONNECTED SYSTEMS / TSOs which are members of the association. Different UCTE SYNCHRONOUS AREAS may exist in parallel on a temporal or permanent basis. Unintentional Deviation {Inadvertent Deviation} ("P1-B) In the SECONDARY CONTROL function, the UNINTENTIONAL DEVIATION is the difference between the actual energy exchange that has taken place in a given time interval (unintended physical power exchange of a CONTROL AREA) and the scheduled CONTROL PROGRAM of a CONTROL AREA (or a CONTROL BLOCK), without taking into account the effect of the frequency bias (see: AREA CONTROL ERROR), following the sign convention. Virtual Tie-Line {Pseudo-Tie-Line} ("P1-B) A VIRTUAL TIE-LINE represents a telemetered reading or value that is updated in real-time and used as a TIE-LINE flow in the AGC/ACE equation but for which no physical tie or energy metering actually exists. The integrated value is used as a metered MWh value for interchange ACCOUNTING purposes. UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) B. List of Acronyms AAC Already Allocated Capacity ACE Area Control Error AGC Automatic Generation Control ATC Available Transmission Capacity BRP Balance Responsible Party CA Control Area CAS Control Area Schedule CAX Control Area Exchange CB Control Block CBS Control Block Schedule CBX Control Block Exchange CC Control Centre CCS Co-ordination Centre Schedule CoC Co-ordination Centre CP Control Program DACF Day Ahead Congestion Forecast EH Electronic Highway EIC ETSO Identification Code EMR Energy Meter Reading ESS European Scheduling System ET Tie-line Flows EVT Virtual Tie-line Flows GENCO Generation Company GMT Greenwich Mean Time GPS Global Positioning System HV High Voltage LFC Load-Frequency Control NTC Net Transfer Capacity OpHB Operation Handbook PI Proportional-Integral SCADA Supervisory Control and Data Acquisition SVC Static Var Compensator TM Tele-measurement TSO Transmission System Operator TRM Transmission Reliability Margin TTC Total Transfer Capacity UCTE Union for the Co-ordination of Transmission of Electricity UD Unintentional Deviation UHV Ultra High Voltage UTC Universal Time Co-ordinated WAMS Wide Inter-Area Measurement System !G–15 UCTE Operation Handbook – Glossary (final v2.2 E, 24.06.2004) C. List of Units A ampere d day GW gigawatt (1.000.000.000W) GWh gigawatt-hour h, hrs hour Hz hertz (1/s) kV kilovolt (1000V) kVA kilovoltampere kVAr kilovars kW kilowatt (1000W) kWh kilowatt-hour mHz milli-hertz (1/1000 Hz) min minute ms milli-second (1/1000 s) MVA megavolt-ampere MVAr mega-vars MW megawatt (1.000.000W) MWh megawatt-hour s, sec second TW terawatt (1.000.000.000.000W) V volt W watt !G–16 POLICY 1 LOAD-FREQUENCY CONTROL AND PERFORMANCE P1 – Policy 1: Load-Frequency Control and Performance [E] Chapters A. B. C. D. E. Primary Control Secondary Control Tertiary Control Time Control Measures for Emergency Conditions Introduction The GENERATION of power units connected to the UCTE network needs to be controlled and monitored for secure and high-quality operation of the SYNCHRONOUS AREAS. The generation control, the technical reserves and the corresponding performance measurements are essential to allow TSOs to perform daily operational business. Control actions are performed in different successive steps, each with different characteristics and qualities, and all depending on each other: • PRIMARY CONTROL (see section !P1-A) starts within seconds as a joint action of all undertakings involved. • SECONDARY CONTROL (see section !P1-B) replaces PRIMARY CONTROL after minutes and is put into action by the responsible undertakings / TSOs only. • TERTIARY CONTROL (see subsection !P1-C) frees SECONDARY CONTROL by re-scheduling generation and is put into action by the responsible undertakings / TSOs. • TIME CONTROL (see subsection !P1-D) corrects global TIME DEVIATIONS of the SYNCHRONOUS TIME in the long term as a joint action of all undertakings / TSOs. Please refer to the glossary of terms of the UCTE Operation Handbook (see !G) for detailed definitions of terms used within this policy and to Appendix 1 (see !A1) for basics and principles of load-frequency control and performance. History of changes v2.2 v2.1 draft draft 20.07.2004 17.06.2004 OH-Team Final wording Changes after consultation Current status This document summarises current UCTE rules and recommendations relating to loadfrequency control and performance issues in a new structure, with additional items describing today’s common practice. This policy replaces previous UCTE ground rules and recommendations regarding PRIMARY and SECONDARY frequency and active POWER CONTROL, regulation reserves and correction of SYNCHRONOUS TIME. This version of the document (version 2.2, level E, dated 20.07.2004) has “final policy” status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) A. "P1–2 Primary Control [UCTE Operation Handbook Appendix 1 Chapter A: Primary Control, 2004] Introduction The objective of PRIMARY CONTROL is to maintain a balance between GENERATION and consumption (DEMAND) within the SYNCHRONOUS AREA, using turbine speed or turbine governors. By the joint action of all interconnected undertakings / TSOs, PRIMARY CONTROL aims at the operational reliability of the power system of the SYNCHRONOUS AREA and stabilises the SYSTEM FREQUENCY at a stationary value after a disturbance or incident in the time-frame of seconds, but without restoring the reference values of SYSTEM FREQUENCY and power exchanges (see !P1-B for SECONDARY CONTROL). Adequate PRIMARY CONTROL depends on generation resources made available by generation companies to the TSOs. Please refer to appendix 1 (see !A1-A) for basics and principles of PRIMARY CONTROL. This policy section replaces the corresponding sections for primary control in the latest “UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE”, dated 1998. Criteria C1. Nominal frequency. The set-point frequency (or scheduled frequency) f0 (see !P1D) defines the target value of the SYSTEM FREQUENCY f for system operation. Outside periods for the correction of SYNCHRONOUS TIME (see !P1-D), the nominal frequency value in the SYNCHRONOUS AREA is 50 Hz. C2. Frequency deviations. A FREQUENCY DEVIATION ∆f (the departure f–f0 of the actual SYSTEM FREQUENCY f from the scheduled frequency f0) results from a disturbance or an incident and may occur during normal system operation. Different criteria are used to distinguish the size of this deviation: C2.1. Calling up of Primary Control. To avoid calling up of PRIMARY CONTROL in undisturbed operation at or near nominal frequency, the FREQUENCY DEVIATION should not exceed ±20 mHz. PRIMARY CONTROL is activated if the FREQUENCY DEVIATION exceeds ±20 mHz (the sum of the accuracy of the local frequency measurement and the insensitivity of the controller, see !P1-A-R1 and !P1A-R2). C2.2. Maximum Quasi-Steady-State Frequency Deviation. The quasi-steady-state FREQUENCY DEVIATION in the SYNCHRONOUS AREA must not exceed ±180 mHz (maximum permissible steady-state FREQUENCY DEVIATION; under the condition of SELF-REGULATION OF THE LOAD according to !P1-A-C4). C2.3. Minimum Instantaneous Frequency. The instantaneous frequency must not fall below 49.2 Hz (that corresponds to -800 mHz as maximum permissible dynamic FREQUENCY DEVIATION from the nominal frequency !P1-A-C1) in response to a shortfall in generation capacity equal to or less than the reference incident according to !P1-A-C3. C2.4. Load-Shedding Frequency Criterion. LOAD-SHEDDING (automatic or manual, including the possibility to shed pumping units) starts from a SYSTEM FREQUENCY of 49.0 Hz (or below). The detailed step-plans for LOAD-SHEDDING (in the responsibility of the TSOs, with the possibility to perform earlier shedding of pumping units at higher frequency value as an operational measure, with the lowest value of 47.5 Hz and the need of progressive stages in between) define additional frequency criteria for further measures. C2.5. Maximum Instantaneous Frequency. The instantaneous frequency must not exceed 50.8 Hz (that corresponds to +800 mHz as maximum permissible dynamic FREQUENCY DEVIATION from the nominal frequency !P1-A-C1) in response to a loss of load or interruption of power exchanges equal to or less than the reference incident according to !P1-A-C3. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) C3. !P1–3 Reference Incident. The maximum instantaneous deviation between generation and demand in the SYNCHRONOUS AREA (by the sudden loss of generation capacity, loadshedding / loss of load or interruption of power exchanges) to be handled by PRIMARY 1 CONTROL starting from undisturbed operation depends on the size of the area / zone and on the size of the largest generation unit or generation capacity connected to a single bus bar located in that area2. C3.1. First Synchronous Zone. For the first synchronous zone as in 2003 the maximum power deviation to be handled is 3000 MW, assuming realistic characteristics concerning system reliability and size of loads and generation units. C3.2. Second Synchronous Zone. For the second synchronous zone as in 2003, the maximum power deviation to be handled is 540 MW. C3.3. Other Synchronous Areas. For other SYNCHRONOUS AREAS (UCTE that are not connected to the main synchronous zone, the size of the reference incident needs to be defined in each particular case with respect to the size of the area and the size of the largest generation units located in that area. SYNCHRONOUS AREAS), C3.4. Observation Incident. Incidents, such as the sudden loss of generation or load, that exceed 1000 MW in the first synchronous zone or 250 MW in the second synchronous zone are considered to be relevant for system observation in that zone3. C4. Frequency Characteristics. Key values of the frequency characteristics are defined on the basis of system observation4. C4.1. Self-Regulation of Load. The self-regulation of the load in all SYNCHRONOUS AREAS is assumed to be 1 %/Hz, that means a load decrease of 1 % occurs in case of a frequency drop of 1 Hz. C4.2. Security Margin. For FREQUENCY CONTROL, a static security margin of 20 mHz is defined, identical with the calling up of PRIMARY CONTROL (see "P1-A-C2.1). C5. Deployment Times of Primary Control Reserve. The time for starting the action of is a few seconds starting from the incident, the deployment time for 50 % or less of the total PRIMARY CONTROL RESERVE is at most 15 seconds and from 50 % to 100 % the maximum deployment time rises linearly to 30 seconds. PRIMARY CONTROL C6. Frequency Change Indicators. For special use in a post-operation analysis, the following criteria are defined to measure the characteristics of absolute changes of the SYSTEM FREQUENCY within a short period of time. C6.1. Periods of Time. Typical periods of time are ±60 minutes, ±15 minutes and ±5 minutes around the time of an incident or the change of the hour. 1: The definitions of synchronous zones (first and second zone as existing today as a result of the Balkan war) are temporal only due to the planned reconnection of the UCTE area. The reconnection is scheduled for 2005. The system load for the first SYNCHRONOUS AREA typically varies between 150 GW off-peak and 300 GW peak. 2: The final values used in the definition of the reference incidents are determined by the UCTE SG “TSO-Forum” and finally confirmed by the UCTE WG “Operations and Security” and the UCTE SC. The values given are under consideration. 3: The values have been adapted by the UCTE SG “TSO-Forum” in 2001 and are reviewed annually. 4: The final values used in the definition are determined by the UCTE SG “TSO-Forum” and finally confirmed by the UCTE WG “Operations and Security” and the UCTE SC. The values given are under consideration. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–4 C6.1. Periods of Time. Typical periods of time are ±60 minutes, ±15 minutes and ±5 minutes around the time of an incident or the change of the hour. C6.2. Maximum Time Grid. The values used for frequency change indicators are based on a maximum time grid of 10 seconds. C6.3. Frequency Patterns. Typical patterns of the frequency within a short period of time can be: constant with / without offset, decrease, increase, peak up, peak down, peak up down and peak down up. C6.4. Peak Frequency Range within Period. The peak frequency range is calculated as the difference between the maximum and the minimum frequency within the given period of time. C6.5. Peak Frequency Derivative within Period. The peak frequency derivative is determined as the maximum or minimum derivative of the frequency within the given period of time. Requirements R1. Accuracy of Frequency Measurements. For PRIMARY CONTROL, the accuracy of local frequency measurements used in the PRIMARY CONTROLLERS must be better than or equal to 10 mHz. R2. Insensitivity of Controllers. The insensitivity range of PRIMARY CONTROLLERS should not exceed ±10 mHz. Where dead bands exist in specific controllers, these must be offset within the CONTROL AREA / BLOCK concerned. R3. Primary Control Reserve. PRIMARY CONTROL RESERVE needs to have certain characteristics to be usable for PRIMARY CONTROL. R3.1. Reserve Distribution. In general, the PRIMARY CONTROL RESERVE must be physically distributed as evenly as possible between the different regions (usually between the CONTROL AREAS / BLOCKS) in the SYNCHRONOUS AREA (see also !P1-B and the distribution procedure). R3.2. Total Size of Reserve. The total PRIMARY CONTROL RESERVE (in MW) required for operation of a SYNCHRONOUS AREA is of the same size as the reference incident for that area (see !P1-A-C3). R3.3. Availability of Reserves. In total and as a minimum, the full PRIMARY CONTROL RESERVE for each area must be available continuously without interruption, not depending on the unit commitment in detail. R3.4. Operational Usability of Reserves. The entire PRIMARY CONTROL RESERVE (and each share of it) must be fully activated in response to a quasi-steadystate FREQUENCY DEVIATION of ±200 mHz or more. R4. Network Power Frequency Characteristic. The NETWORK POWER FREQUENCY between SYSTEM FREQUENCY and CHARACTERISTIC describes the real dependency POWER IMBALANCE with a linear approximation. R4.1. Constant Network Power Frequency Characteristic. In order to ensure that the principle of joint action is observed, the NETWORK POWER FREQUENCY CHARACTERISTICS of the various CONTROL AREAS is taken to remain as constant as possible. This applies particularly to small FREQUENCY DEVIATIONS, where the "dead bands" of generators may have an unacceptable influence upon the supply of PRIMARY CONTROL energy in the CONTROL AREAS concerned. R4.2. Share of Primary Control. The NETWORK POWER FREQUENCY CHARACTERISTIC of PRIMARY CONTROL only for the first synchronous zone is calculated out of !P1-A-R3.2 and !P1-A-C2.2 (including the security margin !P1-A-C4.2) to 15000 MW/Hz. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) R4.3. Share "P1–5 of Self-Regulation. . The NETWORK POWER FREQUENCY of SELF-REGULATION only for the first synchronous zone is calculated out of !P1-A-C4.1 and !P1-A-C3 to 3000 MW/Hz. CHARACTERISTIC R4.4. Overall Network Power Frequency Characteristic. The overall NETWORK POWER FREQUENCY CHARACTERISTIC for the first synchronous zone is set to 18000 MW/Hz and for the second synchronous zone set to 3000 MW/Hz. Standards S1. S2. System Reliability. In case of a first contingency or incident according to !P1-A-C3, such as the loss of generation or load or interruption of power exchanges in an undisturbed situation, PRIMARY CONTROL must maintain reliable system operation. Primary Control Action. The action of the individual generators performing PRIMARY must have the following characteristics, to be ensured by all TSOs: CONTROL S2.1. Adjustment of Generation. Power generation under PRIMARY CONTROL must be constantly adjusted to follow changes of SYSTEM FREQUENCY. S2.2. Deployment. Total PRIMARY CONTROL within the entire SYNCHRONOUS AREA (as well as within each CONTROL AREA / BLOCK) must follow the deployment times of PRIMARY CONTROL RESERVE (see !P1-A-C5). Each TSO must check the deployment times within his CONTROL AREA / BLOCK on a regular basis. S2.3. Duration of Delivery. PRIMARY CONTROL POWER must be delivered until the power deviation is completely offset by the SECONDARY CONTROL RESERVE of the CONTROL AREA / BLOCK in which the power deviation has occurred (the minimum duration for the capability of delivery for primary control is 15 minutes, see !P1-B). S3. Primary Control Target. Starting from undisturbed operation (see !P1-A-C2), a reference incident (see !P1-A-C3) must be offset by PRIMARY CONTROL alone, without the need for LOAD-SHEDDING in response to a FREQUENCY DEVIATION. In addition, where the self-regulating effect of the load is assumed according to !P1-A-C4, the FREQUENCY DEVIATION must not exceed the quasi-steady-state frequency deviation (see !P1-A-C2). S4. Principle of Joint Action. PRIMARY CONTROL is based on the principle of joint action to ensure system reliability and interconnected operation. This includes an overall distribution of reserves and control actions, as determined and decided by the UCTE SG “TSO-Forum” on an annual basis for the next calendar year. S4.1. Contributions to Primary Reserves. Each CONTROL AREA / BLOCK must contribute to the PRIMARY CONTROL RESERVE as required. The respective shares are defined by multiplying the calculated reserve for the entire SYNCHRONOUS AREA (see !P1-A-R3 and !P1-B) and the contribution coefficients ci of the various CONTROL AREAS / BLOCKS. The sum of all shares must amount to the total PRIMARY CONTROL RESERVE. S4.2. Contribution to Control. Each CONTROL AREA / BLOCK must contribute to the correction of a disturbance in accordance with its respective contribution coefficient ci for PRIMARY CONTROL. S4.3. Contribution Coefficients. The contribution coefficients must be determined and published annually for each CONTROL AREA / BLOCK. The contribution coefficients are binding for the corresponding interconnection partner / TSO for one calendar year. They are based on the share of the energy generated within one year in relation to the entire SYNCHRONOUS AREA. The sum of all contributions coefficients must amount to 1. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–6 Procedures P1. Contribution Coefficients. The UCTE SG “TSO-Forum” determines and decides about the contribution coefficients of each CONTROL AREA / BLOCK for each st SYNCHRONOUS ZONE on an annual basis (published before the 1 of December) and st sets these values into operation on the 1 of January of the next year. P2. Observation of Outages. Outages in production or consumption exceeding the size of the observation incident (see !P1-A-C3) are recorded for analysis. The corresponding information about location, time, size and type of the disturbance / incident is recorded and made available to the members of the association. P3. Frequency Analysis. The detailed analysis of the characteristics of the SYSTEM is made according to that of the following procedures. FREQUENCY P3.1. Frequency Change Analysis. The frequency change analysis5, see appendix, uses the frequency change indicators (see !P1-A-C6) for evaluation and comparison. P4. Control Performance Measurement. The NETWORK POWER FREQUENCY is calculated in response to a disturbance (such as an observation incident), based on measurements of the SYSTEM FREQUENCY and other key values and on a statistical analysis. CHARACTERISTIC P4.1. Control Performance Report. UCTE publishes results of a control performance analysis on a regular basis in the “Regular Report of the Performance of the Primary and Secondary Load –Frequency Control”, prepared by the UCTE SG “TSO-Forum”. Guidelines G1. Measurement Cycle for Primary Control. Typically the cycle for measurements for action must be in the range of 0.1 seconds to 1 second. PRIMARY CONTROL G2. Measurement Cycle for Observation. The cycle for measurements of the SYSTEM FREQUENCY for central system observation must be in the range of 1 second (strongly recommended) to at most 10 seconds. 5: Also known as frequency measurement campaign. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) B. "P1–7 Secondary Control [UCTE Operation Handbook Appendix 1 Chapter A: Secondary Control, 2004] [UCPTE Rule 44: Control of active power in the grid of the UCPTE, 1990] [UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, 1998] Introduction SECONDARY CONTROL maintains a balance between GENERATION and consumption (DEMAND) within each CONTROL AREA / BLOCK as well as the SYSTEM FREQUENCY within the SYNCHRONOUS AREA, taking into account the CONTROL PROGRAM, without impairing the PRIMARY CONTROL that is operated in the SYNCHRONOUS AREA in parallel but by a margin of seconds (see !P1-A). SECONDARY CONTROL makes use of a centralised AUTOMATIC GENERATION CONTROL, modifying the active power set points / adjustments of GENERATION SETS in the time-frame of seconds to typically 15 minutes. SECONDARY CONTROL is based on SECONDARY CONTROL RESERVES that is under automatic control. Adequate SECONDARY CONTROL depends on generation resources made available by generation companies to the TSOs. Please refer to Appendix 1 (see !A1-B) for basics and principles of SECONDARY CONTROL. This policy section replaces the corresponding sections for secondary control in the latest “UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE”, dated 1998. Criteria C1. K-Factor. The K-FACTOR defines the dependency between SYSTEM FREQUENCY and deviation of power exchanges for SECONDARY CONTROL. C1.1. Frequency Control Gain. The common gain defined for FREQUENCY CONTROL within SECONDARY CONTROL is set to 1.1 (110 %), used to overcome the uncertainty of the SELF-REGULATING effect. C1.2. K-Factor Calculation. The K-FACTOR Kri of a CONTROL AREA / BLOCK for SECONDARY CONTROL is calculated by the product of the frequency control gain 1.1 (see !P1-B-C1.1), the contribution coefficient ci of that area (see !P1-AS4.3) and the total NETWORK POWER FREQUENCY CHARACTERISTIC (see !P1A-R4.4). C1.3. Total K-Factor for Secondary Control. The total K-FACTOR for SECONDARY CONTROL in the FIRST SYNCHRONOUS ZONE amounts to 19801 MW/Hz for the year 2004. The total K-FACTOR for SECONDARY CONTROL in the SECOND 6 SYNCHRONOUS ZONE comes to 3301 MW/Hz for the year 2004 . C2. Area Control Error. Within each CONTROL AREA / BLOCK, the individual AREA CONTROL ERROR G (ACE) needs to be controlled to zero on a continuous basis. The ACE is calculated as the sum of the power control error and the frequency control error (G=∆P+ K*∆f). C2.1. Power Control Error. The power control error ∆P of a CONTROL AREA / BLOCK is the total POWER DEVIATION of that area in interconnected operation, calculated as the difference between the total active power flow (sum of all related measurements) and the CONTROL PROGRAM (sum of all related exchange schedules and the compensation programs). C2.2. Frequency Control Error. The frequency control error K*∆f of a CONTROL AREA / BLOCK is the product of the FREQUENCY DEVIATION ∆f (see !P1-A-C2) and the K-FACTOR of the CONTROL AREA / BLOCK Kri (see !P1-B-C1.2). 6: The final values are determined by the UCTE SG “TSO-Forum” on a regular basis. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–8 C3. Secondary Control Deviation. A disturbance or an incident (inside or outside of the CONTROL AREA / BLOCK) will result in an AREA CONTROL ERROR. Different criteria are used to distinguish the size of this deviation (see !A1 for further details, look for “Calling up of SECONDARY CONTROL”). C4. Island Operation. In contrast to interconnected operation, island operation is the unusual operation mode, where all interconnections / TIE-LINES of a CONTROL AREA / BLOCK are disconnected (e.g. after a disturbance the CONTROL AREA is not connected to the SYNCHRONOUS AREA any more) and thus no EXCHANGE PROGRAMS are possible. C5. ACE Change Indicators. For special use in a post-operation analysis, special criteria are defined to measure the characteristics of absolute changes of the ACE of a CONTROL AREA / BLOCK within a short period of time (see also !P1-A-C6). Requirements R1. Control Area / Block. The following preconditions are defined for CONTROL AREAS / BLOCKS in the UCTE: R1.1. Control program. A CONTROL AREA / BLOCK is capable to maintain the control program towards all other CONTROL AREAS / BLOCKS of the SYNCHRONOUS AREA at the scheduled value. R1.2. Control Hierarchy and Organisation. Each CONTROL AREA / BLOCK may divide up into sub-control areas that operate their own underlying generation control. A CONTROL BLOCK organises the internal SECONDARY CONTROL according to one of the following schemes (basically, the type of internal organisation must not influence the behaviour or quality of SECONDARY CONTROL between the CONTROL BLOCKS): • Centralised: SECONDARY CONTROL for the CONTROL BLOCK is performed centrally by a single controller (as one CONTROL AREA); the operator of the block has the same responsibilities as the operator of a CONTROL AREA. • Pluralistic: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK CO-ORDINATOR, regulates the whole block towards its neighbours with its own controller and regulating capacity, while all the other TSOs of the block regulate their own CONTROL AREAS in a decentralised way on their own. • Hierarchical: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK COORDINATOR, operates the superposed block controller which directly influences the subordinate controllers of all CONTROL AREAS of the CONTROL BLOCK; the BLOCK CO-ORDINATOR may or may not have regulating capacity on its own. R1.3. Area Demarcation. Each CONTROL AREA / BLOCK is physically demarcated by the position of the points for measurement of the interchanged power to the remaining interconnected network. R2. Responsible Operator. Each CONTROL AREA / BLOCK must be operated by an individual TSO that has the responsibility for the transmission system operation of this area (usually coincident with the territory of a company or a country), including the responsibility for availability, operation and provision of PRIMARY CONTROL and SECONDARY CONTROL within the CONTROL AREA / BLOCK to maintain the POWER INTERCHANGE of his CONTROL AREA / BLOCK at the scheduled value and, consequently, to support the restoration of FREQUENCY DEVIATIONS in the interconnected network. The operator is also responsible for accounting within its territory (see !P2). R3. Secondary Controller. In order to control the ACE (see !P1-B-C2) to zero, SECONDARY CONTROL must be performed in the corresponding control centre by a single automatic SECONDARY CONTROLLER, that needs to be operated in an on-line and closed-loop manner. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–9 R3.1. Controller Type and Characteristic. In order to have no residual error, the SECONDARY CONTROLLER must be of PI (proportional-integral) type. The integral term must be limited in order to have a non-windup control action, able to react immediately in case of large changes or a change of the sign of the ACE. Measurement cycle times, integration times and controller cycle time must be co-ordinated. R3.2. Availability and Reliability. The automatic SECONDARY CONTROLLER, operated on-line and closed-loop, must have a high availability and must operate highly reliable. R3.3. Controller Cycle Time. The cycle time for the automatic SECONDARY CONTROLLER should be between 1 second and 5 seconds, to minimise the total time delay between occurrence, reaction and response in the scope of the overall control performance of the control area7. R3.4. Programmed Values. Programmed values for SECONDARY CONTROL (e.g. for power exchanges and frequency set-points) must be entered into the controller as time-dependant set-point values based on schedules. See !P2 for details on scheduling. R3.5. Frequency Control. The gain for FREQUENCY CONTROL within SECONDARY CONTROL must be set to the K-FACTOR (see !P1-B-C1.2). In case of ISLAND operation (see !P1-B-C4) the SECONDARY CONTROLLER of a CONTROL AREA / BLOCK must perform automatic frequency control for the CONTROL AREA / BLOCK. R3.6. Power Exchange Set-Point Value. The algebraic sum of the programmed power exchanges between a CONTROL AREA / BLOCK and ADJACENT CONTROL AREAS / BLOCKS constitutes the POWER EXCHANGE set point of the CONTROL AREA’S / BLOCK’S SECONDARY CONTROLLER. R3.7. Ramping of Schedules. In order to prevent excessive FREQUENCY DEVIATIONS when changes of CONTROL PROGRAMS occur, it is necessary that each change be converted to a ramp with a ramp period of 10 minutes, starting 5 minutes before the agreed time of change (the change of the hour or of the quarter, see !P2 for definition of exchange schedules) and ending 5 minutes later. It is required that the ramping be performed in the same way by all controllers of the SYNCHRONOUS AREA. R3.8. Manual Control Capability. In case of deficiency of the automatic SECONDARY CONTROL, manual control action must be possible. R4. Secondary Control Reserve. An adequate SECONDARY CONTROL RESERVE must be available at all times to cover expected DEMAND fluctuations and the loss of a generating unit. If the loss of the largest generating unit is not already covered by the requisite SECONDARY CONTROL RESERVE, additional TERTIARY CONTROL RESERVE {15 MINUTE RESERVE} is required to offset the shortfall within a short time, see !P1-C. R4.1. Availability of Resources. Adequate SECONDARY CONTROL depends on generation resources made available by generation companies to the TSO. R4.2. Sufficient Controllable Generation. In each CONTROL AREA / BLOCK, sufficient controllable generation or load control (under automatic control) must be available in order to be able to control the AREA CONTROL ERROR to zero. R4.3. Backup by Tertiary Control Reserve. SECONDARY CONTROL keeps the CONTROL AREA’S / BLOCK’S balance, in normal operating conditions, and contributes to restore it, in case of a sudden unbalance due to an incident (see also !P1-A-C3). In case of a sudden large unbalance or a sustained DEMAND 7: In order to reflect current practice of SECONDARY CONTROL and operational experiences, the “target value of 1 s to 2 s for the future” of the former UCTE rule and recommendation has been replaced accordingly. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) variation, TERTIARY CONTROL RESERVE CONTROL RESERVES (see !P1-C). R5. "P1–10 is required to restore the SECONDARY Tie-Lines. Certain criteria / characteristics need to be matched by different types of TIE-LINES that may be in use for SECONDARY CONTROL. R5.1. Transmission Lines, Transformers. The list of TIE-LINES of the CONTROL AREA / BLOCK in operation is maintained and updated on a regular basis. R5.2. Radial Operation of Generating Units. In case of the radial operation of generating units these are considered as internal generating units within the CONTROL AREA / BLOCK (e.g. using VIRTUAL TIE-LINES). R5.3. Jointly Owned Generating Units. Jointly owned generating (with GENERATION shares belonging to different CONTROL AREAS) shall be equipped with metering and measurement equipment providing function of VIRTUAL TIE-LINE between two or more CONTROL AREAS, unless the share of the production is delivered via SCHEDULE. R5.4. Metering and Measurement. All TIE-LINES from a CONTROL AREA to adjacent CONTROL AREAS (across the border) must have measurements and meters in operation to record the actual active (and reactive) power flow in MW (MVAr) in real-time and the energy in MWh in the time-frame for power exchanges that is used (one hour at the maximum, see !P2). R5.5. Transmission of Measurements. The measurements must be transmitted in a reliable manner to the SECONDARY CONTROLLER. R5.6. Accuracy of Measurements. The accuracy of the active power measurements on each TIE-LINE must be better than 1.5 % of its rated value (the complete measurement range, including discretisation). The measurement cycle time should not exceed 5 seconds and the measurement times of measurement values should not differ more than 5 seconds. Measurement cycle times, controller cycle times and controller integration times shall be coordinated. R6. System Frequency. The following requirements are defined for the use of the SYSTEM FREQUENCY for SECONDARY CONTROL: R6.1. Accuracy of Measurement. For SECONDARY CONTROL, the accuracy of frequency measurement must be between 1.0 mHz and 1.5 mHz (target value for the future). R6.2. Frequency Set-Point. The actual frequency set-point value (nominal value of 50 Hz, see !P1-A-C1) for TIME CONTROL (see !P1-D-S4) must be used within the SECONDARY CONTROLLER for calculation of the FREQUENCY DEVIATION, to be able to limit the deviation between SYNCHRONOUS TIME and UTC. R7. Data Recordings. Each TSO must be equipped with a recording of all values needed for monitoring of the response of (PRIMARY and) SECONDARY CONTROLLERS and for analysis of normal operation and incidents in the INTERCONNECTED SYSTEM. Standards S1. Operation of Secondary Control: Each TSO operates sufficient generating capacity under automatic control by the SECONDARY CONTROLLER to meet its obligation to continuously balance its generation and interchange schedules to its load for the CONTROL AREA / BLOCK. S2. Usage of Secondary Control. SECONDARY CONTROL must only be used in order to correct an AREA CONTROL ERROR. SECONDARY CONTROL must not be used for other purposes, e.g. to minimise unintentional power exchanges or to correct other imbalances. SECONDARY CONTROL shall not counteract PRIMARY CONTROL under UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–11 emergency conditions, with possible impact on the usage of SECONDARY CONTROL in such situations in a co-ordinated way. S3. Control Target. One quality criterion for SECONDARY CONTROL is the time taken for a CONTROL DEVIATION to return to zero, i.e. the time taken to restore the SYSTEM FREQUENCY to its set point value and to restore power interchanges to their set point (programmed) values. In practice, PRIMARY CONTROL action begins within a few seconds of a FREQUENCY DEVIATION, and takes full effect not more than 30 seconds later. Frequency and power interchanges must begin to return to their set point values as a result of SECONDARY CONTROL after 30 seconds, with the process of correction being completed after 15 minutes with a reasonable ramp rate and without overshoot. S3.1. Compliance with large Program Changes. In order to prevent unintentional FREQUENCY DEVIATIONS and major control deviations under normal operating conditions (see !P1-E-C1.1), system operators are required to maintain careful compliance with times for program changes, particularly where changes in the interchange program of several hundred MW are involved. In particular, care must be taken to ensure that generating capacity is brought on line or disconnected on a staggered basis, e.g. for tariff changes at 6 a.m. and 10 p.m, and that the ramp (see !P1-B-R3.7) is followed accurately. A substantial change in scheduling or the scheduled modification of power plant operation must not have a negative impact upon system operation. S4. K-Factor Settings. In order to ensure that SECONDARY CONTROL will only be called up in the CONTROL AREA / BLOCK which is the source of the disturbance, all controller values for Kri must match to the K-FACTORS (see !P1-B-C1). In this meaning, SECONDARY CONTROL must help PRIMARY CONTROL and must not counteract it in any case. Under no circumstances should Kri be modified during an incident, since this action would go against the principle of SECONDARY CONTROL. Guidelines G1. Secondary Controller. The following recommendations and guidelines are given for the setup of the SECONDARY CONTROLLER (see !P1-B-R3 for the complementary requirements on the SECONDARY CONTROLLER): G1.1. Controller Type and Characteristic. In case of a very large control deviation, the control parameters βi and Tn of the SECONDARY CONTROLLER (for proportional and integral part) may be adjusted automatically for a given period of time. The control parameters βi, and Tn are closely linked. At present, values ranging from 0 to 50% may be set for the proportional term βi of the area controller. The time constant represents the "tracking" speed of the SECONDARY CONTROLLER with which the controller activates the control power of participating generators. Values ranging from 50 seconds to 200 seconds may be set for the time constant Tn. G2. Tie-Lines. The following recommendations are given for all TIE-LINES and related equipment that may be in use for SECONDARY CONTROL (see !P1-B-R5 for the complementary requirements on TIE-LINES): G2.1. Metering and Measurement. All TIE-LINE measurements in MW and MWh should be telemetered to both control centres affected (and in parallel to the co-ordination centre, if necessary), using commonly agreed primary equipment (e.g. the ELECTRONIC HIGHWAY, if applicable, see !P6). G2.2. Transmission of Measurements. The measurements shall be transmitted in a reliable manner to the SECONDARY CONTROLLER, at least two ways are recommended, with an alarm in case of deficiency of a data transmission. The largest transmission delay must not exceed 5 seconds; it must be as small as possible and below the controller cycle time. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–12 G2.3. Substitute Measurements. Substitute measurements and reserve equipment should always be available in parallel to the primary measurement. Substitute measurements are obligatory for all TIE-LINES with major operational impact. Accuracy and cycle times for the substitute TIE-LINE measurements must fulfil the same characteristics (see !P1-B-R5). G3. Recommended Secondary Control Reserve. In CONTROL AREAS / BLOCKS of different sizes, load variations of varying magnitude must be corrected within approximately 15 minutes. To this end, the following minimum value for the SECONDARY CONTROL RESERVE related to load variations (derived from the empirical curve shown in the figure below) is recommended for a CONTROL AREA / BLOCK: R = a Lmax + b 2 − b R = the recommendation for SECONDARY CONTROL RESERVE in MW Lmax = the maximum anticipated load in MW for the CONTROL AREA / BLOCK The parameters a and b are established empirically with the following values for the UCTE: a = 10 MW and b = 150 MW The following figure shows the recommended SECONDARY CONTROL RESERVE as a function of the maximum anticipated load: Procedures P1. Trumpet Curve Method. The trumpet curve method for NETWORK POWER FREQUENCY analysis is used after incidents, see description in detail in Appendix 1 (see !A1-B). CHARACTERISTIC UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) C. "P1–13 Tertiary Control [UCTE Operation Handbook Appendix 1 Chapter C: Tertiary Control, 2004] Introduction TERTIARY CONTROL uses TERTIARY RESERVE {15 minute reserve} that is usually activated manually by the TSOs after activation of SECONDARY CONTROL to free up the SECONDARY RESERVES. TERTIARY CONTROL is typically operated in the responsibility of the TSO. Please refer to Appendix 1 (see !A1-C) for further basics and principles of TERTIARY CONTROL. Criteria C1. Tertiary Control Deviation. In case of an incident (such as !P1-A-C3) that causes permanent activation of SECONDARY CONTROL RESERVES, the permanent share of the SECONDARY CONTROL is considered to be a deviation of TERTIARY CONTROL. Requirements R1. Tertiary Reserve. Each CONTROL AREA / BLOCK must have access to sufficient to follow up SECONDARY CONTROL within a short period of time after an incident. An adequate control reserve must be available at all times to cover the loss of a generating unit. If the loss of the largest generating unit is not already covered by the requisite SECONDARY CONTROL RESERVE, a TERTIARY CONTROL RESERVE (minute reserve) will be required to offset the shortfall. TERTIARY RESERVE Standards S1. Activation of Tertiary Reserve: Each TSO must immediately activate TERTIARY in case insufficient free SECONDARY CONTROL RESERVE is available, in order to free up SECONDARY CONTROL RESERVES again. RESERVE Procedures P1. Activation of Tertiary Reserves. TERTIARY RESERVES are activated by either updating the total EXCHANGES SCHEDULE of the CONTROL AREA / BLOCK (the CONTROL PROGRAM) or by changing the generation schedules within the CONTROL AREA / BLOCK. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) D. "P1–14 Time Control [UCTE Operation Handbook Appendix 1 Chapter D: Time Control, 2004] Introduction The objective of TIME CONTROL is to monitor and limit discrepancies observed between SYNCHRONOUS TIME and universal time co-ordinated (UTC) in the SYNCHRONOUS AREA (within each zone of synchronous operation of the UCTE separately). Reasonably it is applied during periods of uninterrupted interconnected operation, where the SYNCHRONOUS TIME is the same in all areas. Please refer to Appendix 1 (see !A1-D) for basics and principles of TIME CONTROL. This policy section replaces the latest “UCTE technical rule for the correction of synchronous time” (dated 01.06.1998). Criteria C1. Tolerated Range of Discrepancy. A discrepancy between SYNCHRONOUS TIME and UTC time is tolerated within a range of ±20 seconds. C2. Target Range of Discrepancy. The discrepancy between SYNCHRONOUS TIME and UTC time should be within a range of ±30 seconds under normal conditions in case of trouble-free operation of the interconnected network. C3. Exceptional Range of Discrepancy. Under exceptional conditions in case of troublefree operation of the interconnected network the discrepancy between SYNCHRONOUS TIME and UTC time should be within a range of ±60 seconds. Requirements R1. Time Monitor. Each UCTE SYNCHRONOUS AREA appoints a central instance (“Time Monitor”) that monitors continually the deviation between SYNCHRONOUS TIME (which is derived from the integration of the common SYSTEM FREQUENCY in this zone of synchronous operation) and the actual time (universal time co-ordinated, UTC). R2. Frequency Set-Point for Secondary Control. For TIME CONTROL purposes in the range of !P1-D-C3 it is required that each CONTROL AREA (see !P1-A) can involve a displacement in the set-point frequency for SECONDARY CONTROL. R3. Frequency Set-Point for Units. For time correction in the range of !P1-D-C3 the set-point frequency of the units involved in PRIMARY CONTROL must not be changed. Standards S1. Mean Frequency Value. The mean value (as a result of PRIMARY CONTROL, SECONDARY CONTROL and TIME CONTROL in co-operation) of the SYSTEM FREQUENCY shall be the nominal frequency value of 50 Hz (see !P1-A-C1), so that on average the TIME DEVIATION results to zero. S2. Time Deviation Calculation. The TIME DEVIATION between SYNCHRONOUS TIME and actual time is calculated for 8 a.m. each day. The relevant time zone is the Central European Time (CET = GMT+1) with daylight saving. S3. Time Correction Offset. If the TIME DEVIATION is within !P1-D-C1, the offset for time correction is set to zero. If the deviation is out of !P1-D-C1 and SYNCHRONOUS TIME is behind the actual time, the offset is set to +10 mHz. If the deviation is out of !P1D-C1 and SYNCHRONOUS TIME is ahead the actual time, the offset is set to –10 mHz. S3.1. Exceptional Time Correction Offsets. Only under exceptional conditions out of !P1-D-C3 offsets larger than 10 mHz (0.010 Hz) for the time correction of the SYNCHRONOUS TIME may be used. They are set by the time monitor. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) S4. "P1–15 Time Correction Standard. The time correction offset is applied by one of the following values: S4.1. Frequency set-point value. The frequency set-point value is calculated out of the sum of the nominal frequency 50 Hz and the FREQUENCY OFFSET and valid for all hours of the next day, starting at 0 a.m., and is relevant for the operation of the SECONDARY CONTROL (see !P1-D-R2) and the calculation of performance criteria for SECONDARY CONTROL. All TSOs apply the transmitted frequency set-point value in their SECONDARY CONTROLLER for the full next day. S5. Time Correction Notice. The information for the time correction is forwarded towards all CONTROL AREAS / BLOCKS of the SYNCHRONOUS AREA every day at 10 a.m. by the time monitor. The CONTROL AREAS / BLOCKS themselves forward this information towards their sub-control areas without delay. S5.1. Content of Notice. Each notice contains the time deviation, the time correction offset, the time correction procedure and the date and duration for the time correction. S5.2. Notice Transmission. This notice is transmitted using secure and reliable electronic communication that allows a half-automated procedure. S6. Time Correction Serialisation. TIME DEVIATIONS and notifications on time error corrections are serialised by the time monitor on a monthly basis. Procedures P1. UCTE Time Monitor. Under normal conditions of UCTE interconnection, the ETRANS control centre in Laufenburg monitors continually the deviation between SYNCHRONOUS TIME and the actual time. P2. Time Correction Notice. Under normal conditions of UCTE interconnection, the information on time correction is forwarded from Laufenburg (ETRANS) to the list of TSOs directly concerned. P3. Re-Connection of Asynchronous Areas. Before re-connecting asynchronous areas of the UCTE network, the differences of TIME DEVIATIONS between the different SYNCHRONOUS AREAS need to be in target range. The smaller grid area being reconnected needs to limit this difference and to take over the synchronous time from the larger grid area once the re-connection is in operation. P4. Outstanding Notice. In case the TIME DEVIATION and correction notice is missing for a TSO, the TSO applies the nominal frequency of 50 Hz (see !P1-A-C1) as frequency set-point value for SECONDARY CONTROL until it receives the outstanding notice. UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) E. "P1–16 Measures for Emergency Conditions [UCPTE Rule 15: Measures for frequency control and precautions for the decrease of the frequency value, 1965] [UCPTE Rule: Recommendations on frequency in UCPTE interconnected operation, 1996] Introduction EMERGENCY SITUATIONS in the interconnected UCTE system occur as a result of abnormal operation caused by dropping of generating power, outages / OVERLOADING of transmission lines that could not be covered by the operational reserve of affected TSOs and cause imbalance of ACTIVE POWER or VOLTAGE decline. When disruptions occur, disturbances may be propagated over a vast area within a very short time. In contrast to the “Operational Security” in policy 3 (see !P3), the objective of this section is to specify possible direct operational measures taken to maintain operation of the interconnected UCTE system. The SYSTEM FREQUENCY is the main criterion for observation of normal operating conditions (see !P1-A-C2). The NETWORK POWER FREQUENCY CHARACTERISTIC (see !P1-A-C4) depends on the size of INTERCONNECTED NETWORKS. Considerable FREQUENCY DEVIATIONS (caused by loss of generation capacity) is more probable in small isolated systems than in a large SYNCHRONOUS AREA. Criteria C1. Operating Conditions. According to the actual SYSTEM FREQUENCY, the following operating conditions and emergency conditions are defined: C1.1. Normal Operating Condition / Undisturbed Operation. If the absolute FREQUENCY DEVIATION (absolute deviation from the nominal SYSTEM FREQUENCY of 50 Hz, see !P1-A-C1) does not exceed 50 mHz, operation qualifies as undisturbed (normal operating condition). C1.2. Impaired Operating Condition. If the absolute FREQUENCY DEVIATION is greater than 50 mHz but less than 150 mHz, operating conditions are deemed to be impaired, but with no major risk, provided that control facilities (controllers and reserves) in the affected CONTROL AREAS / BLOCKS are for sure ready for direct deployment. C1.3. Severely Impaired Operating Condition. If the absolute FREQUENCY DEVIATION is greater than 150 mHz, operating conditions are deemed to be severely impaired, because there are significant operational risks for the interconnected network. C1.4. Critical Operating Condition. If the FREQUENCY DEVIATION reaches the critical value of 2.5 Hz (that means that the SYSTEM FREQUENCY reaches 47.5 Hz, for over-frequency the limit is 51.5 Hz), automatic disconnection of generators is triggered and operation of the interconnected network is at its limit. Requirements R1. Load-Shedding Capabilities. For cases of a major frequency drop, automatic devices for LOAD SHEDDING in response to a frequency criterion must be installed (see !P1-AC2.4). R2. Emergency Situation Declaration. Each TSO has to declare the main characteristics of an emergency situation, for information of all undertakings involved. There must be clearly stated that emergency situation solving is a question of the highest priority at all. R3. Coordination. Neighboring TSOS shall declare in bilateral operational agreements provisions for emergency assistance including provision to obtain emergency UCTE OH – Policy 1: Load-Frequency Control … (final policy 2.2 E, 20.07.2004) "P1–17 assistance from remote systems. All TSOs must co-ordinate LOAD-SHEDDING and action plans during emergency situations. R4. Accuracy of Frequency Measurements for Load-Shedding. Frequency measurements for LOAD-SHEDDING must be maintained at an accuracy of approximately 5 to 10 mHz. In case that a wide triggering band will not cause severe problems in the system, an accuracy of 50 to 100 mHz is sufficient. This has to be observed and reviewed on a case-by-case basis. R5. Tie-lines equipment. In order to maintain advantage and support of interconnection, TIE-LINES shall be equipped with single pole rapid re-closing devices and AUTOMATIC RECLOSING DEVICES for single phase fault. R6. Overload indication. All TIE-LINES and large transformers must be equipped with devices that indicate overloads. R7. Equipment of Generating Units. Depending upon system characteristics (generation mix, network requirements, etc.), a sufficient number of generating sets must be equipped with devices for the isolation of units from the remainder of the system to maintain their own auxiliaries in case of network separation, thereby allowing the more rapid reconnection and resumption of generation by these plants, once network conditions allow this. It should be avoided that the machines (after disconnection from the network) reach the emergency shut-off speed due to loss of load. R8. SCADA System Availability. In case of a general loss of voltage, control centers, operating centers, substations, telecommunication systems and remote control systems must remain in operational condition, in order to allow the reconstitution of the network to be completed. Loss of a telecommunications link or an instrumentation and link between control centers, operating centers and production/transmission installations must not affect the system operation. Standards S1. Maintaining Synchronous Operation. In case of an emergency situation, the main task is to maintain synchronous operation of the UCTE system. TSOs have to take immediately all possible measures to restore normal operating conditions, subject to the available means and resources available at that time. In order to allow the support provided by TIE-LINES to be utilized as long as possible, the deliberate tripping of TIELINES shall be avoided, as long as interconnected operation remains possible. S2. Notifying Neighboring Systems. All TSOs have to notify the neighboring TSOs in case of an emergency situation and ask for co-operation. Guidelines G1. Surplus of Power. In case of a critical increase of the SYSTEM FREQUENCY (significant surplus of power generation), power generation has to be reduced (up to the minimum) and pump operation shall be increased immediately. If the SYSTEM FREQUENCY remains at a critical value, generation units should be disconnected. G2. Lack of Power. In case of a significant lack of power causing a critical drop of the the following actions should be performed immediately: Stop or reduction of the pump operation, increase of all running generation (up to the maximum) and connection of all possible quick-start reserves. SYSTEM FREQUENCY, POLICY 2 SCHEDULING AND ACCOUNTING P2 – Policy 2: Scheduling and Accounting [E] Policy Subsections A. B. C. Scheduling Online Observation Accounting Introduction To operate a large power system like the one of UCTE and to create the suitable conditions for commercial electricity trade it is necessary to schedule in advance the power to be exchanged at the interconnection borders between the system operators. During daily operation, the schedules are followed by means of the LOAD-FREQUENCY CONTROL installed in each CONTROL AREA / CONTROL BLOCK. Notwithstanding LOAD-FREQUENCY CONTROL, UNINTENTIONAL DEVIATIONS invariably occur in energy exchanges. For this reason, it is necessary to co-ordinate the SCHEDULE nomination between the system operators, to observe in real-time UNINTENTIONAL DEVIATIONS and to co-ordinate ACCOUNTING and computation of the COMPENSATION PROGRAMS to balance UNINTENTIONAL DEVIATIONS. History of changes v2.2 v2.1 draft draft 20.07.2004 17.06.2004 WGOS, OH team OH team Final wording Revision after consultation Current status This policy will cancel and replace all previous UCTE ground rules and recommendations regarding the co-ordination of accounting and the organisation of load-frequency control (1999) as well as the recording and offsetting of unintentional deviations in the interconnected network of UCPTE (1988). This version of the document (version 2.2, level E, dated 20.07.2004) has “final policy” status. The following UCPTE rules and recommendations are not used any longer: • UCPTE Ground Rule: Co-ordination of the accounting and organisation of the loadfrequency control, 1999 • UCPTE Recommendation: Recording and offsetting of unintentional deviations in the interconnected network of UCPTE, AR 1988 • UCPTE Recommendation: General principles concerning the recording and offsetting of unintentional deviations in the interconnected network of UCPTE, AR 1973-1974 • UCPTE Recommendation: Automatic programmed value setters, AR 1960-1961 This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) A. !P2–2 Scheduling of Power Exchange [UCTE Rule Co-ordination of the accounting and organisation of LFC] [ETSO ESS Implementation guide Release 1] [ETSO Guideline for FTP Data Exchange] Introduction The task of scheduling EXCHANGE PROGRAMS is performed during the operational planning phase. It aims to guarantee agreed, unique border - crossing EXCHANGE PROGRAMS among all CONTROL AREAS / CONTROL BLOCKS of UCTE. Scheduling of EXCHANGE PROGRAMS is an important issue to check the UCTE-wide consistency of the input variables used by the single parties involved in order to prevent systematic faults in the context of LOAD-FREQUENCY CONTROL (see Policy 1). The scheduling phase starts with the day-ahead schedule nomination of market participants and ends with the last intra-day schedule adaptations before system operation. Criteria C1. EXCHANGE PROGRAM. The EXCHANGE PROGRAM must have the same value on both sides of the border. C2. Sum of the CONTROL PROGRAMS. The sum of the CONTROL PROGRAMS of all CONTROL BLOCKS for each time unit of a SYNCHRONOUS AREA must be at any time equal to zero. C3. Time frame is a time resolution used in EXCHANGE SCHEDULES. C4. Definition of D , D-1, D+1 D : the day when the nominated EXCHANGE SCHEDULES are set into force. D-1 : the day ahead (before) “D” D+1: the day after “D” Requirements R1. Framework for an international Coding Scheme. A common model of an international Coding Scheme is required as a basis for electronic exchange of schedules within UCTE. This model consists out of the UCTE organisation with COORDINATION CENTRES (CC), CONTROL BLOCKS (CB) and CONTROL AREAS (CA). For the CONTROL AREAS, a common naming in accordance with EIC (ETSO Identification Code) is used. R1.1. For CONTROL AREAS the following codes are used R1.1.1. On CO-ORDINATION CENTRE level - 10YCC-UCTE-NO—K for CO-ORDINATION CENTRE North - 10YCC-UCTE-SO—W for CO-ORDINATION CENTRE South R1.1.2. On CONTROL BLOCK level - 10YCB-…. for CONTROL BLOCKS R1.1.3. On CONTROL AREA level - 10YCA-…. for CONTROL AREAS UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) R2. !P2–3 Data exchange among the operators of CONTROL AREAS, CONTROL BLOCKS and COORDINATION CENTRES. data exchange of EXCHANGE PROGRAMS is required (e.g. ftp-dial in via ISDN-line, e-mail; phone and fax as backup if electronic communication is disturbed). R2.1. Electronic ELECTRONIC HIGHWAY, R2.2. The data exchange format for EXCHANGE PROGRAMS has to be agreed among the operators. R2.3. The identification scheme for market participants has to be agreed between the operators. R2.4. Standardisation. It is necessary to standardise the data exchange formats within a CONTROL BLOCK, within a CO-ORDINATION CENTRE and between the COORDINATION CENTRES. R3. Time Frame. R3.1. The following time frames are allowed: ti = ¼h, ½h or 1h. R3.2. The time frame for EXCHANGE SCHEDULES must be agreed bilaterally between adjacent operators. As a general rule, two neighbouring operators have to choose the larger time frame for their bilateral EXCHANGE SCHEDULES. R4. Resolution. R4.1. The value of power in EXCHANGE SCHEDULES will be given in integer number of MW with or without decimal digits for time frame ti = 1h R4.2. The value of power in EXCHANGE SCHEDULES will be given in integer number MW with 3 decimal digits for time frame ti = ¼h or ½h. R5. Availability. The function of a scheduling office must be available every day from 00:00. to 24:00. Standards S1. Day-ahead verification of EXCHANGE PROGRAMS between CONTROL AREAS (D-1 for D) (see"P2-A-G1). S1.1. CONTROL AREA verification. The CONTROL AREA OPERATORS have to agree with the neighbouring CONTROL AREA OPERATORS the EXCHANGE PROGRAMS per border (CAX) for every time unit. (see"P2-A-P1) S1.2. Detail of exchange data. For each time unit, the CONTROL AREA OPERATORS have to exchange the aggregated EXCHANGE PROGRAMS per CONTROL AREA border. S2. Day-ahead CONTROL BLOCK verification (D-1 for D) (see"P2-A-G2). S2.1. Data exchange CONTROL AREA – CONTROL BLOCK. Every day (D-1), the CONTROL AREA OPERATORS have to submit to their corresponding CONTROL BLOCK OPERATOR the following day’s (D) agreed bilateral EXCHANGE PROGRAM per border (CAX) concerning their borders. S2.2. Details of exchange data. For each time unit, the CONTROL AREA OPERATOR has to submit the bilateral EXCHANGE PROGRAM per CONTROL AREA per border (CAX) to the CONTROL BLOCK OPERATOR. S2.3. CONTROL BLOCK validation. The CONTROL BLOCK OPERATOR has to validate the scheduling data received from the CONTROL AREAS (see"P2-A-P2). S2.4. CONTROL BLOCK verification. The CONTROL BLOCK OPERATOR has to submit the bilateral EXCHANGE PROGRAM of all affected CONTROL AREAS (CBS) and agree with the neighbouring CONTROL BLOCK OPERATORS the bilateral UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) EXCHANGE PROGRAMS !P2–4 for the corresponding CONTROL AREAS for every time unit. (see"P2-A-P3) S3. Day-ahead CO-ORDINATION CENTRE verification (D-1 for D) (see"P2-A-G3). S3.1. Data exchange CONTROL BLOCK – CO-ORDINATION CENTRE. Every day (D-1), the CONTROL BLOCK OPERATORS have to submit to their corresponding COORDINATION CENTRE the following day’s (D) agreed EXCHANGE PROGRAMS concerning their borders. S3.2. Details of exchange data. For each time unit, the CONTROL BLOCK OPERATOR has to submit the bilateral EXCHANGE PROGRAMS of all affected CONTROL AREA borders (CBS) to the CO-ORDINATION CENTRE. S3.3. CO-ORDINATION CENTRE validation. The CO-ORDINATION CENTRE has to validate the scheduling data received from the CONTROL BLOCKS. (see"P2-A-P4) S3.4. CO-ORDINATION CENTRE verification. The CO-ORDINATION CENTRE has to verify and agree with the neighbouring CO-ORDINATION CENTRE the bilateral EXCHANGE PROGRAMS for the corresponding CONTROL AREAS (CCT) for every time unit. (see"P2-A-P5) S4. Modification of EXCHANGE SCHEDULES. S4.1. In case of a change of the EXCHANGE PROGRAM scheduled with another neighbouring CONTROL AREA, the operator of the relevant CONTROL AREA has to transmit in due time the information to the corresponding operator of the CONTROL BLOCK. S4.2. In case of a change of the hourly EXCHANGE PROGRAM scheduled with another neighbouring CONTROL BLOCK, the operator of the relevant CONTROL BLOCK has to transmit in due time the information to the corresponding CO-ORDINATION CENTRE. S5. Confirmation of verified EXCHANGE PROGRAMS. S5.1. CO-ORDINATION CENTRE verification. After completion of the CO-ORDINATION CENTRE verification, the CO-ORDINATION CENTRES have to confirm within 30 minutes the agreed EXCHANGE PROGRAMS to the CONTROL BLOCK OPERATORS electronically by a confirmation report. S5.2. CONTROL BLOCK verification. After receipt of the CO-ORDINATION CENTRE confirmation, the completion of the CONTROL BLOCK verification has to be confirmed within 30 minutes by the CONTROL BLOCK OPERATORS to the CONTROL AREA OPERATORS electronically by a confirmation report. S6. Transparency. The EXCHANGE PROGRAMS between CONTROL BLOCKS (CBX) and between CONTROL AREAS (CAX) shall be published by CO-ORDINATION CENTRES on the common information system for TSOs (VULCANUS) within 30 minutes after completion of the verification of EXCHANGE PROGRAMS. S7. Confidentiality. The data used for scheduling may not be transmitted to third parties without authorisation. Guidelines G1. Day-ahead verification of EXCHANGE PROGRAMS between CONTROL AREAS (D-1 for D). G1.1. Latest exchange of EXCHANGE PROGRAMS. Exchange of EXCHANGE PROGRAMS (CAX) between CONTROL AREAS shall be completed till 14:45 . G1.2. CONTROL AREA verification closure. The CONTROL AREA verification shall be completed by the CONTROL AREA OPERATORS till (D-1), 15:45 UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) G2. !P2–5 Day-ahead CONTROL BLOCK verification (D-1 for D). G2.1. Data exchange CONTROL AREA – CONTROL BLOCK. Every day (D-1), the CONTROL AREA OPERATORS shall submit by 15:45 to their corresponding CONTROL BLOCK OPERATOR the following day’s (D) agreed bilateral EXCHANGE PROGRAM per border (CAX) concerning their borders. G2.2. CONTROL BLOCK verification closure. The CONTROL BLOCK verification shall be completed by the CONTROL BLOCK OPERATOR till (D-1), 16:30. G3. Day-ahead CO-ORDINATION CENTRE verification (D-1 for D). G3.1. Data exchange CONTROL BLOCK – CO-ORDINATION CENTRE. Every day (D-1), the CONTROL BLOCK OPERATORS shall submit by 16:30 to their corresponding CO-ORDINATION CENTRE the following day’s (D) agreed EXCHANGE PROGRAMS concerning their borders. G3.2. CO-ORDINATION CENTRE verification closure. The CO-ORDINATION CENTRE verification has to be completed by the CO-ORDINATION CENTRES till (D-1), 17:00. G4. Intra-day control area verification (during D). G4.1. CONTROL AREA verification. The CONTROL AREA OPERATORS have to agree with the neighbouring CONTROL AREA OPERATORS the bilateral exchanges per border (CAS) for every time unit. G4.2. CONTROL AREA verification closure. The CONTROL AREA verification has to be completed by the CONTROL AREA OPERATORS not later than 45 minutes before setting a schedule into force. G5. Intra-day CONTROL BLOCK verification (during D). G5.1. Data exchange CONTROL AREA – CONTROL BLOCK. In case of intra–day changes of the EXCHANGE SCHEDULES, the CONTROL AREA OPERATORS have to submit at least 45 minutes before setting a schedule into force the agreed valid EXCHANGE SCHEDULES concerning their borders to their corresponding CONTROL BLOCK OPERATOR. G5.2. Details of exchange data. For each time unit, the CONTROL AREA OPERATOR has to submit the total bilateral exchange per CONTROL AREA border (CAX) to the CONTROL BLOCK OPERATOR. G5.3. CONTROL BLOCK validation. The CONTROL BLOCK OPERATOR has to validate the scheduling data received from the CONTROL AREAS. Schedules having any changes in a time unit not allowed (out of the past) will be rejected. G5.4. CONTROL BLOCK verification. The CONTROL BLOCK OPERATOR has to submit the bilateral exchange schedules of all affected control areas (CBS) and agree with the neighbouring CONTROL BLOCK OPERATORS the bilateral EXCHANGE SCHEDULES for the corresponding CONTROL AREAS for every time unit G5.5. CONTROL BLOCK verification closure. The CONTROL BLOCK verification has to be completed by the CONTROL BLOCK OPERATOR not later than 30 minutes before setting a schedule into force. G6. Intra-day CO-ORDINATION CENTRE verification (during D). G6.1. Data exchange CONTROL BLOCK – CO-ORDINATION CENTRE. In case of intra– day changes of exchange schedules, the CONTROL BLOCK OPERATORS have to submit at least 30 minutes before setting a schedule into force the agreed valid EXCHANGE SCHEDULES concerning their borders to their corresponding COORDINATION CENTRE. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–6 G6.2. Details of exchange data. For each time unit, the CONTROL BLOCK operator has to submit bilateral exchange schedules per CONTROL AREA border (CBS) to the CO-ORDINATION CENTRE. G6.3. CO-ORDINATION CENTRE validation. The CO-ORDINATION CENTRE has to validate the scheduling data received from the CONTROL BLOCKS. Schedules having any changes in a time unit not allowed (out of the past) will be rejected. G6.4. CO-ORDINATION CENTRE verification. The CO-ORDINATION CENTRE has to verify and agree with the neighbouring CO-ORDINATION CENTRE the bilateral EXCHANGE SCHEDULES for the corresponding CONTROL AREAS (CCT) for every time unit. G6.5. CO-ORDINATION CENTRE verification closure. The CO-ORDINATION CENTRE verification has to be completed by the CO-ORDINATION CENTRES not later than 15 minutes before setting a schedule into force. G7. Confirmation of verified EXCHANGE SCHEDULES. G7.1. CO-ORDINATION CENTRE verification. After completion of the CO-ORDINATION CENTRE verification, the CO-ORDINATION CENTRES have to confirm the agreed EXCHANGE SCHEDULES to the CONTROL BLOCK OPERATORS by a confirmation report. G7.2. CONTROL BLOCK verification. After receipt of the CO-ORDINATION CENTRE confirmation, the completion of the CONTROL BLOCK verification has to be confirmed by the CONTROL BLOCK OPERATORS to the CONTROL AREA OPERATORS by a confirmation report. G8. Nomination. It is recommended to use unambiguous identification procedures for the market participants involved in the case of nomination for exchange schedules crossing control area borders. G9. ELECTRONIC HIGHWAY. For data exchange, the ELECTRONIC HIGHWAY shall be used with FTP protocol. G10. Data exchange. G10.1. For data exchange, the procedures defined in the ETSO ESS are recommended G10.2. For the identification of market participants, the EIC or EAN standard is recommended G11. Schedule registration at the CONTROL AREA by market participants. The market participants’ schedules are registered until 14:30 of D-1 at the CONTROL AREA. The CONTROL AREA OPERATOR verifies the correctness of the EXCHANGE SCHEDULES and informs the parties involved as soon as possible (acknowledgement-, anomaly-, confirmation report). G12. Gate closure for schedule verification between market participants. In case the do not have the same value on both sides of the border by 15:45 of D-1, the following rules shall be applied: EXCHANGE PROGRAMS G12.1. Where no previous EXCHANGE SCHEDULE is available and the registered EXCHANGE SCHEDULES do not have the same delivery direction, the EXCHANGE SCHEDULE is set to zero. G12.2. Where no previous EXCHANGE SCHEDULE is available and the registered EXCHANGE SCHEDULES have the same delivery direction, the EXCHANGE SCHEDULE is set to the lower absolute value. G12.3. CONTROL AREA OPERATORS in the same CONTROL BLOCK may define other rules with market participants. These rules have to be agreed with all the CONTROL AREA OPERATORS within this CONTROL BLOCK UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) G13. !P2–7 Gate closure for intra-day schedule. In case the EXCHANGE PROGRAMS do not have the same value on both sides of the border in intra-day scheduling, the EXCHANGE SCHEDULE previously nominated (if any) will stay valid. Procedures P1. CONTROL AREA verification (see "P2-A-S1). P1.1. Verification routines. P1.1.1. The verification routines are performed by the CONTROL AREA OPERATOR together with the neighbouring CONTROL AREAS in order to ensure clear scheduling data. P1.1.2. The CONTROL AREA OPERATORS verify per time unit if the EXCHANGE SCHEDULES per border are equal for both CONTROL AREA OPERATORS. If an error is detected by the verification routines, troubleshooting is applied between the CONTROL AREA OPERATORS concerned. P1.2. Troubleshooting. P1.2.1. The CONTROL AREA exchange per market participant (CAS) is necessary. P1.2.2. Identification of faulty time unit. P1.2.3. Identification of the faulty individual border crossing market participant schedule and corresponding information of the market participant concerned. P1.2.4. The affected market participant sends the corrected EXCHANGE SCHEDULE to relevant CONTROL AREAS. P1.3. Fault correction. Market participant agree with affected CONTROL AREA on a corrected common value. P2. CONTROL BLOCK validation (see "P2-A-S2.3). P2.1. Checking routines. P2.1.1. The checking routines are performed by the CONTROL BLOCK OPERATOR himself in order to ensure the validity of the complete data set concerning the CONTROL BLOCK. P2.1.2. The CONTROL BLOCK OPERATOR validates whether the data related to the internal borders of the underlying CONTROL AREAS in comparison to the corresponding CONTROL AREAS sum up to zero. If the checking routines fail, troubleshooting is applied. P2.2. Troubleshooting P2.2.1. Identification of the bilateral border (s) between CONTROL AREAS where the fault applies. P2.2.2. Identification of the faulty time unit. P2.2.3. Identification of the faulty individual border crossing market participant EXCHANGE SCHEDULE by affected CONTROL AREA (STEP P1.2) P2.3. Fault correction. Ask the corresponding CONTROL AREA OPERATORS to agree on a corrected common value with the respective market participant. P3. CONTROL BLOCK verification (see"P2-A-S2.4). P3.1. Verification routines. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–8 P3.1.1. The verification routines are performed by the CONTROL BLOCK OPERATOR together with the neighbouring CONTROL BLOCKS in order to ensure clear scheduling data. P3.1.2. The CONTROL BLOCK OPERATORS verify per time unit whether the total EXCHANGE PROGRAM per CONTROL AREA border is equal for both CONTROL BLOCK OPERATORS. If the verification routines fail, troubleshooting is applied between the CONTROL BLOCK OPERATORS concerned. P3.2. Troubleshooting. P3.2.1. Identification of the bilateral border (s) between CONTROL AREAS where the fault appears. P3.2.2. Identification of the faulty time unit. P3.2.3. Identification of the faulty CONTROL AREA border. P3.2.4. Identification of the faulty individual border crossing market participant schedule by affected CONTROL AREA (STEP P1.2.) P3.3. Fault correction. Ask the corresponding CONTROL AREA OPERATORS to agree on a corrected common value with the respective market participant. P4. CO-ORDINATION CENTRE validation (see "P2-A-S3.3). P4.1. Checking routines. P4.1.1. The checking routines are performed by the CO-ORDINATION CENTRE itself in order to ensure the validity of the complete data set concerning the CO-ORDINATION CENTRE. P4.1.2. The CO-ORDINATION CENTRE validates whether the data related to the internal borders of the underlying CONTROL BLOCKS sum up to zero. If the checking routines fail, troubleshooting is applied. P4.2. Troubleshooting P4.2.1. Identification the bilateral border (s) between CONTROL BLOCKS where the fault appears. P4.2.2. Identification the faulty time unit. P4.2.3. Identification of the faulty individual CONTROL AREA border. P4.3. Fault correction. Ask the corresponding CONTROL BLOCK OPERATORS to clear the fault. P5. CO-ORDINATION CENTRE verification (see "P2-A-S3.4). P5.1. Verification routines. P5.1.1. The verification routines are performed by the CO-ORDINATION CENTRE together with the neighbouring CO-ORDINATION CENTRE in order to ensure clear scheduling data. P5.1.2. The CO-ORDINATION CENTRES verify per time unit whether the bilateral EXCHANGE PROGRAM per CONTROL AREA border is equal for both COORDINATION CENTRES. If the verification routines fail, troubleshooting is applied between the CO-ORDINATION CENTRES concerned. P5.2. Troubleshooting. P5.2.1. The CO-ORDINATION CENTRES exchange the bilateral EXCHANGE PROGRAMS for the CONTROL AREAS (CCT) at the border between the CO-ORDINATION CENTRES for every time unit. P5.2.2. Identification of the faulty time unit. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–9 P5.2.3. Identification of the faulty CONTROL BLOCK border. P5.2.4. Identification the faulty individual CONTROL AREA border. P5.3. Fault correction. Ask the corresponding CONTROL BLOCK and CONTROL AREA OPERATORS to clear the fault. Measures M1. Data exchange. M1.1. Day ahead (D-1 for D) M1.1.1. CONTROL AREA. If the CONTROL AREA OPERATOR (s) does (do) not submit the data to the CONTROL BLOCK OPERATOR in time (see "P2-AS2.1) and can not find a common solution with the control block operator, the CONTROL BLOCK OPERATOR shall set these data to zero and inform the CONTROL AREA OPERATOR accordingly. The CONTROL AREA OPERATOR has to arrange the setting with the market participants. M1.1.2. CONTROL BLOCK. If the CONTROL BLOCK OPERATOR (s) does (do) not submit the data to the CO-ORDINATION CENTRE in time (see "P2-AS3.1), and can not find a common solution with the co-ordination centre, the CO-ORDINATION CENTRE shall set these data to zero and inform the CONTROL BLOCK OPERATOR accordingly. The CONTROL BLOCK OPERATOR shall inform the CONTROL AREA OPERATOR, and the CONTROL AREA OPERATOR has to arrange the setting with the market participants. M1.2. Intra-day (during D) M1.2.1. CONTROL AREA. If the CONTROL AREA OPERATOR (s) does (do) not submit the data to the CONTROL BLOCK OPERATOR in time, the CONTROL BLOCK OPERATOR shall validate the data previously agreed and inform the CONTROL AREA OPERATOR accordingly. The CONTROL AREA OPERATOR has to arrange the setting with the market participants. M1.2.2. CONTROL BLOCK. If the CONTROL BLOCK OPERATOR (s) does (do) not submit the data to the CO-ORDINATION CENTRE in time, the COORDINATION CENTRE shall validate the data previously agreed and inform the CONTROL BLOCK OPERATOR accordingly. The CONTROL BLOCK operator will inform the CONTROL AREA OPERATOR, and the CONTROL AREA OPERATOR has to arrange the setting with the market participants. M2. Data validation. M2.1. Day ahead (D-1 for D) M2.1.1. CONTROL BLOCK. If the CONTROL BLOCK OPERATOR is not able to validate in due time the scheduling data with the CONTROL AREAS concerned and can not find a common solution with CONTROL AREA OPERATORS, (see "P2-A-S2.3), the CONTROL BLOCK OPERATOR shall decide which CONTROL AREA data are relevant for scheduling and inform the CONTROL AREA OPERATOR accordingly. The CONTROL AREA OPERATOR has to arrange the setting with the market participants. M2.1.2. CO-ORDINATION CENTRE. If the CO-ORDINATION CENTRE is not able to validate in due time the scheduling data with the CONTROL BLOCKS concerned and cannot find a common solution with control block operators, (see "P2-A-S3.3) the CO-ORDINATION CENTRE shall decide which CONTROL BLOCK data are relevant for scheduling, and inform the CONTROL BLOCK OPERATOR accordingly. The CONTROL BLOCK OPERATOR will inform the CONTROL AREA OPERATOR, and the CONTROL AREA OPERATOR has to arrange the setting with the market participants. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–10 M2.2. Intra-day (during D) M2.2.1. CONTROL BLOCK. If the CONTROL BLOCK OPERATOR is not able to validate in due time the scheduling data with the CONTROL AREAS concerned, the CONTROL BLOCK OPERATOR shall decide which CONTROL AREA data are relevant for scheduling, and inform the CONTROL AREA OPERATOR accordingly. The CONTROL AREA OPERATOR has to arrange the setting with the market participants. M2.2.2. CO-ORDINATION CENTRE. If the CO-ORDINATION CENTRE is not able to validate in due time the scheduling data with the CONTROL BLOCKS concerned, the CO-ORDINATION CENTRE shall decide which CONTROL BLOCK data are relevant for scheduling, and inform the CONTROL BLOCK OPERATOR accordingly. The CONTROL BLOCK OPERATOR shall inform the CONTROL AREA OPERATOR, and the CONTROL AREA OPERATOR has to arrange the setting with the market participants. M3. Data verification. M3.1. CONTROL AREA. If the CONTROL AREA OPERATOR is not able to verify in due time with a neighbouring CONTROL AREA the EXCHANGE PROGRAM per border (see "P2-A-S1.1) he should seek guidance from the CONTROL BLOCK OPERATORS. Follow STEP M2.1.1 / M2.2.1. M3.2. CONTROL BLOCK. If the CONTROL BLOCK OPERATOR is not able to verify in due time with a neighbouring CONTROL BLOCK the EXCHANGE PROGRAM per border (see "P2-A-S2.4) he should seek guidance from the CO-ORDINATION CENTRE (s). Follow STEP M2.1.2 / M2.2.2. M3.3. CO-ORDINATION CENTRE. If the CO-ORDINATION CENTRE is not able to verify in due time with a neighbouring CO-ORDINATION CENTRE the EXCHANGE PROGRAM per border (see "P2-A-S3.4) the two CO-ORDINATION CENTRES shall jointly decide which data are relevant for scheduling and inform the CONTROL BLOCK OPERATOR accordingly. The CONTROL BLOCK OPERATOR shall inform the CONTROL AREA OPERATOR, and the CONTROL AREA OPERATOR has to arrange the setting with the market participants. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) B. !P2–11 Online Observation This policy section replaces the corresponding sections for online observation in the latest “UCPTE-Ground Rules concerning the Co-ordination of the accounting and organisation of LFC within the UCPTE”, dated 1999. Introduction The task of online observation is performed during the system operation phase. In order to prevent systematic faults in the context of LOAD FREQUENCY CONTROL (see Policy 1) it is essential to check the UCTE-wide consistency of the input variables for online operation used by the single parties involved. This comprises the control deviation used as an input value for LOAD FREQUENCY CONTROL as well as the real-time observation of border-crossing exchange power flows and EXCHANGE PROGRAMS among all CONTROL AREAS / CONTROL BLOCKS of UCTE. Criteria C1. CONTROL PROGRAMS. The sum of CONTROL PROGRAMS of all CONTROL BLOCKS of a SYNCHRONOUS AREA must be equal to zero at any time. C2. Physical Exchange. The sum of the measurements of the physical exchange of all of a SYNCHRONOUS AREA must be equal to zero at any time (taking account of the measurement’s range of accuracy). CONTROL BLOCKS C3. C7. POWER DEVIATION. C4. The sum of POWER DEVIATIONs of all CONTROL AREAS of a CONTROL BLOCK must be equal to the POWER DEVIATION of the CONTROL BLOCK concerned (taking account of the measurement’s range of accuracy). C5. The sum of POWER DEVIATIONs of all CONTROL BLOCKS in the area of a COORDINATION CENTRE must be equal to the POWER DEVIATION calculated with respect to the external border of the CO-ORDINATION CENTRE concerned (taking account of the measurement’s range of accuracy). C6. The sum of POWER DEVIATIONS of all CONTROL BLOCKS of a SYNCHRONOUS AREA must be equal to zero at any time. Calculated power deviations are those power deviations which could be generated independently by the control block using the control programs and the transmitted measurements Requirements R1. Accuracy of power measurements. The accuracy of ACTIVE POWER measurement on the OBSERVATION LINE is determined by the accuracy of the measurement chain. The sampling rate of measurements must not exceed 10 seconds. R2. Transmission of measurements. R2.1. The measurements of the TIE-LINE power flows crossing the border of a CONTROL AREA must be transmitted in a reliable manner to the corresponding operator of a CONTROL BLOCK by each CONTROL AREA (with an alarm in case of deficiency of a data transmission). The transmission delay must be shorter than 15 seconds. R2.2. The measurements of the TIE-LINE power flows crossing the border of a CONTROL BLOCK must be transmitted in a reliable manner to the corresponding CO-ORDINATION CENTRE by each CONTROL BLOCK (with an alarm in case of UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–12 deficiency of a data transmission). The transmission delay must be shorter than 15 seconds. R3. Transmission of POWER DEVIATIONS. R3.1. The measurements of POWER DEVIATIONS of the CONTROL AREAS must be transmitted in a reliable manner to the corresponding operator of the CONTROL BLOCK by each CONTROL AREA (with an alarm in case of deficiency of a data transmission). The transmission delay must be shorter than 15 seconds. R3.2. The measurements of the POWER DEVIATIONS of the CONTROL BLOCKS must be transmitted in a reliable manner to the corresponding CO-ORDINATION CENTRE by each CONTROL BLOCK (with an alarm in case of deficiency of a data transmission). The transmission delay must be shorter than 15 seconds. Standards S1. Perturbation of measurement equipment. S1.1. The operator of the relevant CONTROL AREA has to inform the neighbouring CONTROL AREA OPERATORS and the corresponding operator of the CONTROL BLOCK on any perturbation in the measurement equipment with regard to the physical exchange crossing the borders with other neighbouring CONTROL AREAS. S1.2. The operator of the relevant CONTROL BLOCK has to inform the neighbouring CONTROL BLOCK OPERATORS and the corresponding CO-ORDINATION CENTRE about any perturbation in the measurement equipment with regard to the physical exchange crossing the borders with other neighbouring CONTROL BLOCKS. S2. Detection of abnormal operation. The OBSERVATION OF UNINTENTIONAL DEVIATIONS by the CO-ORDINATION CENTRES allows to identify and to correct as soon as possible abnormal operating and ACCOUNTING situations (e.g.: abnormal values of TIE-LINE telemeasurements (TMs), misunderstanding in setting the EXCHANGE SCHEDULE of a CONTROL BLOCK, etc.). Guidelines G1. Data Transmission of the CONTROL AREA. The responsible of each CONTROL AREA shall transmit to the corresponding CONTROL BLOCK the CONTROL PROGRAM set on its load-frequency controller after any modification of this program. G2. Data Transmission of the CONTROL BLOCK. The responsible party of each CONTROL BLOCK shall transmit in real time to the corresponding CO-ORDINATION CENTRE the CONTROL PROGRAM set on its load-frequency controller after any modification of this program. G3. Should the transmitted POWER DEVIATION of a CONTROL AREA differ from the POWER by the CONTROL BLOCK, the operator of the relevant CONTROL immediately the corresponding operators of the CONTROL AREAS in order to solve the problem. DEVIATION calculated BLOCK has to contact G4. Should the transmitted POWER DEVIATION of a CONTROL BLOCK differ from the POWER DEVIATION calculated by the CO-ORDINATION CENTRE, the operator of the relevant COORDINATION CENTRE has to contact immediately the corresponding operator of the relevant CONTROL BLOCK in order to solve the problem. G5. Acquisition of TIE-LINE metering. The CONTROL BLOCK OPERATORS shall acquire the provisional metering data of the TIE-LINES to ADJACENT CONTROL BLOCKS to record the energy in the time-frame used for power exchanges. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) G3. !P2–13 Exchange of metered data. The CO-ORDINATION CENTRE shall be provided with data of total hourly scheduled exchanges for each CONTROL BLOCK and real-time ACTIVE 1 POWER TMs of each TIE-LINE crossing the border of the CO-ORDINATION CENTRE area. Measures M1. In case that the sum of the of POWER DEVIATIONS of the CONTROL AREAS in a CONTROL BLOCK is not equal to the POWER DEVIATION of the CONTROL BLOCK, the operator of the relevant CONTROL BLOCK shall immediately contact the corresponding operators of the CONTROL AREAS in order to solve the problem. M2. In case that the sum of the of POWER DEVIATIONS of the CONTROL BLOCKS in the area of a CO-ORDINATION CENTRE is not equal to the POWER DEVIATION calculated with respect to the external border of the CO-ORDINATION CENTRE concerned, the COORDINATION CENTRE shall immediately contact the corresponding operator of the CONTROL BLOCKS in order to solve the problem. M3. In case that the sum of the CONTROL PROGRAMS of the CONTROL AREAS in a CONTROL BLOCK is not equal to CONTROL PROGRAM of the CONTROL BLOCK, the operator of the relevant CONTROL BLOCK shall immediately inform automatically the corresponding operator of the CONTROL AREAS. M4. In case that the sum of the CONTROL PROGRAMS of all CONTROL BLOCKS in the SYNCHRONOUS AREA is not equal to zero, the responsible CO-ORDINATION CENTRE shall immediately inform automatically the corresponding operators of the CONTROL BLOCKS. ( ) 1 Including virtual tie-lines that may exist for the operation of jointly owned power plants. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–14 C. Accounting of unintentional deviations [UCTE Ground Rule 99 Co-ordination of the accounting and organisation of LFC] [UCTE Recommendation 88 Recording and offsetting of unintentional deviations] This policy section replaces the corresponding sections for accounting of inadvertent exchange in the latest “UCPTE-Ground Rules concerning the “Co-ordination of the accounting and organisation of LFC”, dated 1999. Introduction The task of accounting of UNINTENTIONAL DEVIATIONS is performed "after the fact", i.e. at the next working day following the system operation. It comprises the settlement of the account of UNINTENTIONAL DEVIATIONS of each CONTROL AREA / CONTROL BLOCK with reference to a recording period. The COMPENSATION OF UNINTENTIONAL DEVIATIONS is performed by using a program of compensation "in kind" within the compensation period - as an import / export of the corresponding amount of energy per tariff period, that was accumulated in the recording period. Accounting is an important issue to check the UCTE-wide consistency of the input variable "COMPENSATION PROGRAM" used by the single parties involved in order to prevent systematic faults in the context of LOAD FREQUENCY CONTROL (see Policy 1). The COMPENSATION PROGRAMSof all CONTROL BLOCKS within UCTE must sum up to zero. Criteria C1. EXCHANGE PROGRAMS. The EXCHANGE PROGRAMS must have the same value on both sides of the border. C2. Types of physical energy exchange C2.1. TIE-LINE Flows ET. The sum of the tie line flows on a border between two CONTROL AREAS / CONTROL BLOCKS must have the same value on both sides of the border. C2.2. VIRTUAL TIE-LINE Flows EVT. The sum of the virtual tie line flows between two CONTROL AREAS / CONTROL BLOCKS must have the same value on both sides of the border. C3. C4. UNINTENTIONAL DEVIATION. Calculation of UNINTENTIONAL DEVIATIONS of a CONTROL AREA / CONTROL BLOCK for ACCOUNTING purposes: UD = ET – (CAS + EVT). The sum of all UNINTENTIONAL DEVIATIONS of a SYNCHRONOUS AREA must be equal to zero. Compensation of UNINTENTIONAL DEVIATIONS. The sum of all COMPENSATION for each time unit of a SYNCHRONOUS AREA must be equal to zero. PROGRAMS C5. Accounting point. One side of a TIE-LINE representing an interconnection point is defined as “accounting point“, if it is used as unique basis for accounting of both adjacent TSOs. C6. Virtual accounting point represents a point, associated to a TIE-LINE, for which energy exchange is calculated, using the meters on both sides of the TIE-LINE. That energy exchange is used as unique basis for accounting of both adjacent TSOs. The algorithm for this calculation is agreed between adjacent TSOs C7. Tariff period is the time interval (e.g. season, holiday, working day, etc.) during which DEVIATIONS are attributed the same value for offsetting by compensation in kind (see Appendix). The accumulation of UNINTENTIONAL DEVIATIONS within the recording period is performed separately for each tariff period. UNINTENTIONAL C8. Working day is the calendar day except Saturday, Sunday and 4 holidays: Christmas, New Year, Easter Monday and Ascension. C9. Recording period is the time interval for which UNINTENTIONAL DEVIATIONS for specific CONTROL AREA should be summed up separately for each tariff period. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) C10. !P2–15 Compensation period is the time interval during which the CONTROL AREA / CONTRTOL of UNINTENTIONAL DEVIATIONS according to the calculated BLOCK is clearing the balance COMPENSATION PROGRAM. Requirements R1. Time Basis. The UTC (universal time co-ordinated) is the time reference. R2. Time Frame. The time frame for ACCOUNTING of UNINTENTIONAL DEVIATIONS has to correspond with the time frame of the EXCHANGE PROGRAM (1h, ½ h, ¼ h); this time frame applies to the figures ET, EVT, UD and COMP. R3. Resolution. The operators of neighbouring CONTROL AREAS have to agree on the resolution for the validation of the energy exchange on their common border. The resolution for the validation of the EXCHANGE PROGRAM is the integer value of MWh for the time frame ti = 1h and the integer MWh value with 3 decimal digits for the time frame ti = ½ h or ¼ h. R4. Physical energy exchange R4.1. Data. The physical energy exchange is represented by electricity meter values per accounting point and time unit. The time frame and the energy unit must be the same on a common border between two CONTROL AREAS. R4.2. The electricity meter values from the accounting point should be used by all partners involved as unique representation of the physical energy exchange concerning the interconnection point. R5. Accounting point. R5.1. The partners at a common border have to agree on a common accounting point or virtual accounting point. R5.2. The location of the accounting point has to be bilaterally determined. Usually it is located within the substation close to the border between two partners. R6. Physical energy exchange – metering. R6.1. Voltage and current transformer. Voltage and current transformers have to be operated at each accounting point. Voltage and current transformers at the accounting points should have an accuracy class rating of 0.2. Current transformers should have 2 cores for measurement purposes. R6.2. Electricity metering. On the basis of the current and voltage values measured by the transformers, the electricity meters determine the active energy flow in both directions related to a given time frame. The electricity meters at the accounting points should have an accuracy class rating of 0.2. R6.3. Redundancy. Accounting points should be equipped with main and check meters at each TIE-LINE. Main and check meter should be connected each to a separate core of the current transformer. R6.4. Transformer cables. Due to the accuracy of the whole metering, voltage transformer cables should be designed in such a way that a voltage drop is reduced to 0.1% or less of the nominal voltage. R6.5. Telecounter. The task of a telecounter is the acquisition of metered values from the electricity meters at the accounting point and the teletransmission of this data to the central accounting office of each partner concerned (remote meter reading). The counters at an accounting point should be doubled. For the sake of uniqueness, the data-flow from the electricity meters to the accounting offices has to be agreed unanimously between the partners sharing the accounting point. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–16 R6.6. Availability. Every working day (D+1), metered values of the past working day (D) have to be available at the accounting office by 09:00; after a weekend / holidays, data for additional days have to be made available accordingly. R7. Data exchange among partners. R7.1. Electronic data exchange is required (e.g. ELECTRONIC HIGHWAY, ftp-dial-in via ISDN-line, e-mail; phone and fax as back-up if electronic communication is disturbed). R7.2. The data exchange format has to be agreed among the partners. R7.3. Standardisation. It is necessary to standardise the data exchange formats within a CONTROL BLOCK, within a CO-ORDINATION CENTRE and between the COORDINATION CENTRES. R8. Rounding. The operators of CONTROL AREAS and CONTROL BLOCKS have to agree on the rounding rules for the calculation of the UNINTENTIONAL DEVIATION and the COMPENSATION PROGRAMS. R9. Availability. Accounting offices should be available on working days from 08:00. to 16:00. Standards S1. Scheduled energy exchange. The highest valid version of the data exchange sheets CAX / CBX has to be used by the CO-ORDINATION CENTRES for ACCOUNTING. S2. Physical energy exchange ET / EVT. S2.1. TSOs operating a common TIE–LINE or VIRTUAL TIE–LINE have to agree on unique meter values for every time unit. S2.2. In case of problems concerning metering or telecounting equipment the TSOs operating a common TIE–LINE or VIRTUAL TIE–LINE have to agree on unique substitute meter values for every time unit. S3. CONTROL BLOCK settlement per workday (D+1 for D). S3.1. Data exchange between CONTROL BLOCK – CO-ORDINATION CENTRE. Every working day (D+1), the CONTROL BLOCK OPERATORS have to submit by 11:00 the past working day’s (D) metered values of their TIE – LINES / VIRTUAL TIE – LINES to their corresponding CO-ORDINATION CENTRE; after the weekend / holidays, additional data for additional days have to be made available accordingly. S3.2. Details of exchange data. For each time unit, the CONTROL BLOCK OPERATOR has to submit at least the bilateral sum of metered values per CONTROL BLOCK border to the CO-ORDINATION CENTRE. S3.3. CONTROL BLOCK validation. The CO-ORDINATION CENTRE has to validate the accounting data received from the CONTROL BLOCKS until 14:00. S3.4. CONTROL BLOCK settlement. The CO-ORDINATION CENTRE has to calculate the single CONTROL BLOCK’S account of UNINTENTIONAL DEVIATIONS for every tariff period for the day before (D), 24:00 and submit the result to the CONTROL BLOCK OPERATOR concerned. The data has to be confirmed by the CONTROL BLOCK OPERATOR. S3.5. CONTROL BLOCK settlement closure. The CONTROL BLOCK validation and the CONTROL BLOCK settlement have to be completed as soon as possible, but not later than (D+1), 16:00. S4. CO-ORDINATION CENTRE settlement per workday (D+1 for D). UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–17 S4.1. CO-ORDINATION CENTRE validation. The CO-ORDINATION CENTREs have to calculate the sum of the CONTROL BLOCK’S account of UNINTENTIONAL DEVIATIONS for every tariff period for the day before (D), 24:00 and validate the result vice-versa not later than (D+1), 16:00. S4.2. Confirmation of the settlement per workday. The CO-ORDINATION CENTRES have to submit to the CONTROL BLOCK OPERATORS the account of UNINTENTIONAL DEVIATIONS for every tariff period for the day before (D), 24:00 after the completion of the CO-ORDINATION CENTRE validation. S5. Final CONTROL AREA settlement of a recording period. S5.1. Data exchange CONTROL AREA – CONTROL BLOCK. Corrections concerning the data exchanged during the daily settlement on working days have to be taken into account for the final CONTROL AREA settlement of a recording period if they are submitted from the CONTROL AREA OPERATORS to their corresponding CONTROL BLOCK OPERATOR by 10:00 two working days before the start of the compensation period. S5.2. CONTROL AREA validation. The CONTROL BLOCK OPERATOR has to validate the accounting data received from the CONTROL AREAS. S5.3. CONTROL AREA settlement. The CONTROL BLOCK OPERATOR shall calculate the single CONTROL AREA’S final account of UNINTENTIONAL DEVIATIONS for every tariff period for the last day of the recording period by 24:00 as well as the resulting COMPENSATION PROGRAMS of the recording period, and submit the result to the CONTROL AREA OPERATOR concerned; the data has to be confirmed by the CONTROL AREA OPERATOR. S5.4. CONTROL AREA settlement closure. The final CONTROL AREA validation and the final CONTROL AREA settlement have to be completed by 12:00, at the latest, two working days before the start of the compensation period. S6. Final CONTROL BLOCK settlement of a recording period. S6.1. Data exchange between CONTROL BLOCK – CO-ORDINATION CENTRE. Corrections concerning the data exchanged during the daily settlement on working days have to be taken into account for the final CONTROL BLOCK settlement of a recording period if they are submitted from the CONTROL BLOCK OPERATORS to their corresponding CO-ORDINATION CENTRE by 12:00, at the latest, two working days before the start of the compensation period. S6.2. CONTROL BLOCK validation. The CO-ORDINATION CENTRE has to validate the accounting data received from the CONTROL BLOCKS. S6.3. CONTROL BLOCK settlement. The CO-ORDINATION CENTRE shall calculate the single CONTROL BLOCK’S final account of UNINTENTIONAL DEVIATIONS for every tariff period for the last day of the recording period, 24:00, as well as the resulting COMPENSATION PROGRAMS of the recording period, and submit these results to the CONTROL BLOCK OPERATOR concerned; the data has to be confirmed by the CONTROL BLOCK OPERATOR. S6.4. CONTROL BLOCK settlement closure. The final CONTROL BLOCK validation and the final CONTROL BLOCK settlement have to be completed by 16:00, at the latest, two working days before the start of the compensation period. S7. Final CO-ORDINATION CENTRE settlement of a recording period. S7.1. CO-ORDINATION CENTRE validation. The CO-ORDINATION CENTRES shall calculate the sum of the CONTROL BLOCK’S final account of UNINTENTIONAL DEVIATIONS for every tariff period for the last day of the recording period, 24:00, as well as the resulting COMPENSATION PROGRAMS of the recording period, and validate the result vice-versa by 9:00 one working day before the start of the compensation period. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) S8. !P2–18 Confirmation of the final settlement. S8.1. Within 30 minutes after the final CO-ORDINATION CENTRE settlement of a recording period, the CO-ORDINATION CENTRES have to confirm the CONTROL BLOCK OPERATORS the agreed COMPENSATION PROGRAMS. S8.2. Within 30 minutes after the confirmation of the CO-ORDINATION CENTRES, the CONTROL BLOCK OPERATORS have to confirm the CONTROL AREA OPERATORS the agreed COMPENSATION PROGRAMS accordingly. S9. Transparency. The EXCHANGE PROGRAMS and the physical exchange between CONTROL BLOCKS have to be published according to a common information system for TSOs (VULCANUS) within 30 minutes after final settlement. S10. Confidentiality. The data used for accounting may not be transmitted to third parties without authorisation. Guidelines G1. CONTROL AREA settlement per working day (D+1 for D). G1.1. Data exchange between CONTROL AREA – CONTROL BLOCK. Every working day (D+1), the CONTROL AREA OPERATORS have to submit by 11:00 the metered values of the past working day (D) of their tie-lines / virtual tie-lines to their corresponding CONTROL BLOCK OPERATOR; after the weekend / holidays, data for additional days have to be made available accordingly. G1.2. Details of exchange data. For each time unit, the CONTROL AREA OPERATOR has to submit at least the bilateral sum of metered values per CONTROL AREA border to the CONTROL BLOCK OPERATOR. G1.3. CONTROL AREA validation. The CONTROL BLOCK OPERATOR has to validate the accounting data received from the CONTROL AREAS by 14:00. G1.4. CONTROL AREA settlement. The CONTROL BLOCK OPERATOR shall calculate the single CONTROL AREA’S account of UNINTENTIONAL DEVIATIONS for every tariff period for the day before (D), 24:00, and submit the result to the CONTROL AREA OPERATOR concerned. The data has to be confirmed by the CONTROL AREA OPERATOR. G1.5. CONTROL AREA settlement closure. The CONTROL AREA validation and the CONTROL AREA settlement have to be completed as soon as possible, but not later than (D+1), 16:00. G2. Accounting point location. The location of the accounting points shall be the same as the location of the measurement values used for load frequency control (see "P1A-R1.3). G3. Physical energy exchange ET / EVT. TSOs operating a common TIE-LINE OR VIRTUAL TIE-LINE should read the same agreed meter value via telecounter which ensures that always unique meter values are used for every time unit by all partners involved. G4. Data exchange between partners. G4.1. ELECTRONIC HIGHWAY. For data exchanges, the ELECTRONIC HIGHWAY should be used. G4.2. Details of data exchange between CONTROL AREA – CONTROL BLOCK. It is recommended that the CONTROL AREA OPERATOR submits for each time unit the single meter values of the TIE-LINES / VIRTUAL TIE-LINES to the CONTROL BLOCK OPERATOR. G4.3. Details of data exchange between CONTROL BLOCK – CO-ORDINATION CENTRE. It is recommended, that the CONTROL BLOCK OPERATOR submits for each time UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–19 unit the single meter values of the TIE-LINES / VIRTUAL TIE-LINES to the COORDINATION CENTRE. G5. Quality of on-line observation and accounting. It is recommended that every partner regularly compares the measured values and the corresponding metered values of TIELINE flows (including virtual TIE-LINES) in order to detect early errors. G6. Unique definition of the data flow from the electricity meters to the accounting offices. If each partner uses an own telecounter with data from both main and check meter, one telecounter has to be declared as reference for accounting. Alternatively, each partner at the accounting point is connected to both telecounters and gets the main meter data from one telecounter and the check meter data from the other one. Both variants proposed provide unique values for all partners. G7. Maximum values of UNINTENTIONAL DEVIATIONS G7.1. Maximum values of hourly values of UNINTENTIONAL DEVIATIONS: If the value of UNINTENTIONAL DEVIATIONS during one hour within a CONTROL AREA considerably exceeds a reasonable value, compensation can be treated separately by the CO-ORDINATION CENTRES on request of the partners. G7.2. Maximum values of the account of UNINTENTIONAL DEVIATIONS: If the absolute value of the account of UNINTENTIONAL DEVIATIONs in a recording period of a CONTROL AREA considerably exceeds a reasonable value, compensation can be treated separately by the CO-ORDINATION CENTRES on request of partners concerned. Procedures P1. Recording period. P1.1. The standard recording period is defined to comprise 7 days (one week), from Monday, 0:00 to Sunday 24:00. P1.2. In case of bank holidays or change of tariff seasons, exceptions to this rule may occur. The CO-ORDINATION CENTRES agree on exceptions to the definition of the recording period and inform the CONTROL BLOCK OPERATORS 4 weeks before the start of the recording period accordingly. P1.3. A recording period should last at least 4 days. P2. Compensation period. P2.1. The standard compensation period is defined to comprise 7 days (one week), from Thursday, 0:00 to Wednesday 24:00 , the standard compensation period starts with a delay of three days off the end of the corresponding recording period. P2.2. In case of holidays or change of tariff seasons, exceptions to this rule may occur. The CO-ORDINATION CENTRES agree on exceptions to the definition of the compensation period and inform the CONTROL BLOCK OPERATORS 4 weeks before the start of the corresponding recording period accordingly. P2.3. A compensation period should last at least 4 days. P2.4. A compensation period has to start always with a delay of three working days off the end of the corresponding recording period. P3. CONTROL AREA validation (see "P2-C-G1.3, "P2-C-S5.2 ). P3.1. Checking routines. P3.1.1. The checking routines are performed by the CONTROL BLOCK OPERATOR itself in order to ensure the validity of the complete data set concerning the CONTROL BLOCK. UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–20 P3.1.2. The CONTROL BLOCK OPERATORS validate whether the data related to the internal borders of the underlying CONTROL AREAS sum up to zero. These routines are applied for the figures (CAS, ET and EVT). If the checking routines fail, troubleshooting is applied. P3.2. Troubleshooting. P3.2.1. Identify whether the fault applies to the EXCHANGE PROGRAM or the physical energy exchange on TIE-LINES ET or virtual TIE-LINES EVT. P3.2.2. Identify the bilateral border (s) between CONTROL AREAS where the fault occurs. P3.2.3. If the single (virtual) TIE-LINE flows are available: identify the (virtual) single TIE-LINE (s) between CONTROL AREAS where the fault occurs P3.3. Fault correction. The CONTROL BLOCK OPERATOR asks the corresponding neighbouring CONTROL AREA OPERATORS to agree on a corrected common value. P4. CONTROL AREA settlement (see "P2-C-S5.3). P4.1. Checking routines. P4.1.1. The checking routines are performed by the CONTROL BLOCK OPERATOR together with the underlying CONTROL AREAS in order to ensure the validity of the accounting results. P4.1.2. The CONTROL AREA OPERATORS validate whether the calculated account of UNINTENTIONAL DEVIATIONS per tariff period and – in case of the final settlement - the resulting Compensation Programs of the recording period is identical with the results submitted by the CONTROL BLOCK OPERATOR. If the checking routines fail, troubleshooting is applied between CONTROL BLOCK OPERATOR and CONTROL AREA OPERATOR. P4.2. Troubleshooting. P4.2.1. Identify the faulty tariff period(s) on the basis of the CONTROL AREA’S account of UNINTENTIONAL DEVIATIONS for every tariff period P4.2.2. Identify the faulty time unit(s) on the basis of the CONTROL AREA’S account of UNINTENTIONAL DEVIATIONS for every time unit P4.2.3. Follow STEP P3.2.1. P4.3. Fault correction. The CONTROL BLOCK OPERATOR asks the corresponding CONTROL AREA OPERATOR to agree on the corrected value. P5. CONTROL BLOCK validation (see "P2-C-S3.3, "P2-C-S6.2). P5.1. Checking routines. P5.1.1. The checking routines are performed by the CO-ORDINATION CENTRE itself in order to ensure the validity of the complete data set concerning the CO-ORDINATION CENTRE. P5.1.2. The CO-ORDINATION CENTRE validates whether the data related to the internal borders of the underlying CONTROL BLOCKS sum up to zero. These routines are applied for the figures (CAS, ET and EVT). If the checking routines fail, troubleshooting is applied. P5.2. Troubleshooting P5.2.1. Identify whether the fault applies to the EXCHANGE PROGRAM or the physical energy exchange on TIE-LINES ET or virtual TIE-LINES EVT UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) !P2–21 P5.2.2. Identify the bilateral border(s) between CONTROL BLOCKS where the fault occurs P5.2.3. If the bilateral sums of (virtual) TIE-LINE flows per CONTROL AREA border are available: identify the bilateral border (s) between CONTROL AREAS where the fault occurs; otherwise STEP P3.2.2 P5.2.4. If the single (virtual) TIE-LINE flows are available: identify the (virtual) single TIE-LINE (s) between CONTROL AREAS where the fault occurs; otherwise STEP P3.2.3 P5.3. Fault correction. The CO-ORDINATION CENTRE asks the corresponding neighbouring CONTROL BLOCK OPERATORS to agree on a corrected common value. P6. CONTROL BLOCK settlement (see "P2-C-S3.4, "P2-C-S6.3). P6.1. Checking routines. P6.1.1. The checking routines are performed by the CO-ORDINATION CENTRE together with the underlying CONTROL BLOCKS in order to ensure the validity of the accounting results. P6.1.2. The CONTROL BLOCK OPERATORS validate whether the calculated account of UNINTENTIONAL DEVIATIONS per tariff period and – in case of the final settlement - the resulting Compensation Programs of the recording period are identical with the results submitted by the COORDINATION CENTRE. If the checking routines fail, troubleshooting is applied between CO-ORDINATION CENTRE and CONTROL BLOCK OPERATOR. P6.2. Troubleshooting. P6.2.1. Identify the faulty tariff period (s) on the basis of THE CONTROL AREA’S account of UNINTENTIONAL DEVIATIONS for every price – rating time bracket P6.2.2. Identify the faulty time unit (s) on the basis of the CONTROL AREA’S account of UNINTENTIONAL DEVIATIONS for every time unit P6.2.3. Follow STEP P5.2.1 P6.3. Fault correction. The CO-ORDINATION CENTRE asks the corresponding CONTROL AREA OPERATOR to correct the value. P7. CO-ORDINATION CENTRE validation (see "P2-C-S4.1, "P2-C-S7.1). P7.1. Checking routines. P7.1.1. The checking routines are performed by the CO-ORDINATION CENTRES in order to ensure the validity of the complete UCTE data set. P7.1.2. The CO-ORDINATION CENTRES validate whether the data related to their external borders between the CO-ORDINATION CENTRES sum up to zero. These routines are applied for the figures (CAS, ET, EVT, UD and – in the case of final settlement - COMP). If the checking routines fail, troubleshooting is applied. P7.2. Troubleshooting. Follow STEP P5.2.1 P7.3. Fault correction. The CO-ORDINATION CENTRE asks the corresponding neighbouring CONTROL BLOCK OPERATORS to agree on a corrected common value. Measures UCTE OH – Policy 2: Scheduling and Accounting (final policy 2.2 E, 20.07.2004) M1. !P2–22 Substitute meter values. In case of S2.2 the following procedure is recommended: M1.1. If available, use the check meter values from the accounting point substation. M1.2. If available, use the main meter values from the adjacent substation. M1.3. If available, use the check meter values from the adjacent substation. M1.4. If available, use the integrated measurement values from the on-line observation (see subsection on-line observation). M1.5. Otherwise, the partners involved agree on the methodology to determine substitutes. M2. Data exchange. M2.1. If the CONTROL AREA OPERATOR(s) does (do) not submit the data to the CONTROL BLOCK OPERATOR in due time (see "P2-C-S3.1), the CONTROL BLOCK OPERATOR shall estimate substitute values. M2.2. If the CONTROL BLOCK OPERATOR(s) does (do) not submit the data to the COORDINATION CENTRE in due time (see "P2-C-S3.1), the CO-ORDINATION CENTRE shall estimate substitute values. M3. Data validation. M3.1. If the CONTROL BLOCK OPERATOR is not in a position to validate the accounting data with the CONTROL AREAS concerned in due time (see "P2-C-S5.2 ), the CONTROL BLOCK OPERATOR shall decide which CONTROL AREA data are relevant for accounting. M3.2. If the CO-ORDINATION CENTRE is not in a position to validate the accounting data with the CONTROL BLOCKS concerned in due time (see "P2-C-S6.2), the COORDINATION CENTRE shall decide which CONTROL BLOCK data are relevant for accounting. M3.3. If the CO-ORDINATION CENTRES are not in a position to validate the accounting data vice-versa in due time (see "P2-C-S7.1), the CO-ORDINATION CENTRES agree upon CO-ORDINATION CENTRE data relevant for accounting. M4. Corrections of metered data. Corrections of metered data have to be performed within 4 weeks after the day they correspond to. M5. Settlement. M5.1. If the CONTROL AREA OPERATOR is not in a position to confirm the account of UNINTENTIONAL DEVIATIONS and the resulting COMPENSATION PROGRAM in due time (see "P2-C-S5.3), the result of the CONTROL BLOCK OPERATOR shall be valid. M5.2. If the CONTROL BLOCK OPERATOR is not in a position to confirm the account of UNINTENTIONAL DEVIATIONS and the resulting COMPENSATION PROGRAM in due time (see "P2-C-S6.3), the result of the CO-ORDINATION CENTRE shall be valid. POLICY 3 O P E R AT I O N A L S E C U R I T Y P3 – Policy 3: Operational Security [E] Policy Subsections A. B. C. D. E. F. N-1 Security (operational planning and real-time operation) Voltage control and reactive power management Network faults clearing and short-circuit currents Stability Outages scheduling Information exchanges between TSOs for security of system operation Introduction System safety is the primary goal of the operation of the interconnected network. In an interconnected system there exist numerous inter-dependencies of the networks forming part of the system. In addition, there are impacts attributable to the usage of the system by market players. In an unbundled environment, network operators are not allowed to interfere with market forces unless system safety is at stake. The operation of the interconnected network is founded on the principle that each partner is responsible for its own network. In order to give practical application to the basic principle of the interconnection that each TSO is responsible for its control area, one of the purposes of the Operation Handbook is to define the methods of co-operation also in operational situations when factors outside of the control area can reduce the ability of a TSO to operate its system within the security limits, according to the UCTE rules. To harmonise the operating methods for the interconnected network, UCTE has since the beginning worked out rules, instructions and suggestions, to which the operation of each network has to make reference in order to ease inter-operability. TSOs are in charge of managing the security of operation of their own networks in a subsidiary way. The most relevant rules for the security of interconnected operation are related mainly to the functioning of interconnections. TSOs cooperatively adapt continuously such common rules for inter-operability to be applied mainly at the borders of their CONTROL AREAS and consequently at the borders of countries / blocks. These rules create favourable conditions for cross-border exchanges at destination of network users and of TSOs themselves. All these co-ordinating rules complement any other existing national commitments for network access (legal and contractual) for the transmission networks when they exist. The control of performances of facilities connected to networks remains under the responsibility of TSOs to the extent of their national commitments. This policy specifies the requirements for operating the TRANSMISSION system to maintain security. Each CONTROL AREA and TRANSMISSION SYSTEM OPERATOR - TSO - is responsible of procedures for reliable operation over a reasonable future time period in view of real-time conditions, with CONTINGENCY and emergency conditions, and of their preparation. Coordination between TSOs contributes to enhance the common solidarity (to cope with risks) resulting from the operation of interconnected networks, to prevent disturbances, to provide assistance in the event of failures with a view to reducing their impact and to provide resetting strategies after a collapse. This co-ordination is intensively developed covering today new aspects related to market mechanisms. History of changes v1.3 v1.2 final draft final draft 20.07.2004 18.06.2004 OH team OH team Final wording revision after consultation Current status This policy focuses only on security aspects in operation and does not deal with long-term planning. The commercial rules are out of the scope accordingly (see section I-D in the introduction of the handbook). It is to be linked with Policy 5 “emergency procedures” in UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–2 preparation. This policy will cancel and replace previous UCTE ground rules and recommendations related to operational security. This version of the document (version 1.3, level E, dated 20.07.2004) has “final policy” status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–3 A. N-1 Security (operational planning and real-time operation) Introduction The N-1 SECURITY section refers to the requirements placed upon the operation of the POWER SYSTEM of the SYNCHRONOUS AREA with a view to maintaining the security of the entire interconnected network at any time in operational planning and in real-time conditions. Longterm planning requirements are not dealt with in this context. Secure operation of the interconnected network has made it possible to attain such a good quality of service that in the large majority of cases the outage of any power station or TRANSMISSION element has no influence on the supply of consumers. The “N-1CRITERION” is of major importance to prevent disturbances. This rule applied by all TSOs is combined with an appropriate choice of generation and TRANSMISSION facilities, and the determination of a sufficient reserve. With an organisation of operation based on anticipation, dangerous situations can be identified in due time, and it is possible to take preventive action. Different CONTINGENCIES can occur: • loss of interconnecting elements without any impact on network users or with consequences on commercial power exchanges; • loss of load with immediate consequences for consumers; • loss of interconnected operation, with possible worse consequences. According to the safety, operational and planning standards used by TSOs, the highest importance is attached to the calculation of the TOTAL TRANSFER CAPACITY and the TRANSMISSION RELIABILITY MARGIN based upon the electrical and physical realities of the network. Criteria C1. "N-1" CRITERION: Any probable single event leading to a loss of POWER SYSTEM elements should not endanger the security of interconnected operation, that is, trigger a cascade of trippings or the loss of a significant amount of CONSUMPTION. The remaining network elements, which are still in operation should be able to accommodate the additional load or change of generation, voltage deviation or transient stability regime caused by the initial failure. It is acceptable that in some cases TSOs allow a loss of CONSUMPTION in their own area on condition that its amount is compatible with a secure operation, predictable and locally limited. C1.1. Loss of an element. The loss of any POWER SYSTEM element (generating set, compensating installation or any TRANSMISSION circuit, transformer) must not jeopardise the security of operation of interconnected networks as a result of limits being reached or exceeded for current, VOLTAGE magnitude, STABILITY, etc., and accordingly cannot cause cascade tripping of installations with interruptions in supply. These harmful consequences must be avoided in the system directly supervised by the TSO and also in ADJACENT SYSTEMS. Particular attention is required for TIE-LINES or in the vicinity of borders between different TSOs. The loss of any element according to this “N-1 CRITERION”, however, could affect radially supplied areas (and the output of their local power plants) and as such these areas are excluded from this rule. C1.1.1. Frequency deviations. The loss of elements in the POWER SYSTEM must not cause a FREQUENCY DEVIATION outside acceptable limits according to those referred to in Policy 1 (see !P1-A-C2). C1.1.2. VOLTAGE deviation. The loss of elements in the POWER SYSTEM must not cause a VOLTAGE drop which may lead to VOLTAGE instability. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–4 C1.1.3. INTERCONNECTED SYSTEM STABILITY. The loss of an element in the POWER SYSTEM must not cause a loss of INTERCONNECTED SYSTEM STABILITY. C1.1.4. Cascading outages. A loss of an element in the POWER SYSTEM must not cause cascading outages of other elements in the CONTROL AREA as a result of exceeded operation SECURITY LIMITS. Requirements R1. Monitoring of the N-1 CRITERION R1.1. Monitoring: TSOs monitor at any time the N-1 CRITERION for their own system through observation of the interconnected system (their own system and some defined parts of ADJACENT SYSTEMS) and carry out security computations for risk analysis. R1.2. Violation of the N-1 CRITERION: In real time, after a CONTINGENCY, each TSO returns its POWER SYSTEM to N-1 compliant condition as soon as possible, and in case of a possible delay, it will immediately inform other TSOs affected. R2. Most probable contingencies R2.1. TSOs define the set of most probable CONTINGENCIES in operational planning and in real-time conditions and implement measures to comply with the N-1 CRITERION. Each TSO is directly responsible for coping with the N-1 CRITERION by taking account of the loss of one or multiple network elements (N-k elements when such situations can occur with a sufficient probability to threaten the security of operation: e.g. N-2 lines for some double-circuit lines when appropriate). The specific case of a loss of bus-bars is considered by taking into account an acceptable level of loss of CONSUMPTION predicted and locally limited or not taken into account (due to the extremely low probability of fault and due to the necessity of topology switching by coupling or separating the bus-bars). R2.2. The screening of situations with CONTINGENCIES covers the loss of single or multiple elements of generation or TRANSMISSION equipment at any time. This screening takes also account of temporary weather conditions or weakness of a single network equipment. R3. Bottlenecks. In normal conditions, no restrictions of the TRANSMISSION capacity should occur on the network. If a network operating element fails, necessary measures are taken in the internal network to limit the consequences of such BOTTLENECKs that may adversely affect interconnected operation. In normal operation, any ancillary equipment associated with a TRANSMISSION line, a fortiori with a TIE-LINE, are designed to match the TOTAL TRANSFER CAPACITY so that TSOs do not face capacity limitation. TSOs agree between themselves on a common TOTAL TRANSFER CAPACITY limit for common borders. R3.1. All ancillary equipment associated with a transmission line or a transformer, such as current transformers, disconnectors, power circuit breakers, high frequency chokes, intensity and voltage measurement devices, are designed to match the maximum transmission capacity of the line or transformer, so that they do not represent a bottleneck. R4. Operational Network Reserve. TSOs estimate their operational reserve, i.e. ACTIVE POWER reserve, REACTIVE POWER reserve, acceptable VOLTAGE profile, line loads within acceptable limits, STABILITY margins etc, depending on operating conditions, to securely withstand a first CONTINGENCY. Following the first CONTINGENCY in the network causing a lack of operational network reserve, this immediate deterioration does not lead to rapid deterioration of system operating conditions and is predicted. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–5 Standards S1. Application of the N-1 SECURITY POLICY. Each TSO initially applies the N-1 security policy to its own network on its own responsibility; adjacent TSOs shall be informed about potential problems in the application of this rule. The TSOs concerned jointly verify the respect of the N-1 rule in consideration of cross-border power transfers. The tripping of TIE-LINES at other borders is also considered when appropriate. S2. Network margin at boundary. The entire network, including TIE-LINES, is operated in such a way that sufficient transmission capacity is available for the delivery of reserve power for PRIMARY CONTROL towards the areas which respectively may be affected by the most severe single CONTINGENCY, in the scope of the TRM. S3. Data Exchanges. S3.1. Completion of real-time and forecast calculations of network security. TSOs exchange all useful information and data related to network topology, active and reactive flows, sums of country EXCHANGE PROGRAMS and to some extent the pattern of generation in compliance with the national legal framework in use for confidentiality only when the pattern is relevant for operation at boundary, etc and required for calculations of network security. These data will be used for the completion of real-time and forecast calculations for network security and then for congestion forecasts week and day ahead (P4-A1). S3.2. Day-Ahead Congestion Forecast. With a view to completing the most accurate studies to relieve network congestions, TSOs exchange specific relevant provisional data (see also section F). Procedures P1. Procedures for the N-1 CRITERION. TSOs individually and jointly develop, maintain and implement procedures to comply with the N-1 CRITERION. P2. Types of analysis. Two types of analysis are used for the verification of operational security by members: • forecast analyses based upon network data and various hypotheses for electricity exchanges, generation pattern, incoming power flows and system topology; • real-time analyses based upon network data supplied by a given TSO, together with data on those parts of ADJACENT SYSTEMS which will have a significant influence upon the system of the TSO concerned. TSOs within the SYNCHRONOUS AREA complete forecast calculations for the synchronous network as a whole, using a simulation of N-1 criterion cases. The provision of a uniform set of data hypotheses for incoming power flows allows each TSO to complete individual calculations (forecast and real time) for the verification of the security of their own networks. This will involve the calculation of: P3. • the effects of power plant failures upon power flows, both in national networks and on TIE-LINES, taking account of the PRIMARY CONTROL power supplied by other networks; • power flow transfers associated with the tripping of lines or other elements of national networks, taking account of the influence of other networks. Online calculations for network security. This method involves the representation of the actual condition of networks in the areas concerned, referred to as adjacent zones. To this end, measurements and the signalling of the status of switching devices on the circuits concerned will be elaborated and transmitted in order to allow effective observation of these circuits. Equivalent representation is deemed sufficient for remote zones. Adjacent zones will be limited to the first loop linking the system node points which are directly adjacent to frontier node points. The reduction of UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–6 external networks will therefore be completed beyond the scope of adjacent zones. This method allows members to apply their algorithms for the real-time verification of network security to a cross-border model which takes account the actual situation at any given time. Guidelines G1. Inter-linked double bus bar operation. It is advisable to provide inter-linked double bus-bar operation in a transformer substation if the number of branches exceeds a given number. An operation with multiple electric nodes can be requested at some boundary substations for security reasons. G2. Support from an ADJACENT SYSTEM. The N-1 CRITERION may be assured with the support of an ADJACENT SYSTEM, subject to the prior agreement of the latter. This assumes that scheduled outages for the performance of work affecting ADJACENT SYSTEMS have been agreed in advance by the TSOs concerned. G3. Operational switching for periodical maintenance. In order to ensure the permanent manoeuvrability of TRANSMISSION circuit isolators and breakers at any time, TSOs organise periodical switching of such elements. This must be done without endangering the security of operation. G4. Overload indicators. All TIE-LINES, and the important internal TRANSMISSION lines and large transformers are equipped with devices which enable overloads to be indicated and information to be transmitted to National Control Centres, in order to alert TSOs of a close risk of violating the N-1 CRITERION. Measures M1. Tripping of interconnecting lines. In order to allow the support by INTERCONNECTION to be provided as long as possible, deliberate tripping of TIE-LINES should be avoided, as long as interconnected operation remains possible, except when defined and agreed between neighbouring TSOs. Bibliography : [Review of UCPTE recommendations on interconnected operation– 31/07/1991 (§ Network security (42))] [Network protection devices against faults, QR 1974/75] [UCPTE 37: Operation of the UCPTE interconnected network in normal operation and during disruptions, AR 1985-1986 (§1, 2)] [UCPTE 13 : Measures to prevent or limit major disruptions, AR 1962-1963 (§ 2, 3, et 5)] [UCPTE 15 : Measures to maintain a stable frequency and precautions against falls in frequency, QR I-1965 (§ 2, 3)] [UCPTE 16 : Measures to counteract major disruptions in interconnected network operation, QR IV-1966 (§ 3.2, 3.4, 4, 5(other references)) + Revision of 31/10/1990] [UCPTE 42 : Measures to counteract major disruptions in interconnection and to re-establish normal operating conditions, HR I1990 (§ 3.2, 3.4, 4)] [UCPTE 37 : Operation of the UCPTE interconnected network in normal operation and during disruptions, AR 1985-1986 (§ 3)] [Recommendation UCTE regarding plans of network restoration – 1/12/1999 (§ 2, 4, 5)] [ETSO Web-site] UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) B. P3–7 Voltage Control and Reactive Power Management Introduction VOLTAGE is a measured physical quantity, which fluctuates as a function of network load, generation programmes, POWER SYSTEM operator decisions and POWER SYSTEM contingencies (tripping of generators or TRANSMISSION components). The VOLTAGE levels are maintained by REACTIVE POWER generation assured by different facilities. Nevertheless, for network security reasons, and in accordance with operational VOLTAGE limits of equipment (insulation of network elements, functioning limits of automatic transformer tap changers), a control of VOLTAGE is locally needed to maintain the VOLTAGE deviations within predetermined limits. VOLTAGE conditions in a high-VOLTAGE grid are directly related to the REACTIVE POWER balance at the system nodes. Depending on their operational state, all generators, LOADs and system components (lines, transformers) are either REACTIVE POWER consumers or producers. The network by itself produces or absorbs REACTIVE POWER depending on the load level through the line and their surge impedance loading sometimes called the “natural power”. To compensate for an excessive CONSUMPTION of REACTIVE POWER, TSOs have to make sure that efficient producers feed sufficient reactive power into the networks in addition to the one produced by other devices installed in the networks or in consumers installations. Unlike ACTIVE POWER, REACTIVE POWER cannot be transmitted over long distances, since the TRANSMISSION of REACTIVE POWER leads to an additional demand for REACTIVE POWER in the system components, thereby causing VOLTAGE drops. In order to obtain an acceptable VOLTAGE level, REACTIVE POWER generation and CONSUMPTION have to be situated as close to each other as possible to avoid excessive REACTIVE POWER TRANSMISSION. This REACTIVE POWER can nevertheless be produced in their CONTROL AREA or in the vicinity to those of neighbouring TSOs. In this last case, specific bilateral agreements should be made to transfer REACTIVE POWER through TIE-LINES. VOLTAGE control is thus primarily a regional problem, which may involve several TSOs in an INTERCONNECTED SYSTEM. The operating VOLTAGE reference values are : 380 kV or 400 kV and 220kV or 225 kV. These nominal VOLTAGE values 380kV or 400kV and 220kV or 225kV are slightly different depending on country equipment design ; 750 kV is an accepted operating VOLTAGE reference level, too. They do not introduce significant differences on the synchronously interconnected system operation. Requirements R1. Providing reactive resources. R1.1. REACTIVE POWER resources. Each TSO arranges for providing reactive resources for its requirements and to maintain its control VOLTAGE capability. R1.2. Information. Each TSO shall have information of the main REACTIVE POWER resources available for use in the TRANSMISSION network of its own CONTROL AREA. R1.3. Location. Reactive resources are dispersed and located, whenever possible, close to loads in order to avoid REACTIVE POWER transport and to be applied effectively during normal conditions and when CONTINGENCY occurs. R1.4. REACTIVE POWER Generation/absorption resources. A sufficient number of generators and/or capacitors and/or inductors connected to 380kV/400 kV and 220 kV/225 kV contribute to REACTIVE POWER generation or absorption. All main power plants connected to 380kV/400 kV and 220 kV/225 kV are able to contribute to REACTIVE POWER. Other sources at lower voltage levels can also be used where relevant for operation. R2. Continuous VOLTAGE control. For operation security reasons and respect of mutual commitments for operational conditions, a continuous VOLTAGE control is needed and UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–8 co-ordinated by each TSO in order to maintain VOLTAGE variations within predetermined limits in their CONTROL AREAS. R3. REACTIVE POWER demand and reserve. R3.1. Each TSO shall be able to cover its REACTIVE POWER demand of the own transmission system. R3.2. In order to establish a proper value of the REACTIVE POWER reserve within CONTROL AREAS, TRANSMISSION network nodes are operated at VOLTAGE levels with a sufficient margin as to the VOLTAGE critical point. In this respect, it is advisable to provide a proper REACTIVE POWER reserve. R4. Monitoring and controlling VOLTAGE and Mvar flows. TIE-LINES. R4.1. On REACTIVE POWER flows on TIE-LINES are maintained at a minimum level and if possible not beyond the natural demand of the TIE-LINE in order to limit VOLTAGE drops and to allocate the TOTAL TRANSFER CAPACITY mainly to ACTIVE POWER. In order to ensure a safe operation of the SYNCHRONOUS AREA, the VOLTAGE levels at boundaries need to be optimised with regard to the specific nodes of TIE-LINES – at the points of exchange with neighbouring CONTROL AREAS. The pre-set VOLTAGE levels need to be compatible with and not to be far from the corresponding VOLTAGE value at the other side of the border. R4.2. VOLTAGE and REACTIVE POWER control devices. Devices used to control TRANSMISSION VOLTAGE and REACTIVE POWER flows are available on decision or under the lead of the TSO. R4.3. Within boundaries. Policies and procedures for VOLTAGE control are developed and implemented within boundaries in a subsidiary way by TSOs. R5. Operating reactive resources. In case of a high system load, the system operator shall make sure that, in case of a loss of generation, VOLTAGE control facilities are able to deliver sufficient REACTIVE POWER to maintain the VOLTAGE within the required range. The same applies to the converse situation, where the system load is low and REACTIVE POWER needs to be absorbed. R6. General loss of VOLTAGE. In case of a general loss of VOLTAGE, control centres, operating centres, and the substation personnel shall be in a position to allow the reconstitution of the network. R7. Availability and performance of devices used for VOLTAGE control shall be taken into account for operational planning under real-time conditions. Standards S1. Providing reactive resources: Each TSO operates its capacitive and inductive reactive resources and reserves to maintain the system and TIE-LINES within established limits and to protect VOLTAGE levels under CONTINGENCY conditions. S1.1. At the beginning of peak-LOAD periods, the operators shall make sure that a sufficient level of REACTIVE POWER is available and the VOLTAGE level is close to upper values. S2. Lack of single CONTINGENCY coverage. The TRANSMISSION lines’ loads and VOLTAGE/reactive levels are such that a single CONTINGENCY of a REACTIVE POWER device could not threaten the RELIABILITY of the INTERCONNECTION. S3. Preventing a VOLTAGE collapse. The TSO takes corrective action, including LOAD reduction, LOAD SHEDDING, necessary to prevent a VOLTAGE COLLAPSE when reactive resources are insufficient. S4. Joint action at boundaries between TSOs. The VOLTAGE range for boundary substations has to be jointly agreed and designed to suit particular situations. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–9 Neighbouring TSOs shall jointly seek to optimize the implementation of voltage control facilities. If existing installations are not sufficient, the requisite compensation facilities are installed. Effective management of the voltage level needs co-ordination and contributions of neighboring TSOs involved. S4.1. Pre-set values at boundaries. VOLTAGE levels are kept as close as possible to pre-set values agreed between neighbouring TSOs. POWER flows on TIE-LINES. S4.2. REACTIVE Any VOLTAGE values at boundaries are agreed and controlled bilaterally between neighbouring TSOs depending on the VOLTAGE level agreed at the boundary substations or on specific situations (potential case of REACTIVE purchase from another CONTROL AREA). POWER Depending on operational conditions which could jeopardise the INTERCONNECTED SYSTEM operation, adjacent TSOs can agree on the amount of REACTIVE POWER that may be exchanged during normal operation or when CONTINGENCY occurs. S4.3. Bilateral policies. Bilateral policies are set up between neighbouring TSOs to manage VOLTAGE levels at boundaries in case of disturbances. S4.4. Data to be exchanged. At boundaries, TSOs exchange data on VOLTAGE values and profile and REACTIVE POWER data at boundary substations and TIELINES for the network security analysis and for real-time operation. S5. Use of VOLTAGE reduction and load shedding close to borders S5.1. The TSO operates appropriate settings of the VOLTAGE levels on the transformers to reduce loads. S5.2. When a TSO uses VOLTAGE reduction (3% or 5% in some countries) or LOAD SHEDDING, it shall inform its neighbouring TSOs involved when using such dispositions. Guidelines G1. Range of VOLTAGE values in normal conditions. For ultra-high VOLTAGE networks, the ranges of observed VOLTAGE values in normal condition are respectively close to 380 kV – 420 kV for 380kV/400 kV level and 200 kV – 240 kV for 220kV/225 kV level. Values below 365 kV and 200 kV or above 420 kV and 250 kV can be reached in some circumstances for a short duration. 750 kV is also an existing voltage level the use of which is very limited. For high VOLTAGE networks, these ranges are maintained at around 10% of nominal VOLTAGE values. G2. Policies and procedures for boundary substations and installations are developed with neighbouring TSOs. G3. VOLTAGE control (adjustment of REACTIVE POWER generation). In order to ensure safe operation of the SYNCHRONOUS AREA, the VOLTAGE levels need to be optimised with regard to the specific nodes of the TIE-LINES at the points of exchange with neighbouring CONTROL AREAS. G4. VOLTAGE control facilities. Different kinds of facilities to maintain the VOLTAGE levels are allowed: REACTIVE POWER production by generators, synchronous compensators, fixed capacitor banks, inductors, fixed reactors, SVCs (Static Var Compensators), generators coupling transformer taps, transformer tap controllers etc. G5. Switching TRANSMISSION elements. A manual opening/disconnection of transmission lines is used to maintain the VOLTAGE level in normal operating conditions during offpeak periods with low load flows. G6. TSOs support for voltage level at borders. Adjacent TSOs can agree on mutual voltage support. G7. Remote control of on-load tap changers. In networks including transformers UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–10 equipped with on-load tap changers, the security of operation may be endangered by these devices in case of serious VOLTAGE drops due to the high LOAD and the a REACTIVE POWER deficit. The resulting increase in REACTIVE POWER demand may cause a VOLTAGE collapse. Therefore, it is recommended to use remote control devices to stop the action of on-load tap changers. G8. Emergency strategy. If due to an unforeseen event, the network functioning point approaches a critical VOLTAGE level, an adequate emergency strategy shall be agreed by the TSOs at the boundary. Procedures P1. P2. Primary VOLTAGE control is implemented and is active in operation by the VOLTAGE regulators of generating units, which initiate a rapid variation in the excitation of generators when they detect a variation in VOLTAGE across the generator terminals. Other controllable devices, such as SVCs (Static Var Compensators) may also be involved in primary VOLTAGE control. Secondary VOLTAGE control co-ordinates the action of VOLTAGE and REACTIVE control devices within a given zone of the network in order to maintain the required VOLTAGE level at a ”key node point” in the system. POWER P3. Tertiary VOLTAGE control involves a process of optimisation, using calculations based upon real-time measurements, in order to adjust the settings of devices which influence the distribution of REACTIVE POWER (generating set controllers, transformer load controllers and compensating devices, such as inductances and capacitors). P4. Implementation of secondary and tertiary VOLTAGE control. Each TSO implements secondary and/or tertiary VOLTAGE control in a subsidiary way. Measures M1. VOLTAGE reduction. TSOs reduce the VOLTAGE at customer levels to reduce LOAD (3% or 5%) as preventive measure. M2. (Automatic load) shedding. LOAD SHEDDING is initiated at the time when the VOLTAGE has decreased at an abnormal level. M3. Contribution of power plants to the safeguard measures and to BLACK START. Power plants are able to accommodate variations in VOLTAGE (and frequency) outside of the normal range of operation as long as this is technically feasible before automatic disconnection from the network. Power plants are able to operate under impaired (frequency and VOLTAGE) conditions with reduced performances for a limited period of time accordingly. A number of generating units are equipped for start-up with no external VOLTAGE supply (BLACK START CAPABILITY). These plants should be suitably distributed throughout the network. It is recommended to locate these plants on sites comprising several generating units. Bibliography : [UCPTE 9 : Voltage stability and reactive power flow in the European interconnected network QR I-1959, III-1961, III-1962, I-1964, IV 1967] [UCPTE 38 : Summary of the study « Behaviour in hazardous situations – maintaining the voltage and stability », QR III-1986 » ] [UCPTE 43 : Reactive power and voltage control in the UCPTE system, AR 1990 (§ 6) ] UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) C. P3–11 Network Faults Clearing and Short-Circuit Currents Introduction The network is subject to short circuits between cables or with earth mainly due to critical atmospheric conditions (thunderstorms, heavy fog in polluted areas) which can cause numerous short-circuits. Perturbations can also be caused by other external sources: to some extent for example by blows of excavators in underground cables or by the starting of fishing canes with overhead lines, by planes flying close to the ground, etc. Short-circuit protective devices for all items of equipment (generators, transformers, bus-bars, TRANSMISSION lines) promptly and effectively disconnect any occurring fault with selectivity. Such equipment is backed-up. Its functioning does not result in premature tripping with overloads or loss of synchronism. An effective mutually compatible adjustment of all individual protective devices is very important. Speed and selectivity when disconnecting lines are facilitated by the use of signal links between both ends of the lines. The setting and function of the protective equipment are checked regularly. The best way of doing this is by including it in the maintenance schedule. If there are any changes in operating conditions, the settings of protective devices are immediately adjusted to suit to the new conditions. The protective equipment is also readjusted by remote control via the network management where possible. Criteria C1. Network fault clearing. Whatever the type of power network fault, it is due to be eliminated. That means to disconnect the network element concerned (generators, transformers, bus-bars, TRANSMISSION lines) as quickly as possible and within a specified clearing time, with selectivity and reliability, in order to prevent impairing or jeopardising the rest of the networks, mainly because of safety concerns: Damages to network elements when the fault duration is too long and risk of losing synchronism of power networks. This criterion is applicable to faults located in the interconnecting elements with distribution and generation systems. Requirements R1. Efficiency of protection devices. The protective devices for generators, transformers, bus-bars and lines eliminate all faults selectively and reliably and with the requisite speed. R2. Requisite speed of devices. The requisite speed of protective devices is designed to satisfy STABILITY requirements or to keep equipment within its construction limits. R3. Protection system design. R3.1. Redundant Protection devices. The ultra-high VOLTAGE network protection devices are of a redundant design and equipped with a main and a back-up clearing system (possibly with two protections of the same hierarchical level). R3.2. Proper operation. Protection systems should normally not operate for minor system disturbances, recoverable system power swings or transient overloads. R3.3. Selectivity. The only affected network element has to be automatically disconnected. R3.4. High speed equipment. High speed relays, high speed circuit breakers, and automatic reclosing are used where appropriate. R3.5. Phase reclosing devices. All major lines, and in particular TIE-LINES, are operated with single-phase rapid reclosing devices and, normally, with threephase slow reclosing devices. Automatic three-phase reclosing systems are UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–12 commonly used at the ends of the circuits at suitable locations of interconnecting lines. Manual reclosing is done by means of synchronising equipment. R3.6. Automatic reclosing. Automatic reclosing during out-of-step conditions is prevented with appropriate internal protection functions. TSOs should avoid undesired tripping during out-of-step conditions. If tripping occurs, specific outof-step detection for reclosure blocking is not provided as a standard. R3.7. Reviewing applications (equipment, installation). Protection system applications, settings, and co-ordination are reviewed periodically and in case of major changes in generating resources, TRANSMISSION, load or operating conditions. R3.8. Protection scheme co-ordination. Protection scheme co-ordination is guaranteed with generation and distribution systems and between separately owned transmission systems. R4. Synchronising equipment for switching supervision has to be installed in all major substations, in particular in those involving cross-border or CONTROL AREAs interconnecting lines. R5. Facilities’ short-circuit capability. The facilities and devices connected to networks are designed to operate up to given current limits. Therefore, the POWER SYSTEM is to be operated within construction limits. Technical requirements upon generator connection are defined in order to guarantee that short-circuit currents stay below the established limits. Sound operation requires that, at any node on the POWER SYSTEM, short-circuit currents do not exceed the breaking CAPACITY of devices installed on that node. R6. Efficiency of short-circuit protection. The protection devices are adequately sized for TRANSMISSION equipment, and in particular for frontier substations, to prevent major damage and loss of operating facilities for an unreasonable length of time. R7. TSO Calculation. Each TSO has to calculate where appropriate the short-circuit currents at each node of its system. Standards S1. Co-ordination between TSOs at the boundary. Protection systems for cross-border lines are co-ordinated between TSOs. Each TSO shall inform in advance neighbouring TSOs of setting and changes in operating conditions of protective relays and systems and exchange information on the evaluation of protection system functioning. S2. Basic reliability requirement regarding single contingencies. All TSOs plan and operate their system so that network faults clearing does not lead to cascading outages or to more severe CONTINGENCIES according to the N-1 CRITERION. S2.1. Single contingencies elimination. Any short-circuit current is correctly eliminated and does not impair any TRANSMISSION element. S3. Preventive and corrective actions (repair, maintenance). If a protective relay or equipment failure reduces system RELIABILITY, the responsible personnel is notified, and corrective action is undertaken as soon as possible. Preventive action is taken to guarantee the required reliability indices of protective systems (including circuit breakers, auxiliary power supplies, communication and current and voltage and measuring transformers). S4. Short-circuit calculations are systematically carried out for studying and planning networks taking account of the contributions of adjacent systems to short-circuit power. TRANSMISSION S4.1. Required data. The data needed for experts of different countries jointly UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–13 operating the synchronously interconnected POWER SYSTEM shall be made available. These data are used by everyone to calculate ex-ante short-circuit currents at each node of its own network, once data contributions of neighbouring countries have been provided. S4.2. Periodicity of a complete calculation. In order to provide a basis for assessment by each TSO of the contribution of ADJACENT SYSTEMS in the calculation of short-circuit currents, the UCTE uses its network model to carry out a calculation for the entire synchronously interconnected system every five years, and to get a consistent set of data. S5. Bus-bar operation at boundary sub-stations. Neighbouring TSOs inform each other about specific operation of sub-stations with separated bus-bars. Guidelines G1. Bus-bar protection system. The bus-bar protection system is based on a longitudinal differential or differential protection The recommended response-time limit is lower than 30 ms. G2. Fault locators. Fault locators are provided to ensure rapid fault location. Such devices are installed where they are relevant for operation. They help to save time in locating the origin of faults on affected lines in order to return as soon as possible to normal operation. G3. Fault current limiters. In order to limit the short-circuit currents within the interconnected networks, fault current limiters can be used by TSOs. Procedures P1. Method to limit short-circuit currents. P1.1. Network opening. In order to limit the short-circuit currents within the interconnected networks, some network loop opening can be achieved at different VOLTAGE levels in putting lines out of operation, with the risk of creating partial networks connected only through a limited number of lines. In case of bus-bar maintenance, manual opening of lines can be achieved for short-circuit current limitations. Choices are done depending on operating conditions. P1.2. Separated bus-bars operation. TSOs operate sub-stations with different nodes (separated bus-bars) depending on the level of short-circuit currents. Bibliography : [UCPTE 12 : Short circuit reclosure AR 1961-1962 (table 1 & 2) ] [UCPTE 23 : Reserve protection, AR 1970-1971 (§ philosophy, particular measures…)] [UCPTE 25 : Operational measures for limiting short circuit currents in the operation of interconnected network, AR 1972-1973 (§ 3) ] [UCPTE 28 : Behaviour of electrical protection in the interconnection network, AR 1979-1980] [UCPTE 41 Short circuit current at UCPTE frontier nodes, 17 January 1990, AR 1989] th [UCPTE : Review of UCPTE recommendations on interconnected operation– 31/07/1991 (§ Network security (42)) ] [Network protection devices against faults, QR 1974/75] UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) D. P3–14 Stability Introduction This sub-policy deals with STABILITY issues from the point of view of preserving the synchronous operation of generators, i.e. VOLTAGE STABILITY is not addressed here even if it can be related to the former one. POWER SYSTEM STABILITY consists in the ability of the system to withstand changes in the grid (for example: changes in VOLTAGE, load, frequency) and to survive transition to a normal or at least acceptable operating condition. In absolutely steady conditions, all generating units run synchronously. In case of a change or a large disturbance, some machines can immediately start swinging with respect to each other. This instability phenomenon can lead the POWER SYSTEM to a loss of synchronism and, consequently, can cause tripping of generating units, which jeopardizes the electric energy delivery to customers. Therefore, TSOs carry out computer simulations to check if instability problem will not endanger the secure operation of the system They determine themselves the frequency for the implementation of such simulations. To be able to perform computer simulations and operation, it is essential to get data from producers, although it is increasingly difficult to obtain these data in a liberalized environment. Criteria C1. C2. Preservation of synchronous operation under normal conditions and after loss of an element. Each TSO is responsible for maintaining synchronous operation with other TSOs. Operation security. All TSOs operate their networks in such a way that a loss of should not occur or spread to adjacent TSOs after loss of a system element. STABILITY Requirements R1. Loss of element. The loss of any element, according to chapter A, due to any type of failure, eliminated pursuant to chapter C, must not lead to a loss of STABILITY of the connected generators or to operating constraints in adjacent areas, and does not cause the intervention of the line protection devices. R2. Stability calculation. Each TSO is able to verify operational STABILITY with selected failures in the POWER SYSTEM. Calculation of STABILITY is carried out for planning of the TRANSMISSION system or prior to a substantial change in the TSO’s network. R3. Damping of network oscillations. Network oscillatory phenomena have to be either of sufficiently low amplitude, or need to be damped to a sufficient extent so that they will not impair or jeopardise system operation. Oscillations must not last inadequate period of time nor cause induced swinging of other remote generators which are not directly involved in the origin of this network oscillation. Standards S1. Application of the stability policy. Each TSO shall apply the STABILITY policy to its own network on its own responsibility. Adjacent TSOs jointly apply the STABILITY policy with due account to affected TIE-LINES and border parts of networks. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) S2. P3–15 Co-ordinated analyses. In case of STABILITY problems affecting several TSOs, coordinated analyses are required at UCTE level when appropriate to check the small signal stability of the whole power system. Each TSO shall take part in STABILITY studies if STABILITY problems concern its CONTROL AREA. Guidelines G1. Studies. Each TSO has to implement software models suitable for carrying out calculations. Furthermore, each TSO shall make available all data necessary for these calculations, especially data about generators, and exchange all information and data required for the completion of real-time and forecast calculations for network STABILITY with other TSOs. STABILITY G2. Circuit breaking devices. TSOs can provide automatic devices at appropriate junctions (international or within the internal networks), which in the case of frequency drop, overloading or loss of synchronism break the circuit at predetermined points in the network. If points of disconnection are provided, they should be selected where appropriate so that in each of the isolated network sections a good balance between generation and CONSUMPTION is attained so that each network section can continue to operate under acceptable frequency and STABILITY conditions. G3. Power swing detectors. Power swing detectors provide a power swing blocking function to prevent false tripping by distance measuring elements during power swing. These relays should be installed in the 380 - 400 kV network. G4. POWER SYSTEM stabilisers. Parts of the excitation control system are used for damping network oscillations in the POWER SYSTEM. In the limits of the national transmission rules and requirements, each TSO shall ensure as far as possible that newly built power station units connected to the TRANSMISSION grid with large nominal power are equipped with power system stabilisers which are able to damp inter-area oscillations. G5. Power unit fast valving. Fast valving consists in a fast reduction of the mechanical power supplied to the electrical machine by the turbine in order to enhance the system STABILITY. Large thermal generating units connected to the TRANSMISSION network should be able to perform fast valving. G6. Emergency automatics. If it is not possible to ensure the system STABILITY with common devices, also in view of events of low probability but with serious impact on POWER SYSTEM operation, appropriate emergency automatics should be introduced. Emergency automatics can be used to prevent loss of STABILITY of a generator group in unfavourable conditions. G7. Setting of excitation controllers. The TSO shall ensure that AVR (Automatic on units within its the co-ordination of network protection devices. VOLTAGE Regulators,) and POWER SYSTEM stabilisers settings CONTROL AREA meet its requirements. Special care is taken of G8. Power units operation during network failures. TSOs supervise in accordance with their national regulations that power units meet the requirements of resistance against network failures when their STABILITY is threatened. In case of threatened STABILITY, which has been found by calculations, POWER SYSTEMS can be equipped with relevant protections (leading to power plant tripping). In case of loss of synchronism, power units are equipped with respective protections to trip under predetermined conditions. Measures M1. Assurance of stability. If operational experience or computational results show that there is a risk of STABILITY loss according to the N-1 CRITERION fault or another failure with a high probability of occurrence, the TSO shall solve this problem in order to UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–16 bring its network in line with the requirements of this chapter. Measures can include setting of excitation control systems and power system stabilizers, installation of special automatics or protection and coordinated studies and action with adjacent TSOs. M2. Reducing the risk of instability. TSOs can operate the networks close to the upper value of each voltage range before reaching the peak of load, and reduce the fault clearing time in order to reduce the risk of instability. Bibliography : [UCPTE 9 : Voltage stability and reactive power flow in the European interconnected network QR I-1959, III-1961, III-1962, I-1964, IV 1967] [UCPTE 38 : Summary of the study « Behaviour in hazardous situations – maintaining the voltage and stability », QR III-1986 » ] UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) E. P3–17 Outage Scheduling Introduction The European electric POWER SYSTEM, initially interconnected for RELIABILITY reasons, then used also for commercial purposes through well-defined exchange contracts (mostly longterm contracts), is now the scene for a more complex European market. Potential restrictions of electricity exchanges are mostly due to limits OF THE TOTAL TRANSFER CAPACITY. TRANSMISSION congestion occurs when the TRANSMISSION system cannot be operated securely in the light of a requested pattern of generation, DEMAND and TRANSMISSION. As an absolute minimum, procedures relieve congestion before physical or SECURITY LIMITS are reached. This is particularly true given the meshed nature of the European network. For the purpose of national and international connection, the TSOs of the interconnected network are responsible for ensuring that operational security in accordance with the N-1 CRITERION, network STABILITY and short-circuit current will be maintained within the system as a whole, taking account of existing TIE-LINES and scheduled outages. TSOs mutually determine the most suitable dates for scheduled outages to carry out maintenance work on transport installations such as the main interconnecting lines, other relevant installations close to the borders or installations with a substantial impact on internal lines. These scheduled outages enable TSOs to carry out maintenance work on their installations at regular intervals with a view to ensuring reliability. Unavailability of one TIE-LINE may have immediate consequences on NTC. Outage scheduling is carried out to be able to calculate and publish ATC.. As a result of companies’ unbundling, it is increasingly difficult to TSOs to obtain from producers well in advance information about planning of scheduled outages of their main production installations located close to the borders which have a direct impact on the level of load on tie-lines. Any delay in the knowledge of power plant outages can impede TSOs to publish the summer NTC and the winter NTC in due time (six months ahead). Provided that the aforementioned delays do not occur, TSOs are able to determine on a yearly basis the planning of scheduled outages of transport facilities by the end of the previous year or at the beginning of the forthcoming year, at the latest. Criteria C1. Planned outages of power plants. The outage of a power plant must not jeopardise the security of operation of the INTERCONNECTED NETWORK. Particular attention has to be paid to large-capacity power plants (more than 300 MW) and those in the vicinity of borders between different TSOs. C2. Planned outages of TRANSMISSION lines. The outage of a TRANSMISSION line must not jeopardise the security of operation of the INTERCONNECTED NETWORK. Particular attention has to be paid to TRANSMISSION lines crossing borders or in the vicinity of borders between different TSOs. Requirements R1. Exchange of information about planned outages at the border. R1.1. Planned outages of power plants. Each TSO has to collect information on scheduled outages of power plants and transmit them to the neighbouring TSOs for what is relevant. Each TSO has to provide R1.2. Planned outages of TRANSMISSION lines. information in advance on the planned OUTAGES of TRANSMISSION lines in its system and co-ordinate its planning with the neighbouring TSOs. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–18 Standards S1. Forecast analyses. The provision of a uniform set of data of the TRANSMISSION networks and hypotheses for scheduled power exchange allows each TSO to carry out individual calculations (medium-term and short-term forecast) for the simulation of • the effects of power plant OUTAGES upon power flows, both in national networks and on INTERCONNECTIONS; • S2. flux transfers associated with the outage of lines or other elements of national networks, taking account of the influence of other networks. Co-ordination of scheduled outages planning. S2.1. Medium-term planning. At least once a year, at the end of the preceding year (but not later than at the very beginning of the forthcoming year), the TSOs of neighbouring regions will meet to agree a joint schedule of outages on international lines for which they are responsible. This schedule will take account of overhaul programs for major generating facilities in the vicinity of frontiers, together with the unavailability of lines in these areas. S2.2. Short-term planning. If necessary, this schedule has to be reviewed in the course of the year and any amendments will be notified to each TSO in the region concerned. S3. Confirmation of planned outages. Each TSO will confirm on a weekly basis (and daily when relevant in case of changes) the outages of important power plants (where necessary) and TRANSMISSION lines to neighbouring TSOs involved. The set of these system elements that may affect interconnection, has to be previously agreed among the TSOs involved. Procedures P1. Division in regions. For the purpose of outage co-ordination, the SYNCHRONOUS AREA may be divided into a number of large regions. Bibliography : [see also: ETSO paper: Co-ordinated Auctioning; networks, final report April 2001] a market based method for TRANSMISSION capacity allocation in meshed [see also: ETSO paper: Definition of Transfer Capacities in liberalized electricity markets, final report April 2001] re-establish normal operating conditions, HR I-1990] [see: UCPTE-Recommendation: Co-ordination of work on lines of importance in the interconnected network, AR 1980-1981] UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) F. P3–19 Information Exchanges between TSOs for Operation Introduction Co-ordination and information exchange mechanisms are put in place by TRANSMISSION system operators to ensure the security of the networks in normal and contingency conditions and in the context of congestion management. TSOs are continuously in contact for reasons of security of power network operation, for planning and related data (e.g. NTC) needed by the network users. The monitoring of load flows and the control of power balance for the whole system are carried out in regional and interregional load dispatching centres. Data transfer and data processing systems ensure that these centres are continuously supplied with up-to the minute information on the operating condition of the power stations and of the switching status in the TRANSMISSION network, as well as on the condition of transformer and compensation equipment. Moreover, the current values of active and REACTIVE POWER and the VOLTAGE on TRANSMISSION lines and transformers are continuously known. SCADA systems allow to display such requested information to operators of these dispatching centres whatever the operating conditions of installations. Back-up systems are always operated in reserve. With respect to telecommunication equipment, the transfer of important information to the dispatching centres and between them is still continuously guaranteed with a sufficient number of routes with back-up. These routes are not only used for providing information about any event occurring on networks but also for giving remote orders for switching directives. The supply in electricity of such dispatching centres is guaranteed. TSOs manage continuously available communications even during a loss of communication facilities and set-up suitable procedures between each other. These contacts are mainly managed through telecom channels with private or confidential links. TSOs keep data available for possible exchange of information on system planning, system representation for studies and real-time operation, and for cross-border exchanges. This sub-policy provides a survey of technical aspects of facilities and the main kind of information exchanged through telecom channels for the security of power system operation. It does not enter into details of common datasets to be exchanged in accordance with confidentiality issues. Criteria C1. Responsibility. TSOs are responsible for maintaining continuously available communication with their neighbouring TSOs. C2. System data availability. Each TSO shall always have at its disposal reliable power system data for operational planning and real-time operation. Requirements R1. Prevention of a loss of telecommunications. TSOs are due to be continuously in an on-line liaison with each other whatever CONTINGENCY conditions of telecommunications may occur. Loss of telecommunications links or instrumentation and control links between control centres, operating centres and TRANSMISSION installations must not paralyze the operation of the interconnected network. R2. Reliable and secure telecommunications network. Each TSO shall provide an adequate, reliable, secure, fast and highly available communications infrastructure to assure permanent exchange of information between TSOs. R3. Facilities redundancy. Whenever redundant and diversely routed. R4. Back-up facilities. In order to face any CONTINGENCY in telecommunication facilities and to ensure communication between operators during emergency conditions, any route will be backed-up by other ones. Backup voices/routes for telecommunication possible, telecommunication facilities are UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–20 facilities including alternate telecommunications channels should be provided to assure co-ordinated control of operations during normal and CONTINGENCY/EMERGENCY SITUATIONs. R5. Effective procedures for operation communication. Procedures for communication between TSOs have to be consistent, efficient and effective during normal and emergency conditions. R6. Co-ordination and information exchange mechanisms. They are put in place by TSOs in order to ensure the security of the networks, also in the context of congestion management. R7. Case of general loss of VOLTAGE. In case of general loss of VOLTAGE, telecommunication systems and remote control systems remain in operation to allow the reconstitution of the network to be completed. R8. System data exchange. TSOs are involved in system planning and study processes in order to make clear the operator’s perspectives and TRANSMISSION limits; therefore, TSOs elaborate reliable data of system representation for their networks. Standards S1. General provisions. Information is provided either by voice, fax, e-mail or by other private or confidential routes. S2. Information exchange for power system computation. S2.1. TSOs inform each other about the main evolution of their POWER SYSTEM when planning or commissioning a new equipment. S2.2. TSOs yearly provide to each other a provisional data-set including network, generation, load and exchange programmes for the preparation of a reference case, the so called “UCTE base case” which serve to calculate NTC. Two data-sets are provided: One for winter delivered in April/May, one for summer delivered in October/November. These NTC values are published sixmonths ahead (ETSO web): In December for summer NTC, in July for winter NTC. S2.3. TSOs yearly provide to each other data sets for a full representation of their network in real-time conditions (the so-called “snapshots”). Two data-sets are provided: One file for the following winter delivered in July, one file for the following summer delivered in January. Other snapshots can be exchanged when relevant. S2.4. Day-Ahead Congestion Forecast. With a view to completing the most accurate studies and to help appreciating congestions ex-ante, TSOs exchange specific relevant provisional data for the day-ahead congestion forecast. S2.5. All these data-sets are merged into consistent files, which are used as reference files (UCTE “base case” and a whole snapshot) for further studies and calculations. S3. Cross-border transfer capacity. With respect to borders where capacities are not auctioned, TSOs determine their cross-border transfer capacities six-months ahead, one month ahead, week and day ahead, when appropriate, and publish some of them on their Web-site at different time intervals. S4. Outages planning. Each TSO confirms in advance the planned OUTAGEs to other TSOs (see section E). S5. Exchange programmes. The scheduled energy exchanges aggregated per time unit for each relevant specific CONTROL BLOCK are made available to all TSOs. (see P2-A). S6. Data on real-time conditions. Each TSO determines with neighboring TSOs concerned the suitable set of real-time data to be exchanged on-line such as data at UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–21 boundary sub-stations and at the agreed other stations such as topology, VOLTAGE, LOAD MW and MVAr on tie-lines and at boundary sub-stations. S7. Information on new installations to be commissioned. Each TSO shall inform its neighbouring TSO about planning and commissioning of any new significant installation (power plant, substation) located near the border. This new installation can change the level of short-circuit power to be faced by TRANSMISSION equipment. Verifications or reinforcements of such equipment are carried out accordingly. Guidelines G1. Electronic Highway – EH (exclusively for TSOs). Since opening of markets and unbundling of TSOs from other market actors, confidential channels for information exchange have been developed. In addition to the classic telecommunication channels mentioned above, a specific Electronic Highway between TSOs with encoded data [currently data interchanged over EH are not encoded (confidential)] is implemented for any energy information related to network operational security and, to some extent, to relevant market aggregated data: G1.1. Each TSO will take measures to be connected to EH. G1.2. A wide use of EH is assured by TSOs. G1.3. TSOs are responsible for maintaining their channels of EH. G2. Data on operational planning. Wherever necessary, TSOs shall exchange data on a bilateral basis or among one another for planning purposes and studies, concerning for example: • The results of POWER SYSTEM studies pertinent to operation • OUTAGE scheduling of TRANSMISSION elements at different time intervals: year ahead and more frequently when appropriate. • Assumptions of generation patterns for power plants having a main influence on system operation, when appropriate at the boundary • Aggregated cross-border exchange programmes between CONTROL AREAs and countries • Cross-border transfer capacities (Net Transfer capacities - NTC, Available Transfer Capacities - ATC and TRANSMISSION reliability Margin – TRM) – (Cf. ETSO web-site) • Changes in operating conditions and limits. G3. Campaign of measurements. TSOs exchange data in the context of measurement campaigns in the light of security of operation (Cf. Policy 1 for frequency/power response of the system). G4. WAMS (Wide Inter-area Measurement System). TSOs exchange data in case of measurements following phenomena of low-frequency oscillations between UCTE areas. G5. Data and procedures for emergency operation. In order to withstand fast emergency operation, pre-requested procedures and data should be prepared and exchanged between TSOs to improve the knowledge of bordering networks and to limit transits trough INTERCONNECTIONs for security reasons or to face any major CONTINGENCY. G6. Language. TSOs agree on the language used for any communication issue in operation. English is the official common language. All inter-TSO procedures will be written down in English or in another language agreed with neighbouring TSOs. UCTE OH – Policy 3: Operational Security (final policy 1.3 E, 20.07.2004) P3–22 Bibliography : [UCPTE 29 : Recommendations on a data transmission network between the control centres of the UCPTE, AR 1980-1981] [UCPTE 30 : Co-ordination of work on lines of importance in the interconnected network, AR 1980-1981] [UCPTE 32 : Recommendations relating to the method of « real time » data exchange between computers in control centres, AR 1982-1983 (§ 1, 5, 6)] [UCPTE 36 : Co-operation in the UCPTE via the interconnected networks, AR 1985-1986 (§ 3, 4)] [UCTE regarding a method for the co-ordinated exchange of operating experience within the UCTE system (MESU) – 1/12/1999 (§ 5 + annexes)] [UCPTE 37 : Operation of the UCPTE interconnected network in normal operation and during disruptions, AR 1985-1986 (§ 1, 2)] [UCPTE 39 : Generating and failure – simulation of effects on the load – flows in the UCPTE interconnected network, QR IV-1986] APPENDIX 1 LOAD-FREQUENCY CONTROL AND PERFORMANCE A1 – Appendix 1: Load-Frequency Control and Performance [E] Chapters A. B. C. D. E. Primary Control Secondary Control Tertiary Control Time Control Measures for Emergency Conditions Introduction This appendix to Policy 1 – Load-Frequency Control and Performance (!P1) explains and motivates the basic technical and organisational principles of LOAD-FREQUENCY CONTROL and other relevant control mechanisms for the UCTE, as it is applied in the SYNCHRONOUS AREA by the TSOs of the various CONTROL AREAS / BLOCKS. This appendix, organised as a collection of separate topics, shall be used as a covering paper for Policy 1. Please refer to the introduction of the UCTE Operation Handbook (see !I) for a general overview and to the glossary of terms of the UCTE Operation Handbook (see !G) for detailed definitions of terms used within this appendix. History of Changes v1.9 draft period v1.8 draft 16.06.2004 OpHB-Team update after consultation 01.03.2004 OpHB-Team minor changes Current Status This document summarises technical descriptions and backgrounds of a subset of current UCTE rules and recommendations related to generation control and performance issues, with additional items. This appendix replaces previous UCTE ground rules and recommendations regarding PRIMARY and SECONDARY frequency and active POWER CONTROL, regulation reserves and correction of SYNCHRONOUS TIME. This version of the document (version 1.9, level E, dated 16.06.2004) has “final” status. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) A. "A1–2 Primary Control [UCTE Operation Handbook Policy 1 Chapter A: Primary Control, 2004] [UCTE-Ground Rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] [UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, 1998] [UCPTE Rule 31: Control characteristics of the UCPTE interconnected grid, 1982] [UCTE-Ground Rules – Supervision of the application of rules concerning primary and secondary control of frequency and active power in the UCTE, 1999] 1. Power Equilibrium In any electric system, the ACTIVE POWER has to be generated at the same time as it is consumed. Power generated must be maintained in constant equilibrium with power consumed / demanded, otherwise a POWER DEVIATION occurs. Disturbances in this balance, causing a deviation of the SYSTEM FREQUENCY from its set-point values, will be offset initially by the kinetic energy of the rotating generating sets and motors connected. There is only very limited possibility of storing electric energy as such. It has to be stored as a reservoir (coal, oil, water) for large power systems, and as chemical energy (battery packs) for small systems. This is insufficient for controlling the power equilibrium in real-time, so that the production system must have sufficient flexibility in changing its generation level. It must be able instantly to handle both changes in demand and outages in generation and transmission, which preferably should not become noticeable to network users. 2. System Frequency The electric frequency in the network (the SYSTEM FREQUENCY f) is a measure for the rotation speed of the synchronised generators. By increase in the total DEMAND the SYSTEM FREQUENCY (speed of generators) will decrease, and by decrease in the DEMAND the SYSTEM FREQUENCY will increase. Regulating units will then perform automatic PRIMARY CONTROL action and the balance between demand and generation will be re-established. The FREQUENCY DEVIATION is influenced by both the total inertia in the system, and the speed of PRIMARY CONTROL. Under undisturbed conditions, the SYSTEM FREQUENCY must be maintained within strict limits in order to ensure the full and rapid deployment of control facilities in response to a disturbance. Out of periods for the correction of SYNCHRONOUS TIME, the setpoint frequency is 50 Hz. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–3 Even in case of a major FREQUENCY DEVIATION / OFFSET, each CONTROL AREA / BLOCK will maintain its interconnections with ADJOINING CONTROL AREAS, provided that the secure operation of its own system is not jeopardised. 3. Droop of a Generator The DROOP OF A GENERATOR sG is a ratio (without dimension) and is generally expressed as a percentage: sG = − ∆f / f n in % ∆PG / PGn The variation in SYSTEM FREQUENCY is defined as follows, with fn being the rated frequency: ∆f = f − f n The relative variation in power output is defined as the quotient of the variation in power output ∆PG of a generator (in steady-state operation, provided that the PRIMARY CONTROL RANGE is not completely used up) and its rated active power output PGn. The contribution of a generator to the correction of a disturbance on the network depends mainly upon the DROOP OF THE GENERATOR and the PRIMARY CONTROL RESERVE of the generator concerned. The following figure shows a diagram of variations in the generating output of two generators a and b of different droop under equilibrium conditions, but with identical PRIMARY CONTROL RESERVES. Generated power Pmax a b Primary control reserve f0 fa fb Frequency f0= set frequency In case of a minor disturbance (FREQUENCY OFFSET < ∆fb), the contribution of generator a (which has the controller with the smaller droop) to the correction of the disturbance will be greater than that of generator b, which has the controller with the greater droop. The FREQUENCY OFFSET (∆fa) at which the PRIMARY CONTROL RESERVE of generator a will be exhausted (i.e. where the power generating output reaches its maximum value Pmax) will be smaller than that of generator b (∆fb), even where both generators have identical PRIMARY CONTROL RESERVES. In case of a major disturbance (frequency offset > ∆fb), the contributions of both generators to PRIMARY CONTROL under quasi-steady-state conditions will be equal. 4. Network Power Frequency Characteristic The NETWORK POWER FREQUENCY CHARACTERISTIC of a SYNCHRONOUS AREA / BLOCK is the quotient of the POWER DEVIATION ∆Pa responsible for the disturbance and the quasi-steadystate FREQUENCY DEVIATION ∆f caused by the disturbance (power deficits are considered as negative values): λu = ∆Pa in MW/Hz ∆f UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–4 The NETWORK POWER FREQUENCY CHARACTERISTIC λi is measured for a given CONTROL AREA / BLOCK i. This corresponds to the quotient of ∆Pi (the POWER DEVIATION measured at the TIELINES of the CONTROL AREA / BLOCK i) and the FREQUENCY DEVIATION ∆f in response to the disturbance (in the CONTROL AREA / BLOCK where the disturbance originates, it will be necessary to add the power surplus, or subtract the power deficit, responsible for the disturbance concerned). λi = − ∆Pi in MW/Hz ∆f The contribution of each CONTROL AREA / BLOCK to the NETWORK POWER FREQUENCY CHARACTERISTIC is based upon the set point value λio for the NETWORK POWER FREQUENCY CHARACTERISTIC in the CONTROL AREA / BLOCK concerned. This set-point value is obtained by the multiplication of the set-point NETWORK POWER FREQUENCY CHARACTERISTIC λuo for the entire SYNCHRONOUS AREA and the contribution coefficients Ci of the various CONTROL AREAS / BLOCKS: λio = Ci λuo This formula is used to determine the requested contribution Ci of a CONTROL AREA / BLOCK to PRIMARY CONTROL. The NETWORK POWER FREQUENCY CHARACTERISTIC of a given CONTROL AREA / BLOCK should remain as constant as possible, within the frequency range applied. This being so, the insensitivity range of controllers should be as small as possible, and in any case should not exceed ±10mHz. Where dead bands exist in specific controllers, these must be offset within the CONTROL AREA / BLOCK concerned. The set-point value λuo for the overall NETWORK POWER FREQUENCY CHARACTERISTIC is defined by the UCTE on the basis of the conditions described in the policy, taking account of measurements, experience and theoretical considerations. 5. Primary Control Basics Various disturbances or random deviations which impair the equilibrium of generation and demand will cause a FREQUENCY DEVIATION, to which the PRIMARY CONTROLLER of generating sets involved in PRIMARY CONTROL will react at any time. The proportionality of PRIMARY CONTROL and the collective involvement of all interconnection partners is such that the equilibrium between power generated and power consumed will be UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–5 immediately restored, thereby ensuring that the SYSTEM FREQUENCY is maintained within permissible limits. In case that the frequency exceeds the permissible limits, additional measures out of the scope of PRIMARY CONTROL, such as (automatic) LOAD-SHEDDING, are required and carried out in order to maintain interconnected operation. f f dyn. max. f t fdyn. max. = Dynamic frequency deviation f = Quasi-steady-state deviation This deviation in the SYSTEM FREQUENCY will cause the PRIMARY CONTROLLERS of all generators subject to PRIMARY CONTROL to respond within a few seconds. The controllers alter the power delivered by the generators until a balance between power output and consumption is re-established. As soon as the balance is re-established, the SYSTEM FREQUENCY stabilises and remains at a quasi-steady-state value, but differs from the frequency set-point because of the DROOP OF THE GENERATORS which provide proportional type of action. Consequently, power cross-border exchanges in the interconnected system will differ from values agreed between companies. SECONDARY CONTROL (see !A1-B) will take over the remaining FREQUENCY and POWER DEVIATION after 15 to 30 seconds. The function of SECONDARY CONTROL is to restore power cross-border exchanges to their (programmed) set-point values and to restore the SYSTEM FREQUENCY to its set-point value at the same time. The magnitude ∆fdyn.max of the dynamic FREQUENCY DEVIATION is governed mainly by the following: • the amplitude and development over time of the disturbance affecting the balance between power output and consumption; • the kinetic energy of rotating machines in the system; • the number of generators subject to PRIMARY CONTROL, the PRIMARY CONTROL RESERVE and its distribution between these generators; • the dynamic characteristics of the machines (including controllers); • the dynamic characteristics of loads, particularly the self-regulating effect of loads. The quasi-steady-state FREQUENCY DEVIATION ∆f is governed by the amplitude of the disturbance and the NETWORK POWER FREQUENCY CHARACTERISTIC, which is influenced mainly by the following: • • the droop of all generators subject to PRIMARY CONTROL in the SYNCHRONOUS AREA; the sensitivity of consumption to variations in SYSTEM FREQUENCY. 6. Principle of Joint Action Each TRANSMISSION SYSTEM OPERATOR (TSO) must contribute to the correction of a disturbance in accordance with its respective contribution coefficient to PRIMARY CONTROL. These contribution coefficients Ci are calculated on a regular basis for each CONTROL AREA / BLOCK or interconnection partner / TSO using the following formula: UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) Ci = "A1–6 Ei Eu with Ei being the electricity generated in CONTROL AREA / BLOCK i (including electricity production for export and scheduled electricity production from jointly operated units) and Eu being the total (sum of) electricity production in all N CONTROL AREAS / BLOCKS of the SYNCHRONOUS AREA. In order to ensure that the principle of joint action is observed, the NETWORK POWER FREQUENCY CHARACTERISTICS of the various CONTROL AREAS should remain as constant as possible. This applies particularly to small FREQUENCY DEVIATIONS ∆f, where the "dead bands" of generators may have an unacceptable influence upon the supply of PRIMARY CONTROL energy in the CONTROL AREAS concerned. 7. Target Performance Defining conditions for the target efficiency of PRIMARY CONTROL are based upon the following parameters: • • the simultaneous loss of two power plant units, or the loss of a line section or busbar; experience has shown that incidents leading to an even greater loss of power are extremely rare; • the control of such incidents by the activation of far greater control power than is necessary may lead to the overloading of the transmission system, thereby jeopardising the interconnected network. The design hypothesis applied is based upon unfavourable parameters which provide a margin of safety in estimated values. Consequently, it is probable that even more serious incidents could be accommodated in practice without the need for LOAD-SHEDDING. Based on the parameters above, the reference incident was defined to be 3000 MW for the entire SYNCHRONOUS AREA (see !P1-A-C3). Starting from undisturbed operation of the interconnected network, a sudden loss of 3000 MW generating capacity must be offset by PRIMARY CONTROL alone, without the need for customer LOAD-SHEDDING in response to a FREQUENCY DEVIATION. In addition, where the selfregulating effect of the system load is assumed according to be 1 %/Hz, the absolute FREQUENCY DEVIATION must not exceed 180 mHz. Likewise, sudden load-shedding of 3000 MW in total must not lead to a FREQUENCY DEVIATION exceeding 180 mHz. Where the self-regulating effect of the load is not taken into account, the absolute FREQUENCY DEVIATION must not exceed 200 mHz. The following figure shows movements in the SYSTEM FREQUENCY for a given design hypothesis (case A), where dynamic requirements for the activation of control power are fulfilled in accordance with the requirements for deployment time. Unfavourable assumptions have been selected for all model parameters. The maximum absolute FREQUENCY DEVIATION is 800 mHz - this means that the threshold for LOAD-SHEDDING will not be reached by some margin. "A1–7 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) 0 Frequency deviation [mHz] -200 B1 B2 -400 } Typical movements in network frequency following losses in generating capacity -600 A Design hypothesis -800 -1000 st 1 stage of automatic load shedding -1200 0 10 20 30 40 50 60 70 Time [s] A Loss in generating capacity: P = 3000 MW, Pnetwork = 150 GW, self-regulating effect of load: 1% / Hz B1 Loss in generating capacity: P = 1300 MW, Pnetwork = 200 GW, self-regulating effect of load: 2 % / Hz B2 Loss in generating capacity: P = 1300 MW, Pnetwork = 200 GW, self-regulating effect of load: 1% / Hz For comparative purposes, simulations have also been undertaken using realistic model parameters (case B), in order to allow the typical FREQUENCY DEVIATION associated with customary losses in generating capacity to be plotted in parallel. These simulations show that, for a loss of capacity up to 1300 MW, the absolute FREQUENCY DEVIATION will remain below 200 mHz. If the target performance described above is to be achieved, the system must be operated in such a way, depending upon the system load, that the NETWORK POWER FREQUENCY CHARACTERISTIC for the entire SYNCHRONOUS AREA falls within a relatively narrow band. Taking account of the self-regulating effect of load, this gives the following table: Self-regulating effect Network power 1 %/Hz 1 %/Hz 2 %/Hz 2 %/Hz 150 GW 300 GW 150 GW 300 GW Network power frequency characteristic 16500 MW/Hz 18000 MW/Hz 18000 MW/Hz 21000 MW/Hz The following assumptions have been applied for the definition of marginal conditions for the operation of PRIMARY CONTROL1: • Design basis / reference incident: Sudden deviation of 3000 MW in the balance of production and consumption; system off-peak load about 150 GW and peak load about 300 GW • System start time constant: 10 to 12 seconds • Self-regulating effect of load: 1 %/Hz • Maximum permissible FREQUENCY DEVIATION quasi-steady-state: ±180 mHz and dynamic: ±800 mHz The maximum dynamic FREQUENCY DEVIATION of ±800 mHz includes a safety margin. This margin of 200 mHz in total is intended to cover the following influences and elements of uncertainty: • • • Possible stationary FREQUENCY DEVIATION before an incident (50 mHz) Insensitivity of turbine controller (20 mHz) Larger dynamic FREQUENCY DEVIATION at the site of the incident, not taken into account in the specific network model used for simulations (50 mHz) 1: The value of 3000 MW used here as the reference incident depends on the size of the SYNCHRONOUS AREA and is subject to change in case of extension of the SYNCHRONOUS AREA (or disconnection of an area). UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–8 • Other elements of uncertainty in the model (approximately 10 %, 80 mHz) In case of LOAD-SHEDDING, accuracy of 50 to 100 mHz will generally suffice for relay trip thresholds. 8. Primary Control Reserve The total PRIMARY CONTROL RESERVE for the entire SYNCHRONOUS AREA Ppu is determined by the UCTE on the basis of the conditions set out in the previous subsections, taking account of measurements, experience and theoretical considerations. The shares Ppi of the CONTROL AREAS / BLOCKS are defined by multiplying the calculated reserve for the SYNCHRONOUS AREA and the contribution coefficients Ci of the various CONTROL AREAS / BLOCKS: Ppi = Ppu Ci The entire PRIMARY CONTROL RESERVE is activated in response to a quasi-steady-state FREQUENCY DEVIATION of –200 mHz or more. Likewise, in response to a FREQUENCY DEVIATION of +200 mHz or more, power generation must be reduced by the value of the entire PRIMARY CONTROL RESERVE. In order to restrict the calling up of the PRIMARY CONTROL RESERVE to unscheduled power unbalances, the SYSTEM FREQUENCY should not exceed or fall below a range of ±20 mHz for long periods under undisturbed conditions. 9. Deployment Time of Primary Control Reserve The deployment time of the PRIMARY CONTROL RESERVES of the various CONTROL AREAS / BLOCKS should be as similar as possible, in order to minimise dynamic interaction between CONTROL AREAS / BLOCKS. In this instance, we are concerned with anticipated performance, rather than with the logic of controllers. For the following, a reference incident of 3000 MW (loss of generation or load, see !P1-AC3) for the SYNCHRONOUS AREA is considered. The PRIMARY CONTROL RESERVE of each CONTROL AREA / BLOCK (determined in accordance with the corresponding contribution coefficient) must be fully activated within 15 seconds in response to disturbances ∆P of less than 1500 MW (it has been assumed that, where values for reserve power to be activated are smaller, deployment times of less than 15 seconds will be difficult to achieve), or within a linear time limit of 15 to 30 seconds in response to a ∆P of 1500 to 3000 MW. As a minimum requirement, the deployment time of the PRIMARY CONTROL RESERVE must be consistent with the curves plotted in the following figure, which represent the overall behaviour of the system. The activated power will lie on or above the plotted curves, until the balance between power generation and consumption has been restored. For each CONTROL AREA / BLOCK, the figures for power indicated are multiplied by the relevant contribution coefficient Ci. The following figure illustrates the minimum deployment of PRIMARY CONTROL POWER as a function of time and the size of the disturbance ∆P. "A1–9 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) P = 3000 MW Primary control power [MW] 3000 P = 2000 MW 2000 P = 1500 MW P = 1000 MW 1000 P = 500 MW 0 0 10 20 30 40 Deployment time [s] 10.Performance Measurement A distinction is drawn between the quality of control in the entire SYNCHRONOUS AREA (overall quality) and the quality of control in each CONTROL AREA / BLOCK (local quality). Each interconnected undertaking / TSO must act to provide effective PRIMARY CONTROL, in order to ensure that a high overall level of quality is maintained. The main purpose of an overall quality check is to evaluate the performance of the PRIMARY CONTROL of the entire SYNCHRONOUS AREA. This evaluation is carried out by analysing the SYSTEM FREQUENCY of the network during disturbances. The main purpose of this frequency analysis is to estimate the operational reliability of the interconnected network. The NETWORK POWER FREQUENCY CHARACTERISTIC λu of the entire SYNCHRONOUS AREA is calculated by the following relationship: λu = ∆Pa ∆f with ∆Pa being the variation in power causing a disturbance and ∆f being the quasi-steady-state FREQUENCY DEVIATION in response to a disturbance. This is determined from a "smoothing line" drawn between 10 and 30 seconds after the disturbance, such that the sum of the FREQUENCY DEVIATIONS εi in respect of this line is zero (the line must be drawn so that the sum of the absolute deviations ε is a minimum, see next figure). "A1–10 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) f [Hz] Beginning of a disturbance 50.01 f0 50.00 20 s 49.99 f f10 f30 2 f0 49.98 Smoothing line 49.97 f30 f30 49.96 f10 f10 49.95 i 10 s 30 s 49.94 0 10 20 30 40 50 t [s] It is assumed that the main part of the PRIMARY CONTROL RESERVE is activated after 20 seconds, while the contribution of SECONDARY CONTROL to the correction of the disturbance will not yet be perceptible. A local quality check will allow each party to ascertain whether their respective contribution to PRIMARY CONTROL is consistent with the requirements. An interconnected undertaking / TSO can check the quality of its PRIMARY CONTROL by evaluating the NETWORK POWER FREQUENCY CHARACTERISTIC in its CONTROL AREA / BLOCK each time a disturbance occurs, and comparing it with the NETWORK POWER FREQUENCY CHARACTERISTIC of the entire SYNCHRONOUS AREA. The NETWORK POWER FREQUENCY CHARACTERISTIC λi in a CONTROL AREA / BLOCK is calculated by the following relationship: λi = − ∆Pi ∆f with ∆Pi being the variation in power generated in a CONTROL AREA / BLOCK in response to a disturbance, measured at interconnecting points / TIE-LINES (in the CONTROL AREA / BLOCK where the disturbance occurs, the power deficit/surplus must be added/subtracted) and ∆f being the quasi-steady-state FREQUENCY DEVIATION in response to a disturbance of ∆Pa. These two measurements must be simultaneous (the time stamps of all measurements need to be synchronous). It must be possible to estimate measurement errors. In CONTROL AREAS / BLOCKS, where fast random changes in total cross-border exchange power are comparable with variations in the cross-border exchange power for the area ∆Pi, the latter may be determined from smoothing lines representing the cross-border exchange power before and after a disturbance. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–11 In order to allow the quality of control to be monitored, it is advisable to record and continuously analyse outages in production or consumption exceeding 1000 MW 2. The following information is required for this purpose: • the location of the disturbance, • date and time of the disturbance, • the amount of production/consumption lost during the disturbance, • the type of the disturbance. The affected interconnected undertaking / TSO will make this information available to all other interconnection partners / TSOs. Even if the SYSTEM FREQUENCY measurement and power cross-border exchange measurements taken during a disturbance are inaccurate, they will allow each interconnected undertaking / TSO to carry out a statistical analysis of the NETWORK POWER FREQUENCY CHARACTERISTICS and PRIMARY CONTROL POWER being activated, and to compare the results of this analysis with corresponding values for the entire SYNCHRONOUS AREA. Each interconnected undertaking / TSO needs to complete regular checks in order to ensure that deployment times for their PRIMARY CONTROL RESERVE are consistent with the requirements of PRIMARY CONTROL. 2 : The value depends on the size of the SYNCHRONOUS AREA, the value of 1000 MW holds for the first only, for the second SYNCHRONOUS AREA of 2004 the value is 250 MW instead. SYNCHRONOUS AREA of 2004 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) B. "A1–12 Secondary Control [UCTE Operation Handbook Policy 1 Chapter B: Secondary Control, 2004] [UCPTE Rule 18: Terminology of interconnected operation, 1968] [UCPTE Rule 44: Control of active power in the grid of the UCPTE, 1990] [UCPTE Rule 1: The practical application of load-frequency control in western Europe, 1955] [UCPTE Rule 24: Control equipment for load-frequency control, 1971] [UCPTE Rule 26: General aspects about the registration and the balance of unintended deviation in the interconnected grid, 1974] [UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, 1998] 1. Introduction Any imbalance between electric power generation and consumption will result (in real-time) in a frequency change within the complete network of the SYNCHRONOUS AREA. As a result over time, a FREQUENCY DEVIATION occurs. At SYSTEM FREQUENCIES below 50 Hz, the total DEMAND has been larger than the total generation, at frequencies above 50 Hz the total DEMAND has been less than the total generation. In practise, the DEMAND varies continuously, even without having forecast errors, so that SECONDARY CONTROL on a real-time basis is required on a continuous basis. A deviation ∆f of SYSTEM FREQUENCY from its set-point value of 50 Hz will activate PRIMARY CONTROL power throughout the SYNCHRONOUS AREA: ∆Pu = λu • ∆f with λu = the POWER SYSTEM FREQUENCY CHARACTERISTIC of the whole SYNCHRONOUS AREA, i.e. the sum of the POWER SYSTEM FREQUENCY CHARACTERISTICS of all CONTROL AREAS / BLOCKS. PRIMARY CONTROL (see !A1-A) allows a balance to be re-established at a SYSTEM FREQUENCY other than the frequency set-point value (at a quasi-steady-state FREQUENCY DEVIATION ∆f), in response to a sudden imbalance between power generation and consumption (incident) or random deviations from the power equilibrium. Since all CONTROL AREAS / BLOCKS contribute to the control process in the interconnected system, with associated changes in the balance of generation and consumption in these CONTROL AREAS, an imbalance between power generation and consumption in any CONTROL AREA will cause power interchanges between individual CONTROL AREAS to deviate from the agreed / scheduled values (power interchange deviations ∆Pi). The function of SECONDARY CONTROL (also known as load-frequency control or frequencypower-control, see !A1-B) is to keep or to restore the power balance in each CONTROL AREA / BLOCK and, consequently, to keep or to restore the SYSTEM FREQUENCY f to its set-point value of 50 Hz and the power interchanges with ADJACENT CONTROL AREAS to their programmed scheduled values, thus ensuring that the full reserve of PRIMARY CONTROL POWER activated will be made available again. In addition, SECONDARY CONTROL may not impair the action of the PRIMARY CONTROL. These actions of SECONDARY CONTROL will take place simultaneously and continually, both in response to minor deviations (which will inevitably occur in the course of normal operation) and in response to a major discrepancy between production and consumption (associated e.g. with the tripping of a generating unit or network disconnection). In order to fulfil these requirements in parallel, SECONDARY CONTROL needs to be operated by the NETWORK CHARACTERISTIC METHOD (see !A1-B-2). UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–13 Whereas all CONTROL AREAS provide mutual support by the supply of PRIMARY CONTROL POWER during the PRIMARY CONTROL process, only the CONTROL AREA / BLOCK affected by a power unbalance is required to undertake SECONDARY CONTROL action for the correction. Consequently, only the controller of the CONTROL AREA / BLOCK, in which the imbalance between generation and consumption has occurred, will activate the corresponding SECONDARY CONTROL POWER within its CONTROL AREA / BLOCK. Parameters for the SECONDARY CONTROLLERS of all CONTROL AREAS need to be set such that, ideally, only the controller in the zone affected by the disturbance concerned will respond and initiate the deployment of the requisite SECONDARY CONTROL POWER. Within a given CONTROL AREA / BLOCK, the DEMAND should be covered at all times by electricity produced in that area, together with electricity imports (under purchase contracts and/or electricity production from jointly operated plants outside the zone concerned). In order to maintain this balance, generation capacity for use as SECONDARY CONTROL RESERVE must be available to cover power plant outages and any disturbances affecting production, consumption and transmission. SECONDARY CONTROL is applied to selected generator sets in the power plants comprising the control loop. SECONDARY CONTROL operates for periods of several minutes, and is therefore timely dissociated from PRIMARY CONTROL. This behaviour over time is associated with the PI (proportional-integral) characteristic of the SECONDARY CONTROLLER. SECONDARY CONTROL makes use of measurements of the SYSTEM FREQUENCY and ACTIVE POWER flows on the TIELINES of the CONTROL AREA / BLOCK, a SECONDARY CONTROLLER, that computes power setpoint values of selected generation sets for control (see !A1-B-4), and the transmission of these set-point values to the respective generation sets. When consumption exceeds production on a continuous basis, immediate action must be taken to restore the balance between the two (by the use of standby supplies, contractual load variation or LOAD-SHEDDING or the shedding of a proportion of customer load as a last resort). Sufficient transmission capacity must be maintained at all times to accommodate reserve control capacity and standby supplies. Since it is technically impossible to guard against all random variables affecting production, consumption or transmission, the volume of reserve capacity will depend upon the level of risk which is deemed acceptable. These principles will apply, regardless of the division of responsibilities between the parties involved in the supply of electricity to consumers. 2. Principle of the Network Characteristic Method UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–14 In order to determine, whether power INTERCHANGE DEVIATIONS are associated with an imbalance in the CONTROL AREA / BLOCK concerned or with the activation of PRIMARY CONTROL POWER, the NETWORK CHARACTERISTIC METHOD needs to be applied for SECONDARY CONTROL of all CONTROL AREAS / BLOCKS in the SYNCHRONOUS AREA. According to this method, each CONTROL AREA / BLOCK is equipped with one SECONDARY CONTROLLER to minimise the AREA CONTROL ERROR (ACE) G in real-time: G = Pmeas − Pprog + K ri ( f meas − f 0 ) with Pmeas being the sum of the instantaneous measured active power transfers on the tielines, Pprog being the resulting exchange program with all the neighbouring / ADJACENT CONTROL AREAS, Kri being the K-FACTOR of the CONTROL AREA, a constant (MW/Hz) set on the SECONDARY CONTROLLER, and fmeans-f0 being the difference between the instantaneous measured SYSTEM FREQUENCY and the set-point frequency. The ACE is the CONTROL AREA’s unbalance Pmeas-Pprog minus its contribution to the PRIMARY CONTROL, if Kri is equal to the CONTROL AREA’s POWER SYSTEM FREQUENCY CHARACTERISTIC. The power transits are considered positive for export and negative for import (see !I-J). Hence, a positive (respectively a negative) ACE requires a reduction (resp. an increase) of the SECONDARY CONTROL POWER. The ACE must be kept close to zero in each CONTROL AREA / BLOCK. The purpose is twofold: • Control area / block balance. If the measured SYSTEM FREQUENCY fmeas is equal to the set-point frequency f0, the ACE is the unbalance of the CONTROL AREA / BLOCK, i.e. the difference between the measured power exchanges Pmeas and the scheduled exchanges Psched. • Non detrimental effect on primary control. The power developed by PRIMARY CONTROL in the CONTROL AREA / BLOCK under consideration is given by − λi ( f meas − f 0 ) . This amount of power has to be subtracted from the power unbalance in order not to neutralise the PRIMARY CONTROL action. This is true if Kri=λi. Due to the uncertainty on the self regulating effect of the load, Kri may be chosen slightly higher than λi such that the SECONDARY CONTROL will accentuate the effect of the PRIMARY CONTROL and not counteract it. When ∆f = f means − f 0 = 0 , under balanced conditions ( Pmeas = Pprog ), the ACE will also be equal to zero. For reasons of simplicity, the NETWORK CHARACTERISTIC METHOD will be explained on the basis of an interconnected system comprising of two CONTROL AREAS only. a) Before a disturbance: The situation before the disturbance is assumed to be the following: ∆f = 0 (actual frequency f = set point frequency fo ) (actual exchange capacity = set point exchange capacity) ∆P12 = 0 b) Disturbance and PRIMARY CONTROL: Let us suppose that, in network 2, a generated power Pa is lost. PRIMARY CONTROL stabilises the frequency at fo+∆f . The following relationship will apply to the entire system: ∆f = Pa/λu , where λu is the NETWORK POWER FREQUENCY CHARACTERISTIC. Since generating capacity is lost, Pa will have a negative value. Hence, ∆f will also be negative. In response to the FREQUENCY DEVIATION ∆f, and on the basis of the NETWORK POWER FREQUENCY CHARACTERISTICS λ1 and λ2 of the two separate networks, the following power values will be activated by PRIMARY CONTROL: "A1–15 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) ∆P1 = − λ1 • ∆f ∆P2 = − λ2 • ∆f The loss of power Pa will be offset by the power values ∆P1 and ∆P2 : ∆P1 + ∆P2 = − ∆Pa , and the frequency will be stabilised at a lower value, reduced by ∆f. c) Behaviour of SECONDARY CONTROL The exchange power ∆P between the two CONTROL AREAS will no longer be zero, but becomes ∆P12 = ∆P1, considered from CONTROL AREA 1, is an exported power, i.e. has a positive value, ∆P21 (= -∆P12 ), considered from CONTROL AREA 2, is an imported power, i.e. has a negative value. Under the condition that the value of Kr1 is set at λ1 on controller 1, and the value of Kr2 is set at λ2 on controller 2, this will give the following relationship for the overall control deviations G1 and G2: G1 = ∆P12 + K r1 • ∆f = ∆P1 + (− ∆P1 ) = 0 i.e. controller 1 does not react, and PRIMARY CONTROL in CONTROL AREA 1 will be maintained as long as a ∆f persists; no SECONDARY CONTROL will be activated in CONTROL AREA 1. For area 2, the AREA CONTROL ERROR is given by: G 2 = ∆P21 + K r 2 • ∆f = − ∆P1 + (− ∆P2 ) = ∆Pa i.e. controller 2 activates SECONDARY CONTROL, and PRIMARY CONTROL in CONTROL AREA 2 will be maintained as long as a ∆f persists; the loss of power Pa will be offset by the action of the SECONDARY CONTROLLER in area 2, such that the deviation associated with the loss of power Pa will be restored to zero. P12 = - P21 Characteristic of network 2 G2( f) seen from network 1 Power interchange deviation P12 2 f Pa Network 1 ~ Pa Network 2 1 f f f Frequency deviation Characteristic of network 1 G1( f) If SECONDARY CONTROL is to behave as described above, the following conditions need to be fulfilled: • • Power plants involved in SECONDARY CONTROL must have sufficient SECONDARY CONTROL POWER available at all times, thereby ensuring that a change in the setting of the SECONDARY CONTROLLER will produce an actual change in power produced by generating sets (SECONDARY CONTROL RESERVE), see !A1-B-6. Gi may not include any additional term, e.g. a corrective term for the automatic minimisation of an involuntary hourly exchange or any other form of compensation. 3. K-Factor In order to ensure that SECONDARY CONTROL will only be called up in the CONTROL AREA / BLOCK which is the source of the disturbance, all values for K-FACTORS Kri set on the UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–16 SECONDARY CONTROLLERS should, in theory, be equal to the CONTROL AREA’s POWER SYSTEM FREQUENCY CHARACTERISTIC λ1 (if the Darrieus equation is to be satisfied). The NETWORK POWER FREQUENCY CHARACTERISTIC of a CONTROL AREA will change in accordance with the rated load of generator sets in service at any given time. Consequently, it might be envisaged that Kri should be adjusted regularly to take account of generators in service. However, this is to be avoided, since the uncoordinated adjustment of Kri by the various interconnection partners will produce greater discrepancies in their respective SECONDARY CONTROL behavior than those associated with the preservation of the various Kri at constant values. Due to the uncertainty on the self regulating effect of the load, the K-FACTOR Kri may be chosen slightly higher than the rated value of the POWER SYSTEM FREQUENCY CHARACTERISTIC such that the SECONDARY CONTROL will accentuate the effect of the PRIMARY CONTROL and not counteract it. 4. Secondary Controller The desired behaviour of the SECONDARY CONTROLLER over time will be obtained by assigning a proportional-integral characteristic (PI) to control circuits, in accordance with the following equation: ∆Pdi = − β i • Gi − 1 Tri ∫ Gi • dt where: ∆Pdi = the correcting variable of the SECONDARY CONTROLLER governing control generators in the CONTROL AREA i ; Βi = the proportional factor (gain) of the SECONDARY CONTROLLER in CONTROL AREA i ; Tr = the integration time constant of the SECONDARY CONTROLLER in CONTROL AREA i ; Gi = the AREA CONTROL ERROR (ACE) in CONTROL AREA i. As SYSTEM FREQUENCY and POWER DEVIATIONS are to return to their set point values within the required time (without additional control needed), an appropriate integral term needs to be applied. An excessively large proportional term may have a detrimental effect upon the stability of interconnected operation. In particular, where hydroelectric plants are used for SECONDARY CONTROL, there is a risk that an increase in the proportional term will initiate network oscillations. This natural period of oscillation may range from 3 to 5 seconds, and may be subject to change as the SYNCHRONOUS AREA is extended. In case of a persisting positive or negative ACE, leading to a saturation of the SECONDARY CONTROL RESERVES, the integral term should be limited. The non-windup character of the SECONDARY CONTROLLER allows to recover control as soon as the ACE returns to zero. Parameter settings for SECONDARY CONTROLLERS of all CONTROL AREAS / BLOCKS need to follow a common guideline to ensure co-operative SECONDARY CONTROL within the SYNCHRONOUS AREA. 5. Control Hierarchy and Organisation The SYNCHRONOUS AREA consists of multiple interconnected CONTROL AREAS / BLOCKS, each of them with centralised SECONDARY CONTROL. Each CONTROL AREA / BLOCK may divide up into sub-control areas that operate their own underlying SECONDARY CONTROL, as long as this does not jeopardise the interconnected operation. The hierarchy of SECONDARY CONTROL consists of the SYNCHRONOUS AREA, with CONTROL BLOCKS and (optionally) included CONTROL AREAS, see the following figure: UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) "A1–17 If a CONTROL BLOCK has internal CONTROL AREAS, the CONTROL BLOCK organises the internal SECONDARY CONTROL according to one of the following schemes (basically, the type of internal organisation must not influence the behaviour or quality of SECONDARY CONTROL between the CONTROL BLOCKS): • Centralised: SECONDARY CONTROL for the CONTROL BLOCK is performed centrally by a single controller (as one CONTROL AREA); the operator of the CONTROL BLOCK has the same responsibilities as the operator of a CONTROL AREA. • Pluralistic: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK CO-ORDINATOR, regulates the whole block towards its neighbours with its own controller and regulating capacity, while all the other TSOs of the block regulate their own CONTROL AREAS in a decentralised way by their own; • Hierarchical: SECONDARY CONTROL is performed in a decentralised way with more than one CONTROL AREA; a single TSO, the BLOCK CO-ORDINATOR, operates the superposed block controller which directly influences the subordinate controllers of all CONTROL AREAS of the CONTROL BLOCK; the BLOCK CO-ORDINATOR may or may not have regulating capacity on its own. 6. Secondary Control Range and Reserve The SECONDARY CONTROL RANGE is the range of adjustment of the SECONDARY CONTROL POWER, within which the SECONDARY CONTROLLER can operate automatically, in both directions (positive and negative) at the time concerned, from the working point of the SECONDARY CONTROL POWER. The SECONDARY CONTROL RESERVE is the positive part of the SECONDARY CONTROL RANGE between the working point and the maximum value. The portion of the SECONDARY CONTROL RANGE already activated at the working point is the SECONDARY CONTROL POWER. The size of the SECONDARY CONTROL RESERVE that is required typically depends on the size of typical load variations, schedule changes and generating units. The recommended minimum reserve related to load variations is given in the following figure: "A1–18 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) Generators participating in secondary control Secondary control reserve Working point Working points and control ranges in the case of a proportional distribution of control power from the two generators M1 and M2 Secondary control power M1 working point M1 control range M1 instantaneous output M1+M2 instantaneous output M2 working point M2 control range Secondary control range M2 instantaneous output Non-adjustable output M1 Non-adjustable output Values resulting from the two generators M2 If the consumption exceeds production on a continuous basis, notwithstanding the availability of this reserve capacity, immediate action must be taken to restore the balance between the two (by the use of TERTIARY CONTROL, standby supplies, contractual load variation / LOADSHEDDING (some countries refer to ”load interruption”) or the LOAD-SHEDDING of a proportion of customer load as a last resort). Sufficient transmission capacity must be maintained at all times to accommodate reserve control capacity and standby supplies (see !A1-C). 900 800 700 Recommended secondary control reserve in MW 600 500 400 300 200 100 90000 80000 70000 60000 50000 40000 30000 20000 10000 0 0 L max. in MW The rate of change in the power output of generators used for SECONDARY CONTROL must in total be sufficient for SECONDARY CONTROL purposes. It is defined as a percentage of the rated output of the control generator per unit of time, and strongly depends upon the type of generator3. Typically, for oil- or gas-fired power stations, this rate is of the order of 8% per minute. In the case of reservoir power stations, the rate of continuous power change ranges from 1.5 to 2.5% of the rated plant output per second. In hard coal- and lignite-fired plants, this rate ranges from 2 to 4% per minute and 1 to 2% per minute respectively. The maximum rate of change in output of nuclear power plants is approximately 1 to 5% per minute. These sample figures for customary rates of change in SECONDARY CONTROL action will be used as an aid to the definition of an optimum offset correction time. 7. Exchange Programs The algebraic sum of the agreed hourly EXCHANGE PROGRAMS of cross-border exchange transfers between CONTROL AREAS / BLOCKS and the ADJACENT CONTROL AREAS constitutes 3: The type of generators that may be used for SECONDARY CONTROL within a CONTROL AREA depends on the generation mix / primary energies available in that geographical area and is therefore not evenly distributed in the SYNCHRONOUS AREA. "A1–19 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) the power interchange set point for the CONTROL AREAS’ SECONDARY CONTROLLER. In order to prevent excessive fluctuations on interconnections when program changes occur, it is necessary that this jump is converted to a ramp lasting 10 minutes in total, starting 5 minutes before the agreed change of the EXCHANGE PROGRAM and ending 5 minutes later (see example in figure below), regardless of the time-step (one hour, 30 minutes or 15 minutes) or the step size of the schedule (see !P2 and !A2 for further details of scheduling and accounting). Export 10 min t 6 7 8 9 10 h Import Set point value of power interchange Agreed hourly schedule In order to prevent unintentional FREQUENCY DEVIATIONS and major control actions under undisturbed conditions, TRANSMISSION SYSTEM OPERATORS (TSOs) are required to maintain careful compliance with times for programme changes, particularly where changes in the EXCHANGE PROGRAMS of several hundred MW are involved. In particular, care must be taken to ensure that generating capacity is brought on line or disconnected on a staggered basis, particularly for tariff changes at 6 a.m. and 10 p.m. A substantial change in SCHEDULING of he scheduled modification of power plant operation must not have a negative impact upon system operation of the type which might be associated e.g. with a disturbance. 8. Quality of Control during Normal Operation In order to allow the continuous monitoring of the quality of SECONDARY CONTROL, the FREQUENCY DEVIATION is evaluated statistically each month by determining the standard deviation σ: σ = 1 n 2 ⋅ ∑ ( fi − f0 ) n i =1 (n is the number of average values over 15 minutes) and the number and duration of frequency corrections. FREQUENCY DEVIATIONS ∆f > 50 mHz must also be monitored with respect to the frequency set-point, and the proportion of time during which ∆f exceeds 50 mHz must also be measured. 9. Quality of Control during Large Deviations "A1–20 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) The quality of SECONDARY CONTROL must be monitored by measuring and analysing control in individual CONTROL AREAS / BLOCKS after losses of generating capacity or load exceeding 1000 MW 4 (observation incident). The necessary data will be provided by the TSOs / interconnected undertaking concerned. Measurements of SYSTEM FREQUENCY and power interchanges behaviour during an incident allows a statistical analysis of PRIMARY and SECONDARY CONTROL performance. The reaction or response of the SYNCHRONOUS AREA to a major disturbance Pa (generator shutdown or loss of load) in a CONTROL AREA / BLOCK and the return of the SYSTEM FREQUENCY f to its initial value (quality of SECONDARY CONTROL) are monitored by using the “trumpet method”, described here after. In order to assess the quality of SECONDARY CONTROL in CONTROL AREAS / BLOCKS, trumpet-shaped curves of the type H (t ) = f 0 ± A ⋅ e −t T have been defined on the basis of values obtained from experience and the monitoring of SYSTEM FREQUENCY over a period of years. When the SYSTEM FREQUENCY is maintained within the trumpet during the SECONDARY CONTROL process, the completion of the latter is deemed to be satisfactory, in terms of technical control. The trumpet curve for a given incident will be plotted using the following values (see figure below): • the set-point frequency f 0 (on the figure below, f 0 = 50.01 Hz) • the actual frequency f1 before the incident (on the figure below, f1 is different from f 0 ) • the maximum frequency deviation ∆ f 2 after the incident, with respect to the set-point f 0 • the loss of generating capacity ∆ Pa responsible for the incident. The following relationship between the above mentioned parameters do apply (see next figure): ∆f 2 = f 2 − f 0 = ∆f 1 + ∆f 0 ´ 50.250 ´´ ´´ ´´ f [Hz] ´´ ´´ ´´ ´´ 50.150 ´´ ´´ ´´ ´´ ´´ ´´´ ´´´ ´´´ ´´´ ´´´ ´´´´ ´´´´ ´´´´ 50.050 fo = 50.010 ´´´´´´ ´´´´´´´ ´´´´´´´´ ´´´´´´´´´´ ´´´´´´´´´´´´´´´´´´´´´´´ d fo f50 f1 49.950 f2 f1 49.850 f2 49.750 -100 ´´´´´ ` 0 `` `` ` `` ` `` `` 100 `` ` `` `` `` `` 200 ` ` ``` ``` ``` ` `` ``` ```` ```` ````` ````` ````` ``````` ```````` ``````````` ````````````````````` 300 400 500 600 700 800 900 1000 1100 t [s] The following relationship will apply to the trumpet curve (envelope curve) H (t ) H (t ) = f 0 ± A ⋅ e −t T 4 The value of 1000 MW holds for the first synchronous zone only, for the second synchronous zone the value currently is 250 MW instead. "A1–21 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) The value A is established on the basis of frequency monitoring over a period of years for A = 1.2 ⋅ ∆f 2 The SYSTEM FREQUENCY must be restored to a margin of d = ± 20 mHz of the set point frequency 900 seconds (15 minutes) after the start of an incident. Hence, the time constant T of the trumpet curve is determined by the following formula: T = 900 A ln d for T ≤ 900 s and d = 20 mHz The series of curves described hereafter and shown on the figure below indicate the SYSTEM FREQUENCY response required after a given loss of power ∆ Pa . The following relationship will apply after the loss of ∆ Pa : λu = ∆Pa ∆P or ∆f 1 = a ∆f1 λu For each loss of power, this relationship gives the corresponding frequency deviation ∆f1 . Frequency monitoring over many years has shown that the FREQUENCY DEVIATION ∆f 0 is often greater (up to ±30 mHz) before an incident than after the secondary control process (up to ±20 mHz). This is due to the insensitivity of PRIMARY and SECONDARY CONTROL and the inaccuracy of the measurements. In the series of curves, this is taken into account by a general increase of 30 mHz in factor A*: 1 ⋅ ∆Pa + 30 mHz A* = ± 1.2 ⋅ ( ∆f1 + 30 mHz ) = ± 1.2 ⋅ λu All other initial values will remain the same. This gives the following for the series of curves H * (t ) with ∆ Pa as parameter: 1 ⋅ ∆Pa + 30 mHz ⋅ e −t T H * (t , ∆Pa ) = f 0 ± A* ⋅ e −t T , H * (t , ∆Pa ) = f 0 ± 1.2 ⋅ λu Pa (parameter) -3200 MW -2800 MW 50.2 -2400 MW -2000 MW f [Hz] -1600 MW 50.1 -1200 MW -800 MW -400 MW d 50.0 400 MW 49.9 800 MW 1200 MW 1600 MW 2000 MW 49.8 2400 MW 2800 MW 3200 MW -100 0 100 200 300 400 500 600 700 800 900 1000 1100 t [s] The SYSTEM FREQUENCY itself depends on a lot of other circumstances, physical effects and underlying control mechanisms (see !A1-A), that cannot be clearly distinguished in all cases. Therefore, the analysis is usually made on a case-by-case basis. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) C. "A1–22 Tertiary Control [UCTE Operation Handbook Policy 1 Chapter C: Tertiary Control, 2004] [UCPTE-Ground Rules concerning primary and secondary control of frequency and active power within the UCPTE, 1998] 1. Introduction TERTIARY CONTROL is any automatic or manual change in the working points of generators or loads participating, in order to: • • guarantee the provision of an adequate SECONDARY CONTROL RESERVE at the right time, distribute the SECONDARY CONTROL POWER to the various generators in the best possible way, in terms of economic considerations. Changes may be achieved by: • • • • connection and tripping of power (gas turbines, reservoir and pumped storage power stations, increasing or reducing the output of generators in service); redistributing the output from generators participating in secondary control; changing the power interchange programme between interconnected undertakings; load control (e.g. centralised telecontrol or controlled LOAD-SCHEDDING). Typically, operation of TERTIARY CONTROL (in succession or as a supplement to SECONDARY is bound to the time-frame of SCHEDULING, but has on principle the same impact on interconnected operation as SECONDARY CONTROL. CONTROL) 2. Tertiary Control Reserve The power which can be connected automatically or manually under TERTIARY CONTROL, in order to provide / restore an adequate SECONDARY CONTROL RESERVE, is known as the 5 TERTIARY CONTROL RESERVE / 15 minute reserve . This TERTIARY CONTROL RESERVE must be used in such a way that it will contribute to the restoration of the SECONDARY CONTROL RANGE when required (see !A1-B for details on SECONDARY CONTROL). 5: Because of the typical time-frame for SCHEDULING of 15 minutes. "A1–23 UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) Increase in secondary control reserve by starting up the non-adjustable generator M3 as tertiary reserve (minute reserve) Secondary control reserve Working point Secondary control reserve Working point Secondary control range Secondary control range Secondary control power New working points M1+M2+M3 instantaneous output Secondary control power M2 nonadjustable output M1+M2 instantaneous output M3 tertiary (minute) reserve Nonadjustable output Values resulting from the two generators M1 and M2 M1 M2 M3 Values resulting from all the generators M1 M2 M3 The restoration of an adequate SECONDARY CONTROL RANGE may take, for example, up to 15 minutes, whereas TERTIARY CONTROL for the optimisation of the network and generating system will not necessarily be complete after this time. The timing of the various (partially overlapping) ranges of action of PRIMARY, SECONDARY and TERTIARY CONTROL are shown in the following figure. Range of primary control Range of secondary control Range of optimisation Range of tertiary reserve (minute reserve) Range where primary control is still operative. It is progressively replaced by secondary control action Type of control Tertiary control manual and/or automatic Secondary control Primary control 30 s 15 min Time from beginning of overall system deviation 3. Capacity Constraints The following non-usable capacity must be taken into account in the calculation of capacity needed to meet power requirements: • • • units subject to long-term shutdown; units shut down for repair and maintenance; limits on capacity associated with restrictions in fuel supplies (e.g. restrictions on gas supplies during the peak winter months); UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) • "A1–24 limits on capacity associated with environmental restrictions (e.g. temperature of waste water in summer, pollution, etc.); • limits on the capacity of hydroelectric plants associated with hydraulic and environmental constraints (e.g. output restrictions, etc.); • the primary control reserve; • reserves to cover variations in production and consumption (secondary and tertiary reserves). In addition to these factors, which are directly associated with production, account must also be taken of system conditions, given that network constraints may reduce scope for the transmission of power produced. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) D. "A1–25 Time Control [UCTE Operation Handbook Policy 1 Chapter D: Time Control, 2004] [UCPTE Rule: Technical rule for the correction of synchronous time, 1998] [UCPTE Rule: Recommendations for the frequency in the interconnected operation of the UCPTE, 1996] 1. Summary If the mean SYSTEM FREQUENCY in the SYNCHRONOUS ZONE deviates from the nominal frequency of 50 Hz, this results in a discrepancy between SYNCHRONOUS TIME and universal coordinated time (UTC). This time offset serves as a performance indicator for PRIMARY, SECONDARY and TERTIARY CONTROL (power equilibrium) and must not exceed 30 seconds. The Laufenburg control centre in Switzerland is responsible for the calculation of SYNCHRONOUS TIME and the organisation of its correction. Correction involves the setting of the set-point frequency for SECONDARY CONTROL in each CONTROL AREA / BLOCK at 49.99 Hz or 50.01 Hz, depending upon the direction of correction, for full periods of one day (from 0 to 24 hours). The quality of SYSTEM FREQUENCY will be regarded as satisfactory over a one month period: • • where the standard deviation for 90% and 99% of measurement intervals is less than 40 mHz and 60 mHz respectively for the whole month considered; where the number of days’ operation at a set point frequency of 49.99 Hz or 50.01 Hz does not exceed eight days per month respectively (to be confirmed by experience). UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) E. "A1–26 Measures for Emergency Conditions [UCTE Operation Handbook Policy 1 Chapter E: Measures for Emergency Conditions, 2004] [UCPTE Rule 15: Measures for frequency control and precautions for the decrease of the frequency value, 1965] [UCPTE Rule 33: Recommendations for measures for frequency control and large disturbances, 1983] [UCPTE Rule: Recommendations for the frequency in the interconnected operation of the UCPTE, 1996] 1. Introduction The direct measures for emergency conditions are based to a certain extent on the philosophy that in the event of a major disruption (short-term and where possible), selective restrictions in the energy supply are more acceptable then the consequences of an extended network breakdown resulting in a power cut lasting for several hours. The main principles of “Operational Security” are described in policy 3 (see !P3). The SYSTEM FREQUENCY as a global parameter is the main criterion that signalises emergency situations in the system. Due to its equal value in the interconnected system, all partners are automatically participating at problem solving by the automatic action of the PRIMARY CONTROLLERS (see !A1-A). Local indicators, that inform about possible emergency situations, are “overloading of the interconnecting TIE-LINES” that can result in action of automatic protection devices and isolating of some part of the system. Important local signals of the emergency situation are also “decreasing of the transmission voltage” that can cause voltage collapse due to abnormally high flow of reactive power in the transmission system. Counteraction of the SECONDARY CONTROLLER and the measures for emergency conditions (e.g. in the scope of system defence during a big drop of frequency) shall be avoided in a coordinated way. 2. Recommendations for Load-Shedding Frequency thresholds must be defined for LOAD-SHEDDING. The UCTE recommends that its members should initiate the first stage of automatic load-shedding in response to a frequency threshold not lower than 49 Hz. • Sudden failure of 3000 MW of the generating capacity in normal operation without other disruptions have to be corrected solely by the action of the PRIMARY CONTROLLER without frequency sensitive action triggering of LOAD-SHEDDING. • In case of a frequency drop of 49 Hz the automatic LOAD-SHEDDING begins with a minimum of 10 to 20% of the load. Each TSO determines shedding plans on his own. In case of lower SYSTEM FREQUENCIES, the synchronously interconnected network may be divided into partial networks. In this case, far more difficult conditions will arise in those partial networks affected by a shortfall in capacity. For this reason, the staggered operation of relays for LOAD-SHEDDING in response to a frequency criterion will allow the system load to be reduced to a sufficient extent for the restoration of balanced conditions in these partial networks, before the threshold for the isolation of plants for the supply of auxiliaries or the tripping of generators is reached. LOAD-SHEDDING should be performed at trigger frequencies of 48.7 Hz and 48.4 Hz (or as in France at 48.5 Hz and 48.0 Hz) to the amount of about 10 to 15% of the load. The partners accept LOAD-SHEDDING also if the failure occurs outside the CONTROL AREA of the respective TSO. Triggering frequencies should be modified by the competent TSO - slight dissipation of the triggers will cause gradual increasing of the load. • LOAD-SHEDDING in each stage shall be established to minimize the risk of further uncontrolled separation, loss of generation, or system shutdown. 3. Recommendations for Power Plants The following possible measures for emergency conditions are related to power plants: • At 49.8 Hz, quick-start power plants should be connected to the grid. • Under emergency conditions and if applicable, the operating mode of (thermal) generating units should/may be changed from power pressure into speed control. A very fast rate of change can be possible within the whole operating range, yet being very uneconomic. UCTE OH – Appendix 1: Load-Frequency Control … (final 1.9 E, 16.06.2004) • "A1–27 Power stations automatically disconnect at 47.5 Hz6 without time delay, and shall safeguard auxiliary service supply. Operation of power plants below this frequency is endangered (loss of capacity in the auxiliary gear, danger vibration, damage of the blade and foundations). 4. Recommendations for power plants regarding U/Q control Measures for emergency conditions regarding U/Q control can be supported by: • transformers with regulation on-load tap changing device • static compensation Measures must be taken to maintain reactive power near to the point of consumption to ensure minimal transfer of reactive power through the network. 6: The critical negative limit of the SYSTEM FREQUENCY of 47.5 HZ (and the positive limit of 52.5 Hz as well) are known to be critical for generation sets, because this may trigger automatic disconnection of generators for safety reasons. APPENDIX 2 SCHEDULING AND ACCOUNTING A2 – Appendix 2: Scheduling and Accounting Appendix Chapters A. B. C. Scheduling of Power Exchange Online Observation Accounting of Unintentional Deviations Introduction This Appendix to Policy 2 explains and motivates the basic technical and organisational principles of Scheduling, Online Observation and Accounting mechanism for the UCTE, as it is applied in the SYNCHRONOUS AREA by the TSOs of the various CONTROL AREAS/BLOCKS. In order to prevent systematic faults in the context of LOAD FREQUENCY CONTROL (see Policy 1) it is an important issue to check the UCTE wide consistency of the input variables used by the single parties involved. For this purpose the task of co-ordination is performed, which takes into account the exchange schedules (Process: Schedule Management), the real – time measurements (Process: Online Observation) and the compensation programs (Process: Accounting). The task of UCTE co-ordination is organised on the basis of the three hierarchical levels CO-ORDINATION CENTRE, CONTROL BLOCK and CONTROL AREA (see figure 1). NL D CENTREL RWE E.ON VEAG DK VE-T BEWA PL G B CEGEDEL TIRAG EnBW Acc. Block CZ VKW FE P F CH UCTE North Acc. Area S K H A E RO BG UKR 7 P MO R JIEL I SLO HR BIH UCTE South Figure 1: Hierarchical Levels of UCTE Co-ordination1 1 Situation after re-synchronisation of the second synchronous zone CG EKC SR MK AL GR UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) !A2–2 History of changes v0.4 v0.3 draft 5.04.2004 draft 12.03.04 OH Team OH Team draft for internal consultation comments RWE Current Status This document summarises technical descriptions and backgrounds of a subset of current UCTE rules and recommendations related to scheduling and accounting issues, with additional items. This document and other chapters of the UCTE Operation Handbook as well as excerpts from it may not be published, redistributed or modified in any technical means or used for any other purpose outside of UCTE without written permission in advance. UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) A. !A2–3 Scheduling of Power Exchange [UCTE-Ground Rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] [ETSO ESS Implementation guide, R2V2] [ETSO EIC] 1. Definitions In the operational planning phase the market participants have to nominate their border crossing trades by the use of an exchange schedule to the control area operator. The exchange schedule counts positive in export direction and negative in import direction. For each time unit t the market participant α has to declare within the Control Area k a cross border trade with the market participant β in the Control Area l by means of the exchange schedule ESklαβτ. The market participant β declares a corresponding exchange schedule ESklβατ within the Control Area l. The following equation applies: (1) ES klαβ t = − ES lkβαt Each Control Area operator k accumulates the declared exchange schedules per time unit t and per border to an adjoining Control Area l to the total exchange schedule ESklt. For each border between two Control Areas k and l the following equation applies. (2) ES klt = − ESlkt The exchange schedules form an essential input quantity for the LOAD-FREQUENCY CONTROL. Thus the validity of the equations (1) and (2) has to be checked for every time unit and for every border. Equation (2) has to be checked on the different levels of co-ordination, i.e. CONTROL AREA, CONTROL BLOCK and CO-ORDINATION CENTRE. 2. Procedure To prove the validity of the equations introduced above an information exchange has to be set up among the parties involved. In figure 2 five types of information exchanges are introduced (Market Party Responsible Schedule, CAS, CAX, CBS, CCT) including a description of sender and receiver of the information. Obviously, the Market Party Responsible Schedule has to include the detail of exchange schedules between market participants α and β. Since the data exchange between CONTROL AREAS has the purpose to prove equation (1) the CAS has to provide the same degree of detail. The following data exchanges are all needed to prove equation (2) at different hierarchical levels of co-ordination. Thus the CAX, CBS and CCT has to include the detail of exchange schedules between CONTROL AREAS k and l. !A2–4 CCT CBS CAX CAS (Market) Party Responsible schedule Control Block Receiver Control Area Market Party Control Area Control Block Sender Co-ordination Centre Co-ordination Centre UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) Figure 2: Information Exchange Type at different hierarchical Levels of UCTE Co-ordination The hierarchical procedure of the schedule management co-ordination starts with the verification of exchange schedules between control areas. After the receipt of the final exchange schedules from the Market Party Responsibles the Control Area Operators exchange a CAS and check the validity of equation (1). In case of any discrepancies the affected market participants and time units are identified and the Market Party Responsibles are asked for clarification. If the discrepanncy can not be solved before a pre-defined gate closure time (see Chapter 3) the exchange schedule is rejected. The co-ordination procedure continues with the control block verification. The control block verification starts after completion of the control area verification by the submitting of CAX from the control area operators to the control block operator concerned. First the control block operator validates the complete data set received by checking equation (2) for the internal control area borders of its control block. Second the control block operators exchange CBS and validate the external control area borders of its control block by checking equation (2). The last step of the co-ordination procedure is the co-ordination centre verification. The coordination centre verification starts after completion of the control block verification by the submitting of CBS from the control block operators to the co-ordination centre concerned. First the co-ordination centre operator validates the complete data set received by checking equation (2) for the internal control area borders of its co-ordination centre. Second the coordination centre operators exchange CCT and validate the external control area borders of its co-ordination centre by checking equation (2). Taking into account the significant number of participants in the scheduling process, as well as the different verification levels, common procedure and methodology must be applied in order to enable automation of the process. First of all common ETSO Exchange Scheduling System (ESS) shall be used for scheduling. Second, all participants in the scheduling process shall be recognised by the ETSO Exchange Identification Code (EIC). Third, all the data exchange shall be executed via Electronic Highway. UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) !A2–5 3. Gate Closure (Day - Ahead D-1 and Intra-Day D) Due to different market models and regulatory framework there are different rules and gate closure times for the nomination of exchange schedules by market participants in the UCTE countries. To enable an orderly procedure of the UCTE co-ordination common gate closure times have to be defined for the different hierarchical levels of co-ordination. As a precondition, these gate closure times have to be after the latest gate closure time in any country involved. On the other hand they must allow sufficient time for the execution of the data exchange, validation, verification and troubleshooting at each level of the co-ordination. Figure 3 and 4 give an overview on the co-ordination process and point out the common gate closure times for both the day – ahead process and the intra – day process. !A2–6 UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) 7 CC 5 6 3 2 CB Data Validation Submit Exchange Schedules CBS 16:30 CC Verification CCT 17:00 4 CB CB CA datavalidationVerification CBS CB Submit Exchange Schedules CAX 15:45 CA CA 1 CA Verification CAS 7 CC 5 6 Submit Exchange Schedules CBS 16:30 CB Data Validation 4 CB 3 2 CC Verification CCT 17:00 CB Verification CA data validation CBS Submit Exchange Schedules CAX 15:45 CA CA 1 CA Verification CAS Figure 3: Gate Closure Times for the Day - Ahead Process (D-1) CB !A2–7 UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) 7 CC 5 6 Submit Exchange Schedules CBS H - 30 CB Data Validation 4 CB 3 2 CC Verification CCT H - 15 CA data validation CB Verification CBS Submit Exchange Schedules CAX H - 45 CA CA 1 CA Verification CAS Figure 4: Gate Closure Times for the Intra - Day Process (D) CB UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) B. !A2–8 Online Observation [UCTE-Ground Rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] 1. Definitions During online operation each control area operator k calculates the control program CPkt from the total exchange schedules agreed during the schedule management process and its compensation program COMPkt for each time unit t: (3) CPkt = ∑ ES klt + COMPkt l The control program CPkt represents the planned total exchange of the control area. For the sum of compensation programs the following equation applies: (4) 0 = ∑ COMPkt k The real exchange of control area is represented by the physical tie - line flows crossing each border. The physical flow between control area k and control area l at each interconnection line γ measured for the time unit t is called ETklγt. The following equation applies in the range of accuracy of the measurement: (5) ETklγt = − ETlkγt Each Control Area operator k accumulates the physical flows per time unit t and per border to an adjoining Control Area l to the total exchange schedule ETklt. For each border between two Control Areas k and l the following equation applies in the range of accuracy of the measurement: (6) ETklt = − ETlkt During online operation each control area operator k calculates its total real exchange ETkt : (7) ETkt = ∑ ETklt l The load frequency controller uses the control deviation CDkt: (8) CDkt = ETkt − CPkt UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) !A2–9 The same equations apply for the operation of a control block. 2. Procedure To avoid a systematic, UCTE wide fault in the load frequency control, resultion in a permanent frequency deviation, the following equation has to apply in the range of accuracy of the measurement: (9) 0 = ∑ CDkt k The validity of this equation can be proven by equations (2), (3), (4), (6), (7) and (8). In real time operation different fault scenarios can occur deteriorating the validity of equation (9). Such fault scenarios comprise wrong exchange schedules or on-line telemeasurement as well as faulty calculations of the control deviation. In order to improve detecting, as early as possible, any error concerning on-line telemeasurements, any misunderstanding which may occur in setting the exchange programs, etc. and in order to implement without delay the appropriate corrective actions the online observation of a set of pre-defined figures is performed at the different levels of co-ordination. On the control block level each control area operator k provides the on-line telemeasurement values per tie –line ETklγt and its control deviation CDkt to the control block operator concerned. With this information the control block operator receives a global overview about the situation within his control block and is in the position to validate the tie - line measurement at the internal borders in its control block. On the co-ordination centre level each control block operator k provides the on-line telemeasurement values per tie –line ETklγt and its control deviation CDkt to the co-ordination centre concerned. With this information the co-ordination centre receives a global overview about the situation within the co-ordination centre and is in the position to validate the tie line measurement at the internal borders. In close co-operation the two UCTE co-ordination centres check the validity of equation (9). UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) D. !A2–10 Accounting of Unintentional Deviations [UCTE-Ground Rule for the co-ordination of the accounting and the organisation of the load-frequency control, 1999] [UCTE-Ground rule for the recording and offsetting of unintentional deviations in the interconnected network of UCPTE, 1988] 1. Definitions Due to operational reasons of intermeshed systems it cannot be avoided that UNINTENTIONAL occur in such interconnected networks, i.e. difference between the agreed or scheduled values and the actual values of power deliveries made. These UNINTENTIONAL DEVIATIONS can be dealt with by various methods. UC(P)TE has been applying certain methods since 1958 for compensation by offsetting such difference in kind, separated by tariff periods and agreed by all participating countries. DEVIATIONS The unintentional deviations UDkt of a control area k and time unit t are calculated ex - ante as difference BETWEEN physical and programmed exchange: (10) UDkt = ETkt − ES kt In this equation the total executed schedules ESkt are used. The physical exchange ETkt is calculated on the basis of meter values. The following equation has to be applied for the physical exchange for each border between two Control Areas k and l: (11) ETklt = − ETlkt Although in the context of measurement values (equation (6)) the accuracy of the measurement equipment has to be taken into account, dealing with meter values the equation has to apply absolutely. This aim is reached by using a single meter value from one side of the tie line (Accounting Point) for the accounting of both control areas at the border. For the sum of the unintentional deviations the following equation applies: (12) 0 = ∑ UDkt k The validity of this equation can be proven by equations (2), (10) and (11). The unintentional deviations of each control area k are accumulated to an account ACCkt(T) under consideration of a pre-defined set of tariff periods T: (13) ACC kt (T ) = ACCk ( t −1) (T ) + UDkt !A2–11 UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) The tariff period is the time interval fixed by UCTE agreement, during which UNINTENTIONAL are attributed the same value for offsetting by compensation in kind. The valid tariff periods of UCTE are indicated in figure 5. The tariff periods consist of NT, HT, HHT1 and HHT2 and distinguish between the summer period and the winter period. Four UCTE wide common holidays are taken into account. DEVIATIONS 0 HHT Winter* Monday - Saturday Sunday / Holiday HT Winter* Monday - Saturday Sunday / Holiday NT Winter* Monday - Saturday Sunday / Holiday HHT 1 Summer** Monday - Friday Saturdaye Sunday / Holiday HHT 2 Summer** Monday - Friday Saturdaye Sunday / Holiday HT Summer** Monday - Friday Saturdaye Sunday / Holiday NT Summer** Monday - Friday Saturdaye Sunday / Holiday 6 12 18 24 *: Winter: 01.10. - 31.03.; Holidays: 25.12. und 01.01. **: Summer: 01.04. - 30.09.; Holidays: Easter Monday and Ascension Figure 5: UCTE Tariff Periods used for the Accounting of Unintentional Deviations For each control area k the account of unintentional deviations ACCkm(T) is settled with reference to a recording period m. The compensation of unintentional deviations is performed “in kind“ within the compensation period – as an import / export of the corresponding amount of energy per tariff period T, that was accumulated in the recording period. Figure 6 gives an overview to this procedure. Recording Period m 0:00 Fr Sa Su Fr Sa Recording Period (m+1) 24:00 0:00 Mo Tu We Th 24:00 0:00 Fr Sa Su Mo Tu We Th Fr Sa Su Mo Tu We Th 0:00 Su Mo Tu We Th Recording Period (m+2) Fr Sa Su Mo Tu We Th Fr Sa Su Mo Tu We Th 24:00 0:00 Fr Sa Su Fr Sa Su 24:00 0:00 Compensation Period m Mo Tu Mo Tu Mo Tu Final Accounting m Figure 6: Definition of Recording Period and Compensation Period The standard recording period is defined to comprise 7 days (one week), from Monday, 0:00 to Sunday 24:00 whereas the standard compensation period is defined to comprise 7 days (one week), from Thursday, 0:00 to Wednesday 24:00. UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) !A2–12 In case of bank holidays or the change of tariff seasons exceptions to the standard recording and compensation periods may occur. The co-ordination centres agree on exceptions to the definition of the recording period / compensation period and inform the control block / area operators 4 weeks before the start of the recording period accordingly. The following rules have to be taken into account: • A recording period should last at minimum 4 days • A compensation period should last at minimum 4 days • The compensation period has to start always with a delay of three days off the end of the corresponding recording period. Two day difference between the end of an recording period and the start of the corresponding compensation period are needed for the performance of the final accounting; one additional day has to be taken into account to enable the control area operators to buy / sell their compensation program at the market. With reference to the recording period m the compensation program COMPkm(T) is calculated for each control area k and tariff period T during final accounting: (14) COMPkm (T ) = − ACC km (T ) Count (T ) In this equation Count(T) represents the number of hours referring to the tariff period T in the compensation period m. With equation (12), (13) and (14) follows for each compensation period m and tariff period T: (15) 0 = ∑ COMPkm (T ) k For the execution of the compensation program the figure COMPkm(T) referring to compensation period m and tariff period T is transferred to COMPkt for each time unit t of the compensation period m. Equation (15) warrants the validity of equation (4). During the accounting procedure the control deviation CDkt can be calculated on the basis of the accounting data. Equations (8) and (10) result to: (16) CDkt = UDkt − COMPkt The resulting CDkt is usually taken for the statistic evaluation of the performance of load - frequency control (see Policy 1). The same equations apply for the accounting of a control block. !A2–13 UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) 2. Procedure At first glance the compensation of any UNINTENTIONAL DEVIATIONS occurring between CONTROL AREAS/BLOCKS participating in the interconnected operation could be accounted entirely independent from one another. In practice, however, the likelihood of errors in the computations made for the determination relating to the programs for compensation by one or several participating CONTROL AREAS/BLOCKS cannot be ruled out entirely. Such errors might entail inconveniencies for practical operation and for final compensation for any deviations. Consequently, the process of compensation of UNINTENTIONAL DEVIATIONS is organised, controlled and checked following the same procedure and hierarchical levels as the procedure for scheduling: CONTROL BLOCK operator checks and harmonises compensations among CONTROL AREAS under its jurisdiction, and CO-ORDINATION CENTRES do the same among CONTROL BLOCKS in their area of responsibility. In addition to that, CO-ORDINATION CENTRES North (Brauweiller) and South (Laufenburg) harmonise COMPENSATION PROGRAM among them, bringing such total COMPENSATION PROGRAM of UCTE interconnected power systems by default to zero. Figure 7 gives an overview of the different steps of accounting co-ordination and the corresponding gate closure times. 8 CC 5 Submit meter values 12:00 6 CB data validation 7 CB settlement 14:00 CB 3 2 Submit meter values 10:00 CA CC settlement 15:00 CB CA data validation 4 Control area settlement 12:00 1 CA Agreement on meter values Figure 7: Process of Accounting Co-ordination at (D+1) including Gate Closure Times The hierarchical procedure of the accounting co-ordination starts with the agreement of meter values among the control area operators joining one border. This step has to be completed until (D+1) 10:00. In case of problems concerning the metering or telecounting equipment the TSO’s operating a common tie – line have to agree on unique substitute meter values. The co-ordination procedure continues with the control area validation and settlement. The control area validation and settlement starts after completion of the verification of the meter UCTE OH – Appendix 2: Scheduling and Accounting (final 0.4 E, 16.06.2004) !A2–14 values by the submitting of at least the total physical flow per control area border and time unit from the control area operators to the control block operator concerned. It is recommended to submit the single meter values per tie – line and time unit to enable a faster procedure of fault detection. First the control block operator validates the complete data set received by checking equation (2) and (11) for the internal control area borders of its control block. Second the control block operator calculates the single control area’s account of unintentional deviations for every tariff period for the day before (D), 24:00 and – in case of final accounting – the corresponding compensation program and submits the result to the control area operator concerned. The data has to be confirmed by the control area operator until (D+1) 12:00. The next step of the co-ordination procedure is the control block validation and settlement. The control block validation and settlement starts after completion of the control block validation and settlement by the submitting of at least the total physical flow per control block border and time unit from the control block operators to the co-ordination centre concerned. It is recommended to submit the single meter values per tie – line and time unit to enable a faster procedure of fault detection. First the co-ordination centre validates the complete data set received by checking equation (2) and (11) for the internal control area borders of its area. Second the co-ordination centre calculates the single control block’s account of unintentional deviations for every tariff period for the day before (D), 24:00 and – in case of final accounting – the corresponding compensation program and submits the result to the control block operator concerned. The data has to be confirmed by the control block operator until (D+1) 14:00. The last step of the co-ordination procedure is the co-ordination centre settlement. The coordination centres calculate the sum of the control block’s account of unintentional deviations for every tariff period for the day before (D), 24:00 and – in case of final accounting – the corresponding compensation program and validate the result vice - versa latest until (D+1), 15:00. The co-ordination centres submit to the control block operators the account of unintentional deviations for every tariff period for the day before (D), 24:00 after the completion of the co-ordination centre validation. The control block operators inform the control area operators accordingly. Contact Boulevard Saint-Michel, 15 B-1040 Brussels – Belgium Tel +32 2 74169 40 – Fax +32 2 74169 49 info @ ucte.org www.ucte.org