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Trang chủ Biểu mẫu - Văn bản Văn bản Circular no. 252016tt bct dated november 30, 2016, regulations on electricity tr...

Tài liệu Circular no. 252016tt bct dated november 30, 2016, regulations on electricity transmission system

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THE MINISTRY OF INDUSTRY AND TRADE -------- SOCIALIST REPUBLIC OF VIETNAM Independence – Freedom - Happiness ---------------- No. 25/2016/TT-BCT Hanoi, November 30, 2016 CIRCULAR REGULATIONS ON ELECTRICITY TRANSMISSION SYSTEM Pursuant to the Government's Decree No. 95/2012/ND-CP dated November 12, 2012, defining the functions, tasks, powers and organizational structure of the Ministry of Industry and Trade; Pursuant to the Law on Electricity dated December 03, 2004 and the Law on Amendments to a number of articles of the Law on Electricity; Pursuant to the Government's Decree No. 137/2013/ND-CP dated October 21, 2013 detailing the implementation of a number of articles of the Law on Electricity and the Law on Amendments to the Law on Electricity; At the request of general director of Electricity Regulatory Authority, The Minister of Industry and Trade promulgates the Circular stipulating electricity transmission system. Chapter I GENERAL PROVISIONS Article 1. Governing scope This Circular stipulates: 1. Requirements of operation of the electricity transmission system 2. Load forecasts 3. Transmission grid development plan 4. Technical requirements and procedures for connection to transmission grid. 5. Assessment of electricity system security 6. Operation of electricity transmission system Article 2. Regulated entities 1. This Circular applies to: a) Transmission network operator; b) Electricity system and market operator; c) Electricity wholesalers; d) Electricity distribution units; dd) Electricity retailers; e) Generating units; g) Electricity customers receiving electricity from transmission grid (hereinafter referred to as “electricity customers”); h) Vietnam Electricity; i) Other organizations, individuals. 2. Generating sets of a power plant with total installed capacity greater than 30 MW connected to distribution grid must meet technical requirements of equipment connected to transmission grid and other relevant requirements prescribed herein. Article 3. Interpretation of terms In this Circular, some terms are construed as follows: 1. AGC (Automatic Generation Control) is an automatic equipment system for adjusting active power of generating sets to maintain stability of electricity system frequency within permissible scope according to operating principles of generating sets. 2. Electricity system security is the ability of the system to supply power to meet demands for loads at a certain point of time or for a specified period with account taken of electricity system obligations. 3. AVR (Automatic Voltage Regulator) is a system used to control terminal voltage of generating sets through the impact on the excitation system of the generating set to ensure terminal voltage of the generating set within permissible limits. 4. Voltage level is one of nominal voltage values of a system, including: a) Low voltage: nominal voltage level to 01 kV; b) Medium voltage: nominal voltage level over 01 kV to 35 kV; c) High voltage: nominal voltage level over 35 kV to 220 kV; d) Ultra- high voltage: nominal voltage level over 220 kV. 5. Dispatching level with control authority (hereinafter referred to as “the dispatch level”) is a dispatching level that has the right to direct and dispatch the electricity system under the dispatching hierarchy prescribed in the Dispatch Procedure of national electricity system promulgated by the Ministry of Industry and Trade. 6. Available capacity of a generating set is the maximum generating capacity of the generating set for a specified period of time. 7. Governor deadband is a frequency band within which any change of electricity system frequency shall not result in reactions or impacts of the governor for adjusting primary frequency. 8. Spinning reserve is the ability of a generating set operating in the national electricity system to increase or decrease generating capacity to restore electricity system frequency to permissible scope after a single fault and restore reserve capacity of frequency control. 9. Primary frequency adjustment is the process of adjusting electricity system frequency immediately by a large number of generating sets equipped with a governor. 10. Secondary frequency adjustment is the adjustment process following the primary frequency adjustment carried out through the impact of AGC system on some generating sets specified in the system or load shedding system under the frequency or dispatching instructions 11. Electricity system dispatching is activities of directing and controlling the process of power generation, transmission and distribution in the national electricity system according to the defined procedures, technical regulations and operation modes. 12. Electricity wholesaler is the electricity unit that is granted the operation licence in electricity wholesaling. According to level of competitive electricity market, an electricity wholesaler shall be one of the following units: a) Electric Power Trading Company; b) Power Corporations; c) Other electricity wholesalers which are established according to individual levels of competitive electricity market. 13. Generating unit is an electricity unit which is granted the operation licence in power generation, possesses one or several power plants connected to the transmission grid or a power plant of over 30 MW in installed capacity connected to distribution grid. 14. Electricity distributor means the electricity unit that is granted the operation licence in electricity distribution, including: a) Power Corporations; b) Electricity companies of provinces, central-affiliated cities (hereinafter referred to as “provincial electricity companies”) affiliated to Power Corporations. 15. Electricity retailer is an electricity unit that is granted the operation licence in electricity retailing. 16. Transmission network operator is the electricity unit that is granted the operation licence in electricity transmission responsible for management and operation of national transmission grid. 17. Electricity system and market operator (the national electricity system dispatch center) is the unit responsible for directing and controlling the process of power generation, transmission and distribution in the national electricity system and conducting transactions in electricity market. 18. Reliability of a protection system includes: a) Impact reliability of the protection system is the factor indicating ability of the protection system to work properly on an incident within the determined scope of protection; b) Non-impact reliability of the protection system is the factor indicating ability of the protection system to avoid malfunctioning at the normal operation mode or any incident arising beyond the determined scope of protection. 19. Governor is a device used to regulate rotating speed of the turbine of a generating set according to frequency changes to restore frequency to nominal electricity system frequency. 20. EMS (Energy Management System) is an energy management software system to optimize operation of the electricity system. 21. DCS (Distributed Control System) is a system of control equipment in a power plant or power station connected to the network on the principle of distributed control to increase reliability and restrict effects caused by breakdown of control elements in the power plant or power station. 22. Electricity system is a system of generating equipment, electricity network and utilities connected to each other. 23. The national electricity system is an electricity system which is managed in a uniform manner across the country. 24. Electricity transmission system is an electricity system including a transmission grid and power plants connected to the transmission grid. 25. SCADA (Supervisory Control and Data Acquisition) is a data collection system serving monitoring, control and operation of the electricity system. 26. Earth-fault factor is the ratio between the voltage on a healthy phase during a fault and value of voltage of such phase before the fault (in case of single or double phase to ground fault). 27. Synchronization is the act of connecting generating sets to the electricity system or two parts of the electricity system together according to synchronization conditions prescribed in the operating procedure in the national electricity system issued by the Ministry of Industry and Trade. 28. Black start capability is the ability of a power plant to restore at least one generating set to operation from the state of complete stop and synchronize to the electrical grid without relying on transmission network in the area. 29. Black start is the process of restoring all or part of an electricity system to operation from the state of wholly or partial loss of power by using generating sets with black start capability. 30. Customers using transmission grid are organizations and/or individuals possessing electrical equipment, electrical grid to connect to transmission grid, including: a) Generating units; b) Electricity distribution units receiving electricity direct from transmission grid; c) Electricity retailers receiving electricity direct from transmission grid; d) Electricity customers. 31. Dispatch instruction is an order of commanding and controlling operation mode of an electricity system in real time. 32. Electrical grid is a system of transmission lines, power station and utilities for power transmission. 33. Distribution grid is a part of an electrical grid including transmission lines and power stations of up to 110 kV. 34. Transmission grid is a part of an electrical grid including transmission lines and power stations of over 110 kV. 35. Short-term flicker perceptibility (Pst) is a value measured for ten minutes by a flicker meter of IEC868 standard. 36. Long-term flicker perceptibility (Plt) is a value calculated from 12 measurement results of short-term perceptibility for about two hours in following formula: Plt  3 1 * 12 12 P 3 stj j 1 37. Year N is the current year of operating an electricity system, calculated according to calendar year. 38. Typical day is a day that has the typical day of consumption of loads as prescribed in the contents, methods and procedure for electrical load research issued by the Ministry of Industry and Trade. Typical days include typical working days, weekends, holidays (if any) of years, months and weeks. 39. Outage or reduction of power supply according to plan is the suspension of power supply to carry out the plan for maintenance, repairs, overhaul and installation of electrical works; regulation and restriction of loads in case of a shortage according to the plan as informed by the electricity system and market operator. 40. Thermo-electric plant is a power plant operating on the principle of thermal to electrical energy conversion including biomass, biogas and solid waste power plants. 41. Regulations on competitive electricity market operation are the regulations issued by the Ministry of Industry and Trade and also the responsibility of the units in the electricity market by level. 42. Load shedding is the process of cutting loads from electricity system in case of incident or lack of electricity system security, carried out through an automatic load shedding system or dispatch instruction. 43. Breakdown is an event or one or several equipment in the electricity system causing a disruption of power supply or affecting safe and stable supply of power to the national electricity system. 44. Single fault is a breakdown occurring in a single component of an electricity transmission system as the electricity system is in normal operation mode. 45. Multi fault is a breakdown occurring in at least two components of an electricity transmission system at the same time. 46. Serious fault is an breakdown causing extensive loss of power on the entire transmission grid, or fire & explosion which damages people and property. 47. Electricity system split is a situation in which the national electricity system is separated into disconnected small electricity systems by a fault. 48. RTU/Gateway (Remote Terminal Unit/Gateway) is a device placed at a power station or power plant serving collection and transmission of data to SCADA system of the electricity system dispatch center or control center. 49. PSS (Power System Stabilizer) is a device added to the automatic voltage regulator to decrease voltage fluctuation in the electricity system. 50. Time of starting is a minimum period of time needed to start a generating set from the time the generating unit receives the starting order from the electricity system and market operator to the time the generating set is synchronized into the national electricity system. 51. N-1 criterion is a criterion for planning, design, investment, construction and operation of an electricity system that ensures the electricity system operates normally in accordance with the operating standards, permissible operating limits when a breakdown occurs in the system or a component is taken from the system for maintenance and repairs. 52. IEC standards are electrotechnical standards issued by the International Electrotechnical Commission. 53. Automatic under-frequency load shedding is the act of cutting loads by frequency relays when frequency or frequency slope of the electricity system drops below permissible limit. 54. Power station is a substation, switching station or compensation station. 55. Control center is a center equipped with information technology and telecommunications infrastructure system to remotely monitor and control a group of power plants, power stations or switchgears on the electrical grid. 56. pu is a per-unit system expressing the ratio between actual value and rated value. Chapter II REQUIREMENTS FOR OPERATION OF ELECTRICITY TRANSMISSION SYSTEM Article 4. Frequency 1. Nominal frequency of the national electricity system is 50 Hz. In normal operation mode, electricity system frequency may fluctuate within ± 0.2 Hz compared with nominal frequency. In other operation modes, permissible frequency band fluctuation and time for restoration of electricity system to normal operation are prescribed in Table 1 below: Table 1 Permissible frequency band fluctuations and time for restoration of electricity system to normal operation at other operation modes of the national electricity system Operation mode Permissible frequency band fluctuations Single fault 49 Hz ÷ 51 Hz Time of restoration since the time of fault (effective as of January 01, 2018) Unstable status (reset mode) Restoration to normal operation mode Two minutes to bring the frequency to range 49.5 Hz ÷ Five minutes to bring the frequency to range 49.8 Hz ÷ 47.5 Hz ÷ 52 Hz Multi fault, serious fault or extreme emergency mode 50.5 Hz 50.2 Hz Ten seconds to bring the frequency to range 49 Hz ÷ 51 Hz Ten minutes to bring the frequency to range 49.8 Hz ÷ 50.2 Hz Five minutes to bring the frequency to range 49.5 Hz ÷ 50.5 Hz 2. Permissible frequency band and acceptable number of beyond-the-limit times (the number of times the frequency may exceed the permissible limits) in case of multi fault, serious fault or extreme emergency mode are determined according to annual or biennial cycle in Table 2 below: Table 2 Permissible frequency band and acceptable number of beyond-the-limit times in case of multi fault, serious fault or extreme emergency mode Permissible frequency band (Hz) Acceptable number of beyond-the-limit times (“f” is electricity system frequency) (from the beginning of the cycle) 52 ≥ f ≥ 51.25 Seven times a year 51.25 > f > 50.5 50 times a year 49.5 > f > 48.75 60 times a year 48.75 ≥ f > 48 12 times a year 48 ≥ f ≥ 47.5 Biennial 3. During the operation of the national electricity system, the electricity system and market operator shall be responsible for dispatching and operating the national electricity system and mobilizing all forms of ancillary services to ensure the frequency is within the permissible band. Article 5. Stabilization of electricity system 1. Stabilization of an electricity system is the ability of the electricity system, with predetermined initial conditions, to return to normal operation mode or reset mode after a physical impact has changed operational parameters of the electricity system. Stabilization of electricity system is classified as follows: a) Transient stability is the ability of generating sets in the electricity system to maintain consistent operational state when subjected to major disturbances. b) Small signal stability is the ability of generating sets in the electricity system to maintain consistent operational state when subjected to small disturbances; c) Dynamic voltage stability is the ability of an electricity system to maintain steady voltage at all buses when subjected to major disturbances. d) Steady state voltage stability is the ability of an electricity system to maintain steady voltage at all buses when subjected to small disturbances. dd) Frequency stability is the ability of an electricity system to maintain steady frequency when disturbances have caused loss of load-generation balance. 2. Sub-synchronous resonance is a phenomenon in which the resonant frequency of the turbine shaft coincides with electricity system frequency resulting in torsional stress on the turbine shaft. 3. The national electricity system operating at normal operation modes or after the fault is cleared must maintain consistency and meet electricity system stability standards prescribed in Table 3 below: Table 3 Electricity system stability standards Type of stability Transient stability Stability standards Rotor angle not in excess of 120 degrees Within 20 seconds after the fault is cleared, rotor angle fluctuation must be stamped out. Small signal stability Damping ratio should not be less than 5%. Dynamic voltage stability Within five seconds after the fault is cleared, at least 75% of the voltage must be restored. The electricity system must a reserve capacity of at least 5% in case a component is taken from the system (N-1). Frequency stability The electricity system must meet frequency stability standards as prescribed in Clause 1, Article 4 herein. Article 6. Voltage 1. Nominal voltage levels of a transmission grid are 500 kV, 220 kV. 2. In normal operation conditions or in case of a single fault in a transmission grid, permissible voltage at busbars on the transmission grid is prescribed in Table 4 below: Table 4 Voltage at busbars on transmission grid Voltage level Operation mode Normal operation Single fault 500 kV 475 ÷ 525 450 ÷ 550 220 kV 209 ÷ 242 198 ÷ 242 3. In case of a multi fault, serious fault, in an extreme emergency operation mode or electricity system restoration mode, permissible voltage fluctuation on the transmission grid is greater than ± 10 % to ± 20 % compared with nominal voltage. 4. During the fault, voltage at the place where the fault occurs and surrounding areas may drop to 0 at phases with fault or increase over 110% of the nominal voltage at phases without fault until the fault is cleared. Article 7. Phase balance In normal operation mode, negative sequence voltage components are not allowed to exceed 3% of nominal voltage on transmission grid. Article 8. Harmonics 1. Permissible maximum value of total harmonic distortion (based on percentage of nominal voltage) caused by high-level harmonic components to the voltage level 220 kV and 500 kv is not allowed to exceed 3%. 2. Permissible maximum value of total demand distortion (based on percentage of nominal voltage) to the voltage level 220 kV and 500 kv is not allowed to exceed 3%. 3. In normal operation mode, the transmission network operator shall ensure total harmonic distortion on the transmission grid is within the range as prescribed in Clause 1, this Article. 4. Customers using transmission grid shall ensure harmonics in the equipment connected to the transmission grid must not exceed the range as prescribed in Clause 2, this Article. 5. If total harmonic distortion shows signs of violation of the range as prescribed in Clause 1 or 2, this Article, the customer using transmission grid or the transmission network operator has the right to order other relevant units to inspect harmonic values or hire an independent testing unit to do the job. If the result of inspection shows that the total harmonic distortion violates the range as prescribed in Clause 1 or 2, this Article, all the expenses for inspection, verification, damage and implementation of remedial measures shall be incurred by any entity that is found in breach of the regulation. Article 9. Flicker perceptibility 1. Permissible maximum flicker perceptibility in a transmission grid is stipulated in Table 5 below: Table 5 Flicker perceptibility Voltage level Plt95% Pst95% 220 kV, 500 kV 0.6 0.8 Where: Plt95%, Pst95%: Threshold value of Plt, Pst respectively. 2. The transmission network operator shall control flicker perceptibility on the transmission grid to ensure that the flicker perceptibility at connection point must not exceed the value prescribed in Table 5 in normal operation mode. Customers using transmission grid shall ensure flicker perceptibility on the equipment connected to the transmission grid must not exceed the value as prescribed in Table 5. 3. If flicker perceptibility shows signs of violation of the range as prescribed in Clause 1, this Article, the customer using transmission grid or the transmission network operator has the right to order other relevant units to inspect flicker perceptibility or hire an independent testing unit to do the job. If the result of inspection shows that the flicker perceptibility violates the range as prescribed in Clause 1, this Article, all the expenses for inspection, verification, damage and implementation of remedial measures shall be incurred by any entity that is found in breach of the regulation. Article 10. Voltage fluctuation 1. Voltage fluctuations at connection points on the transmission grid by fluctuating loads shall be not allowed to exceed 2.5% of nominal voltage and must be within permissible voltage values according to each voltage level prescribed in Article 6 herein. 2. If a voltage divider is operated manually, the voltage fluctuations at the points connected to loads are not allowed to exceed voltage value indicated by the transformer’s voltage divider. 3. Permissible adjustable voltage level is 5% of nominal voltage to a maximum provided that such adjustment shall not cause damage to the equipment on electricity transmission system and equipment belonging to customers using transmission grid. Article 11. Neutral grounding 1. Neutral grounding of a transmission grid is the connection of the grid direct to the ground. 2. If the neutral grounding of some equipment in the transmission grid is in opposition to the provisions prescribed in Clause 1, this Article, a written consent of the electricity system and market operator is required. Article 12. Short-circuit current and fault clearing time 1. Permissible maximum value of short-circuit current and fault clearing time by main protection on the electricity system are stipulated in Table 6 below: Table 6 Permissible maximum value of short-circuit current and fault clearing time by main protection Minimum time of withstandibility of equipment (s) Permissible maximum shortcircuit current (kA) Maximum fault clearing time by main protection (ms) Effective up to December 31, 2017 Effective as of January 01, 2018 500 kV 50 80 03 01 220 kV 50 100 03 01 Voltage level 2. For 110 kV busbars of 500 kV or 220 kV transformers in the transmission grid, permissible maximum short-circuit current is 40 kA/1s. 3. Total value of unsaturated sub transient reactance of a generating set (X d’’-%) and short-circuit reactance of a terminal transformer (Uk-%) according to the per-unit system pu is not allowed to be less than 40%. If the aforesaid requirements cannot be met, the investor shall be responsible for installing further reactance so that total value of Xd’’, Uk and electrical reactance according to the per-unit system is not less than 40%. 4. If value of short-circuit current at connection point of any electrical works to an electricity transmission system is greater than permissible maximum short-circuit as stipulated in Table 6, the investor shall take measures to restrict the short-circuit current at connection points to a level lower or equal to permissible maximum short-circuit current as stipulated in Table 6. 5. Main protection of an electrical equipment is a key element of protection which is installed and set to make initial impacts, ensuring quickness, sensitivity, selectivity and reliability of impacts of the protection system in case of a fault within the scope of protection. 6. If maximum short-circuit current exceeds the values as stipulated in Table 6, the transmission network operator or customers using transmission grid shall be responsible for reporting to the Electricity Regulatory Authority for instructions. 7. The transmission network operator shall be responsible for informing the customer using transmission grid about maximum value of short-circuit current at connection point for coordination during the investment and installation of equipment, ensuring that the switchgears are able to deenergize maximum short-circuit current at connection point at least for the next 10 years. Article 13. Earth fault factor Earth fault factor of a transmission grid at all voltage levels is not allowed to exceed 1.4. Article 14. Reliability of transmission grid 1. Reliability of a transmission grid is determined by percentage of electrical production not supplied annually due to outage or reduction of power supply outside and inside the plan, and faults on the transmission grid causing loss of power to electricity customers. 2. Electrical production not supplied is calculated as the product of the load power suspended or reduced and the corresponding time of suspension, reduction in case the loss of power lasts over one minute, except for following cases: a) Outage or reduction of power supply due to lack of power from national electricity system b) Outage or reduction of power supply due to force majeure events. 3. Percentage of electrical production not supplied annually by a transmission grid is determined in following formula:   1(T  n k kccđ i i  Pi ) Att Where: - kkccd: Percentage of electrical production not supplied in a year by a transmission grid; - Ti: Time of outage or reduction of power supply lasting over one minute at time I is determined as the period from the time of outage or reduction to the time power supply is restored (hour); - Pi: Average load power suspended, reduced at time i (kW); - n: Number of times of outage or reduction of power supply in a year; - Att: Total electrical production transmitted through a transmission grid in a year (kWh). Article 15. Loss of power on transmission grid 1. Annual loss of power on a transmission grid is determined in following formula: ∆A = Attreceived - Attdelivered Attreceived Where: - ΔA: Annual loss of power on a transmission grid; - Attreceived: Total electrical production transmitted to the transmission grid in a year is the production received by all the customers using transmission grid at connection points plus total electrical production imported through the transmission grid; - Attdelivered:Total electrical production delivered from the transmission grid in a year is the production the electricity distribution units and electricity customers receive from connection points plus total electrical production exported through the transmission grid; Chapter III LOAD FORECASTING FOR NATIONAL ELECTRICITY SYSTEM Article 16. General provisions on load forecasting for national electricity system 1. Load forecasting for the national electricity system is forecasts on demand for loads to be supplied by the national electricity system except loads from independent power supplies and not connected to the national grid. Load forecasting for the national electricity system is grounds for making annual electricity transmission system development plans, plans and methods for operation of electricity system, electricity market. 2. Load forecasting for the national electricity system includes annual, monthly, weekly and daily forecasts on loads and electricity market transaction cycle. 3. Responsibility for making forecasts a) The electricity system and market operator shall make forecasts on loads for the national electricity system, electricity systems in the Northern, Central and Southern Vietnam and connection points. b) Electricity distribution units, electricity retailers and electricity customers shall provide load forecasts to the electricity system and market operator including forecasts on demand for loads of the entire unit and individual 110 kV transformers c) Electricity wholesalers shall provide forecasts on exportation and importation of electricity to the electricity system and market operator including forecasts on general demand and demands of connection points serving exportation and importation of electricity. 4. Regarding forecasts on demand of connection points and resolution of load forecasting cycle and depending on each stage of development and market demand, the Electricity Regulatory Authority shall provide instructions on implementation of this regulation. Article 17. Annual load forecasting 1. Annual load forecasting made for next year (year N+1) and the year thereafter (year N+2). 2. Figures serving annual load forecasting include: a) Monthly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle for 104 weeks provided by electricity distribution units, electricity retailers and electricity customers; b) Monthly export, import forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle for 104 weeks provided by electricity wholesalers. 3. Elements taken into account for annual load forecasting: a) Economic growth (GDP) for the next two years officially published by competent agencies; b) Annual load forecasts and load factor under approved electricity development master plan; c) Statistical figures on capacity, electrical energy consumed, exported and imported at least for at the last five years by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers; d) Solutions and targets of the plan for energy saving and demand management; dd) Other necessary information. 4. Results of annual load forecasting for national electricity system include: Maximum capacity, electrical energy, typical daily diagrams in a 30-minute cycle for 104 weeks of national, regional electricity systems and connection points. 5. Implementation a) Before August 01 annually, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide results of annual load forecasting to the electricity system and market operator as prescribed in Clause 2, this Article. If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last year’s figures to make forecasts on loads for the national electricity system. b) Before September 01 annually, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of annual load forecasting on its website as prescribed in Clause 4, this Article. Article 18. Monthly load forecasting 1. Monthly load forecasting made for next month. 2. Figures serving monthly load forecasting include: a) Weekly load forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle every week provided by electricity distribution units, electrical retailers and electricity customers; b) Weekly export, import forecasts concerning electrical energy, maximum capacity, typical daily diagrams in a 30-minute cycle every week provided by electricity wholesalers. 3. Elements taken into account for monthly load forecasting: a) Results of monthly load forecasting in the published annual load forecasting; b) Statistical figures on capacity, consumed, exported and imported electrical energy, maximum loads in daytime and nighttime for the month year-on-year and the last three months provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers; c) Events that may cause major changes to demand for loads and other necessary information. 4. Results of monthly load forecasting for national electricity system include: Maximum capacity, electrical energy, typical daily diagrams for each week with a 30-minute cycle of national, regional electricity systems and connection points. 5. Implementation a) Before 20th every month, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide monthly load forecasts to the electricity system and market operator as prescribed in Clause 2, this Article. If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last month’s figures or results of annual load forecasting to make forecasts on loads for national electricity system. b) Before the last seven days every month, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of month loading forecasting on its website as prescribed in Clause 4, this Article. Article 19. Weekly load forecasting 1. Weekly load forecasting made for the next two weeks. 2. The figures serving weekly load forecasting include figures on capacity, electrical energy forecasts in a 30-minute cycle every day of the next two weeks provided by electricity distribution units, electricity retailers and electricity customers and 110 kV transformers. 3. Elements taken into account for weekly load forecasting: a) Results of weekly load forecasting in the published monthly load forecasting; b) Statistical figures on capacity, consumed electrical energy, maximum loads in daytime and nighttime for the last four months provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers; c) Daily weather forecasts for the next two weeks, public holidays, Tet holidays and events that may cause major changes to demand for loads. 4. Results of weekly load forecasting for national electricity system include: Capacity, electrical energy in a 30-minute cycle every day of the next two weeks of national, regional electricity systems and connection points. 5. Implementation a) Before 10:00 every Tuesday, electricity distribution units, electricity retailers, electricity wholesalers and electricity customers shall provide weekly load forecasts to the electricity system and market operator as prescribed in Clause 2, this Article. If the figures provided by electricity distribution units, electricity retailers, electricity wholesalers and electricity customers are inaccurate or inadequate according to the prescribed time limit, the electricity system and market operator shall rely on last week’s figures or results of monthly load forecasting to make forecasts on loads for national electricity system. b) Before 15:00 every Thursday, based on the figures provided by relevant units, the electricity system and market operator shall be responsible for completing and publishing results of weekly load forecasting on its website as prescribed in Clause 4, this Article. Article 20. Daily load forecasting 1. Daily load forecasting made for the next two days. 2. Elements taken into account for daily load forecasting: a) Results of daily load forecasting in the published monthly load forecasting; b) Figures on capacity, electrical energy of the electricity system of the last seven days or the holidays, Tet holidays of last year if the figures fall within public holidays, Tet holidays; c) Weather forecasts of the next two days and other necessary information. 3. Results of daily load forecasting for national electricity system include: Capacity, electrical energy in a 30-minute cycle of national, regional electricity systems and connection points. 4. Before 10:00 every day, the electricity system and market operator shall be responsible for completing and publishing results of daily load forecasting as prescribed in Clause 3, this Article. Article 21. Load forecasting in a electricity market transaction cycle 1. Load forecasting made for next transaction cycle and eight cycles thereafter. 2. Elements taken into account for load forecasting in a transaction cycle: a) Results of load forecasting from the published daily load forecasting and the electricity market transaction cycle previously published; b) Figures on capacity, electrical energy of the same period of last week; c) Weather forecasts; dd) Other necessary information. 3. Results of load forecasting in a electricity market transaction cycle include: a) Capacity and production of the national electricity system and regional electricity systems in a 30minute cycle of the next transaction cycle and eight cycles thereafter; b) Capacity and production at each point connecting the transmission grid and distribution grid in a 30minute cycle of the next transaction cycle and eight cycles thereafter. 4. At least 15 minutes before the next transaction cycle, the electricity system and market operator shall be responsible for completing and publishing results of load forecasting of a transaction cycle as prescribed in Clause 3, this Article. Chapter IV TRANSMISSION GRID DEVELOPMENT PLAN Article 22. General principle 1. Annually, the transmission network operator shall be responsible for making a transmission grid development plan for next year (year N+1) with account taken of the year thereafter (year N+2). 2. Annual transmission grid development plans shall be made based on: a) Published annual load forecasting plans; b) Approved national electricity development plans, provincial electricity development planning and signed connection agreements; c) Requirements for operation of the electricity system prescribed in Chapter II and technical requirements of connection points prescribed in Chapter V herein; d) Demand for loads and requirements for electricity system and market operation; ensuring the national electricity transmission system operates in a safe, reliable and stable manner. 3. The electricity system and market operator shall be responsible for cooperating with the transmission network operator during the process of transmission grid development plan formulation to ensure investment, connection and operation of the power generation and electrical grid works meet the requirements prescribed in Clause 2, this Article. Article 23. Content of transmission grid development plan The transmission grid development plan includes following subject matters: 1. Assessment of performance of the transmission grid to the end of June 30 of the current year. 2. Load forecasts in each point of delivery between the transmission grid and distribution grid for the next year with account taken of the year thereafter. 3. Assessment of implementation of investment and estimated implementation of investment in the list of transmission grids according to the approved transmission grid development plan until the end of December 31 of current year. 4. List of power generation projects connecting to the transmission grid for next year with account taken of the year thereafter accompanied by planned connection points, connection agreements for these power generation projects. 5. List of information system works, SCADA system, RTU/Gateway, measurement system, data collection system serving electricity market and electricity system operation and dispatching. 6. Results of calculation of reset modes of the electricity transmission system for each month next year, dry and rainy seasons of the year thereafter including results of calculation of methods and assessment of ability of the transmission grid to meet N-1 criterion. 7. Results of calculation of short-circuit current at 500 kV, 220 kV, 110 kV busbars on the transmission grid in which the positions where maximum value of short-circuit current exceed 90% of permissible maximum value as prescribed in Article 12 herein must be determined. 8. Results of calculation and analysis of stability of the electricity transmission system. 9. Results of calculation of reactive power compensation on the transmission grid. 10. Determination of obligations and constraints on the transmission grid that may have effect on safe and stable operation of the electricity transmission system including effects on requirements for stability of the electricity system as prescribed in Article 5 herein. 11. Proposals for norms of reliability and loss of power of the transmission grid for the next year according to Article 14 and Article 15 herein. 12. Analysis of ability to meet operational requirements of the electricity system prescribed in Chapter II and technical requirements of connection points prescribed in Chapter V herein, and proposals for solutions to meet the prescribed requirements. 13. Analysis and selection of methods of investment in the transmission grid to ensure transmission of all the power from power plants meeting demand for loads, technical requirements and lowest costs. 14. Lists and schedules of construction of transmission grid items by month of next year and by quarter of the year thereafter. Fund plan for each project. 15. Proposals (if any). Article 24. Responsibility for supplying information serving formulation of transmission grid development plan 1. Generating units shall be responsible for supplying following information: a) Lists of new power plants planned to be connected to the transmission grid in the next year with account taken of two years thereafter, progress of investment and connection, and expected date of operation of such power plants. b) Main parameters of power plants shall be connected to the electricity transmission system and information about connection points are stipulated in Annex 1B enclosed herewith; c) Changes related to connection to existing power plants in the next year with account taken of two years thereafter. 2. Electricity distribution units, electricity retailers and electricity customers shall be responsible for providing following information: a) Lists of connection points in the next year with account taken of the year thereafter; lists of transmission grid projects to be invested and constructed; b) Planned progress of energizing new connection points; c) Maximum load capacity at new connection points and information about connection are specified in Annex 1C enclosed herewith; d) Expected proposals for changes to existing connection points in the next year with account taken of the year thereafter. 3. The electricity system and market operator shall be responsible for providing following information: a) Results of annual load forecasting as prescribed in Article 17 herein; b) Expected demand for ancillary services in next year with account taken of the year thereafter; c) Plan for mobilization of power supplies in the next year with account taken of the year thereafter. 4. Electricity wholesalers shall be responsible for supplying following information: a) Exported, imported capacity and electrical energy; b) Progress of putting new power generation projects into operation in the next year with account take of two years thereafter. Article 25. Procedures for formulation, approval and public announcement of transmission grid development plans 1. Before August 01 annually, the transmission network operator shall be responsible for delivering requests for supply of information and time limit of supply of information to the electricity market and system operator, electricity wholesalers and customers using transmission grid (including customers who need to establish new connections). 2. Before September 01 annually, the electricity system and market operator, electricity wholesalers and customers using transmission grid shall be responsible for providing sufficient information as prescribed in Article 24 herein to the transmission network operator. 3. Before October 15 annually, the transmission network operator shall be responsible for completing draft plans for transmission grid development in the next year with account taken of the year thereafter, and submitting requests to the electricity system and market operator for suggestions on assessment of impacts of expected transmission grid projects on safety, stability and reliability of the electricity transmission system. 4. Before November 01 annually, the transmission network operator shall be responsible for completing the plan for transmission grid development in the next year with account taken of the year thereafter and reporting to Vietnam Electricity. 5. Before November 15 annually, the transmission network operator shall be responsible for submitting the plan for transmission grid development in the next year with account taken of the year thereafter approved by Vietnam Electricity to Electricity Regulatory Authority. 6. Before December 15 annually, the Electricity Regulatory Authority shall conduct assessment, grant approval and publish on its website the plan for transmission grid development in the next year with account taken of the year thereafter. 7. Within 15 working days since the plan for transmission grid development is approved by Electricity Regulatory Authority, the transmission network operator shall be responsible for publishing the plan on its website. Chapter V CONNECTION TO TRANSMISSION GRID Section 1. GENERAL PRINCIPLE Article 26. Connection point 1. Connection points are the points connecting equipment, electrical grids and power plants of customers using transmission grid with the electricity transmission system. 2. Depending on structure of the electrical grids and connection lines, connection points shall be determined as follows: a) Regarding overhead lines, connection points are the end points of the suspension string for outgoing feeders connected to the disconnect switches of the substation or distribution area of the power plant. b) Regarding underground lines, connection points are the cosse of disconnector insulators on the outgoing side of the substation or distribution area of the power plant. 3. Any connection point which is in opposition to provisions prescribed in Clause 2, this Article shall be agreed by the two parties. 4. Connection points must be detailed in relevant drawings, diagrams and explanations in the connection agreement or power purchase agreement (PPA). Article 27. Borders of assets and operation management 1. Borders of assets between the transmission network operator and customers using transmission grid are connection points. 2. Assets belonging to each party at connection point must be detailed and accompanied by relevant drawings and diagrams or power purchase agreement (PPA). 3. Each party shall be responsible for investing, constructing and managing assets of its own in accordance with standards and laws unless otherwise agreed. Article 28. General requirements 1. The transmission network operator shall be responsible for developing transmission grids according to approved electricity development planning and investment plan, ensuring transmission grid facilities meet requirements of the electricity system as prescribed in Chapter II herein and technical requirements of connection points prescribed in this Chapter. 2. Connecting electrical equipment, electrical grids and power plants of customers using transmission grid with the transmission grid must be consistent with the electricity development planning approved by competent state agencies, ensuring transmission grid facilities meet requirements of the electricity system as prescribed in Chapter II herein and technical requirements of connection points prescribed in this Chapter. 3. The transmission network operator shall be responsible for making notification to the electricity customer of any connection proposed by such customer which is in opposition to the approved electricity development planning. Any customer who needs to get connected shall be responsible for submitting an application for grant of approval for adjustments and supplements to the planning according to the regulation on contents and procedures for formulation, assessment, approval and adjustment of electricity development planning issued by the Ministry of Industry and Trade before taking next steps. 4. The transmission network operator and customer that request connection must execute a connection agreement according to the form prescribed herein including following information: a) Position of connection point; b) Technical information related to connection point; c) Progress of connection; d) Responsibility for investment and operation management; dd) Terms and conditions of the connection agreement. 5. The transmission network operator is entitled to reject proposals for connection in following cases: a) Customer’s electrical equipment, grids fail to meet operational and technical requirements prescribed herein and other relevant technical regulations; b) Proposals for connection are inconsistent with the approved electricity development planning. 6. The transmission network operator is entitled to disconnect the customer from its transmission grid if such customer violates technical and operational requirements as prescribed herein or violates the regulation on safety and operation of its assets. The procedures for settlement of dispute prescribed in Chapter IX herein shall apply if the two parties fail to reach an agreement on the disconnection. 7. If any change or upgrading of equipment or change of connection diagram by the customer using transmission grid within its scope of management affects safe operation of the electricity transmission system or electrical equipment belonging to the transmission network operator at connection point, such customer must make a written notification to the transmission network operator and the dispatch level before implementation. 8. Any change related to connection point during the investment and operation must be updated in the dossier of connection point and signed connection agreement. 9. The customer using transmission grid shall be responsible for storing figures concerning working modes, operation and maintenance and incidents on the components within its management for a period of five years. As requested by the transmission network operator, the customer shall provide adequate information related to the incident on the components within its management. For any connection serving purchase and sale of electricity between power plants overseas or outside the territory of Vietnam and the national electricity system, the technical and operational requirements of the equipment connecting to the transmission grid shall be in order of priority as follows: a) Be conformable with regulations, international agreements and commitments of which Vietnam is a signatory; b) An agreement between relevant parties must be reached to meet all the technical requirements and technical regulations on each country’s electricity system and ensure that the operation of the electrical grids is safe, reliable and stable. Section 2. GENERAL TECHNICAL REQUIREMENTS FOR EQUIPMENT CONNECTING TO TRANSMISSION GRID Article 29. Requirements for connecting equipment 1. The diagram of main connection point shall represent all the electrical equipment from middlevoltage to super high-voltage levels and connectivity between the electrical grid of the customer using transmission grid and the transmission grid. The electrical equipment must be described in symbols, standard signs and numbered by the dispatch level according to the operating procedure of the national electricity system issued by the Ministry of Industry and Trade. 2. Circuit breakers directly related to connection points accompanied by protection, measurement and control systems must be capable of de-energizing maximum short-circuit current at connection point, meeting the electrical grid and power generation development diagram under the approved electricity development planning at least for the next 10 years. 3. Equipment connecting directly to the transmission grid shall be fully capable of withstanding possible maximum short-circuit current at connection points according to the calculations by the transmission network operator, meeting the electrical grid and power generation development diagram under the approved electricity development planning at least for the next 10 years. Article 30. Requirements for protective relay system 1. The transmission network operator and the customer using transmission grid shall be responsible for designing, installing, setting and testing the protective relay system within their own management to meet requirements for quickness, sensitivity, selectivity and reliability in case of fault clearance to ensure safe and reliable operation of the electricity system. 2. Coordination in installing protective relay equipment at connection points must be agreed between the dispatch level, the transmission network operator and the customer using transmission grid. The transmission network operator or the customer using transmission grid shall not be allowed to change its own protective relay equipment and installation parameters without consent of the dispatch level. 3. The dispatch level shall be responsible for issuing relay setting notes within scope of transmission grid belonging to the transmission network operator and granting approval for the relay settings of the protective relay equipment belonging to the customer using transmission grid. 4. Maximum time limit for fault clearance through main protection on the components of the electricity system belonging to the customer using transmission grid is not allowed to exceed the values prescribed in Article 12 herein. 5. If the protection equipment belonging to the customer is required to connect to the transmission network operator’s protection equipment, such equipment must meet requirements of the transmission network operator for connection and be approved by the dispatch level. 6. If the electrical grid belonging to the customer using transmission grid has a problem, the protective relay equipment in the electrical grid may send commands to disconnect circuit breakers on the transmission grid with consent of the transmission network operator and the dispatch level with regard to these circuit breakers. 7. Reliability of impacts of the protective relay system shall not be less than 99%. 8. In addition to requirements prescribed from Clause 1 to Clause 7, this Article, the protective relay system belonging to the customer using transmission grid and the transmission network operator must meet following requirements: a) Power plants must be equipped with synchronization system; b) Power plants must be equipped with a GPS. c) Power plants with total installed capacity from 300 MW and on must be equipped with a phasor measurement unit (PMU) and a GPS. Power plants with total installed capacity less than 300 MW, equipment of PMU must follow calculations and requirements of the electricity system and market operator; d) The transmission network operator and customer using transmission grid other than generating units shall be responsible for installing a GPS, PMU according to requirements of the dispatch level, ensuring compatible, reliable and stable connection to the GPS and PMU located at the electricity system and market operator. The dispatch level shall be responsible for integrating the GPS and PMU of the transmission network operator and customer using transmission grid to the system located at the dispatch level; dd) During operation, in case of upgrading or changing the GPS and PMU, the transmission network operator and customer using transmission grid shall be responsible for making notifications and entering negotiations with the dispatch level before implementation; e) The transmission lines from 220 kV and over connecting to generating sets or distribution area of the power plant must be equipped with two independent communication channels serving transmission of signals of protective relay between two ends of lines (transmission time no more than 20 ms); g) Electricity customers shall be responsible for investing and installing low-frequency relays within scope of automatic load shedding management according to calculations and requirements of the dispatch level. 9. Scope, positioning and technical requirements of protective relay equipment for generating sets, transformers, busbars and lines connecting to the transmission grid shall be conformable with the regulation on technical requirements of protective relay and automation system in the power plant and transformer issued by Electricity Regulatory Authority. Article 31. Requirements for information system 1. The customer using transmission grid shall be responsible for investing, installing and managing the information system and ensuring it is connected to the information system belonging to the transmission network operator and the dispatch level. Means of communications serving dispatching and operation include direct communication channel, telephone and facsimile. 2. The information system belonging to the customer using electrical grid must be compatible with that of the transmission network operator and the dispatch level. The customer may negotiate an agreement for use of information system of the transmission network operator or other suppliers to connect to the information system of the dispatch level to ensure continuous and reliable communication serving electricity system and market operation. 3. The transmission network operator shall be responsible for investing and managing the information system of its own to serve electricity system and market operation; cooperating with the dispatch level in establishing a information transmission line to the dispatch level. 4. The dispatch level shall be responsible for providing requirements for information data, data transmission and necessary information interface serving electricity system and market operation to the transmission network operator and customer using transmission grid. 5. The dispatch level and the transmission network operator shall be responsible for cooperating with the customer using transmission grid in testing, inspecting and connecting the customer’s information system to the existing information system managed by the units. Article 32. Requirements for connection of SCADA system 1. Transformers from 220 kV and on, power plants with installed capacity greater than 30 MW and power plants connected to the transmission grid which is not yet connected to the Control Center must be equipped with a Gateway or RTU with two ports connecting directly, simultaneously and independently to the SCADA system of the dispatch level. 2. Power plants with installed capacity greater than 30 MW and power plants connecting to the transmission grid which is connected to the Control Center must be equipped with a Gateway or RTU with one port connecting directly to the SCADA system of the dispatch level and two ports connecting directly to the Control Center. Transformers from 220 kV and on which is connected to the Control Center must be equipped with a Gateway or RTU with two ports connecting directly to the Control Center. 3. If a power plant, transformer has multiple dispatching levels with control authority, such dispatching levels shall be responsible for sharing information to serve electricity system operation coordination. 4. The transmission network operator and customer using transmission grid shall be responsible for investing, installing and operating the RTU/Gateway within management or hiring the data transmission lines from service providers to ensure continuous and reliable connection to the SCADA system of the dispatch level and the Control Center. 5. Technical characteristics of RTU/Gateway belonging to the transmission network operator and customer using transmission grid must be compatible with the SCADA system of the dispatch level and the Control Center (if any). 6. The dispatch level shall be responsible for integrating data according to the list of data agreed with the transmission network operator and customer using transmission grid to its SCADA system. The transmission network operator and customer using transmission grid shall be responsible for cooperating with the dispatch level in configuring and setting database on its system to ensure compatibility with the SCADA system of the dispatch level and control system of the Control Center (if any). 7. If the SCADA system of the dispatch level has had some technological changes approved by competent agencies after the connection agreement is signed resulting in changes or upgrading of the control system, RTU/Gateway of the transmission network operator and customer using transmission grid, the dispatch level, the transmission network operator and customer shall be responsible for making necessary adjustments to ensure that the equipment belonging to the transmission network operator and customer using transmission grid is compatible with changes of the SCADA system. The transmission network operator and customer using transmission grid shall be responsible for investing and upgrading the control system and RTU/Gateway to ensure compatibility with the SCADA system of the dispatch level. 8. During operation, in case of upgrading or expansion of the control system, RTU/Gateway, the transmission network operator and customer using transmission grid shall be responsible for entering negotiations with the dispatch level before the upgrading or expansion is carried out. 9. Requirements on lists of data, technical requirements of RTU/Gateway are detailed in the regulation on technical requirements and SCADA system operation management issued by the Electricity Regulatory Authority. Article 33. Neutral grounding in transformers Neutral grounding in transformers must ensure value of earth fault factor does not exceed the value prescribed in Article 13 herein. Article 34. Power factor 1. In normal operation mode, electricity distribution units and electricity customers must maintain a power factor (cosφ) at key measuring positions from 0.9 and over in case of receiving reactive power and from 0.98 and on in case of transmitting reactive power. 2. The customer using transmission grid must provide parameters of reactive power compensation equipment in its electrical grid (if any) to the transmission network operator and the dispatch level, including: a) Rated reactive power and adjustment range; b) Principle of reactive power adjustment. Article 35. Load fluctuation The speed of changing power consumption by electricity customers in a minute is not allowed to exceed 10% of power consumption in normal operation mode unless the electricity customer adjusts demand as requested or under an agreement with the electricity system and market operator. Article 36. Automatic frequency load shedding system 1. The customer using transmission grid shall be responsible for cooperating with relevant units in unifying the installation of the automatic frequency load shedding system and ensuring that it operates in accordance with calculations and requirements of the dispatch level. 2. The system must be designed to meet following requirements: a) Reliability not less than 99%; b) Any unsuccessful load shedding must not affect operation of the entire electricity system. c) Load shedding procedures and amount of shed power must be in compliance with level of distribution by the dispatch level and must not be changed in any case without consent of the dispatch level. 3. Low-frequency relays must be installed and put into operation at the request of the dispatch level. 4. Load recovery procedures after frequency is restored to normal operation mode must be in compliance with dispatch instruction of the dispatch level. Article 37. Requirements of Control Center 1. General technical requirements a) Monitoring, control and information systems installed in the Control Center must be equipped to ensure safe and reliable operation of power plants, substations; b) The Control Center’s monitoring and control systems must be technically compatible and ensure stable, reliable and continuous connection of power plants, substations and switchgears to SCADA system of the dispatch level; c) The Control Center must have a backup power supply to ensure normal operation in case of loss of power from the national electricity system. 2. Requests for connection from Control Center - There are two independent data transmission lines to be connected to the information system of the dispatch level. If multiple dispatching levels with control authority exist, an information sharing method must be agreed by all the dispatching levels; - There are two data transmission lines to be connected to the control and information system of power plants, substations remotely controlled by the Control Center; - Means of communications serving dispatching and operation include direct communication channel, telephone, facsimile and computer network. b) Requirements for connection to SCADA system - There are two ports connecting directly, simultaneously and independently to SCADA system of the dispatch level. If multiple dispatching levels with control authority exist, a common information sharing method must be agreed by all the dispatching levels; - There are ports connecting to RTU/Gateway, control system of power plants, substations and switchgears on the electrical grid remotely controlled by the Control Center. c) The Control Center must install a monitoring screen connected to the surveillance camera at power plants, substations and switchgears on the electrical grid. 3. Power plants, substations or switchgears on the electrical grid remotely controlled by the Control Center must be equipped with a control and surveillance camera system to establish stable, reliable and continuous connection to the Control Center meeting requirements prescribed in Clause 1 and Clause 2, this Article. Section 3. TECHNICAL REQUIREMENTS FOR CONNECTION TO HYDRO POWER PLANTS AND THERMO POWER PLANTS Article 38. Requirements for generating sets’ power control 1. Power plants with installed capacity over 30 MW must be equipped with facilities, control systems , AGC system to ensure stable and reliable connection to a generating set’s power control system of the electricity system and market operator serving remote control of the generating set’s power according to dispatch instruction of the electricity system and market operator. Particular technical requirements for connection of the generating set's AGC system to SCADA/EMS of the electricity system and market operator are prescribed in the regulation on technical and operation requirements of SCADA system issued by the Electricity Regulatory Authority. 2. The generating set of a power plant must be capable of generating rated active power in a power factor from 0.85 (corresponding to reactive power generation mode) to 0.9 (corresponding to reactive power receiving mode) in accordance with characteristics of the generating set’s reactive power. 3. The generating set must be capable of adjusting primary and secondary frequency as prescribed in the national load dispatch process issued by the Ministry of Industry and Trade and controlling voltage in the electricity system through continuous adjustment of active power and reactive power of the generating set. 4. In normal operation mode, voltage changes at connection point to transmission grid within permissible scope prescribed in Article 6 herein must not affect amount of active power generated and reactive power generation capability of the generating set. 5. The generating set of a power plant must be capable of generating rated active power continuously within frequency band 49 Hz – 51 Hz. In a frequency band from 46 Hz to under 49 Hz and over 51 Hz, level of power reduction must not exceed value according to frequency reduction ratio of the electricity system. Minimum time to maintain operation of power plants with installed capacity over 30 MW or power plants connected to the transmission grid in proportion to frequency bands of the electricity system is specified in Table 7 below: Table 7 Minimum time to maintain power generation in proportion to frequency band of the electricity system Frequency band Minimum time Hydro power plants Thermo power plants From 46 Hz to 47.5 Hz 20 seconds Not required From 47.5 Hz to 48.0 Hz 10 minutes 10 minutes From 48 Hz to under 49 Hz 30 minutes 30 minutes Continuous generation Continuous generation From 51 Hz to 51.5 Hz 30 minutes 30 minutes From 51.5 Hz to 52 Hz 03 minutes 01 minute From 49 Hz to 51 Hz 6. Generating sets of a power plant must be capable of withstanding level of voltage symmetry loss in the electricity system as prescribed in Article7 herein. 7. Generating sets of a power plant must be capable of working continuously in following modes: a) Unbalanced three-phase loads from 10% and under; b) Indicator of response of the exciter in a synchronous generating set greater than 0.5%; c) Negative sequence current is 5% less than rated current. Article 39. Excitation system of a generating set 1. The excitation system of a generating must ensure that the generating set can operate in a power factor range prescribed in Clause 2, Article 38 herein. The excitation system must ensure the generating set operates at a rated apparent power (MVA) within the range ± 5 % of rated voltage at the generating set’s terminal posts. 2. The generating set must be equipped with AVR which operates continuously and is capable of maintaining deviation of terminal voltage within ± 0,5 % of rated voltage in the entire permissible working band of the generating set. 3. AVR must be capable of making up for voltage drop on terminal transformers and ensure stable distribution of reactive power among generating sets connected to a common busbar. 4. AVR must be installed with following limits: a) Minimum excitation current; b) Maximum excitation current. 5. When terminal voltage of a generating set is in a range from 80 to 120% of rated voltage and the system frequency is in a range from 47.5 to 52Hz in a maximum of 0.1 second, the excitation system of the generating set must be capable of increasing the current and excitation voltage to following values: a) For a generating set of a hydro power plant: 1.8 rated value; a) For a generating set of a thermo power plant: 2.0 rated value; 6. Change of excitation voltage is not allowed to be less than 2.0 rated excitation voltage/second when a generating set carries the rated load. 7. A generating set with a capacity over 30 MW must be equipped with a PSS capable of dampening 0.1 Hz – 5 Hz frequency fluctuation contributing to improvement of the electrical system. Generating units must install and set parameters of the PSS according to calculations by the electricity system and market operator to ensure dampening ratio of the PSS is not smaller than 5%. For generating sets equipped with PSS, the generating units shall be responsible for putting the PSS into operation at the request of the dispatch level. Article 40. Governor 1. Generating sets of a power plant in operation must engage in adjusting primary frequency in the national electricity system. 2. Generating sets of a power plant must be equipped with a governor capable of responding to changes of system frequency in normal operation conditions. The governor must be capable of performing commands from SCADA/EMS system of the electricity system and market operator unless it is not required. 3. The governor must be capable of setting value of static coefficient less than or equal to 5%. Set value of static coefficient shall be determined by the electricity system and market operator. 4. Apart from add-on generating sets of combined cycle power plants, minimum value of a dead-band in the governor must range within ± 0,05 Hz. Value of dead-band of the governor of each generating set shall be calculated and determined by the electricity system and market operator during connection and operation. 5. The governor control system must be installed with following limits and anti-over speed control as follows: a) For steam turbines: From 104% to 112% of rated speed; b) For gas and thermo power turbines: From 104% to 130% of rated speed; c) If the generating set in the grid area is temporarily disconnected from the national electricity transmission system but keeps supplying power to customers, the governor system of the generating set must maintain frequency stability for such grid area. Article 41. Black start 1. In some important positions in electricity transmission system, some power plants must be capable of black starting. Requirements for installation of black start capability must be stated in the connection agreement. 2. The electricity system and market operator shall be responsible for determining important positions in the national electricity system for the construction of power plants capable of black start and cooperate with the transmission network operator, generating units in determining specific requirements for black start of individual power plants. Section 4. TECHNICAL REQUIREMENTS OF WIND AND SOLAR POWER PLANTS Article 42. Technical requirements of wind and solar power plants 1. Wind and solar power plants must be capable of maintaining generation of active power within frequency band from 49 to 51 Hz in following modes: a) Free generation mode b) Generating capacity control mode Wind and solar power plants must be capable of adjusting generation of active power as commanded by the dispatch level in accordance with change of primary sources no more than 30 seconds with tolerance within ± 01 % of rated power, specifically as follows: - Generation of power in accordance with dispatch instruction in case primary sources are equal or greater than forecast value; - Generation of possible maximum power in case primary sources are lower than forecast value. 2. In normal operation mode, wind and solar power plants must be capable of generating active power and ensure no negative effect is caused by change of voltage at connection point within permissible band prescribed in Article 6 herein. 3. Wind and solar power plants must be capable of maintaining generation of power for a minimum period of time in proportion to frequency band prescribed in Table 8 below: Table 8 Minimum time to maintain power generation in proportion to frequency band of electricity system Frequency band Minimum time From 47.5 Hz to 48.0 Hz 10 minutes Over 48 Hz to under 49 Hz 30 minutes From 49 Hz to 51 Hz Continuous generation From 51 Hz to 51.5 Hz 30 minutes Over 51.5 Hz to 52 Hz 01 minute 4. When the electricity system’s frequency is greater than 51 Hz, wind and solar power plants must reduce active power at a speed no less than 01% of rated power. Level of power reduction in proportion to frequency is determined as follows:  51.0  fn  P  20  Pm x   50   Where: - ΔP: Level of active power reduction (MW); - Pm: Active power in proportion to the point of time prior to power reduction (MW); - fn: Electricity system frequency prior to power reduction (Hz). 5. Wind and solar power plants must be capable of adjusting reactive power and voltage as follows: a) If a power plant generates an active power greater or equal to 20% of rated active power and voltage in normal operation band, such power plant must be capable of adjusting reactive power continuously in a power factor from 0.85 (corresponding to reactive power generation mode) to 0.95 (corresponding to reactive power receiving mode) at connection point in proportion to rate power; b) If a power plant generates an active power less than 20% of rated power, such power plant may reduce ability to receive or generate reactive power in accordance with characteristics of the generating set; c) If voltage at connection point is within ± 10 % of rated voltage, the power plant must be capable of adjusting voltage at connection point with deviation no more than ± 0,5 % of rated voltage in permissible working band of the generating set; d) If voltage at connection point varies beyond ± 10 % of rated voltage, the power plant must be capable of adjusting reactive power to the minimum of 2% compared with rated reactive power in proportion to each per cent of voltage varying at connection point. 6. Wind and solar power plants at every time of connection to the grid must be capable of maintaining generation of power in proportion to voltage range as follows: a) Voltage less than 0.3 pu, minimum time is 0.15 seconds; b) Voltage from 0.3 pu to under 0.9 pu, minimum time is calculated in following formula: Tmin = 4 x U – 0.6 Where: - Tmin (second): Minimum time to maintain power generation: - U (pu): Actual voltage at connection point (pu). c) Voltage from 0.9 pu to under 1.1 pu, wind and solar power plants must maintain continuous generation; d) Voltage from 1.1 pu to under 1.15 pu, wind and solar power plants must maintain generation for three seconds; dd) Voltage from 1.15 pu to under 1.15 pu, wind and solar power plants must maintain generation for 0.5 seconds; 7. Wind and solar power plants must ensure not to cause negative phase sequence component in excess of 01% of rated voltage. Wind and solar power plants must be capable of withstanding negative phase sequence components up to 03% of rated voltage for voltage from 220 kV and on. 8. Total harmonic distortion caused by wind, solar power plants at connection point is not allowed to exceed 03%. 9. Flicker perceptibility caused by wind and solar power plants at connection point is not allowed to exceed the value prescribed in Article 9 herein.
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