Operating modes of electric power systems

The mode of the electric power system (EPS) is its state, determined by the loads of power plants (and individual power units) in terms of active and reactive power, voltages of nodes, loading of network elements and other variables called mode parameters (mode parameters) that characterize the process of production, transmission, distribution and electricity consumption. Sometimes the concept of “mode” is used in a broader sense, i.e. consider as a variable also the topology of the network. There are energy, hydropower and electric modes.

Energy modes (EnR). Power plant planning consists in determining the composition and loading in terms of active power (loading in terms of reactive power refers to electrical modes) of various types of power plants (taking into account imports from other power systems) to cover the load of the EPS and carry out export deliveries at any time (usually for every hour) , as well as power reserves.

The energy mode is normal if the balance of active powers of the EPS is ensured at any time at frequency values corresponding to the standard. The frequency deviation can serve as a measure of active power imbalance. from the nominal value or directly power unbalance , where – frequency deviation from the nominal value (permissible frequency deviations are regulated by GOST); – EES frequency static coefficient, MW/Hz.

Power mode optimization – load coverage at minimum cost, subject to all restrictions. The following are used as initial information:

– forecasts of daily load schedules of the EPS as a whole and its individual parts, as well as schedules of external electricity supplies;

– load schedules for nuclear power plants and other block stations;

– loading ranges of condensing units using different types of fuel;

– CHP loading modes according to the thermal schedule;

– energy characteristics (characteristics of relative increments) of individual units or their groups at TPPs;

– fuel consumption for the start-up of units after shutdowns of various durations;

– daily output of HPPs and PSPs;

– model of the electrical network, taking into account the planned repairs of network elements, as well as the value of the allowable active power flows in the controlled sections of the EPS during these repairs.

As a result of optimizing the energy regime, daily load schedules are obtained for the active power of all power plants and, as derivative schedules, for the balance of individual EPS and power associations, as well as load schedules for controlled interconnections.

Distinguish between long-term (year, quarter, month) and short-term (week, day) EnR planning. In long-term planning, there are much more uncertainties associated with the weather, emergency repairs of generating and network equipment, therefore, they are guided by the average ambient temperature, the normal network layout, and the larger the planned period, the greater the power reserves. In short-term planning, the consumption forecast is made taking into account the weather forecast, network bandwidth limitations associated with repair plans for network equipment and (or) emergency control devices are taken into account, and in operational planning (for the next hour), emergency repairs and consumption forecast errors are also taken into account.

In large energy associations, power generation planning is carried out according to a hierarchical principle. At the same time, information about consumption forecasts (including external power exchanges), about the constant and regulated parts of generation, and consumption characteristics for each type of power plants comes from the regional power systems to the ODU, and from the ODU to the CDU.

When planning the EnR in one form or another, the developments of hydropower and electric regimes are used (as a rule, in the form of restrictions). These are the allowable loading limits of individual power plants and daily output, allowable active power flows in controlled sections (between different regions) in full and repair schemes, obtained on the basis of preliminary studies of the stability of the EPS, as well as to take into account changes in losses in the electrical network – the sensitivity of total losses in networks to a change in generation (or load) in each of the nodes of the circuit.

The difficulties of planning EnR include overcoming the unevenness of the daily (weekly, including weekends) load schedule.

NPPs in the UES of Russia operate in a base mode with a high number of hours of use, determined by shutdowns for refueling and repairs.

The technical minimum for 150-500 MW coal-fired power units is from 50 to 80%, the average for the UES is approximately 70% and is determined for each specific power unit, taking into account its condition, the use of “lighting” with fuel oil or gas. Gas-oil power units of 300 MW are unloaded, as a rule, by 40% (some up to 30), larger units – 800-1200 MW can be unloaded up to 50-60%.

Inefficient gas turbine plants are used 1–4 hours per day and up to 1000 hours per year. They are very effective for overcoming the irregularity of the daily schedule of pumped storage power plants (the Zagorskaya pumped storage power plant with a capacity of 6 × 200 MW operates in the UES of Russia), despite their rather low efficiency – about 70%. At the same time, closing costs* change during the day by 3 times or more, since they allow you to even out not only the peaks, but also the dips in the schedule. PSPPs are used in generator mode 4-6 hours per day and up to 8 hours in pumping mode with one or two cycles of filling and drawdown of the reservoir per day.

The use of zone (by time of day) tariffs is very effective for leveling the consumption schedule. Reducing the tariff at night and increasing it during the day and peak hours encourage consumers to organize their activities accordingly and lead to a decrease in the unevenness of the total load schedule of the EPS.

HPPs are of decisive importance in covering the daily load schedules of EPS, and in particular their sharply variable parts, therefore, the flood period, when HPPs are forced to work on the basis of the load schedule to prevent losses of energy resources, is the most difficult for the UPS. Their share in the European part of the UES is about 14% (for comparison, in the IPS of Siberia it is 60%), and they usually operate during the day in a sharply variable mode with an annual number of hours of use of 3000–4000. At the same time, the rate of load change is approximately 3%/s over the entire range, the minimum load is approximately 10–15% and follows from the requirements of the environment and the entire set of water users.

Hydropower regimes (HER). The task of planning the GER is to forecast the annual, quarterly and monthly electricity generation at each HPP for long-term planning and to determine the daily (sometimes weekly) generation for short-term planning of EnR. The initial information for planning GER is the data of long-term observations after their statistical processing, the results of hydrological and meteorological forecasts of different prospects and reliability. For different forecasting periods, estimates are made of inflow, costs, including by other users, natural losses; the data of direct measurements of the pressure and recommendations for the drawdown of the reservoir are taken into account, which would maximize the generation of electricity at the HPP. It is important to prepare the reservoir for the flood in order to prevent idle discharges, bearing in mind its random nature, and to maintain the HPP control range at any time.

When optimizing EnR, the task is to replace the most expensive (usually fuel oil) thermal power units with the generation at HPPs.

Electric modes (ElR). The planning of electrical regimes consists in determining the composition of reactive power compensation devices and loading generators in terms of reactive power, as well as the composition and configuration of emergency control devices (PA) that ensure the implementation of a given ERP (as indicated above, ERP planning, in turn, is carried out taking into account the restrictions arising from the developments of ElR). EL optimization consists in determining the composition and load of reactive power compensation devices, transformation ratios of adjustable transformers and reactive power load of generators for a given generation of active power, active and reactive load of each node and preset permissible voltage levels of nodes corresponding to a minimum of active power losses in the power system.

Another main task of planning an EL is to determine the areas of permissible modes, the necessary composition and configuration of PA devices in various circuit-mode situations, including promising ones, necessary for planning an ER, as well as for the operational maintenance of modes, taking into account the possible loss at any time of a network element or (i) power unit. This problem is solved by calculating the limiting power flows in various sections of the power system (weak or potentially weak), mathematical modeling of transient modes caused by normative disturbances, taking into account the action of the PA.

There are the following main electrical modes (special modes, such as incomplete-phase, oscillatory, etc., are not considered):

Normal mode is a steady state (not counting irregular fluctuations, slow and (or) insignificant fluctuations of parameters, including those caused by the operation of frequency, voltage control devices, etc.), characterized by long-term permissible values of frequency, currents and voltages, standard margins stability in a given network scheme, a stable transition to any post-emergency modes that may arise as a result of regulatory disturbances, and a steady post-emergency mode that has no less than standard stability margins.

Normal mode is characterized by acceptable areas of mode parameters. In practice, the maximum allowable active power flows in controlled sections are used as a generalized characteristic of normal modes, which, based on the above definition (definition), are determined by the following conditions:

1) the safety factor for active power in any section for a given network diagram must be at least 20%:


where – limiting in terms of aperiodic static stability the flow of active power in the considered section in this circuit (normal, repair); – current (or planned) value of power flow; – the amplitude of irregular power fluctuations in the network section; , – respectively, the total load, MW, of each of the subsystems on different sides of the section; – respectively, with automatic or manual regulation (limitation) of the flow in the cross section. The limiting flow almost always depends on a number of factors, among which some have little effect, others have a significant effect on its value. Therefore, it is presented in the general case as a function of the parameters that are taken into account and significantly affect . The remaining parameters that are not taken into account are taken according to the most pessimistic option;

2) the voltage safety factor in all nodes of the power system must be at least 15%, i.e. , where – voltage (current) in the node in this mode; is the critical stress in this node.

This condition means, in particular, that when other possibilities of voltage regulation are exhausted, the necessary voltage margin is provided by reducing the power flow in the cross section:


where – active power flow, at which the voltage at intermediate substations has a 15% margin in relation to the critical voltage;

3) the load of any element of the electrical network should not exceed the permissible values (taking into account the permitted overloads);

4) power flow in any section in the mode under consideration should not exceed the limiting flow in terms of dynamic stability in the same section for all standard disturbances:


where – the smallest limit of dynamic stability, taking into account the action of automatic stability violation prevention (APNU) for each of the standard perturbations for this scheme;

5) the safety factor for active power in any of the established post-accident modes that have arisen as a result of standard disturbances must be at least 8%, i.e.


where – limiting in terms of aperiodic static stability the flow of active power in the section under consideration in this post-accident scheme, taking into account the control actions of the PA, aimed at changing the passive parameters of the network, for example, shutdown of shunt reactors; in particular, it can coincide with the limit in the original circuit when disturbed in the form of an emergency power imbalance; – power surge in the cross section due to emergency unbalance ; – total loads and frequency static coefficients of subsystems on different sides of the section; – flow increment in the section due to the control actions of the APNU;

6) in each node and in each of the standard post-accident modes, the voltage safety factor must be at least 10%, i.e. by analogy with paragraph 2


where – voltage in the post-emergency steady state, including after the action of the PA devices, in the node of the circuit with the lowest voltage, from where .

The dependence of the flow in the initial mode on the lowest voltage in the steady post-accident mode is built on the basis of numerical simulation of standard perturbations and the action of the PA at various initial power flows in the considered section;

7) the load of any element of the electrical network in any normative post-accident mode must exceed the values allowed for 20 minutes.

It is accepted that the dispatching personnel within the specified 20 minutes should correct the established post-accident mode with reduced stability margins and (or) equipment overloads (paragraphs 5–7) in such a way as to ensure the fulfillment of the conditions of paragraphs. 1–3. To do this, in the relevant instructions for the dispatcher, the maximum allowable values of power flows in controlled (critical) sections in complete and repair schemes and other necessary instructions are given.

Not all of the above limitations are decisive. In particular, current overloads in the UES of Russia occur extremely rarely, since due to the length of networks, the conditions for ensuring static stability cause more restrictions. With dynamic stability on intersystem (i.e., as a rule, weak) connections, problems arise much less frequently than on connections of individual large power plants or power centers in an EPS. Voltage limitation occurs more often at lower levels of the control hierarchy and very rarely at the CDU level. In practice, the allowable cross-sectional flow is most often determined by one or two of the seven conditions listed above.

Forced mode – a mode that does not meet at least one of the listed conditions (clauses 1–7). Forced mode is not allowed in the sections adjacent to the nuclear power plant. In other cases, work with reduced stability margins should be formalized as a separate decision.

Post-accident regimes are regimes resulting from an emergency disturbance. Sometimes the following post-accident modes are also distinguished:

– normative post-accident mode (accidentally permissible flow), characterized by stability margins not less than according to paragraphs. 5–7. If these stocks do not correspond to the conditions of the normal mode (clauses 1–4), then the dispatching personnel must provide them in 20 minutes;

– established post-emergency mode with less than according to paragraphs. 5–7, reserves. Such a regime may arise if the previous regime did not correspond to the normal regime or (and) the disturbance was more severe than the normative one. At the same time, the dispatching personnel must also increase the stability margins to normal (regulated);

– asynchronous mode – unstable post-accident mode.

The most severe emergency disturbances include:

in a normal pattern :

– disconnection of a network element after a multi-phase short circuit and an unsuccessful AR action;

– disconnection of a network element after a single-phase short circuit and failure of one circuit breaker and the operation of a circuit breaker failure backup device;

– simultaneous disconnection of two circuits of a double-circuit line on common supports or two lines located in a common corridor for more than half the length of a shorter line;

– the occurrence of an emergency power imbalance due to a generator or generator block with a common switch on the high voltage side, a large substation or a large consumer, a direct current transmission or its element, etc. district; or emergency shutdown of the load of the same power;

in the repair scheme :

– disconnection of a network element with a multi-phase short circuit and an unsuccessful AR action;

– the occurrence of an emergency power imbalance, the value of which does not exceed the power of the largest power unit or two generators of one nuclear power plant, or an emergency load loss of the same power.

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