Description:

Improving Efficiency
distribution network management

V. E. Vorotnitsky, doctor of tech. Sci., Professor, Deputy Executive Director for Research, JSC VNIIE

The main tasks of managing electric networks in market conditions

Ensuring the technological infrastructure function of the electric grid on the terms of equal opportunities for its use by all participants in the electricity market;

Ensuring the stable and safe operation of electrical network equipment, reliable power supply to consumers and the quality of electricity that meet the requirements established by regulatory enactments, and taking measures to ensure the fulfillment of obligations of electric power industry entities under contracts concluded on the electricity market;

Ensuring contractual conditions for the supply of electricity to participants (s) of the electricity market;

Ensuring non-discriminatory access of subjects of the electricity market to the electrical network, subject to their compliance with the Market Rules, technological rules and procedures, if such connection is technically possible;

Minimization of network technical limitations within economically justified limits;

Reducing the cost of transmission and distribution of electricity through the introduction of advanced technologies for the maintenance and repair of power grid equipment, new equipment and energy-saving measures.

The purpose of the article is to consider:

The main tasks of managing electrical networks in market conditions;

General characteristics of distribution networks 0.38–110 kV in Russia;

Technical condition of distribution networks, facilities and systems for their management;

Trends and development prospects:

a) digital information technologies;

b) basic information technologies;

c) geoinformation technologies;

d) automated systems for operational and technological management of distribution networks of companies and their main subsystems;

e) means of partitioning distribution networks;

Problems of creating a regulatory framework for automation of distribution networks management.

General characteristics of distribution electrical networks in Russia

Rural electrical networks

The total length of electrical networks with a voltage of 0.4–110 kV in rural areas of Russia is about 2.3 million km, including lines with voltages of:

0.4 kV - 880 thousand km

6–10 kV - 1,150 thousand km

35 kV - 160 thousand km

110 kV - 110 thousand km

513,000 transformer substations 6–35/0.4 kV with a total capacity of about 90 million kVA have been installed in the grids.

City electrical networks

The total length of urban electrical networks with a voltage of 0.4–10 kV is 0.9 million km, including:

cable lines 0.4 kV - 55 thousand km

overhead lines 0.4 kV - 385 thousand km

cable lines 10 kV - 160 thousand km

overhead lines 10 kV - 90 thousand km

outdoor lighting overhead lines - 190 thousand km

outdoor lighting overhead lines - 20 thousand km

About 290 thousand transformer substations of 6–10 kV with a capacity of 100–630 kVA are installed in the networks.

Technical condition of distribution electrical networks, means and systems for their control

Electrical network equipment

About 30-35% of overhead lines and transformer substations have worked out their standard period. By 2010, this figure will reach 40%, if the pace of reconstruction and technical re-equipment of electrical networks remains the same.

As a result, problems with the reliability of power supply are exacerbated.

The average duration of consumer outages is 70–100 hours per year. In industrialized countries, it is statistically defined as a “good” state of power supply when the total duration of interruptions for a medium voltage network during the year is in the range of 15–60 minutes per year. In low voltage networks, these figures are slightly higher.

The average number of damages that cause disconnection of high-voltage lines with voltage up to 35 kV is 170–350 per 100 km of the line per year, of which 72% are unstable, turning into single-phase ones.

Relay protection and automation

Of the currently in operation in the distribution networks of Russia, about 1,200 thousand devices of relay protection and automation (RPA) of various types, the main share is electromechanical devices, microelectronic or devices with partial use of microelectronics.

With the standard service life of relay protection devices equal to 12 years, about 50% of all relay protection kits have worked out their standard service life.

The backlog of the level of manufactured domestic RPA equipment in comparison with the RPA equipment of leading foreign manufacturers is 15–20 years.

As before, over 40% of cases of improper operation of relay protection and automation devices occur due to the unsatisfactory condition of the devices and errors of the personnel of the relay protection services during their maintenance.

It should be noted that not everything is safe with the reliability of the relay protection, not only in Russia, but also in some industrialized countries.

In particular, at the session of the International Conference on Distribution Networks (CIRED) in 2001, it was noted that in the Norwegian electric networks the annual damage from incorrect actions of protection and control systems is about 4 million US dollars. At the same time, 50% of false alarms of protection fall on the share of protection and control devices. Of these, more than 50% - with errors during the verification and testing of equipment and only 40% due to its damage.

In other Scandinavian countries, the damage rate of relay protection devices is 2–6 times lower.

The main obstacle to the wide automation of power grid facilities is the unavailability of primary electrical equipment for this.

System for collecting and transmitting information, information and computer systems

More than 95% of telemechanics devices and sensor sets have been in operation for more than 10–20 years. Means and communication systems are mainly analog, morally and physically obsolete, do not meet the necessary requirements for accuracy, reliability, reliability and speed.

In the vast majority of control rooms of district electric networks (RES) and electric grid enterprises (PES), the technical basis of automated control systems is personal computers that do not meet the requirements of continuous technological monitoring and control. The service life of personal computers operating in continuous mode does not exceed 5 years, and their obsolescence period is even shorter. For an automated supervisory control system (ASCS) of electrical networks, it is necessary to use special computers that reliably operate in a continuous mode, complete with process control tools.

Requires widespread licensing of system software Microsoft, ORACLE, etc. used in electrical networks.

Application (technological) software (SCADA-DMS) in many electrical networks is also clearly outdated, does not meet modern requirements both in terms of functions and in terms of the volume of information processed.

In particular, the existing automated control systems for PES and RES mainly provide information services to personnel and practically do not solve the problems of operational management of power systems, optimization of operational and repair maintenance of electrical networks.

Voltage regulation system

On-load voltage regulation in distribution network feed centers and non-excited switching (with transformer disconnection) at 6-10 kV transformer substations are almost never used or are used sporadically as consumers complain about low voltage levels during peak hours.

The result is that at separate electrically remote points of 0.38 kV electrical networks in rural areas, voltage levels are 150–160 V instead of 220 V.

In such a situation, the electricity market can impose very serious sanctions on distribution grid companies for the reliability and quality of electricity supply to consumers. If you do not prepare for this in advance, in the very near future network companies will suffer serious material losses, which will further aggravate the situation.

Electricity metering system

The vast majority of distribution network power centers (about 80%) and about 90% of residential consumers have morally and physically obsolete, often with expired calibration and service dates, induction or electronic meters of the first generations, providing the possibility of only manual readings.

The result is an increase in commercial losses of electricity in electric networks. With total electricity losses in Russian electrical networks of about 107 billion kWh per year, distribution networks of 110 kV and below account for 85 billion kWh, of which commercial losses, according to minimal estimates, amount to 30 billion kWh per year.

If at the end of the 80s of the twentieth century the relative losses of electricity in the electrical networks of power systems did not exceed 13–15% of the supply of electricity to the network, then at present they have reached the level of 20–25% for individual power systems, and 30–40 for individual TPPs. %, and for some RES already exceed 50%.

In developed European countries, the relative losses of electricity in electrical networks are at the level of 4-10%: in the USA - about 9%, Japan - 5%.

In accordance with the Decree of the Government of the Russian Federation on the regulation of tariffs for electric energy, the Rules of the wholesale market and the draft Rules of the retail market for the transitional period, standard losses of electricity in electric networks (and this is no more than 10-12% of the supply to the network) can be included in the cost of transmission services electricity and will be paid by market entities, and excess electricity losses will have to be bought by grid companies to compensate them.

For some companies with losses of 20-25%, this means that more than half of the reported losses will be direct financial losses of hundreds of millions of rubles per year.

All this requires qualitatively new approaches to electricity metering both in electrical networks and at consumers, first of all, to automation of accounting, to automation of calculations and analysis of electricity balances, selective disconnection of non-paying consumers, etc.

Regulatory framework for optimizing the development of electrical distribution networks and their control systems

The regulatory framework has hardly been updated since the mid-1980s and early 1990s. Today, about 600 sectoral regulatory documents require revision.

Many fundamental documents, primarily the rules for the installation of electrical installations, the rules for technical operation are not agreed upon by the Ministry of Justice of the Russian Federation and, in essence, have ceased to be mandatory for use.

Until now, the new Rules for the use of electricity have not been agreed with the same Ministry of Justice of the Russian Federation. The Criminal Code of the Russian Federation does not contain the concept of "theft of electricity", which causes great material damage to the electric power industry. The volume of electricity theft is growing and will objectively grow with an increase in electricity tariffs. To stop this, we need not only the efforts of power engineers, but also legal assistance from the state. Unfortunately, this assistance is not always adequate. In particular, with the entry into force of the Law of the Russian Federation "On Technical Regulation", the status of GOSTs is sharply lowered, which for a country like Russia can create and is already creating significant problems. The main one is the lack of a unified technical policy in the development and management of distribution networks.

Financing of this development and its scientific support is clearly insufficient and is carried out according to the residual principle. More than a decade of crisis in the Russian electric power industry has significantly aggravated the situation. The power industry management reforms that have begun in recent years have so far affected the backbone networks of 220 kV and above, in which there are also many problems, but not as much as they have accumulated in distribution networks.

Hopes for the activity of domestic and Western investors and the introduction of Western technologies in the management of domestic distribution networks are most likely doomed due to the fact that Russian legislation, mentality, climatic conditions, features of building networks (large branching and length, other network equipment, low quality electricity, high levels of interference, etc.), control systems and software differ significantly from foreign ones. It is more correct to focus on one's own strengths, taking into account the best domestic and foreign experience. There are all the prerequisites for this, as evidenced by the emerging trends in the world and advanced domestic energy systems and networks.

In the mid-1980s and early 1990s, JSC VNIIE developed a whole set of documents on the creation and development of automated control systems for PES and RES. Of course, these documents are now very outdated and require revision.

Trends and development prospects

Digital and information technologies

Global trends in the development of control systems are inextricably linked with the transition to digital technologies, which provide the ability to create integrated hierarchical systems. At the same time, distribution electrical networks in these systems are the lower hierarchical link, inextricably linked with the upper levels of management.

The basis for the transition to digital technologies is the technical re-equipment and modernization of the communication and telecommunications system with a sharp increase in the volume and speed of information transfer. A phased transition to digital integrated control systems will be determined by the stages of implementation of the Unified Digital Communication System in the energy sector and will take at least 10-15 years.

In the last years of the 20th century, the world's leading experts in the field of telecommunications put forward the thesis: "The 20th century is the century of energy, and the 21st century is the century of informatics." At the same time, a new term appeared: “infocommunications”, which combines “informatization” and “telecommunications”. I think it would be more correct to say that the 21st century will be the century of both energy and infocommunications based on modern information and digital technologies.

The most important trends in the development of infocommunication networks are:

Increasing the reliability and service life of telecommunication networks;

Development of methods for forecasting the development of telecommunications in the regions, depending on the consumption of electricity;

Creation of information and communication environment management systems;

Simultaneously with the development of digital networks, the introduction of modern telecommunication technologies, primarily fiber-optic technology;

Introduction in a number of countries of the so-called PLC-technologies for using 0.4–35 kV electrical networks for transmitting any information from substations, power enterprises, industrial enterprises to monitoring and managing energy consumption in everyday life, including solving AMR problems, information support for the activities of electrical network subscribers 0.4–35 kV;

Use of communication facilities for the protection of power facilities, video surveillance.

Basic Information Technology

One of the main features of modern automated control systems is the integration (aggregation) of many software products into a single information space.

Currently, integration technology based on Internet technologies and open standards is developing very rapidly, which allows:

Create a technical infrastructure for application design and system development capabilities for a long time;

Provide the ability to integrate products from companies such as Microsoft, ORACLE, IBM, etc.;

Ensure the possibility of consistent integration of existing products without significant changes and reprogramming;

Ensure the scalability and portability of the software in order to replicate it at the company's enterprises.

Geoinformation technologies

The rapid development of computer technology and telecommunications, satellite navigation systems, digital cartography, the success of microelectronics and other technological advances, the continuous improvement of standard and applied software and information support create objective prerequisites for an ever wider application and development of a qualitatively new field of knowledge - geoinformatics. It arose at the intersection of geography, geodesy, topology, data processing, computer science, engineering, ecology, economics, business, other disciplines and areas of human activity. The most significant practical applications of geoinformatics as a science are geographic information systems (GIS) and geoinformation technologies (GIS technologies) created on their basis.

The abbreviation GIS has existed for more than 20 years and originally referred to a set of computer methods for creating and analyzing digital maps and related thematic information for managing municipal facilities.

Increasing attention is paid to the use of GIS technologies in the electric power industry and, first of all, in the electric networks of JSC FGC UES, AO-energos and cities.

Already the first experiences of using GIS as information and reference systems in domestic electrical networks have shown the unconditional usefulness and effectiveness of such use for:

Certification of network equipment with their binding to a digital map of the area and various electrical circuits: normal, operational, supporting, calculated, etc.;

Accounting and analysis of the technical condition of electrical equipment: lines, transformers, etc.;

Accounting and analysis of payments for consumed electricity;

Positioning and displaying on a digital map the location of operational mobile teams, etc.

Even greater prospects open up in the application of GIS technologies in solving problems: optimal development planning and design; repair and maintenance of electrical networks, taking into account the features of the terrain; operational management of networks and elimination of accidents, taking into account spatial, thematic and operational information about the state of network facilities and their modes of operation. To do this, even today information and functional linkage of GIS, technological software systems of automated control systems for electrical networks, expert systems and knowledge bases for solving the above tasks is needed. JSC "VNIIE" has developed a system-adviser for the analysis of requests for repairs of network equipment. Work is underway to link loss calculation programs to GIS.

In recent years, there has been a well-defined trend in the development of integrated engineering communications systems on a single topographic basis of a city, district, region, including thermal, electrical, gas, water, telephone and other engineering networks.

The structure of the automated system for operational dispatch control of distribution grid companies (AS DGC)

The purpose of creating the RGC AS is to increase the efficiency and reliability of the distribution of electrical energy and power by ensuring the maximum efficiency of the operational and technological activities of the RGC through the integrated automation of the processes of collecting, processing, transmitting information and making decisions based on modern information technologies.

The RSC AS should be a distributed hierarchical system, at each level of which the mandatory basic set of tasks is solved, ensuring the performance of the main functions of operational and technological management.

The main subsystems of AS RSK:

Automated operational dispatch control of electrical networks, performing the following functions:

a) current management;

b) operational management and planning;

c) control and management of power consumption;

d) planning and management of repairs;

Automated technological control:

a) relay protection and automation;

b) voltage and reactive power;

Automated system for commercial and technical accounting of electricity (ASKUE);

System of communication, collection, transmission and display of information.

Due to restrictions on the volume of articles, we will focus only on the main trends and development prospects of the main subsystems of the RSC AS.

Relay protection and automation

The main directions of development of relay protection and automation in distribution electrical networks:

Replacement of physically worn-out equipment that has worked out its service life;

Modernization of relay protection and automation devices with a focus on the use of a new generation of microprocessor devices;

Integration of microprocessor-based relay protection and automation equipment into a single automated process control system for supply substations;

Expansion of relay protection and automation functions for the tasks of measurement and control, taking into account the requirements for the reliability of its operation, including the use of international standards for communication interfaces.

Voltage and reactive power regulation

The main tasks to improve the efficiency of voltage regulation:

Improving the reliability and quality of operational maintenance of voltage regulation means, first of all, voltage regulation under load and automatic voltage regulation;

Control and analysis of load graphs of consumers and voltages in the nodes of electrical networks, increasing the reliability and volume of measurements of reactive power in distribution networks;

Implementation and systematic use of software to optimize the laws of voltage regulation in distribution networks, the practical implementation of these laws;

Organization of remote and automatic control of transformer taps from dispatch centers;

Installation of additional remotely controlled means of voltage regulation, for example, booster transformers on the mains of long medium voltage distribution lines, on which it is impossible to ensure permissible voltage deviations at the network nodes by means of centralized regulation.

Electricity metering automation

Automation of electricity metering is a strategic direction for reducing commercial electricity losses in all countries without exception, the basis and a prerequisite for the functioning of the wholesale and retail electricity markets.

Modern ASKUE should be created on the basis of:

Standardization of formats and protocols for data transmission;

Ensuring the discreteness of accounting, collection and transmission of commercial accounting data necessary for the effective functioning of the competitive retail electricity market;

Ensuring the calculation of actual and permissible imbalances of electricity in electric networks, localization of imbalances and taking measures to reduce them;

Mutual linkage with the means of automated control systems, automated process control systems and emergency automation.

To collect information, there is a steady trend to replace induction meters with electronic ones, not only because of higher accuracy limits, but also due to lower consumption in the current transformer and voltage transformer circuits.

Of particular importance for the retail electricity market and for reducing electricity losses in electrical networks is the exclusion of self-service (self-recording of readings) of electricity meters by household consumers. To this end, ASKUE for household consumers is being developed all over the world with data transmission from electricity meters via a 0.4 kV power network or via radio channels to data collection centers. In particular, the PLC technologies already mentioned above are widely used.

Application of modern means of sectioning distribution electrical networks and decentralized automation

In many countries, in order to increase the reliability of distribution networks, reduce the time to search for a fault location and the number of interruptions in power supply, for many years they have been using the "main principle" of building such networks, based on equipping networks with automatic sectioning points of column design - reclosers, combining the functions of:

Determination of the place of damage;

Localization of damage;

Power restoration.

findings

1. Necessary priorities:

Development of a concept and a long-term program for the development, modernization, technical re-equipment and reconstruction of 0.38–110 kV distribution electrical networks, means and systems for managing their modes, repair and maintenance;

The transition from the residual to the priority principle of allocation of financial and material resources for the phased practical implementation of this concept and program, with an understanding of the crucial importance of the advanced development of distribution networks and their management systems for the effective functioning of not only retail, but also wholesale electricity markets;

Development of a modern, market-oriented business and management, normative and methodological base for the development of distribution electrical networks and their management systems;

Development of economically justified requirements for the domestic industry for the production of modern equipment for electrical networks and their control systems;

Organization of a system of certification and admission to operation of domestic and imported equipment for distribution networks and their management systems;

Implementation and analysis of the results of the implementation of pilot projects for the development of new promising technologies and systems for automated control of distribution electric networks.

2. Development and implementation of efficient automated control systems for distribution electric networks is a complex task that requires significant capital investments.

Each distribution company and AO-energo, before starting the modernization and technical re-equipment of the existing power grid management system or creating a new one, must clearly understand the set of tasks to be solved, the expected effect of the introduction of automated control systems.

It is necessary to develop modern methods for calculating the economic efficiency of ACS PES and RES (distribution grid company), the stages of their creation and development.

3. The main question that always arises when developing and implementing new technologies for managing electric networks is where to get the money for all this?

In fact, there can be several sources of funds:

1) centralized funding of pilot projects and regulatory and methodological documents;

2) electricity tariffs;

3) consolidation of a certain part of the financial resources of future distribution grid companies and today's AO-energos in an officially established partnership - the Russian Association of Enterprises;

4) interested investors.

In Russian conditions, as the practice of advanced energy systems has shown, the principle “Who wants to solve a problem, seeks and finds ways to solve it, who does not want to, looks for reasons why a solution is impossible, or waits for others to solve it for him” should work.

As follows from the article, there are enough opportunities and ways to improve the efficiency of management of distribution networks in Russia. An understanding of the importance and an active desire to implement these opportunities in practice is necessary.

According to the Federal Law "On the Electric Power Industry", JSC FGC UES is responsible for the technological management of the Unified National Electric Grid (UNEG). At the same time, questions arose about a clear delineation of functionality between JSC SO UES, which carries out a unified dispatch control of electric power facilities, and grid companies. This led to the need to create an effective structure for the operational and technological management of the facilities of JSC FGC UES, the tasks of which include, among other things:
ensuring the reliable functioning of UNEG facilities and the fulfillment of the technological modes of operation of power transmission lines, equipment and devices of UNEG facilities specified by JSC SO UES;
ensuring the proper quality and safety of work during the operation of UNEG facilities;
creation of a unified system for training operational personnel to perform the functions of OTU;
ensuring the technological equipment and readiness of operational personnel to carry out dispatcher commands (orders) of COs and commands (confirmations) of operational personnel of the Central Control Center of FGC UES;
ensuring a reduction in the number of technological violations associated with erroneous actions of operational personnel;
in cooperation and in agreement with SO UES JSC, participation in the development and implementation of UNEG development programs in order to increase the reliability of electric power transmission, network observability and controllability, and ensure the quality of electric power;
planning activities for the repair, commissioning, modernization / reconstruction and maintenance of power transmission lines, power grid equipment and devices for the coming period;
development in accordance with the requirements of JSC "SO UES", coordination and approval in the prescribed manner of schedules for emergency limitation of the mode of consumption of electric energy and the implementation of actual actions to introduce emergency restrictions on the dispatching team (order) of JSC "SO UPS";
fulfillment of the tasks of SO UES JSC on connecting the FGC electric grid facilities and power receiving installations of electric energy consumers under the action of emergency automatics.

To fulfill the tasks set, JSC FGC UES developed and approved the concept of operational and technological management of UNEG facilities. In accordance with this concept, a four-level organizational structure is being created (with a three-level control system): the executive office, the head MES NCC, the PMES NCC and the substation operational personnel.

The following functions are distributed between the respective levels of the organizational structure:
IA FSK - information and analytical;
head NCC MES - information-analytical and non-operational;
NCC PMES - non-operational and operational;
substation personnel - operating rooms.

At the same time, non-operational functions include tasks such as monitoring and monitoring the state of the network. The adoption by the network control centers of operational functions related to the issuance of commands for the production of switching requires highly qualified operational personnel, as well as appropriate technical equipment of the NCC.

In order to increase the efficiency and reliability of the transmission and distribution of electricity and power by automating the processes of operational and technological management based on modern information technologies, grid control centers of JSC FGC UES are equipped with software and hardware complexes (STCs) that allow automating such processes as monitoring modes equipment, production of switching in strict accordance with the approved program and others. Thus, due to the automation of the OTU, the reliability of the operation of electrical networks is significantly increased, the accident rate is reduced due to the elimination of errors of operational personnel, and the number of necessary operational personnel is minimized.

It should be noted that the technical policy of JSC FGC UES for new construction and reconstruction provides for:
ensuring energy security and sustainable development of Russia;
ensuring the required indicators of the reliability of the services provided for the transmission of electricity;
ensuring the free functioning of the electricity market;
improving the efficiency of the functioning and development of the UNEG;
ensuring the safety of production personnel;
reducing the impact of the UNEG on the environment;
along with the use of new types of equipment and control systems, ensuring the preparation of the PS for operation without permanent maintenance personnel.

Currently, the schemes of primary electrical connections of existing substations are focused on equipment that requires frequent maintenance, therefore, they provide for excessive ratios of the number of switching devices and connections according to modern criteria. This is the reason for a significant number of serious technological violations due to the fault of operational personnel.

At present, automation of technological processes has been completed at 79 UNEG PSs, and another 42 PSs are under implementation. Therefore, the main scheme of organization of operation is focused primarily on the round-the-clock presence of maintenance (operational) personnel on them, controlling the state of the facility and performing operational switching.

Operational maintenance of the UNEG Substation includes:
monitoring of the UNEG condition - control of the equipment condition, analysis of the operational situation at the UNEG facilities;
organization of operational actions to localize technological violations and restore UNEG regimes;
organization of operational maintenance of substations, production of operational switching, regime and circuit support for the safe production of repair and maintenance work in electrical networks related to the UNEG;
performance by operational personnel of operational functions for the production of switching in the UNEG.

Planning and organization:
to carry out repair planning in accordance with the schedules of scheduled preventive repairs with the determination of the scope of work based on the assessment of the technical condition, using modern methods and diagnostic tools, incl. without decommissioning equipment;
conducting a comprehensive survey and technical examination of equipment that has reached its standard service life in order to extend its service life;
development of proposals for modernization, replacement of equipment, improvement of design solutions;
optimization of financing for operation, maintenance and repairs by determining the scope of repairs based on the actual state;
reduction of costs and losses;
improvement of organizational structures of management and service;
organization of vocational training, retraining and advanced training in accordance with the SOPP-1-2005 standard;
analysis of the parameters and indicators of the technical condition of equipment, buildings and structures before and after repair based on the results of diagnostics;
optimization of the emergency reserve of equipment and elements of overhead lines;
the solution of technical problems during operation and construction is issued in the form of information letters, operational instructions, circulars, technical solutions with the status of mandatory execution, orders, instructions, decisions of meetings and other management decisions.

Monitoring and management of UNEG reliability:
organization of control and analysis of equipment accidents;
assessment and control of power supply reliability;
creation of an appropriate information base.

CREATION OF FULLY AUTOMATED SUBSTATIONS
WITHOUT SERVICE PERSONNEL.
DIGITAL SUBSTATIONS

In order to exclude the dependence of the trouble-free operation of a grid company on the qualifications, training and concentration of attention of operational and relay personnel, it is advisable to spread the automation of technological processes that has been taking place for a long time - relay protection, technological automation (AR, AVR, OLTC, AOT, etc.), emergency control - on production of operational switches. For this, first of all, it is necessary to significantly increase the observability of technical parameters, to ensure control, position verification, effective operational blocking of switching devices, and automation of control actions. The power equipment used must be adapted to the latest control, protection and monitoring systems.

When introducing microprocessor devices, preference should be given to devices designed to work as part of automated systems. Stand-alone devices should be used only if there are no system analogues. In this regard, the facilities of JSC FGC UES should centrally exclude the possibility of using microprocessor devices with closed exchange protocols, devices that do not support operation in the common time standard.

The architecture and functionality of the automated process control system of a substation (APCS of the substation) as an integrator of all functional systems of the substation is determined by the level of development of technology designed to collect and process information on the substation to issue control decisions and actions. Since the beginning of the development of projects in the domestic power industry for automatic process control systems for substations, there has been a significant development of hardware and software for control systems for use in electrical substations. High-voltage digital current and voltage measuring transformers appeared; primary and secondary power grid equipment with built-in communication ports is being developed, microprocessor controllers equipped with development tools are being produced, on the basis of which it is possible to create a reliable software and hardware complex of the PS, the international standard IEC 61850 has been adopted, which regulates the presentation of data on the PS as an automation object, as well as protocols digital data exchange between microprocessor intelligent electronic devices of the substation, including monitoring and control devices, relay protection and automation (RPA), emergency automation (PA), telemechanics, electricity meters, power equipment, current and voltage measuring transformers, switching equipment, etc. .

All this creates the prerequisites for building a new generation substation - a digital substation (DSS).

This term refers to a substation using integrated digital measurement systems, relay protection, control of high-voltage equipment, optical current and voltage transformers and digital control circuits built into switching equipment, operating on a single standard information exchange protocol - IEC 61850.

The introduction of DSP technologies provides advantages over traditional PS at all stages of the implementation and operation of the facility.

Stage "Design":
simplification of the design of cable connections and systems;
data transmission without distortion over virtually unlimited distances;
reduction in the number of pieces of equipment;
unlimited number of data recipients. Distribution of information is carried out by means of Ethernet networks, which allows you to transfer data from one source to any device at the substation or outside it;
reduction of time for interconnection of individual subsystems due to a high degree of standardization;
reduction of labor intensity of metrological sections of projects;

unity of measurements. The measurements are performed with a single high-precision measuring device. Dimension recipients receive the same data from the same source. All measuring devices are included in a single clock synchronization system;
the ability to create standard solutions for objects of different topological configurations and lengths;
the possibility of preliminary modeling of the system as a whole to determine the "bottlenecks" and inconsistencies in various modes of operation;
reducing the complexity of redesigning in case of changes and additions to the project.

Stage "Construction and installation work":
reduction of the most labor-intensive and non-technological types of installation and commissioning works related to laying and testing of secondary circuits;
more thorough and comprehensive testing of the system due to the wide possibilities for creating various behavioral scenarios and their modeling in digital form;
reducing the cost of unproductive movement of personnel due to the possibility of centralized configuration and control of work parameters;
reducing the cost of the cable system. Digital secondary circuits allow multiplexing of signals, which involves the two-way transmission through one cable of a large number of signals from different devices. It is enough to lay one optical backbone cable to switchgears instead of tens or even hundreds of analog copper circuits.

Stage "Operation":
a comprehensive diagnostic system, covering not only intelligent devices, but also passive measuring transducers and their secondary circuits, allows you to quickly determine the location and cause of failures, as well as identify pre-failure conditions;
line integrity control. The digital line is constantly monitored, even if no significant information is being transmitted over it;
protection against electromagnetic interference. The use of fiber optic cables provides complete protection against electromagnetic interference in data transmission channels;
ease of maintenance and operation. Switching digital circuits is much easier than switching analog circuits;
reduction of repair time due to the wide offer on the market of devices from different manufacturers that are compatible with each other (the principle of interoperability);
transition to the event-based method of equipment maintenance due to the absolute observability of technological processes allows to reduce operating costs;
support of design (calculated) parameters and characteristics during operation requires lower costs;
the development and refinement of the automation system requires lower costs (unlimited in the number of information receivers) than with traditional approaches.

JSC FGC UES adopted the Kuzbass and Prioksky NCCs as pilot facilities for the creation of a central control center with operational functions.

The Kuzbass NCC became the first grid control center implemented as part of the program of JSC FGC UES to create a NCC with operational functions. As part of the creation of an innovative NCC to ensure continuous operational and technological control and dispatching, the center is equipped with modern software and hardware systems, a video wall is installed to display the network diagram, software is installed that allows you to fully display the state of the energy facility selected by the dispatcher on-line, receive information about outages produced repair and preventive measures up to the names of fitters working at the facility. In addition, the equipment allows NCC dispatchers to intercept control of remote objects in the event of an emergency and make a decision in the shortest possible time to reduce the recovery time for normal operation of the equipment.

The Prioksky Central Control Center was also created using the latest technologies. Among the equipment used here is a video wall for displaying information, consisting of fifty-inch projection modules and a redundant high-performance video controller, an operational information complex for monitoring the modes of the electrical network and the state of switching devices of substations, which allows the operational personnel of the NCC to monitor the operation of the equipment and control it in real time, the latest system satellite communications, uninterruptible power supply and automatic fire extinguishing systems.

Vladimir Pelymsky, Deputy Chief Engineer - Head of the Situational Analytical Center of JSC FGC UES, Vladimir Voronin, Head, Dmitry Kravets, Head of Department, Magomed Gadzhiev, Leading Expert of the Electric Regime Service of JSC FGC UES

The energy system is a single network consisting of sources of electrical energy - power plants, electrical networks, as well as substations that convert and distribute the generated electricity. To manage all the processes of production, transmission and distribution of electrical energy, there is operational dispatch control system.

May include several enterprises of different forms of ownership. Each of the electric power enterprises has a separate operational dispatch control service.

All services of individual enterprises are managed central dispatching system. Depending on the size of the power system, the central dispatching system can be divided into separate systems by regions of the country.

The power systems of neighboring countries can be switched on for parallel synchronous operation. Central dispatching system (CDS) carries out operational dispatch control of interstate electric networks, through which power flows between the energy systems of neighboring countries are carried out.

Tasks of operational dispatch control of the power system:

maintaining a balance between the amount of produced and consumed power in the energy system;

reliability of power supply to supplying enterprises from 220-750 kV main networks;

synchronous operation of power plants within the power system;

synchronism of the operation of the country's energy system with the energy systems of neighboring countries, with which there is a connection between interstate power lines.

Based on the above, it follows that the system of operational dispatch control of the energy system provides key tasks in the energy system, the implementation of which depends on the energy security of the country.

Features of the organization of the process of operational dispatch control of the power system

Organization of the process operational dispatch control (ODU) in the energy sector is carried out in such a way as to ensure the distribution of various functions over several levels. Each level is subordinate to the one above.

For example, the most initial level - operational and technical personnel, who directly carries out operations with equipment at various points in the power system, is subordinate to higher operational personnel - the dispatcher on duty of the power supply enterprise unit, to which the electrical installation is assigned. The dispatcher on duty of the unit, in turn, reports to the dispatching service of the enterprise, etc. up to the central dispatching system of the country.

The power system management process is organized in such a way as to ensure continuous monitoring and control of all components of the integrated power system.

To ensure normal operating conditions for both individual sections of the power system and the power system as a whole, special modes (schemes) are developed for each facility, which should be provided depending on the mode of operation of a particular section of the electrical network (normal, repair, emergency modes).

To ensure the fulfillment of the main tasks of the ODE in the power system, in addition to operational management, there is such a thing as operational management. All operations with equipment in a particular section of the power system are carried out at the command of higher operational personnel - this is operational management process.

Performing operations with equipment to some extent affects the operation of other objects of the power system (changes in consumed or generated power, reduced reliability of power supply, changes in voltage values). Therefore, such operations must be agreed in advance, that is, they must be carried out with the permission of the dispatcher who provides operational maintenance of these objects.

That is, the dispatcher is in charge of all equipment, sections of the electrical network, the operation mode of which may change as a result of operations on the equipment of adjacent facilities.

For example, the line connects two substations A and B, while substation B receives power from A. The line is disconnected from substation A by the operating personnel at the command of the dispatcher of this substation. But the disconnection of this line should be carried out only in agreement with the dispatcher of substation B, since this line is under his operational control.

Thus, with the help of two main categories - operational management and operational maintenance, the organization of operational dispatch control of the power system and its individual sections is carried out.

To organize the ODU process, instructions, instructions and various documentation are developed and coordinated among themselves for each individual unit in accordance with the level to which this or that operational service belongs. Each level of the ODU system has its own individual list of required documentation.

The TSF software outside the core consists of trusted applications that are used to implement security features. Note that shared libraries, including PAM modules in some cases, are used by trusted applications. However, there is no instance where the shared library itself is treated as a trusted object. Trusted commands can be grouped as follows.

• System initialization
• Identification and authentication
• Network Applications
• batch processing
• System management
• User level audit
• Cryptographic support
• Virtual machine support

The execution components of the kernel can be divided into three parts: the main kernel, kernel threads, and kernel modules, depending on how they will be executed.

• The core core includes code that is executed to provide a service, such as servicing a user system call or servicing an exception event or interrupt. Most compiled kernel code falls into this category.
• Kernel threads. To perform certain routine tasks, such as flushing disk caches or freeing up memory by swapping out unused page frames, the kernel creates internal processes or threads. Threads are scheduled just like regular processes, but they don't have a context in non-privileged mode. Kernel threads perform certain functions of the kernel C language. Kernel threads reside in kernel space, and only run in privileged mode.
• The kernel module and device driver kernel module are pieces of code that can be loaded and unloaded into and out of the kernel as needed. They extend the functionality of the kernel without the need to reboot the system. Once loaded, the kernel module object code can access other kernel code and data in the same way as statically linked kernel object code.

A device driver is a special type of kernel module that allows the kernel to access hardware connected to the system. These devices can be hard drives, monitors, or network interfaces. The driver interacts with the rest of the kernel through a specific interface that allows the kernel to deal with all devices in a generic way, regardless of their underlying implementations.

The kernel consists of logical subsystems that provide various functionality. Even though the kernel is the only executable program, the various services it provides can be separated and combined into different logical components. These components interact to provide specific functionality. The kernel consists of the following logical subsystems:

• File subsystem and I/O subsystem: This subsystem implements functions related to file system objects. Implemented functions include those that allow a process to create, maintain, interact with, and delete file system objects. These objects include regular files, directories, symbolic links, hard links, device-specific files, named pipes, and sockets.
• Process Subsystem: This subsystem implements functions related to process control and thread control. The implemented functions allow creating, scheduling, executing, and deleting processes and thread subjects.
• Memory subsystem: This subsystem implements functions related to managing system memory resources. The implemented functions include those that create and manage virtual memory, including the management of pagination algorithms and page tables.
• Network subsystem: This subsystem implements UNIX and Internet domain sockets, as well as the algorithms used to schedule network packets.
• IPC Subsystem: This subsystem implements functions related to IPC mechanisms. Implemented features include those that facilitate the controlled exchange of information between processes by allowing them to share data and synchronize their execution when interacting with a shared resource.
• Kernel Module Subsystem: This subsystem implements the infrastructure to support loadable modules. Implemented functions include loading, initializing, and unloading kernel modules.
• Linux security extensions: Linux security extensions implement various aspects of security that are provided throughout the kernel, including the framework of the Linux Security Module (LSM). The LSM framework serves as the basis for modules that allow you to implement various security policies, including SELinux. SELinux is an important logical subsystem. This subsystem implements the mandatory access control functions to achieve access between all subjects and objects.
• Device driver subsystem: This subsystem implements support for various hardware and software devices through a common, device-independent interface.
• Audit Subsystem: This subsystem implements functions related to recording security-critical events in the system. Implemented functions include those that capture each system call to record security-critical events and those that implement the collection and recording of control data.
• KVM Subsystem: This subsystem implements virtual machine life cycle maintenance. It performs statement completion, which is used for statements requiring only minor checks. For any other instruction completion, KVM invokes the user-space component of QEMU.
• Crypto API: This subsystem provides a kernel-internal cryptographic library for all kernel components. It provides cryptographic primitives for callers.

The kernel is the main part of the operating system. It interacts directly with the hardware, implements resource sharing, provides shared services for applications, and prevents applications from directly accessing hardware-dependent functions. The services provided by the kernel include:

1. Management of the execution of processes, including the operations of their creation, termination or suspension, and interprocess data exchange. They include:

• Equivalent scheduling of processes to run on the CPU.
• Separation of processes in the CPU using time-sharing mode.
• Process execution in the CPU.
• Suspend the kernel after its time quantum has elapsed.
• Allocation of kernel time to execute another process.
• Rescheduling kernel time to execute a suspended process.
• Manage process security related metadata such as UIDs, GIDs, SELinux labels, feature IDs.

2. Allocation of RAM for the executable process. This operation includes:

• Permission granted by the kernel to processes to share a portion of their address space under certain conditions; however, in doing so, the kernel protects the process's own address space from outside interference.
• If the system is low on free memory, the kernel frees memory by writing the process temporarily to second-level memory or the swap partition.
• Consistent interaction with the machine's hardware to establish a mapping of virtual addresses to physical addresses, which establishes a mapping between compiler-generated addresses and physical addresses.

3. Maintenance of the life cycle of virtual machines, which includes:

• Set limits on resources configured by the emulation application for this virtual machine.
• Running the program code of the virtual machine for execution.
• Handling the shutdown of virtual machines either by terminating the instruction or delaying the completion of the instruction to emulate user space.

4. Maintenance of the file system. It includes:

• Allocation of secondary memory for efficient storage and retrieval of user data.
• Allocation of external memory for user files.
• Utilize unused storage space.
• Organization of the file system structure (using clear structuring principles).
• Protection of user files from unauthorized access.
• Organization of controlled access of processes to peripheral devices, such as terminals, tape drives, disk drives, and network devices.
• Organization of mutual access to data for subjects and objects, providing controlled access based on the DAC policy and any other policy implemented by the loaded LSM.

The Linux kernel is a type of OS kernel that implements preemptive scheduling. In kernels that do not have this capability, execution of the kernel code continues until completion, i.e. the scheduler is not capable of rescheduling a task while it is in the kernel. In addition, kernel code is scheduled to execute cooperatively, without preemptive scheduling, and execution of this code continues until it terminates and returns to user space, or until it explicitly blocks. In preemptive kernels, it is possible to unload a task at any point, as long as the kernel is in a state in which it is safe to reschedule.

Dispatching technological control should be organized according to a hierarchical structure, providing for the distribution of technological control functions between levels, as well as strict subordination of lower levels of control to higher ones.
All supervisory technological control bodies, regardless of the form of ownership of the relevant market entity that is part of the energy system (IPS, UES), must obey the commands (instructions) of the superior technological dispatcher.
There are two categories of operational subordination:
operational management and operational management.
The operational control of the relevant dispatcher should include power equipment and controls, operations with which require coordination of the actions of subordinate dispatch personnel and coordinated performance of operations at several objects of different operational subordination.
The operational control of the dispatcher should be the power
equipment and controls, the condition and mode of which
affect the mode of operation of the corresponding power system (IPS, UES). Operations with such equipment and controls
must be carried out with the permission of the relevant dispatcher.
The current rules and regulations provide that
that all elements of the EPS (equipment, apparatus, automation devices and controls) are under the operational control and management of dispatchers and senior duty personnel at different levels of management.
The term operational control denotes the type of operational subordination, when operations with one or another EPS equipment are carried out only by order of the appropriate dispatcher (senior duty personnel) who manages this equipment. The operational control of the dispatcher is equipment, operations with which require coordination of the actions of subordinate operational personnel.
The term operational management refers to the type of operational
subordination, if operations with one or another EPS equipment
are carried out with the knowledge (by permission) of the relevant dispatcher in whose jurisdiction this equipment is located.
Operational maintenance of two levels is envisaged. Operational control of the 1st level is equipment, operations with which are carried out by agreement or with notification of a higher-level dispatcher or a dispatcher of the same level.
Level II operational control includes equipment, the condition of which or operations with which affect
mode of operation of a certain part of the electrical network. Operations with
this equipment are carried out in agreement with the higher
by the controller and notifying the concerned controllers.
Each element of the EPS can be under the operational control of the dispatcher not only of one stage, but also under the authority of several
dispatchers of one or different levels of control. The division of equipment, automation and control between the levels of the territorial hierarchy by types of management characterizes not only the distribution of management functions between the levels of the territorial hierarchy at the temporary level of operational management, but to a large extent determines the distribution of functions at other temporary levels.
Along with this, in operational management, and in some cases in the planning of regimes, it is envisaged that one of the subdivisions, on a certain range of issues, is subordinate to another, located at the same level of management. Yes, dispatcher
one of the power systems can be entrusted with the operational management of the power transmission line connecting this power system with the neighboring one. Thus, the unloading of the ODU dispatcher is organized by transferring to the energy system dispatchers some of the functions that can be performed at this level.
All EPS equipment that ensures the production and distribution of electricity is under the operational control of the duty dispatcher of the power system or the operational personnel directly subordinate to him (shift supervisors of power plants; dispatchers of electrical and thermal networks, substation duty personnel (PS), etc.). Lists of equipment in operation
management and maintenance, are approved by the chief dispatchers of the CDU
UES of Russia, ODU of UES and CDS of energy systems, respectively.


The operational control of the power system dispatcher is the main equipment, the operation of which requires
coordination of actions of the duty personnel of power enterprises (power facilities) or coordinated changes in relay protection and automation
multiple objects.
The operational management of energy facilities that play a particularly important role in the association or in the UES, as an exception, may be entrusted not to the power system dispatcher, but to the dispatcher of the ODU or CDU of the UES.
Under the operational jurisdiction of the on-duty dispatcher of the ODU are
total operating power and power reserve of power systems, power plants and high-power units, inter-system communications and objects of main networks that affect the IPS mode. In operational
control of the ODU dispatcher is transferred to the equipment, operations with
which require coordination of the actions of dispatchers on duty
power systems.
The dispatcher on duty of the CDU UES, the top operational head of the UES, is in charge of the total operating capacity and power reserve of the UES, electrical connections between the associations, as well as the most important connections within the UES and facilities, the mode of which decisively affects the mode of the UES.
In the operational management of the dispatcher of the CDU UES are the main links between the IPS and some objects of system-wide importance.
The principle of operational subordination applies not only to the main equipment and apparatus, but also to the relay protection of the relevant facilities, linear and emergency automation, means and systems for automatic control of the normal mode, as well as dispatch and technological control tools used by operational personnel.
Duty dispatchers of AO-energos, ODUs and CDUs of the UES are the top operational managers of the energy system, the association and the UES as a whole, respectively. Equipment that is under the operational control or control of the dispatcher of the corresponding link cannot be taken out of operation or in reserve, and also put into operation without the permission or instructions of the dispatcher. Orders of the administrative management of power facilities and power systems on issues within the competence of dispatchers can be carried out by operational personnel only with the permission of the operational
senior officer on duty.
The top level (CDU UES) provides round-the-clock operational management of the parallel operation of the UES and continuous regulation of the UES mode. The middle link (MDL) leads the combination mode and manages the parallel operation of power systems. The dispatching service of the power system manages the mode of the power system, ensuring the coordinated operation of all its energy facilities.
During the operation of the EPS as part of the IPS, the responsibility of the energy systems for the use of the power of power plants, ensuring the maximum available power and expanding the range of regulation is fully preserved. At the same time, the available power and adjusting capabilities are determined by the conditions for covering the loads of the IPS, taking into account the throughput of intersystem communications.
The main responsibility for maintaining the normal frequency rests with the top operating manager of the UES - dispatcher of the UES remote control. Dispatchers of the ODS and power systems ensure the maintenance of schedules of power flows between the UES and power systems set respectively by the CDU of the UES and the ODS, the implementation of instructions for changing the flows in order to maintain
normal frequency when changing the power balance. The responsibility for maintaining the frequency is also shared by the dispatchers of the ODE and power systems in terms of providing a given rotating power reserve, and in the case of automatic frequency and active power control, in terms of using automatic systems and devices involved in automatic regulation and to maintain the required control range at power plants.
The control of the mode of the main electric networks by voltage is carried out by the coordinated actions of the personnel of the corresponding stages of dispatching control. Dispatchers
CDU UES and ODU maintain voltage levels at the corresponding points of the main electrical network, determined by the instructions.
In the event of a temporary shortage of power or electricity in the UES, the duration of load or power consumption restrictions
established by the CDU UES and agreed with the management of RAO "UES of Russia"; orders to impose restrictions CDU dispatcher
Gives ODEs to controllers, and the latter to power system controllers.
The highest level of operational management (CDU UES) develops and approves the basic instructions for maintaining the regime and operational management, which are mandatory for the operational personnel of the ODU and facilities directly subordinate to the CDU. Territorial ODUs for their associations develop instructions that are in accordance with the general provisions of the instructions
CDU and employees, in turn, serve as the basis for the development of CDS local instructions that take into account the peculiarities of the structure and mode of power systems.