Volume 55, Number 10 October 2008

ISSN: 0040-601 5

THERMAL ENGINEERING

English Transl.--:ion of Teploenergetika

Editor-in-Chief Viktor I. Dobrokhotov

A Popular Scientific Journal of Original Papers on the Problems of Thermal Energy and Engineering

*P: PLEIADES PUBLISHING *

Distributed by - Springer

811

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 811–818. © Pleiades Publishing, Inc., 2008.Original Russian Text © V.V. Lysko, A.G. Sviderskii, V.A. Bilenko, A.A. Anan’ev, 2008, published in Teploenergetika.

ZAO Interavtomatika (Interautomatika AG) wasestablished in 1993 as a result of efforts undertaken byspecialists of the All-Russia Thermal Engineering Insti-tute (VTI), which were supported by RAO UnifiedEnergy Systems of Russia, Siemens, and OAO TPE. Infact, the past 15 years signaled the main stage of equip-ping Russian power stations with modern automaticcontrol systems. The time at which Interavtomatika wasdeveloped and its first projects relate to the period inwhich the first distributed microprocessor-based instru-mentation and control systems (I&CSs) emerged in theRussian market. The microprocessor process controlsystems (PCSs) that were developed at the first stagemostly replicated the previous old functions of equip-ment control. The 1990s saw experience being gainedfrom the development and operation of the first micro-processor systems, the requirements and approachesfor constructing PCSs being formulated on the basis ofthis experience, the PC market emerging, and compa-nies appearing that were able to develop and producesuch systems and put them into operation in one vol-ume or another.

The main requirement with which the modern stageof furnishing power stations with automatic controlsystems must comply is achieving better quality of theoperation of automated equipment and the work of thepersonnel in charge of its operation. This technical andeconomic challenge is considered a key issue in theactivities of Interavtomatika. The PCSs being designedmust allow the operation of equipment to be brought toa higher level; namely, the operating conditions shouldbecome more economically efficient, and reliable andbe conducted with better quality; the volumes of harm-ful emissions should be reduced; and the number oferrors committed by the operators should be mini-mized. Service maintenance of the system should beminimal in volume and guaranteed in nature. These arethe main lines, because it is only on their basis that themodern PCSs of Interavtomatika can compete withnumerous Russian and foreign systems. To meet thischallenge, Interavtomatika specialists use intercon-

nected principles and approaches, the main ones ofwhich are selecting an I&CS adequate to the automa-tion tasks, furnishing a plant with the optimal volumeof automation, conducting active marketing policy, andoffering a comprehensive scope of services.

Since the time Interavtomatika was established, itsmain area of concern has been comprehensive solutionof the problems pertinent to automation of powerindustry facilities. The range of services Interavtoma-tika offers to its customers includes the following:

(i) giving advice on automation matters;(ii) preparing technological assignment and input

data for developing PCSs;(iii) designing PCSs;(iv) carrying out integrated tests of an assembled

system at the manufacturer’s;(v) supplying self-contained equipment;(vi) supervising construction and carrying out

adjustment work;(vii) carrying out tests and commissioning work;(viii) training the customer’s personnel with the use

of full-scale computer-based training simulators; and(ix) offering maintenance services.At present, the number of PCSs Interavtomatika

specialists have commissioned (their list is given in thetable) approaches 70 and should reach 80 by the end ofthis year. Power-generating units account for the mainvolume of the plants that have been furnished withautomatic control systems (42). It should be pointed outthat, along with traditional units (31), this groupincludes almost all Russian combined-cycle plants (9),as well as the power units of the first Russian geother-mal power station and the 1000-MW unit No. 3 at theKalinin nuclear power station, the first Russian unitfully automated with the use of microprocessor controlsystems. Interavtomatika specialists were fully incharge of the entire scope of automatic control systemsfor the secondary coolant circuit in this project. It canbe seen from the table that, along with furnishing power

Main Results of the Work Accomplished at ZAO Interavtomatika for 15 Years

V. V. Lysko, A. G. Sviderskii, V. A. Bilenko, and A. A. Anan’ev

ZAO Interavtomatika, ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

Abstract

—Main results of the activities carried out by ZAO Interavtomatika in the Russian market of powerengineering are presented. Main lines of activities are described, the results of putting in use control systemsare analyzed, and prospects for their further development are presented.

DOI:

10.1134/S0040601508100017

812

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Commissioned Interavtomatika projects (as of April 2008)

Automated equipment Power station Station

numbers

Year of commis-sioning

Automated equipmen Power station Station

numbers

Year of commis-sioning

800-MW power units

Suizhong TPS (China)

12

19992000

PGU-39 Sochi TPS 1, 2 2004

Berezovo DPS 12

20012003

25-MW geother-mal power units

Mutnovsk geothermal power station

1, 2 2002

Perm DPS 21

20032006

Nuclear power sta-tions

Kalinin nuclear power station

3 2004

500-MW power unit

ReftaDPS 1097

199720062007

110-MW gas tur-bine unit

Ivanovo DPS – 2001

300-MW power units

Zmievka DPS (Ukraine)

8 2003 Sredneural’sk DPS – 2001

Aksu TPS (Kazakhstan)

43

20032006

50-MW gas turbine unit

TPS of Uralkalii – 2008

Sredneural’sk DPS

10 2003 Common-station level of unit-type TPSs

Severozapadnaya cogeneration station

– 2000

Konakovo DPS 8 2004 Mutnovsk geothermal power station

– 2002

Iriklinsk DPS 13.5

4

200420052006

Sochi TPS – 2004

Stavropol DPS 5 2005 Kaliningrad TETs-2 cogeneration station

– 2005

Ivanovo DPS – 2007Kirishi DPS 4

220052007

420 t/h steam boiler Novgorod cogenera-tion station

12

19951997

250-MW power unit

Mosenergo’s TETs-25 cogener-ation station

7 2007 500 t/h steam boil-ers

Krasnoyarsk TETs-2 cogeneration station

6 2002

200-MW power units

Surgut GRES-1 DPS

16 2003 Sakmar cogeneration station

4 2005

Shchekino DPS 12

20032004

PT-65 turbine sets Orsk cogeneration sta-tion

0 2002

Kharanorsk DPS 21

20062007

Volzhskii cogeneration station

1 2003

100-MW power units

Kostolats TPS (Serbia)

2007 Sakmar cogeneration station

2 2004

55-MW power units

Obra TPS (India) 21

20072008

R-85 turbine set Krasnoyarsk TETs-1 cogeneration station

10 2003

Gorazal TPS (Bangladesh)

1 2008 Chemical water treatment

Nizhnekamsk cogener-ation station

– 1999

PGU-450 Severozapadnaya cogeneration sta-tion of St. Peters-burg

12

20002005

Konakovo DPS – 2004

Kaliningrad TETs-2 cogenera-tion station

1 2005 Sredneural’sk DPS – 2008

Mosenergo’s TETs-27 cogener-ation station

3 2007 Condensate polish-ing plant

Syrdar’ya TPS (Uzbekistan)

7, 8 2002

PGU-325 Ivanovo DPS 1 2007 Automatic control of water chemistry

Pskov DPS 1, 2 2001

PGU-195 Dzerzhinsk cogen-eration station

– 2006 Kirishi DPS 3 2005

PGU-60S Mosenergo’s TETs-28 cogener-ation station

– 2008 FPCS for hydraulic power stations

Khaobin hydraulic power station (Viet-nam)

– 1995

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units with automatic control systems, Interavtomatikawas in charge of developing and putting into operationPCSs for the common-station level and for common-station auxiliary plants.

The majority of plants that have been automated aresituated in Russia. At the same time, a number of PCSsdeveloped at Interavtomatika have been put into opera-tion abroad Russia—in the CIS countries (Ukraine,Kazakhstan, and Uzbekistan), China, Serbia, India,Bangladesh, and Vietnam.

The above-mentioned technical and economic prob-lem is solved in Interavtomatika projects at the back-ground of rapidly rising volumes in which new gener-ating capacities are constructed in accordance withRussia’s state and industrial programs. According tothese programs, the volumes in which modern combined-cycle plants and coal-fired steam turbine plants have to becommissioned are increased considerably (several-fold).This generates a need to increase the volume of work onautomatic control systems, shorten the time taken todevelop projects, and improve their quality.

INSTRUMENTATION AND CONTROL SYSTEMS

The PCSs developed at Interavtomatika are con-structed on the basis of Siemens I&CSs. At the firststage of work, this was the TELEPERM XP-R system,which was manufactured at the Dukhov All-RussiaResearch Institute of Automation under a Siemenslicense and found wide use in Interavtomatika’sprojects. Since 2004, Interavtomatika specialists beganto use, along with TELEPERM XP-R, the SIMATICPCS7 I&C system equipped with Power Solutions, adedicated library of algorithms for power engineeringapplications. The SIMATIC PCS7 system was prima-rily used in projects for partially upgrading existingPCSs, in systems for automatically controlling the fre-quency and power (FPCS) of power units, and in someprojects for common-station plants. This I&Cs wasthen successfully used in full-scale PCSs of largepower-generating facilities, such as the combined-cycleplant at the Sochi thermal power station (TPS) and the200-MW power units at the Kharanor district powerstation (DPS). The positive experience that has beengained for many years is used in new projects devel-oped on the basis of the TELEPERM XP-R andSIMATIC PCS7 systems. And, finally, starting from2007, Interavtomatika specialists began to develop andput in operation PCSs constructed on the basis ofSPPA-T3000, the newest fourth-generation SiemensI&CSs [1]. The first successful projects of full-scalePCSs built around the SPPTA-T3000 system wereimplemented in the PGU-450 power unit and the T-250unit at Mosenergo’s TETs-27 and TETs-25 cogenera-tion stations. All these I&CSs are successive, especiallyin software, a property that allows the experiencegained from implementing technological algorithms tobe efficiently used, irrespective of the type of the I&CSused. They feature highly reliable hardware, well-

developed basic and proprietary software, computer-aided design tools, and functions for diagnosing fieldequipment. It due to insufficient reliability of domesti-cally made field equipment, such as failures of sensorsand valves, false information on the state of endswitches, and other factors that did not allow steppedprograms and other complex algorithms to be madesufficiently operable, since the operative personnel hadto constantly keep an eye on their operation. The use ofbasic software furnished with algorithms for automati-cally diagnosing the state of peripheral devices, whichwere improved at Interavtomatika taking into accountthe specific features of Russian peripheral equipmentand conditions of its operation (in particular, the way inwhich power supply is organized), allowed steppedprograms of all levels, disconnected interlocks, andother control algorithms to be used on a wide scale.

MARKETING

Automation of power stations is a market withextremely intense competition. Most competitions (ten-ders) are held with the participation of many compa-nies, including the best Russian and world-renownedforeign companies. In order to retain and strengthen thepositions of a leader in development of automatic con-trol systems for thermal power stations and to receive apotential customer’s approval for high-tech and univer-sal Interavtomatika PCSs built around the mostadvanced I&CSs, the company pays serious attention topromoting its developments and offers to the market.Efforts taken in this field include advertising and pre-sentation of Interavtomatika products at Russian andinternational exhibitions, conferences, and meetings(Electric Power Engineering of Russia, Power-Gen,and others), in industry-branch and professional jour-nals, and conducting informational work with powercompanies and power stations. Carrying out pretender-ing work, during which the state of a plant is analyzedand the concept of its automation is developed and dis-cussed with the customer, is a very important line ofactivity. Central to the marketing policy and work withpotential customers are the following weighty and seri-ous arguments:

(i) the projects are developed on the basis of Sie-mens firmware, the most advanced I&CSs superior tothe solutions offered by other competitors;

(ii) all stages of the projects are implemented withthe involvement of highly skilled specialists;

(iii) the company offers interesting proposals ade-quately meeting the requirements of customer both intechnical and economic respects and with deeply devel-oped technological and hardware contents of the PCSs;

(iv) Interavtomatika enjoys a reputation of a reliablepartner for its customers;

(v) Interavtomatika specialists have experience insuccessful cooperation with power-generating compa-nies, power stations, and strong EPC companies;

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(vi) Interavtomatika has a convincing reference listof accomplished PCSs, especially in the fields of com-bined-cycle technologies, full-scale and partial upgrad-ing of gas-and-oil-fired and coal-fired power units, sys-tems for automatically controlling frequency andpower of traditional and combined-cycle power units,and microprocessor control and protection systems forsteam turbines, gas turbines, and other plants;

(vii) quality management and environment protec-tion system according to ISO 9001 and ISO14001 havesuccessfully been in operation at Interavtomatika since2000;

(viii) Interavtomatika specialists work in close con-tact with specialists of power stations during all stagesof a project in such a way that the customer’s requestsbe maximally satisfied;

(ix) Interavtomatika involves its permanent (strate-gic) partners in carrying out individual stages of work,such as manufacture of equipment, development of aproject, procurement of auxiliary equipment and elec-trical connections, assembling, and adjustment; and

(xii) the company organizes comprehensive trainingof the customers' specialists both at its office and at thepower station site in the course of PCS adjustment andtests; training simulators are used for carrying out train-ing courses in some projects.

AUTOMATION OF COMBINED-CYCLE PLANTS

It is not a coincidence that Interavtomatika wasestablished at the same time as the development ofwork on designing the Severozapadnaya cogenerationstation in St. Petersburg, Russian power engineering’s firststation equipped with a heat-recovery type PGU-450combined-cycle power plant (CCPP) built aroundV.94.2 Siemens gas turbines (GTs), since such equip-ment needs to be furnished with an PCS built around ahighly reliable and functionally developed I&CS forbeing properly controlled. It should be noted that quitea long period of time passed since the time this I&CSwas developed, manufactured and tested for theSeverozapadnaya cogeneration station (from 1994 to1997) to the time the first power unit was commis-sioned in 2000. Nonetheless, the work accomplished atthat time made it possible to elaborate fundamentalsolutions for automating this sort of equipment thatwere employed to some extent or another in the PCSsthat were quite successfully put in operation in theperiod 2005–2007 for a series of similar power units,among which were the PGU-450 units at the Severoza-padnaya cogeneration station (Unit 2), KaliningradTETs-2 cogeneration station, and Mosenergo’s TETs-27cogeneration station; the PGU-325 unit at the Ivanovodistrict power station (DPS) (this one on the basis of theRussian GTE-110 gas turbine of NPO Saturn), as wellas the PCS for a smaller combined-cycle plant (PGU-39)at the Sochi thermal power station (TPS) that was com-missioned in 2004–2005. Interavtomatika specialists

developed and commissioned the PCSs for all theseCCPPs and for all power stations at which they wereinstalled.

The list of distinctive features of heat-recovery typeCCPPs equipped with two gas turbines and one steamturbine as controlled objects and the PCSs used to con-trol them includes the following:

(i) the process of starting and initially loading a gasturbine, as well as all operations on other technologicalequipment of the CCPP related to this process have tobe fully automated;

(ii) the static operating modes of the power unit arefairly diverse (with one or two GTs and, in case of usinga certain configuration of a cogeneration plant, alsowithout the steam turbine), and, accordingly, so are thedynamic conditions when a transition is made from onemode to another, and such transient conditions need tobe highly automated;

(iii) the system must be designed so that healthyCCPP turbines could be left in operation when one ofthem is shut down in an emergency manner;

(iv) the control of level in the drums of heat recoveryboilers involves certain difficulties when the GTs arestarted and when the GTs and ST are shut down in anemergency manner;

(v) the number of electrical equipment that has to beautomated is much greater than that in case of tradi-tional power units (three generators instead of one);common solutions have to be used for controlling heat-generating, mechanical, and electrical equipment; andefficient exchange of information in digital form has tobe organized with the workstations of the power stationshift supervisor and the shift supervisor for electricalequipment at the central control board; and

(vi) the process control system must be designed sothat one process operator could control the entireCCPP; hence, identical operator interfaces must be fur-nished for all CCPP equipment taking into account thatthe gas turbines and the steam turbine may come withtheir local PCSs (partially or fully functional) builtaround the devices adopted at their manufacturingplants.

All these factors had a considerable effect on theway in which technical solutions for developing thePCSs for CCPPs and for the common-station level weredeveloped. One of these solutions is the integration oflocal turbine control systems into a unit-level PCS. Forexample, whereas the PGU-450 unit at the Severoza-padnaya cogeneration station was furnished, in accor-dance with the solutions that existed in the early 1990s,with dedicated controllers for the electrical part of thecontrol and protection system of gas turbines (EPCP)and the electrical part of control system (EPCS) ofsteam turbine that differed considerably from the I&CSof the power unit PCS, the controllers for the GT pro-tections and for the EPCS of the steam turbine in thePGU-450 power unit at the Kaliningrad TETs-2 cogen-eration station were constructed using the same

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TELEPERM XP-R (TPTS-51) I&CS as that for themain PCS. All local systems for controlling the GTsand STs in the PGU-325 and PGU-450 power units atthe Ivanovo DPS and Mosenergo’s TETs-27 cogenera-tion station have been constructed using the same I&CSas that for the unit-level PCS: TEPEPERM XP-R forthe Ivanovo DPS and SPPA-T3000 for TETs-27.Microprocessor systems have also been used for thesetwo CCPPs instead of the hydraulic turbine speed gov-ernors that were employed in earlier projects.

As an example, the figure shows the function dia-gram of the PCS for the PGU-450 unit No. 3 at Mosen-ergo’s TETs-27 cogeneration station constructed on thebasis of the SPPA-T3000 I&CS [1]. The controller levelof this PCS has been constructed in accordance with theprinciple of functional groups and comprises the fol-lowing automation servers:

(i) unit-level servers supplied as part of the powerunit’s PCSs (for the gas turbines GT1 and GT2, heat-recovery boilers HRB1 and HRB2, steam turbine ST,common-unit steam–water path equipment, and unit-level electrical equipment);

(ii) servers for the EPCPs of GTs and the EPCS ofST, which are supplied complete with the gas turbinesand steam turbine; and

(iii) servers for the common-station heat-generatingand mechanical equipment related to this power unit(the circulation pumpstation, liquid-fuel facility, etc.).

All SIMATIC S7-417 automation servers are redun-dant. The controllers used in the EPCPs of GTs and theEPCS of ST are connected not only to the usual controland interfacing modules (CIMs), but also to the high-speed FM-458 modules, together with their dedicatedAddFEM CIMs.

The application server of T3000 is a web server andsupports the workstations of operative and maintenancepersonnel (operators, shift supervisors, and PCS engi-neers). Communication to the power station PCS isorganized through the Firewall internetwork screen. Inaddition, the power-unit PCS interacts with the PCSsfor electrical equipment: relay protections, common-station level, etc.

AUTOMATION OF POWER UNITS EQUIPPED WITH COAL-FIRED BOILERS

One of the most important problems that remainedunresolved in Russian power engineering for a longtime was automation of large 500- and 800-MW powerunits with once-through coal-fired boilers furnishedwith direct-injection coal-dust systems. The main diffi-culties were encountered in controlling the fuel supplyand combustion process. The full-scale PCS for the500-MW power unit (No. 10) at the Refta DPS com-missioned in 1997 was the first project of this sort forInteravtomatika. Special mention should be maderegarding the level Interavtomatika specialists suc-

MCR of Unit 3

Workstations existing at the cogeneration station

Workstation (WS) of power

Freeassignment

Information to the enterprise

WS of electricWS of PCS

WS of boiler-turbineMCR

Automati

Application server of T3000 GPS Clock

To

the

APC

S of

ele

ctri

cal e

quip

men

t

ECU

PMCS of ST

STHRB2HRB1 GT2

PMCS of GTPMCS of GT

GT1

ControlCommon-station

ST control

GT1

computer-aided management system

of functionsfor displays

unit operatordepartment

shift supervisorof Unitdepartment

shift supervisor

FIREWALL

engineerWS of PCS

engineerWS of PCS

engineer

on serverAutomation server

Automation server

Automation server

Automation server

Automation server

Steam–water

generator

and protections

generator

Automation server

Automation server

Automation server

heat-transferand mechanical equipment

GT2

Web/OPC-clients

Internet(ICP/IP) 100Mb/s

Internet(ICP/IP) 100Mb/s

AddFEMAddFEM

Function diagram of the PCS for Unit 3 at Mosenergo’s TETs-27 cogeneration station.

generator

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ceeded to achieve in this project [2] in automating theoperations that have to be carried out not only in theload working range, but also in starting modes. Thislevel was well above those existed in Russian powerunits and corresponded to that found in similar foreignequipment. In particular, the extent to which the start-ing modes were automated made it possible to relievethe operating personnel from doing the most importantand complex control tasks. The scope of automationincluded not only making more than 150 controllers ofthe power unit fully operable, but putting in operationmore than 80 logic programs, including around 40stepped ones. The key problem of automating the com-bustion process was solved [3] by constructing multiplyconnected control systems (CSs) for each dust system,a multiply connected CS for the total fuel flowrate andfor the feeding unit with multiloop cascade temperaturecontrol, systems for automatically taking into accountautomatic control disabling state for each dust systemand for the entire supply of fuel, and stepped programsfor starting and shutting down the dust systems. Mostof the above solutions were novel and were used inpractice for the first time.

In the subsequent, the proposed solutions wereimplemented, taking into account the specific featuresof the equipment being automated, within the scope offull-scale PCSs in the 800-MW power units at theSuizhong TPS in China (Units 1 and 2) and the Bere-zovo DPS (Units nos. 1 and 2), 300-MW units at theAksu TPS in Kazakhstan (Units 3 and 4), and 200-MWunits at the Kharanor DPS (Units 1 and 2). In recentyears, such solutions have been implemented in theinformational and control system in the remaining 500-MW power units at the Refta DPS.

The facilities mentioned above are equipped withdifferent types of direct injection systems: the ReftaDPS and the Aksu TPS are furnished with hammermills; the Suizhong TPS, with medium-speed mills; andthe Berezovo and Kharanor DPSs, with pulverizing fans.

The results obtained from putting FPCSs in opera-tion in the power units at the Berezovo, Refta, and Kha-ranor DPSs and from testing them for conformity withthe requirements of common primary regulation of fre-quency have shown the following. If power unitsequipped with coal-fired boilers are furnished with theproposed fuel-supply CS and with an FPCS constructedin accordance with appropriate solutions, the dynamiccharacteristics of such units differ only slightly fromthese of power units of the same capacity equipped withgas-and-oil-fired boilers [4].

THE FREQUENCY AND POWER CONTROL SYSTEM. CONTROL OF TURBINES

Projects for FPCSs have recently made up a consid-erable volume of work carried out at Interavtomatika.The need for carrying out activities in this field hasstemmed from the new requirements power stations

must comply with for participating in the market of sys-tem services for selling electric energy with requiredquality under normal and emergency conditions ofpower system operation. The appropriate norms weredeveloped on the orders of RAO Unified Energy Sys-tems of Russia and in the Standard of the System Oper-ator – Centralized Dispatching Administration (SO–CDA),documents determining the quality of power unit char-acteristics and conditions under which they have to par-ticipate in selective primary and automatic secondarycontrol of frequency (SPFC and ASFC). Interavtoma-tika specialists have carried out the correspondingprojects in 11 gas-and-oil-fired power units at the Perm,Iriklinsk, Konakovo, Kirishi, and Stavropol DPSs; cer-tificates of conformance with the requirements of theSO–CDA Standard have now been received for nine ofthem [4]. Systems for common primary control of fre-quency have been implemented in some projects forFPCSs, primarily those for coal-fired power units andCCPPs.

The development and implementation of theseprojects became an important stage of Interavtomatikaactivities. Not only did these projects allow Interav-tomatika to become a leader in the number of FPCSprojects and variety of power unit types, but they alsogenerated the need to develop many new technical solu-tions. These projects incorporated solutions for opti-mizing the circuits of devices for controlling the powerunit output under normal and emergency operating con-ditions. Among the devices that were included in thesecircuits were an automatic emergency power unitunloading system, an automatic emergency control sys-tem, systems for taking automatic control disablingstate into account, the necessary scope of automaticcontrollers for the boiler, and systems for automaticallycontrolling the burners. An important feature of unit-level FPCSs is that they are incorporated in a common-station power control system, one version of which hasbeen implemented at the Iriklinsk DPS.

Microprocessor electrohydraulic steam turbine con-trol systems, which were developed for the main typesof turbines in all I&CSs used at Interavtomatika is anecessary component for solving the tasks of SPFC [5].It is only these turbine control systems that make it pos-sible to obtain the characteristics required in accor-dance with the SO–CDA Standard, including the deadband (

±

10 mHz), high power output variation rate, andmaintaining the turbine power output with an accuracyof

±

1% of the rated power in response to frequencydeviations.

The development of an PCS for the GTE-110 gasturbine unit of NPO Saturn [6] intended for being usedas part of PGU-325, PGU-170, and power units of othercapacities, as well as part of GTU-based cogenerationstations, also belongs to this field. This project incorpo-rated for the first time new high-speed modules on thebasis of domestically made XP-R facilities, devicesdeveloped in accordance with Interavtomatika’s assign-

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ment and with participation of Interavtomatika special-ists for constructing rotation frequency controllers, gasturbine temperature and power output controllers, andautomatic emergency control systems. The use of newalgorithms for closed-loop control, logic control, andstepped programs made it possible to achieve reliableoperation of the GTE-110 unit at all loads during itsoperation both independently at the GTE-110 test rigand as part of the PGU-325 unit at the Ivanovo DPS.The characteristics of this FPCS are in line with allmodern requirements.

An electronic turbine overspeed protection system,which has been implemented in units nos. 1–3 at thePerm DPS and unit No. 5 at the Stavropol DPS, becameanother line of development of microprocessor-basedturbine control systems.

UPGRADING PCSS

In parallel with construction of new power plants,activities for upgrading the equipment of existingpower stations are being conducted on a growing scale.Upgrading PCSs is an important part of Interavtoma-tika’s activities that generates the need of using specialapproaches for formulating the problem. A fundamen-tally important principle of upgrading is that the previ-ous PCS functions should not be retained but extendedin such a way that the equipment being automatedattains new qualities, such as:

(i) the equipment becomes able to meet the newrequirements of regulatory documents and standards; inparticular, it becomes able to solve power system tasks;

(ii) better environmental characteristics areobtained;

(iii) possibilities for extending the service life andincreasing intervals of time between overhauls areobtained;

(vi) the failures and outages caused by malfunctionsin the PCS operation and personnel errors becomefewer in number; and

(v) smaller costs have to be spent for PCS operationand repairs.

When implemented in full scope, such an approachresults actually in that the existing PCS is upgraded ona full scale with complete replacement of its equipment(without taking field devices into account). If a cus-tomer has limited resources in terms of money andtime, partial upgrading is possible as a forced solutiondue to insufficient money and time and the need tourgently install and put into operation a system forautomatically controlling frequency and power, aburner control system, etc. To select the optimal solu-tion, the technical state of monitoring and control facil-ities, including peripheral ones, has to be carefully ana-lyzed, an approach that makes it possible to determinethe justified volume in which the existing equipmenthas to be retained in the course of upgrading.

Among the typical problems that have to be solvedin the course of partial upgrading in power engineeringapplications is fulfilling the requirements of regulatorydocuments, standards, and orders of supervisoryauthorities. These include fulfilling the requirementsfor common or selective primary and automatic sec-ondary control of the frequency in power units, retrofit-ting a burner control system taking into account theexplosion and fire safety requirements, obeying thecontrols for reducing harmful emissions into the envi-ronment, and others. These activities can frequently beregarded as the first stage of the subsequent full-scaleupgrading of the PCS. If this is the case, the approachthat has to be taken from the very beginning of thedesign process should result in a minimal expenditureof money and time for the subsequent extension of thePCS to full scope. For example, Interavtomatikaapplied a staged upgrading approach for the 200-MWpower units at the Kharanor DPS.

Interavtomatika specialists have gained rich experi-ence with both full-scale and partial upgrading in coal-fired and gas-and-oil-fired power units of differentcapacities. These activities constituted the main volumeof work for a long period of time, because new powerfacilities were constructed in a very limited volume.Different versions of technical and organizational solu-tions that were taken in PCS upgrading projects aredescribed in some papers of this issue.

TRAINING SIMULATORS

Such well-known circumstances as complexity oftechnological processes at a modern power station,especially in combined-cycle plants; shortage of skilledpersonnel; and the introduction of microprocessor-based PCSs incorporating a considerably larger scopeof automation functions and implying an entirely newprinciple for the operation of personnel via displays andnew functions for control of power installations havegenerated the need of using new-generation trainingsimulators in the education process. Such training sim-ulators must be full-scale in nature; that is, they must beable to simulate the technological process, control algo-rithms, and the dynamic performance of the I&CS andPCS peripheral equipment with maximum accuracyand fully replicate the man–machine interface, i.e., theworkplaces of power unit operators. Interavtomatikaspecialists, working together with Eniko TSO Co., havedeveloped training simulators of this sort for the com-bined-cycle power plants at the Sochi TPS and thePGU-450 unit at Mosenergo’s TETs-27 cogenerationstation [7]. The experience gained from putting theminto use and bringing them to a state of industry stan-dard has shown that these simulators have an importantadditional function: they can be used for testing andcorrecting algorithms of closed-loop and logic controlat the stages during which the PCS is designed andadjusted, a feature especially important when PCSs forplants with new technologies are developed. It is

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exactly the use of the training simulator at Mosenergo’sTETs-27 cogeneration station that made it possible tocheck and optimize some algorithms and correct tuningparameters, after which less effort had to be taken toadjust the corresponding controllers and logic pro-grams on the field equipment.

REFERENCES

1. A. G. Sviderskii and Kh. Kharpel’, “New TechnicalFacilities for Equipping Power Industry Plants Facilitieswith Automatic Control Systems,” Teploenergetika,No. 10, 9–13 (2008) [Therm. Eng., No. 10 (2008)].

2. L. L. Grekhov, V. A. Bilenko, N. N. Derkach, et al., “TheAutomatic Process Control System for the 500-MWPower Unit at the Reftinsk District Power Station,” Elektr.Stn., No. 5, 61–68 (2002).

3. V. A. Bilenko, N. N. Derkach, E. E. Mikushevich, andD. Yu. Nikol’skii, “Development and Commissioning ofSystems for Regulating the Main Parameters of a Boilerwithin the Scope of the Process Control System of the500-MW Power Unit at the Reftinsk District Power Sta-

tion,” Teploenergetika, No. 10, 2–9 (1999) [Therm. Eng.,No. 10 (1999)].

4. V. A. Bilenko, A. D. Melamed, E. E. Mikushevich, et al.,“Development and Application of Automatic Frequencyand Power Control Systems for Large Power Units,”Teploenergetika, No. 10, 13–26 (2008) [Therm. Eng.,No. 10 (2008)].

5. I. Z. Chernomzav and K. A. Nefedov, “Improvement ofAutomatic Control Systems for Large-Capacity SteamTurbines,” Teploenergetika, No. 10, 27–33 (2008)[Therm. Eng., No. 10 (2008)].

6. I. Z. Chernomzav, D. A. Zhezherya, R. V. Mukharrya-mov, and A. A. Perezhogina, “The System for Automat-ically Controlling the Processes in a GTE-110, Russia’sFirst High-Temperature Large-Capacity Gas Turbine,”Teploenergetika, No. 10, 61–68 (2008) [Therm. Eng.,No. 10 (2008)].

7. K. A. Molchanov, V. P. Strashnykh, D. A. Zhezherya, andO. A. Manevskaya, “A Full-Scale Training Simulator forEducating the Operative Personnel of the PGU-450 Unitat OAO Mosenergo’s Cogeneration Station TETs-27,”Teploenergetika, No. 10, 69–76 (2008) [Therm. Eng.,No. 10 (2008)].

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ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 819–823. © Pleiades Publishing, Inc., 2008.Original Russian Text © A.G. Sviderskii, H. Herpel, 2008, published in Teploenergetika.

The applications of control systems that exist inpower engineering place a wide range of requirementson the speed of response, reliability, availability, theway in which the operator interface should be orga-nized, and the operating conditions and user functions,such as efficiency of application, scope of functions,simplicity of maintenance, and availability of service.All these factors determine, in turn, the requirementsfor instrumentation and control systems (I&CSs) andare reflected in guiding departmental documents. Inparticular, it should be pointed out that, in view of thelevel that has been achieved in the development of auto-mation facilities and experience gained with usingthem, the industry-branch requirements for I&CSs,specifically, the regulations published in 2002, need tobe revised and refined.

The experience Siemens Corp. has gained on theworld’s market, as well as the experience Interavtoma-tika has gained in development and commissioning ofprocess control systems (PCSs) in Russia, shows thatthe use of I&CSs thoughtfully constructed in terms oftheir hardware and software content allow a truly tangi-ble effect to be obtained from automation.

Modern I&CSs have capacities using which a reli-ably and efficiently operating system can be con-structed within a very short period of time, a factorextremely important for solving retrofitting matters.The shorter period of time required for constructing asystem is obtained due to the fact that well-elaboratedsolutions are used on the basis of I&CSs, which are ini-tially developed as a system; that powerful multiusertools for development and commissioning are avail-able; and that the equipment passes comprehensive pre-supply checking. The systems built around SiemensI&CS and used at Interavtomatika meet all theserequirements.

The Siemens microprocessor control facilities havepassed in their development a path from very simpleones to integrated distributed systems with wide possi-bilities of implementation, the so-called IT solutions.

At present, Interavtomatika’s fleet comprises three sys-tems: TELEPERM XP-R, PCS7, and SPPA T3000.*

We will not consider the TELEPERM and PCS7here, since many papers have been published on them,e.g., [1]. It should only be pointed out that these are“living” systems, using which various automationprojects are being developed and will be developed inthe future. These systems feature functional complete-ness, reliability, and other important features; therefore,they have their supporters and, undoubtedly, deserveattention.

The SPPA-T3000, a new I&CS that emerged on theworld market and, which is a remarkable fact, on theRussian market in 2005–2006, is the latest developmentof Siemens in the field of facilities for automation ofpower stations. In terms of its architecture, the SPPA-T3000 system is part of the last, fourth generation ofI&CSs [2].

First-generation systems emerged at power stationsin the 1960s. These were the so-called control comput-ers, which were used primarily at nuclear power sta-tions. With the advent of microprocessors, these sys-tems were augmented with programmed logic control-lers (PLC).

Second-generation I&CSs, which came in the1980s, were related to the development of local areanetworks, using which it became possible to combinestandalone controllers into a unified system and createpowerful operator interface facilities, unified designtools, and the like. The era of such systems has notpassed, and the absolute majority of I&CSs available inthe market are representatives of exactly this genera-tion. Systems with client–server architecture can beconsidered the upper point in the development of sec-ond-generation systems.

* TELEPERM, PCS7, and SPPA-T3000 are trademarks of Sie-mens.

New Technical Facilities for Equipping Power Industry Plants with Automatic Control Systems

A. G. Sviderskii

a

and H. Herpel

b

a

ZAO Interavtomatika, ul. Avtozavodskaya, 14/23, Moscow, 115280 Russia

b

Siemens PGL, Frauenauracher str. 85, Erlangen, 910053 Germany

Abstract

—The specific features of SPPA-T3000, a new instrumentation and control system intended for auto-mation of processes in power engineering, are briefly described. Distinctive features of the system architecture,central to which is using the model of web systems, are singled out.

DOI:

10.1134/S0040601508100029

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The next, third-generation systems are so-calledWeb-enabled systems, i.e., those extended with Webcapabilities. These are usually systems with client–server architecture, in which a Web server plays the roleof one of their clients; a component that allows the PCSto be extended through the use of Web clients primarilyfor creating additional workplaces for operating ormaintenance personnel. TELEPERM XP-R and PCS7are examples of Web-enabled I&CSs.

Fourth-generation systems encompass Web-basedsystems, the essence of which consists in that Internet orweb technology with its three-level model (data presenta-tion, data processing, and data acquisition levels) are thebasis or kernel of the system rather than its topping.

There are also other approaches for categorizingsystems into development stages; however, it is exactlythis division that allows one to get an idea of what thenovelty and advantages of a new system are. Is shouldbe pointed out that the new system has emerged as aresult of the development of automation systems, oftheir being aimed at a concrete field of application (inour case, power stations), and very rapid developmentof network data transmission technologies, IT solu-tions, the Internet, media applications, and the like. TheSPPA-T3000 system can be considered the quintes-sence of the state of the art in informational technolo-gies in their application for automation of technologicalprocesses.

In accordance with a three-level (three-tier) model,the SPPA-T3000 system has a data presentation level(the client tier), a data processing level (the tier ofapplication algorithms and data processing), and a datalevel (the tier of data sources).

The data presentation level (the client tier) is con-structed using so-called thin clients. The scope ofrequirements imposed on these devices includes, alongwith the possibilities of network data exchange via theTCP/IP protocol, the availability of an Internet browserthat supports execution of Java applets (applications ofa virtual Java machine). Such a Web terminal can beconstructed on a variety of platforms; in particular, aPDA device can serve as such terminal. No other soft-ware is installed in clients and is not required. Every-thing that is required for the user in accordance with itsstatus and tasks (e.g., for the operator, engineer, job set-ter, etc.) is loaded from the server of applications. Suchan approach for constructing the level of workstationsfor operators, engineers, and technicians allows lessstringent demand to be placed on the technical facilitiesused in the system and allows it to be easily integratedin the existing infrastructure of the customer.

The processing level (the tier of application algo-rithms and data processing) incorporates two types ofdevices: an application server and an automation server.

An application server may come in different ver-sions: first of all, it comes in a fail-safe makeup, accord-ing to which a unified series-produced device com-prises components (processors, memory, I/O devices,

etc.) with redundancy at the hardware level. Suchdevices have an availability factor of not less than99.999%.

A nonredundant server can also be used, as well asa server with so-called distributed redundancy. Thebasic idea behind such a server consists in using twoservers with full mutual redundancy. Application serv-ers can be multiplied; i.e., one system can be furnishedwith several devices performing different applicationfunctions. However, even in this case, the end user willsee the entire pool of application servers as a single vir-tual space.

SIMATIC S7-400 controllers are used as automa-tion servers. The automation servers perform real-timetasks, which can comprise both those for very fast pro-cesses, e.g., turbine control processes with digital posi-tioning of valves, and for relatively slow processes,e.g., control of temperature, operations for automati-cally starting and heating elements, etc.

Fail-safe industrial ethernet networks connect thetiers and elements with one another. At present, suchnetworks are in fact used as a standard solution for themajority if systems, and industrial hardware for them iscommercially available from different manufacturers.The SPPA-T3000 system uses networks with a datatransmission rate of up to 1 Gb/s and different types ofcarriers (fiber-optic lines, copper wire lines, and radiochannels). Internetwork shields are applied in net-works, devices using which different safety policies canbe organized when the SPPA-T3000 is integrated intothe data networks of a power station, connections to thesystems of other suppliers can be established, etc.

The level (tier) of data comprises all data input–out-put devices, also called interfacing devices (IDs). Theseinclude both the IDs from the standard set of SIMATICmodules and smart IDs with built-in capacities of inde-pendent data processing, e.g., for emergency drive con-trol applications and other similar tasks, and facilitiesfor fast (in less than 5 ms) data processing, which arerequired, in particular, for implementing turbine con-trol algorithms.

Smart field devices, such as SIPOS 5, AUMATIC,DREHMO, and I-MATIC drives; SITRANS PDS IIItransducers; etc., can be used as data sources or datausers. Communication with IDs and other devices isarranged using the PROFIBUS DP and PA buses.

The system is open for interaction with external sys-tems: data exchange can be performed in accordancewith such protocols as OPC (a client and a server),Modbus, IEC 61850, IEC 60370-5-101(4), andDNP3.0. The latter ones allow both an PCS for heat-generating and mechanical equipment and an PCS forelectrical equipment to be integrated into a united sys-tem. The IEC 61850 protocol, the latest development inthe field of automation systems for substations con-structed on the basis of ethernet technology, makes itpossible to use the terminals of microprocessor protec-tions, cell control devices, and SIPROTEC 4 line string

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synchronizers of Siemens or other manufacturers support-ing the IEC 61850 protocol at the level of smart datasources within the framework of the T3000 system.

A CM104 automation server is used for settlingmatters of data exchange and communication withexternal systems at the data processing level.

The SPPA-T3000 incorporates facilities usingwhich devices at all hierarchical levels can be maderedundant, including automation servers, networks,IDs, etc. Another important aspect of SPPA-T3000 isthat it has built-in facilities for constructing fail-safe (F)systems and fail-safe systems with high availability(FH), which are a version of F systems with simplifiedredundancy. These systems conform to the require-ments of the IEC 61508 standard, classes from SIL1 toSIL3; DIN V19250/DIN VDE 0801, classes from AK1to AK6, and others. An appropriate certificate fromRussian supervisory authorities is available.

Thus, even such a brief review of technical facilitiesavailable in SPPA-T3000 or those that can be integratedinto it in a standard manner allows us to conclude thatthe SPPA-T3000 system has sufficient capacities forsettling all maters related to automation of a power sta-tion, including both heat-generating-and-mechanicalequipment and electrical equipment.

It can be said with confidence that the fundamentaldifference between SPPA-T3000 and other systems isin the field of software. The architecture and the way inwhich data are presented are such that the user (devel-oper, operator, job setter, and maintenance personnel)can interact with the system in an understandable lan-guage that can be easily adjusted by individual users.This interaction is arranged though a web browser. Itshould be noted that different users in charge of solvingvery different tasks may work simultaneously and inparallel. All these users interact with the same subject,i.e., the PCS, and work with the same information, butthey have different views on this subject and interpretthis information in different ways.

The SPPA-T3000 system has been designed just insuch a way that any user obtains the picture of the sys-tem he or she wants to have. For example, the job setterwho adjusts a controller needs a function diagram, thevalues of parameters, a graph, etc., as well as the possi-bility of changing the function diagram online, switch-ing it into operation, analyzing the result, returning toprevious versions, and so on. All these possibilities areavailable for SPPA-T3000 users in accordance with thesystem of passwords and rights. Moreover, users cancreate their own views (either temporary or permanent)most consistent with the nature of their activities.

Since the system is united and indivisible and alldata, such as current values of variables, propertiesassigned for them, projects, archiving results, etc., existin the system only once, discrepancy between or loss ofdata cannot occur in principle.

The system has been developed using the Java pro-gramming language. The system uses HTML as a stan-

dard format of all documents, XML as a data exchangeformat, and HTTP as a means for data transmission.These features make the system independent on theplatform.

Thin clients form the basis on which the Internetbrowser and the virtual Java machine operate. When aclient is connected to the application server (its Webpart), the required Java applications (computer pro-grams) are downloaded into the client, and the virtualJava machine, which, in turn, interacts with the thin cli-ent’s original operating system, runs them.

When one user or another generates his or her viewon the system, the required HTML page is called in thethin client; the required Java applets are started for exe-cution; the plug-ins are activated; and the appropriateservlet is raised on the application server. In otherwords, the typical Web client to Web server interactionprocedure is fully implemented. First, such an approachresults in a lower cost of operator interface facilitiesand other workstations. Second, maintenance, replace-ments, and modifications of this system level becomemuch simpler. And, third, the boundaries of the systembecome wider: if a system is furnished with internet-work shields and protected (virtual private network)channels, it is in principle possible to access it from anypoint from around the world; hence, it becomes possi-ble to maintain and support the system remotely andtransmit any required information to upper manage-ment levels, such as the automated enterprise manage-ment system of a power station, power company, etc.

The distinctive feature of SPPA-T3000 and, prima-rily, the software used at the data processing level(application and automation servers) is that all the nec-essary subsystems are united into a single software sys-tem. For example, all currently existing I&CSs, includ-ing preceding-generation systems of Siemens, have dif-ferent functional parts developed using differenttechnologies (Fig. 1).

The system incorporates an individual engineeringworkstation, archive station, controllers, operators'workstations, etc. All these components usually havetheir own software, which is sometimes constructed ondifferent platforms. These subsystems are connected toone another to arrange their joint operation: data, com-pilation results, etc. are exchanged between the soft-ware components.

If we take any system constructed using relativelyindependent components, even the most advanced one,discrepancy and inconsistency may occur between thedata in different software subsystems, and problemswith maintenance and follow-up of such systems arise.

As to SPPA-T3000, all software and hardware com-ponents have already built into the system (Fig. 2).There are no components outside the system, outsidethe unified informational field, or outside the unified prin-ciples for interaction among the components inside thesystem. This idea, known as embedded component ser-

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vices (ECS

®

), is the foundation stone of the entire archi-tecture of SPPA-T3000 and its data processing level.

The software of this level (see Fig. 2) has been con-structed using Java, XML, and HTTP and consists,leaving aside minor details, of servlet services servingthe data presentation level, e.g., the servlets of operatorinterface, engineering, logs, and the like. These ser-vices interact with the system of containers that have a

unified structure and charged with ensuring differentproperties of SPPA-T3000. All these containers are inter-connected, like cells, with one another and with services,in a standard way via the unified space of objects.

The design container is the basis on which the sys-tem is described. It serves to store and organize thestructure of the project, the topology of technical facil-ities, video frames, functional diagrams, and all docu-

Web client

Classic I&CSs

Workstations

Web

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Archives

Data

Diagnostics Engineering

Processing level

Presentation level

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All components are integrated into a single system

Data level

Data

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Systemsoftware

Systemsoftware

Systemsoftware

Systemsoftware

station

Data Data Data Data

SPPA-T3000

I&CSs

Application

Unified software

or any applications

and automationservers

for all applications

Fig. 1.

Structures from the set of components and with built-in components.

SoftwareHardware

Data presentation level

Video frame,

Web

Bra

user

App

lica

tion

ser

ver

automation serverapplication server

Data processing level

Data level

Data from IDs

Design containerReal-time container

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of lo

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Fig. 2.

System architecture.

BT container(Real-time)

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ments. This container is in charge for constantly saving,tracing changes (revisions), and summing up the cur-rent state of the results from engineering activities.

It should be pointed out that the notions “compila-tion” and “downloading” do not exist in SPPA-T3000in the sense usually understood for third-generationI&CSs. In fact, neither is in SPPA-T3000. The softwareis constructed in such a way that any changes that arecarried out in the system and that can in principle bedone to it exclusively through engineering view of dataat the workplaces of the appropriate personnel may beas if confirmed, i.e. saved simultaneously in the designcontainer and in the real-time container. It should benoted that such changes have not come in force yet butare ready for this. It is possible to return to the preced-ing state. It is only when the “Activation” command isissued that the changes in the real-time container comeinto force and are executed in the next cycle of processing.

However, even these changes that have come intoforce are not yet final. Even in this state the user cantake a step back; only after the “Acknowledge (Accept)Changes” is issued do these changes become final.

All of this procedure takes a few seconds even invery large systems, a result that should be regarded anundoubted success of the developers and confirms thatthe ideas laid down into the system architecture are cor-rect. For example, if we take a concrete system consist-ing of 1000 functions and around 8000 connections, theoperations for downloading and activating data in thereal-time containers take as little as 15 s.

All elements (components) of SPPA-T3000 have asingle structure of data, which reflects the characteris-tics of any object that are of interest when the system isviewed from one position or another and correspond tocertain properties. For example, these may be currentdata, archived data, parameters, other properties, diag-nostic information, etc.

The project container consists of functions. Thelibrary of these functions requires an individualdescription, which is not given here; otherwise it wouldoccupy too much space. It should only be noted that thislibrary, which is a further development of Siemens soft-ware, outperforms its predecessors in completeness of func-tions and in coverage of real practical applications encoun-tered in developing power station automation systems.

Apart from the functions, the system comprises theso-called substitutes or proxy modules, which serve asvirtual representations of physical I–O devices, dataexchange devices (e.g., OPC-proxy), etc. As any othercomponents, the proxy modules have similar structuresof data and the set of properties and are used in thecourse of designing (configuring) a system on equalterms with other elements, like functions. Proxy mod-ules accompany any physical element of the system. Aspecial role is given to the control proxy module, the

unit in charge of coordinating all software componentsand representing an operating system, servers, networkexchange, etc.

SPPA-T3000 incorporates the widest possibilitiesfor visualizing, signaling, carrying out calculationswith the use of a power-engineering library, and datalogging and archiving.

Particular mention should be made of the archivingsystem, which offers almost unlimited possibilities forstoring archives and working with them, changing theset of data being archived in the online mode, andsimultaneously storing data with resolutions from a fewmilliseconds to several hours, days, etc.

The wide set of diagnostic facilities available in thesystem enables the operator to timely reveal any prob-lem with both hardware and software and analyze it tothe finest detail.

Apart from the real-time and design containers, thesystem incorporates other ones, which are charged withtasks that are solved in the offline mode and performedin the application server, with data exchange betweenthe containers, etc.

It can be seen even from this brief description of only asmall part of SPPA-T3000 that this system is a new step for-ward in the development of automation facilities.

By using SPPA-T3000 it is possible to automate alltechnological processes typical for power stations,including such specific ones as control of steam and gasturbines, and development of automatic control sys-tems for electrical equipment. The new architecturalsolutions used both in hardware and software make thesystem simple in design and further use, and the smallnumber of components makes its maintenance easier.The solutions adopted in the system enabled its devel-opers not to stick to concrete platforms, thus renderingthe product more stable to changes in the IT marketenvironment.

A number of projects have been developed in Russiaon the basis of the SPPA-T3000 system. The largest ofthese, which was implemented by Siemens jointly withInteravtomatika is the PCS for heat-generating andmechanical equipment and electrical equipment of thePGU-450 unit, as well as for the common-station sys-tems and equipment at Mosenergo’s TETs-27 cogener-ation station. The results obtained from the use ofSPPA-T3000 at the TETs-27 cogeneration station andother plants have confirmed that the system has uniqueproperties in many respects.

REFERENCES

1. A. G. Sviderskii, H. Herpel, and V. L. Kishkin, “TechnicalFacilities for Equipping Power Industry Facilities with Auto-matic Control Systems,” Elektr. Stn., No. 1, 7–12 (2004).

2. H. Rainer, “The Fourth Generation,” Power Engineering,No. 5 (2006)

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The range of automated process control systems(PCSs) that ZAO Interavtomatika control supplies forlarge power units usually includes, among other things,an automatic frequency and power control system(FPCS), previous versions of which were made in themain with the use of standard solutions [1].

1

In recentyears, since the time RAO Unified Energy Systems ofRussia (RAO EES Rossii) Order No. 524, dated Sep-tember 18, 2002, as well as others to follow, was issued,the task of actively involving power units in of thepower system frequency control has become a top-pri-ority one in selecting the general line and scope inwhich the control and monitoring systems of powerunits that are in operation have to be upgraded and hasreceived a determining role in the decisions of powerstations on partially retrofitting their control and moni-toring systems (CMSs). This is why the last five yearshave seen Interavtomatika placing greater emphasis onpartially upgrading the CMSs of equipment already inoperation with putting into use an FPCS proper andimproving other CMS parts directly or indirectly con-nected with it.

It is exactly this problem that has come in the fore-front in the sphere of interests of organizations involvedin activities for controlling power systems in the lasttwo or three years since the date the SO–CDA Standard[2] came in force, a document specifying the extent towhich power units have to participate in selective pri-mary and automatic secondary frequency control(SPFC and ASFC, respectively), and in view of the factthat a market of systems services is expected to emergein the nearest future, although work on involving powerunits in common primary controlling of frequency(CPFR) was also continued.

1

The term “automatic power control system” is widely used alongwith the term FPCS adopted in this paper.

Among the first six power units of UES for whichcertificates affirming their conformity to the Standard[2] were given in autumn of 2006, four were equippedwith FPCSs supplied by Interavtomatika: unit No.5 atthe Stavropol district power station (DPS), unit No.4 atthe Kirishi DPS, and units nos.1 and 5 at the IriklinskDPS, each having a capacity of 300 MW. By the timethis paper was written (February 2008), another fourcertificates had been received; these were for 300-MWunit No.8 at the Konakovo DPS, 300-MW units nos.3and 4 at the Iriklinsk DPS, and 800-MW unit No.1 atthe Perm DPS. In addition, a certificate for the 800-MWunit No.3 at the Perm DPS was received, a unit in whichInteravtomatika specialists retrofitted the turbine’shydraulic automatic control system (ACS) and the tur-bine part of the FPCS (its boiler part is built around theProcontrol-P equipment of ABB, which was installedas far back as the time at which the power unit was con-structed. Finally, it is planned to receive certificates fortwo more power units equipped with the FPCSs sup-plied from Interavtomatika: 300-MW unit No.2 at theKirishi DPS and 800-MW unit No.2 at the Perm DPS,units the preliminary tests for which have already beenaccomplished.

Historically, only gas-and-oil-fired power unitswere involved in the tasks of SPFC and ASFC startingas far back as the time at which Order No. 524 wasissued. This is why most attention was paid to this typeof equipment, and the power units mentioned above areexactly of this type. At the same time, Interavtomatikaspecialists continued activities for applying FPCSs alsoin coal-fired units, among which were 200-MW Unitsnos. 1 and 2 at the Kharanor DPS and 500-MW Unitsnos. 7–9 at the Refta DPS. Below, it will be shown thatcoal-fired power units can also be involved for solvingthe tasks of SPFC and ASFC. Certain experience withapplying FPCSs for combined-cycle plants of differentcapacities has also been gained [3].

Development and Application of Automatic Frequency and Power Control Systems for Large Power Units

V. A. Bilenko, A. D. Melamed, E. E. Mikushevich, D. Yu. Nikol’skii, R. L. Rogachev, and N. A. Romanov

ZAO Interavtomatika (Interautomatika AG), ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

Abstract

—We describe the results of work carried out at ZAO Interavtomatika on the development and puttinginto use of a system for automatically controlling the frequency and power output of large power units involvingthe retrofitting of the turbine’s hydraulic automatic control system. Certificates affirming conformity to theStandard of the System Operator – Centralized Dispatching Administration (SO–CDA) have been received foreight power units as an outcome of these efforts.

DOI:

10.1134/S0040601508100030

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DEVELOPMENT AND APPLICATION OF AUTOMATIC FREQUENCY 825

This paper summarizes the results of activities onputting in use FPCSs complying with the requirementsof SPFC and ASFC, formulates the necessary prerequi-sites under which an FPCS complying with the require-ments of the SO–CDA Standard can be developed, ana-lyzes the effect different types of automated equipmentand solutions used in constructing FPCSs have on thesuccess in achieving certain indicators of SPFC andASFC, and gives examples of the results obtained fromtests of different types of process equipment.

The activities on putting in use FPCSs conformingto the standard [2], including those on arranging andcarrying out the tests the results of which are used inthis paper, were conducted with active participation ofpower station representatives.

2

FUNCTIONS AND COMPOSITION OF THE FPCS OF POWER UNITS INVOLVED IN SPFC

AND ASFC

The main problem faced by the personnel of powerstations the power units of which are involved in SPFCand ASFC consists, along with solving the problem of

2

We are grateful to V.N. Kindyakov, V.V. Butskikh, andV.S. Sadykov from the Iriklinsk DPS; V.Yu. Krylov, M.A. Osint-sev, and N.T. Belyakov from the Stavropol DPS; A.I. Shalamov,V.I. Andreenko, A.I. Panasenko, O.A. Smirnov, and P.I. P’yankovfrom the Perm DPS; P.I. Korotenkov and Yu.A. Belousov fromthe Konakovo DPS; M.E. Petushkov from the Kirishi DPS; andthe representatives of voluntary certification bodies at the All-Russia Thermal Engineering Institute N.I. Davydov andN.N. Zorchenko and at ORGRES V.K. Tereshchenko, I.I. Lebe-dev, and I.S. Labutin for their participation in an analysis of resultsfrom preliminary tests and in carrying out certification tests.

upgrading the turbine automatic control system [4], ofdetermining the list of FPCS functions, the compositionof automation functions required for implementingthem, and the appropriate volume of hardware used toconstruct the FPCS. This problem is more acute forpower stations with limited financial resources, whichhave no choice but to upgrade their control and moni-toring systems only in to a partial extent. Selecting theoptimal scope of upgrading becomes in this case themost relevant problem. This is not so important ifupgrading is carried out to a full extent; nonetheless,correct algorithmic solutions and a clear-cut choice ofhardware for implementing them remain a must.

The outline function diagram illustrating theapproach Interavtomatika specialists follow in develop-ing FPCSs is shown in Fig. 1. The list of main (manda-tory) FPCS units required to fulfill the requirements ofSPFC and ASFC includes the following:

(i) the unit part of the FPCS, comprising boiler andturbine power controllers (BPC and TPC), a frequencyconditioning corrector (FC), setpoint adjusters forASFC (earlier, the term “external component of powersetpoint” was used) and for the planned (internal)com-ponent of power setpoint, a parameter characterizingtertiary control of frequency;

(ii) an electronic turbine speed governor (TSG) [4];(iii) the boiler’s main closed-loop control systems

(CLCSs); and(iv) a system for taking “automatic control dis-

abling” (ACD) statuses into account.The scope of the boiler’s main CLCSs (henceforth,

we primarily consider once-through boilers as theapparatuses most widely used for large power units and

System

Unified

Unit part

Boiler

Additional

AEUS

Automation

Boiler Turbine High response

Advanced

Highly

Main

I&CS

components

for accountingACDs of the FPCS

AECS

components

ElectronicTSG

of switchingoperations

ACS developedengineering

system

operatorinterface

speed algorithms

Fig. 1.

Illustration of the approach Interavtomatika specialists follow in developing FPCSs. ACDs—automatic control disabled fromthe process, AECS—automatic emergency control system, TSG—turbine speed governor, and AEUS—automatic emergency powerunit unloading system.

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most complicated in terms of their control) includes notonly the CLCSs participating directly in changing theboiler’s control inputs affecting its load, such as fuel,feedwater, and air flowrates and rarefaction. Anothercondition that must necessarily be fulfilled for the tech-nical parameters of a power unit participating in con-trolling the frequency and power be maintained withhigh quality demands that essential improvements haveto be made also in the CLCSs responsible for theboiler’s most important parameters, such as the CLCSsof injections into primary and secondary steam, andthose of other systems for controlling the secondarysteam temperature; cascade controllers of temperaturealong the boiler path to the first controlled injection,devices for correcting the content of oxygen in fluegases, and so on. In view of the fact that the processesthrough which the frequency and power are controlledmay entail a considerable increase in the steam pressureand taking into consideration the tasks related to emer-gency unloading of a power unit (the power unit auto-matic emergency unloading system (AEUS) serves toperform them) and automatic emergency control, a man-datory need also arises for furnishing the power unit withdevices for controlling the pressure of steam upstream ofthe high-speed reduction-and-cooling installation and thesteam temperature downstream of it.

The CLCSs generating the main control inputs forthe boiler (fuel and feedwater flowrates) are in them-selves highly branched multiloop systems. Even in thesimplest case of a gas-and-oil-fired boiler, its fuelCLCS must allow the boiler to run with separately com-busting gas and fuel oil and with combusting themjointly with different ratios between their flowrates. If aboiler is equipped with AMAKS burners with the use ofindividual shutters controlling the supply of gas to eachburner, it becomes possible to redistribute the flowrateof gas between the half-furnaces and between the tiers(to suppress the emission of nitrogen oxides) and widenthe range in which the supply of gas can be adjustedwith a given number of burners. Finally, the fuel CLCSfor coal-fired boilers with direct injection of dust includes,along with a total flowrate controller, individual multiplyconnected CLCSs for each dust system [5, 6]. Such solu-tions are also applied for controlling individual dust feed-ers for boilers with an intermediate hopper.

A detailed description of Interavtomatika’s solu-tions for automatic control of boilers, including thoseof power units participating in SPFC and ASFC, isgiven in [7].

Whereas that the first three main FPCS componentsare commonly recognized, some suppliers and custom-ers of FPCSs cast doubts regarding the need to use asystem for taking ACDs into account. It is supposedthat a properly designed plant should not have any lim-itations, that no constraints should arise if the 5% nor-mal margin or 12.5% emergency margin is provided forSPFC and 5% margin is available for ASFC, and so on.In addition, even the tests for ascertaining conformity

to the SO-CDA Standard can be carried out under theinitial technological operating conditions selected andadjusted so that no ACDs will arise. At the same time,when power units equipped with FPCSs operate for along time in modes with SPFC and ASFC, it is hardlypossible to avoid cases in which ACDs would arise orcases in which they would have at least a short-terminfluence on the pattern of transients in power andpower unit’s internal parameters.

ACDs may arise due to a variety of factors. First,attempts to distribute the dispatch schedule of the totalload transmitted via one power line (the number of suchlines is equal two or three at the majority of power sta-tions) among power units in such a way that the SPFCand ASFC margins would not be violated, at least tem-porarily, in each of the power units that are in operation,do not always met with success. Second, external con-ditions—primarily, the ambient temperature—mayseriously affect the actual margin. Third, since existingpower units have been in operation for a long time, it isquite probable that their characteristics will becomedegraded, at least temporarily, or that individual equip-ment items fail. Fourth, as will be shown below, certaindynamic overshoot of boiler control elements isrequired to obtain the necessary quality of transients inthe power unit’s output. The list of the most typicalACDs includes those on the displacement of the boileractuators, turbine valves, or the cases when such pro-cess parameters as the pressure of gas or fuel oil, thepressure of steam upstream of the turbine, and the pres-sure of feedwater downstream of the turbine-drivenfeedwater pump reach their limiting values. ACDs thatarise may be both continuous and persist for the entiretransient and temporary, i.e., vanish after some time.

Thus, the function of taking ACDs into account ismandatory and is implemented by reconfiguring theinterconnected FPCS and boiler’s main CLCSs in sucha way that the power unit retains its ability to operateand that the static or dynamic quality of transients in itspower output and internal parameters deteriorates to theminimum possible extent.

One more task, which is similar to that of taking theACDs into account in the way it is implemented, andmandatory for CLCSs with such complex functionstructures as the FPCS and boiler’s main CLCSs, is thatof taking functional failures into account, such as fail-ures of sensors and the loss of the possibility of per-forming control by means of actuators. Here again,reconfiguration of function structures is used; however,unlike ACDs, the occurrence of which causes automaticcontrol becoming disabled in one direction, the closed-loop controller must be switched over to manual oper-ation, if a noncompensated functional failure occurs,this causing automatic control to become disabled inboth directions.

Two groups of FPCS elements are shown in Fig. 1as supplementary ones. These, first of all, are elementsperforming the function of power unit emergency

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unloading when one of the boiler’s main mechanismsfails (a feedwater pump, a forced-draft fan, an exhaustfan, or the circulating pump due to the operation of theemergency power unit unloading system), when one ofthe shells of a two-shell boiler is shut down, or to pre-vent the occurrence of a power system failure (due tothe operation of the unit-level automatic emergencycontrol system). In all cases, the aim of power unitunloading is to avoid the need of shutting down thepower unit.

These tasks are not directly connected to the prob-lem of SPFC and ASFC. However, since the automaticemergency control system generates control inputs tothe turbine speed governor, the emergency power unitunloading system generates inputs to the boiler CLCSs,and both of them interact with the unit part of the FPCS,the projects Interavtomatika specialists develop forupgrading CMSs incorporate these elements as a stan-dard solution.

Another supplementary task consists of automatinga small volume of discrete operations that have to beperformed in the course of changing the power unit out-put in the working range of loads. Examples of suchoperations are starting-up and shutting-down burnersand changing the speeds of forced-draft fans. Whetheror not these operations have to be automated dependson the characteristics of burners and fans and on howthe power unit operating conditions are organized.Some plants at which FPCSs were put in use did not putforward such a task, and at others, e.g., the Konakovoand Iriklinsk DPSs, it had to be solved. Therefore, ret-rofitting of the burner control system was included inthe scope of upgrading project together with means forsolving the SPFC and ASFC problems.

Being a complex multifunctional structure, the auto-matic frequency and power control system must be nec-essarily furnished with an up-to-date operator interfacethat would, first of all, provide the operating personnelwith means for clear and efficient monitoring of howthe SPFC and ASFC functions are performed and howcorrectly all the FPCS elements operate, as well as forintervention into the control of the process in urgentoccasions. Alarms, which include both process andI&C function signals, play a fundamentally importantrole here.

Process alarms bear information on the followingevents: that the frequency corrector (of the SPFC sys-tem) has come into action when the frequency wentbeyond the specified setpoints (if the dead band is

±

10 mHz, there is no point in indicating each case ofthe frequency to go beyond these limits), that the ASFChas started and ceased to operate, that the processparameters have deviated beyond the setpoints charac-terizing the quality of power unit operation both in theSPFC and ASFC modes and as a whole, and that abnor-malities have occurred, primarily, the ACDs due towhich the power unit cannot participate in the SPFC

and ASFC or due to which such participation becomesdifficult.

I&C function alarms inform the operators aboutfailures of sensors, about the loss of possibility of auto-matically controlling the actuators; about the automati-cally generated signals disabling the FPCS operation inone or in both directions, and on the causes due towhich these signals were generated; about the fact thatthe BPC, TPC, or the boiler’s main closed-loop control-lers were switched over to manual operation; and aboutthe fact that the structure of the FPCS’ power unit partor that of the boiler’s main CLCSs was automaticallyreconfigured.

The list of the necessary components of the FPCSoperator’s interface also includes the following:

(i) logging the events that characterize the participa-tion of the power unit in the SPFC and ASFC and devi-ations from the normal conditions of FPCS operation;

(ii) archiving and storing for a long time analog anddiscrete information of the FPCS operation; and

(iii) clearly presenting on-line and off-line transientcurves for the main controlled parameters and FPCScontrol element positions.

Perfect function diagrams of all algorithms used inthe FPCS structure have to be developed to complywith the requirements of the SO–CDA Standard andensure that the internal parameters of the power unitwill be maintained with high quality in the entire rangeof working loads. Therefore, a well-developed engi-neering system has to be used during its adjustment andsubsequent operation that would allow solutions them-selves to be selected and subsequently optimizedtogether with the tuning parameters of their elements ina convenient manner. The position Interavtomatika spe-cialists have always held with respect to an APCS as awhole and to the FPCS in particular is that an engineer-ing system must be open for the customer and it mustallow the customers to introduce—by themselves orwith consulting assistance of the supplier—the neces-sary corrections in the software of I&C system duringlong-term operation of the system to bring the systemin line with possible changes in the requirements for theFPCS and the technology in accordance with whichpower unit operation has to be conducted.

An analysis of the elements constituting the FPCSfunction diagram (Fig. 1) has shown that all these ele-ments can be constructed on the basis of I&C systemdedicated for thermal power engineering. A specificfeature of such a I&C system is that it should haveenough capacities for implementing high-speed algo-rithms of an electronic turbine speed governor and anemergency control system [4].

The approach Interavtomatika specialists followedfrom the very first projects has always placed anemphasis on constructing the entire FPCS, if possible,on the basis of a unified I&C system, and it is just thisway in which Interavtomatika specialists have put into

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use all their FPCS in the power units that were retrofit-ted.

This approach has the following important advan-tages over that applied to some other facilities with theuse of turbine control systems built around another I&Csystem that usually has no bus connection to the I&Csystem of the main part (as a rule, these systems incor-porate, along with the turbine speed governor and auto-matic emergency control system, a turbine power con-troller):

(i) the overall FPCS is not artificially broken intotwo dissimilar controllers with wiring connectionsbetween them, and less complicated software isrequired to run the interconnected algorithms of the twoparts of the system;

(ii) a single engineering system is used for debug-ging and operating the power unit’s overall FPCS; thisallows the power station personnel to avoid difficulties thatfrequently occur in other systems when changes have to bemade to its part relating to the turbine I&C system; and

(iii) the system is furnished with a common opera-tor’s interface in contrast to alternative approaches,according to which the turbine controller usually comeswith its own operator’s workstation.

The Interavtomatika’s FPCSs considered in this paperwere constructed on the basis of two types of I&CS:

The systems supplied for the Stavropol and PermDPSs were built around the TELEPERM XP-R I&CS(also known as the TPTS-51–OM650 system) withinthe scope of the power units' full-scale PCSs.

The systems supplied for the Konakovo, Iriklinsk,and Kirishi DPSs were built around the SIMATICPCS7-PS I&CS within the scope of partial retrofittingof their control and monitoring systems.

Each of the above I&CS performed the entire scopeof FPCS functions. It should be mentioned that theSIMATIC PCS7-PS incorporated special FM-458 mod-ule, a dedicated device for running control tasks requir-ing high response speed, whereas the TPTS-51 I&CSwas furnished with additional functional modulesVNIIA specialists had developed in accordance with anassignment from Interavtomatika. Featuring highresponse speed, these modules covered the entire rangeof turbine control tasks [4].

FUNCTION DIAGRAM OF THE FPCS POWER UNIT PART

The standard solutions used in FPCSs for powerunits equipped with once-through boilers [1] were ori-ented toward using the so-called automatic power con-trol system SAUM-1 (according to which the control ofpower unit output

N

is placed on the BPC and the steampressure upstream of the turbine is controlled bymeans of the TPC), the improved version of whichemployed a configuration in which the BPC controldeviation (

N

ref

–

N

) was applied to the TPC input. How-ever, the first tests for checking the conformance of800-MW Unit 1 at the Berezovo DPS with the require-ments of common primary frequency control (CPFC)have shown that the boiler has to be forced considerablyinitially in the transient [5]. The need of doing so(although with a lower forcing degree) was subse-quently revealed also in 300-MW power units. To bringthe system in conformity with the SO–CDA Standardwith such a structure, in which the requirementsimposed on the SPFC are much more stringent thanthose on CPFC, a transition had to be made to a com-bined structure of the FPCS, in which the solutionstaken in the so-called SAUM-2 were partially used(according to the SAUM-2 concept, the TPC controlsthe power unit output, and the BPC controls the pres-sure of steam upstream of the turbine).

The function diagram in accordance with which thecombined version of the FPCS unit part correspondingto such approach is constructed is shown in Fig. 2. Thesetpoint for the power unit output is generated on thebasis of the following three components:

(i) the internal (planned) setpoint value of power

corresponding to the task of tertiary control

(ii) the ASFC setpoint signal arriving from theFPCS’s common-station level, which is received from

the district (united or central) and

(iii) the setpoint value for the primary frequency

control channel generated by the frequency cor-rector.

p't

Nsett ;

Nsets ;

Nsetp

Fig. 2.

Function diagram of the FPCS unit part. FDS—sim-ulator of frequency deviations.

N

reft

ACDs

N

refs

RRL

t

RRL

s

Σ

Generation

p

'

t.ref

N

refs,t

DC

FCb

Accounting

Dp

'

t.ref

H

t.ref.

ACDsMSC

BPC

DC

RRLt

N

DC

FCt

FC

Σ

Accounting

p

'

t.ref

N

t.refp

TPC

Boiler

G

r.ref

TSG

∆

N

t

N

ref.t

f

ref

∆

f

f

of

p

'

t.ref

DC

RRLb

ACDsACDs

p

t

H

t

ACDs

FDS

∆

N

b

ACSs

N

b.ref

∆

H

t

∆

p

t

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DEVELOPMENT AND APPLICATION OF AUTOMATIC FREQUENCY 829

The referentces (setpoints) for the secondary andtertiary control channels are transformed in the corre-sponding setpoint rate-of-change limiters RRL

s

andRRL

t

. However, since very stringent requirements areplaced on the accuracy with which the SPFC signalshave to be responded to, not only does any RRL imposeno limitation on the rate of change in the power setpoint

signal but on the contrary, this signal is applied tothe boiler and turbine control channels with enhancedforcing as compared with the total setpoint from the

secondary and tertiary control RRLs To this end,the structure incorporates in the general case fourdynamic functions (DFs): from the RRLs and fre-

quency corrector to the boiler and turbine (

and ). Only some of these DFscan be used in individual cases, depending on thedynamic characteristics of a boiler and static turbinecontrol characteristic.

The setpoint values for the boiler and turbine loads

N

b.set

and

N

t.set

obtained by summing the output signalsfrom the corresponding DFs and limited in accordancewith ACDs are used to generate the control deviationsignals for the BPC

∆

N

b

and TPC

∆

N

t

, which are thenfed to the input of the control deviation signal converter(CDSC). As regards the setpoint signal for the boilerload, the configuration incorporates the possibility ofapplying a direct signal for setting up the specifiedflowrate of fuel to the boiler

G

f.ref

, which does notdepend on the BPC tuning parameters.

An FPCS constructed on the basis of SAUM-1 usedthe position of turbine control valves

H

t

as the TPC’scontrolled parameter for operation with sliding pres-sure of steam. Such an approach was also supported bythe decision taken earlier at many power stations,according to which a special gently sloping corridorwas assigned in the vicinity of the sliding point, achange in the valve position in which did not result in aconsiderable change in the power unit output or steampressure. However, the tests in which the plant waschecked for conformity with the CPFC—and evenmore so, with the SPFC requirements, have shown thatsuch a solution adversely affects the dynamic charac-teristics of a power unit during its operation at slidingpressure. In addition, the use of electronic turbine speedgovernors made it possible to bring the turbine controlcharacteristic to a form fairly close to linear [5], alsodue to discarding the use of the above-mentioned corri-dor, thus obtaining the same rate of change in the powerunit loads in the initial (most important) part of SPFCtransients over the entire range of loads. Owing to thesecircumstances, it became possible to do without the sig-nal for

H

t

and under sliding pressure mode to use thesteam pressure signal, which is more convenient whenthe SAUM-2 solutions are employed. The setpointvalue of this pressure is generated as a function ofthe total assigned power unit load, which is almost lin-

Nsets ,

Nsets t, .

DFbRRL,

DFbFCC, DFt

RRL, DFtFCC

p't.set

ear in nature, and allows the required position of valvesto be obtained. The control deviation signal of valvepositions

∆

H

t

is used in the TPC only when the BPC isdisconnected.

The pressure control deviation signal

∆

obtained using is applied to the input of theCDSC, which uses it together with the power controldeviation signals

∆

N

b

and

∆

N

t

to generate control devi-ations for the BPC and TPC.

The rule in accordance with which the control sig-nals are generated depends on the following:

(i) the absolute value of the signal at the FCC output

which determines if the SPFC assignments haveto be strongly responded to;

(ii) the pressure of steam upstream of the turbine, aparameter characterizing the boiler’s dynamic capabil-ities; and

(iii) whether or not any ACDs have arisen, and, ifyes, then of what nature (for the boiler or turbine, inwhich direction, etc.).

The signal is applied directly to the CDSC,which uses it for taking into account the maximum andminimum pressure limits when generating the controldeviation signals for the BPC and TPC. The use of theBPC control deviation signal proportional to the pres-sure time derivative is in line with the standard solu-tions for the SAUM-1 and helps improve the dynamicproperties of the BPC in the SAUM-2.

A frequency deviation simulator (FDS) has beenincorporated into the function diagram of the FPCS’sunit part, which allows tests for conformity with theSO-CDA Standard to be carried out: by changing FDSsetpoint, one can carry out experiments on the SPFC.

RESULTS OF TESTING THE FPCS FOR CONFORMITY WITH THE SO–CDA

STANDARD

The typical test program specified in the SO–CDAStandard can be conditionally subdivided into threeparts. The first part, which is described in Clauses 8.2.1and 8.2.2 of the Standard, includes tests for checkingthe turbine speed governor’s dead band and how cor-rectly the SPFC system operates at different droop val-ues. The second, and the most complicated and bulky,part of the tests (specified in Clause 8.2.3 of the Stan-dard) reflects the dynamics with which the SPFC set-points are followed within the normal (

±

5% of ratedload) and emergency (

±

12.5% of rated load) margins.The third part (specified in Clauses 8.3–8.8 of the Stan-dard) characterizes the performance of the power unitwhen the ASFC comes into action, when the primary,secondary, and tertiary control system operate jointlywith one another, when the power unit indeed partici-pates in the SPFC, etc. This paper gives examples takenfrom the second part of the tests. The results from the

p't.set

p't.set

Nsetp ,

pt'

830

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first part of tests are described in [3]. The third part oftests presents no special problems provided that posi-tive results have been obtained from the precedingseries of tests. An example of the mode in which theload of a 300-MW power unit was changed at a rate of10 MW/min (more than 3%/min) can be found in [7].

The main requirements the SPFC dynamic charac-teristics must comply with are as follows:

(i) the time taken for the power to reach half therequired change must be equal to 10 s within both thenormal and emergency margins; and

(ii) the time taken for the required load to fit into therange

±

1%

N

nom

(where

N

nom

is the rated power unitoutput) must be equal to 30 s within the normal marginand 2 min within the emergency margin.

The examples we used to illustrate how the SPFCsetpoints are responded (Figs. 3–6) were selected so asto cover the variety of the composition of equipmentand its operating conditions. Thus, the dynamics ofboiler equipment is illustrated on three types of 300-MWpower units: a double unit equipped with a TGMP-114boiler and two single units differing from each other innumber of flows in which medium is supplied to thebuilt-in gate valve (two for the TGMP-114 boiler andone for the TGMP-324 boiler) and also an 800-MWpower unit. The dynamic characteristics of turbines andthe ways in which their steam admission systems areorganized are demonstrated on two types of turbines:the K-300-23.8 turbine of Leningrad Metal Works(LMZ) [see Figs. 3 and 5] and OAO Turboatom (seeFig. 4) and the K-800-23.8 turbine of LMZ (see Fig. 6).Most of these examples show the results from tests car-ried out in the upper and lower parts of the workingrange of loads, and Figs. 2 and 3 illustrate the results oftests on two power facilities carried out in the middlepart of their working ranges of loads.

Special mention should be made of the effect theamplitude of frequency disturbance (

±

5 and ±12.5%)has on the quality of transients. The difference thatexists in the requirements for the time for which theprocess must fit into the range ±1% Nnom (30 and 120 s,respectively) allows the transient to be artificiallyslowed down for tests within the emergency margin,thus making the equipment operating conditions lessheavy. This can be done by inserting an additionaldynamic function unit into the channel through whichthe control deviation from the frequency deviation sim-ulator is applied to the TPC and BPC; see Fig. 2. Oncethe stepped frequency deviation signal exceeds theabsolute value corresponding to 5% load, this dynamic

function unit dampens it or transforms it into a linearlyrising signal.

Agreeing, in principle, with the possibility of fol-lowing such an approach, Interavtomatika specialistshave took a decision together with the customers,according to which tests in most of their projects arecarried out without introducing an additional dynamicfunction for frequency deviation in belief that the actualpattern of transients, such as the effect of ACDs, non-monotonic behavior, etc., will be revealed more clearlywhen natural deviations of the network frequencyoccur. Nonetheless, the aforesaid “smoothing” wasused for Unit 4 at the Kirishi DPS (see Fig. 5) on agree-ment with the customer and certification authority.Since no variations were made in the ways the fre-quency deviation signal was applied in the remainingfacilities, and considering that experiments with a dis-turbance equal to ±12.5% are much more complicatedfrom the viewpoint of fulfilling the requirements of theStandard, the majority of test results are presented exactlyfor the “emergency” disturbance, and it is only for Unit 4at the Iriklinsk DPS that transient curves for both the dis-turbance values are presented as an illustration.

An analysis of the test results allows the followingstatements to be made.

(1) Good quality of SPFC transients during their ini-tial stage is observed in all experiments; i.e., the timetaken for the power to reach half of its change does notexceed 10 s in the entire range of loads irrespectively ofthe sign of frequency deviation. This result is obtaineddue to the steam turbine’s characteristic being accept-ably linear. It should be pointed out that much lesseffort is required for linearizing it if the turbine CS isretrofitted with the use of an electronic turbine speedgovernor and installation of electromechanical andelectrohydraulic converters (EMCs or EHCs) [4]. Atthe same time, even if the above-mentioned retrofittinghas been carried out, the degree to which the turbinecontrol characteristic is close to linear in the entirerange of loads may be different depending on the steamadmission system used in the turbine. For example, lesseffort has to be taken to linearize the turbine controlcharacteristic for K-300-23.8 turbines of LMZ thanthose for the turbines of Turboatom.

(2) The time taken for the process to fit into therange ±1% Nnom, which is the second main indicatorcharacterizing the SPFC dynamics, also depends onhow linear the turbine static characteristic is. It dependsto a no smaller degree (and to a considerably largerdegree for the emergency margin), however, on the

Fig. 3. Transients obtained in experiments for checking the dynamic response of SPFC to frequency deviations in the double 300-MWUnit 4 at the Iriklinsk DPS (the TGMP-114 boiler and the K-300-23.8-3 turbine) during the operation on gas. Frequency deviation:(a) ±150 mHz in the middle of the control range, (b) ±370 mHz in the upper part of the control range (emergency deviation of fre-quency), and (c) ±150 mHz in the lower part of the control range. (1) Power, MW; (2) upper permissible boundary of the accuracywith which the power output must be maintained, MW; (3) lower permissible boundary of the accuracy with which the power outputmust be maintained, MW; (4) steam pressure upstream of the turbine, kg/cm2; (5) group signal indicating the position of turbinevalves, %; (6) fuel flowrate, thousands of m3/h; (7) frequency deviation, mHz; and (8) RRL output, MW.

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boiler’s dynamic capacities and on the structural solu-tions in accordance with which the FPCS’s unit part isconstructed (see Fig. 2) and on the tuning of its ele-ments. The latter factor, i.e., the way in which the FPCSis constructed, determines also the quality of theremaining part of transients: whether the process settleswithin the given range and whether the power is con-trolled without oscillations.

(3) It can be seen from the presented graphs that thetime for which the process must fit into the specifiedrange (30 s) is fulfilled not only in the tests within thenormal margin (see Fig. 3), as is determined in the

Standard, but also in the majority of tests within theemergency margin. The only exception to this are thefirst experiments in all tests for 800-MW Unit 1 at thePerm DPS. This is attributed to the limited range inwhich the turbine valves can move. Somewhat slowerdynamics with which the transients for the KirishiDPS’s 300-MW Unit 4 proceed (see Fig. 5) is due to theabove-described way in which the frequency deviationsignal is applied for disturbances of ±12.5 MW.

(4) As was already indicated, making a steam tur-bine’s control characteristic linear is of fundamentalimportance for obtaining the required indicators of

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Fig. 5. Transients obtained in experiments for checking the dynamic response of SPFC to emergency frequency deviations withamplitude of ±370 mHz in the single 300-MW Unit 4 at the Kirishi DPS (the TGMP-324 boiler and the K-300-23.8-3 turbine); (a) isfor the operation on gas in the middle part of the control range, and (b) is for the operation on fuel oil in the lower part of the controlrange. The meaning of (1)–(5) is the same as in Fig. 3. (6) Frequency deviation, mHz.

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SPFC. This problem is solved most conveniently for theK-300-23.8 turbine of LMZ, each of the seven high-pressure valves of which is furnished with its ownEMC. The resulting control characteristic can be madesufficiently linear by properly selecting the tuningparameters determining the characteristic of this valve.The least favorable conditions for solving this problemare in the case of the K-300-23.8 turbine of Turboatom,because each half of the turbine’s steam admission unit

is equipped with its own EMC, and each of them con-trols a group of hydraulically interconnected valves.

This is why nonmonotonic behavior was observed atthe beginning of transients in some tests carried out onthe Stavropol DPS power unit equipped with a K-300-23.8turbine of Turboatom in contrast to almost monotonicprocesses in the power units at the Iriklinsk and KirishiDPSs equipped with K-300-28.3 turbines of LMZdespite the fact that the initial nonlinearity of the tur-

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Fig. 6. Transients obtained in experiments for checking the dynamic response of SPFC to emergency frequency deviations withamplitude of ±370 mHz in 800-MW Unit 5 at the Perm DPS (the TPP-804 boiler and the K-800-240-5 turbine) during operation ongas; (a) and (b) are for the operation, respectively, in the upper and lower parts of the control range. The meaning of (1)–(6) is thesame as in Fig. 3.

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DEVELOPMENT AND APPLICATION OF AUTOMATIC FREQUENCY 835

bine’s static characteristic had been compensated for toa considerable extent by inserting a dynamic dynamicfunction unit at the TPC input, the characteristics ofwhich were automatically adapted depending on theload (see Fig. 2).

(5) The forcing of the boiler, i.e., the ratio of the ini-tial change in the fuel flowrate to its steady value at theend of the transient, depends on the dynamic character-istics of the boiler, which depend on the power unitcapacity and its flows. It should be pointed out that,since the time for which each experiment could be car-ried out was limited to 5 min, the transient in the powerunit usually does not have enough time to die out com-pletely (this can be seen from the pressure curves), acircumstance that adds difficulty to a visual assessmentof the forcing factor.

The smallest forcing (by a factor of 1.5) is observedfor the 300-MW double unit equipped with the TGMP-114 boiler and four flows of medium. The required ratiowith which the boiler of a single unit equipped with aTGMP-314 boiler with two flows of medium has to beforced increases to 1.6, and that for the 300-MW singleunit equipped with a TGMP-324 boiler the medium inwhich goes in one flow to the built-in gate valve, to 1.7.Finally, the required ratio with which the boiler of an800-MW power unit equipped with a TPP-804 boilerhas to be forced for obtaining acceptable transients inpower is equal to 2.

The required boiler forcing ratio depends on thepower unit operating conditions and increases when ashift is made from rated pressure to sliding pressure.The actual forcing ratios we observed in the course oftests at each load varied from experiment to experimentdepending on the conditions under which an individualexperiment was started: the pressure of steam upstreamof the turbine and the dynamics with which the con-trolled values varied over the boiler (pressures, temper-atures, and flowrates of medium).

Clearly, the higher the required boiler forcing ratio,the more complicated the FPCS is. First, a need arisesto introduce dynamic function units for the boiler con-trol signals (see Fig. 2), to tune them in the entire rangeof operating conditions, and to automatically adapt thetuning parameters. Second, the probability that ACDsmay arise during the transients increases, so that mea-sures for automatically taking them into account needto be developed, including those for reconfiguring theFPCS’s unit part and the CLCS of the boiler. Finally,more considerable changes may occur in the marginthat has to be provided in the power unit control rangefor SPFC.

PROPOSALS FOR IMPROVING THE ARRANGEMENTS TAKEN TO INVOLVE

POWER UNITS IN THE FREQUENCY CONTROL MODES

The experience Interavtomatika specialists gainedfrom equipping large power units with FPCSs, includ-ing the results obtained from putting FPCS in use inpower units equipped with gas-and-oil-fired boilers inconformity with the SO–CDA Standard, which weredescribed in this paper, as well as the furnishing ofmany power units equipped with coal- and gas-and-oil-fired boilers with FPCS complying with the require-ments of CPFC, allow us to propose that a wider rangeof power units can be involved in SPFC and ASFC.

At present, the power units have been categorizedinto two groups. The first group comprises condensinggas-and-oil-fired power units that are charged, alongwith participation in CPFC, with SPFC and ASFCtasks, and the second group encompasses the remainingpower units intended only for the CPFC purposes. It isexactly the first group of power units that is currentlyconsidered for participation in the market of systemsservices.

At the same time, the following question arises:why, unlike the well-known approach used outsideRussia, have coal-fired units been classed in the secondgroup? The following three drawbacks of coal-firedpower units can be indicated in substantiation of suchdecision: they have poorer dynamic characteristics, it ismore difficult to control the supply of fuel and the com-bustion process as a whole, and they have a narrowerrange of working loads.

The poorer dynamics may be due to the followingtwo factors:

(i) the fuel-load channel comprises the dynamics ofmills, which can be described by a first-order delayfunction with a time constant of not higher than 1 min(this feature is characteristic only for boilers with directinjection of fuel);

(ii) the boiler has a somewhat higher inertia (experi-ence shows that this difference between the dynamiccharacteristics is much smaller for coal- and gas-and-oil-fired boilers than it is for boilers intended to fire thesame kind of fuel but with different outputs).

Difficulties with controlling the combustion processin coal-fired boilers existed in Russian power engineer-ing approximately until the late 1990s, the time untilwhich traditional control equipment had been used forsolving such problems. The use of microprocessordevices allowed these problems to be successfullysolved. Interavtomatika specialists alone have suc-ceeded in commissioning systems for comprehensivelyautomating the combustion process and boiler’s mainCLCSs in more than ten large coal-fired power units ofdifferent types [7].

As for the narrower range of loads, the situation isas follows. The working range’s lower boundary for

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gas-and-oil-fired power units is equal to 40-50%,whereas that for coal-fired units is 60–70%. This draw-back is indeed essential, since, if we take the 5% mar-gins for SPFC and ASFC in both directions, the rangein which the power unit load can be varied becomes asnarrow as 10–20%. It is exactly in this indicator thatRussian equipment is inferior to its foreign analogs, forwhich the range of working loads has a lower boundaryof 40% or less. At the same time, if we take a coal-firedpower station with a large number of power units and/orthe one equipped with large 500- and 800-MW powerunits, even such a narrow range may turn to be quitesignificant. One more way in which the range of loadscan be widened is to confine the operating modes withone kind of control: either SPFC or ASFC.

Thus, there is no tangible difference between gas-and-oil- and coal-fired power units so far as control ofthe frequency and power is concerned except with thecontrol range. Moreover, if we take into account thatcoal-fired power units prevail in many regions, the par-ticipation of such units in the market of system servicesmay happen to be not only desirable, but even manda-tory. If it is decided that coal-fired power units have tobe involved in SPFC and ASFC, it will be necessary todevelop a controllery document that would take intoaccount, in particular, that the working range in whichthe loads of coal-fired units can be varied is narrowerthan that of gas-and-oil-fired units.

Below, the main requirements of SPFC and ASFCare considered from the standpoint of which powerunits should preferably be used to fulfill them. The fol-lowing ones can be separated as such requirements:

(i) the possibility of controlling the frequency witha dead band of ±10 mHz;

(ii) the dynamic characteristics of SPFC consideredin detail in the previous section; and

(iii) the dynamic characteristics of ASFC carried outwith load variation rates of up to 4%/min.

Whether the control of frequency can be performedwith a dead band of ±10 mHz depends only on the capa-bilities of the turbine CLCS and is achieved throughreplacing the hydraulic CLCSs by microprocessor-based controllers and installing electrohydraulic orelectromechanical converters and high-precision fre-quency rotation sensors. Small deviations of turbineload that occur during such control can be compensatedfor without any serious problems by means of boilercontrol. The only thing that has to be done here is to fur-nish the boiler with a load controller with a moderateresponse speed. Thus, for this requirement to be ful-filled, it is sufficient that the turbine were equipped withan electronic CLCS, a condition that will be satisfiedfor all new power units and for those operating units inwhich the turbine CLCS is retrofitted, irrespective ofwhether the power unit is a coal- or gas-and-oil-fired one.

The same conditions determine whether it is possi-ble to fulfill the requirements for the SPFC dynamic

performance initially in the transient, according to whichthe load must reach half of its change within 10 s.

As was shown before, making the turbine staticcharacteristic close to a linear dependence also has apositive effect on the time taken for the process to fitinto the range ±1% Nnom, but the boiler’s dynamic char-acteristics and perfect structural solutions for construct-ing the unit part of the FPCS are the most important fac-tors here. The latter factor means that the power unit’scontrol and monitoring system must be upgraded in therange we considered in detail in this paper (see Fig. 1).

As regards the effect of boiler’s dynamic character-istics, drum boilers, which have larger accumulatingcapacity and, hence, better dynamics with which steamflowrate varies in response to displacement of the tur-bine control valves, are preferable to once-through boil-ers. Among the different designs of once-through boil-ers, psetpoint should be given to those having smallerthroughput capacity of the entire unit or its individualflows. The kind of fuel being fired (gas and fuel oil orcoal) does not have an essential effect on how well therequirements are fulfilled. An analysis of the resultsfrom tests Interavtomatika specialists carried out on theFPCSs used in the 200-MW coal-fired power units atthe Kharanor DPS for conformity with the CPFCrequirements shows the following. The curves of tran-sients in the power unit output obtained for a 10%change in the load are in full conformity with the SPFCrequirements in case of a 5% change in the load evendespite the fact that the turbines are equipped withhydraulic CLCSs.

Finally, the experience gained at Interavtomatikashows that whether or not the ASFC requirements arefulfilled depends on the same factors that affect the sec-ond indicator characterizing the dynamics of SPFC: thetime taken for the process to fit into the range ±1%Nnom; i.e., this depends to a lesser extent on how linearthe turbine’s static characteristic is and to a greaterextent on the boiler dynamic characteristics and howperfect the FPCS is.

CONCLUSIONS

(1) It has been demonstrated that the requirementsthe SO–CDA Standard places on the conditions underwhich power units can participate in SPFC and ASFCmay really be fulfilled in Russian power units with dif-ferent types of equipment. The one-and-a-half yearsthat have passed since the time the Standard was put inforce saw Standard conformity certificates to have beenissued for eight power units equipped with FPCSs ofInteravtomatika.

(2) The necessary conditions for developing FPCSsconforming to the SO–CDA Standard consist of retro-fitting the turbine CS, in the course of which a micro-processor-based system has to be installed instead of ahydraulic one; upgrading considerably the boiler’sCLCS; and implementing the FPCS unit part and a sys-

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DEVELOPMENT AND APPLICATION OF AUTOMATIC FREQUENCY 837

tem for taking ACDs into account. The FPCS itselfshould be furnished with a well-developed operatorinterface and an engineering system.

(3) The optimal solution consists of implementingall FPCS elements on the basis of a single I&C system.

(4) The unit-level part of the FPCS is made as ahybrid structure in which the solutions used in two well-known approaches, namely, SAUM-1 and SAUM-2, arecombined, and the configuration of this structure anddynamic characteristics of its units are automaticallychanged depending on the operating conditions.

(5) The quality of the dynamic characteristics withwhich the SPFC and ASFC setpoints are responded todepends on how linear the turbine control characteristicis and on the boiler’s dynamic characteristics. Thehigher the capacity of the boiler or its individual flows,the more difficult it is to fulfill the SPFC requirements:a higher boiler forcing ratio is required, the FPCS tun-ing becomes more complicated, and the effect of ACDsbecomes stronger in nature.

(6) We consider it advisable that coal-fired powerunits be involved in solving the tasks of SPFC andASFC, primarily those with a relatively small capacity,since the problems that have to be solved for achievingthe characteristics complying with the SPFC and ASFCrequirements when a shift is made from gas-and-oil-firedunits to coal-fired ones are much less complicated thanthose in case of shifting to units of a larger capacity.

REFERENCES1. N. I. Davydov, A. D. Melamed, M. D. Trakhtenberg, and

L. P. Fotin, “An Automatic Frequency and Power Control

System for Unit-Type Thermal Power Stations Equippedwith Once-Through Boilers,” Teploenergetika, No. 8, 2–6(1979) [Therm. Eng., No. 8 (1979)].

2. Norms for the Participation of Power-Generating Unitsat Thermal Power Stations in Selective Primary andAutomatic Secondary Control of Frequency: A SO-CDAStandard (Moscow, 2005) [in Russian].

3. V. A. Bilenko, A. D. Melamed, and O. A. Manevskaya,“Results from Tests of the Systems for AutomaticallyControlling the Frequency and Power of the PGU-450Power Unit at the Kaliningrad TETs-2 Cogeneration Sta-tion, Teploenergetika, No. 10, 52–60 (2008) [Therm.Eng., No. 10 (2008)].

4. I. Z. Chernomzav and K. A. Nefedov, “Improvement ofSystems for Automatically Controlling Large-CapacitySteam Turbines,” Teploenergetika, No. 10, 27–33 (2008)[Therm. Eng., No. 10 (2008)].

5. V. A. Bilenko, N. N. Derkach, E. E. Mikushevich, andD. Yu. Nikol’skii, “Development and Commissioning ofSystems for Controlling the Main Parameters of theBoiler in the Process Control System of a 500-MWPower Unit at the Reftinsk District Power Station, Tep-loenergetika, No. 10, 2–10 (1999) [Therm. Eng., No. 10(1999)].

6. V. V. Belyi, Yu. A. Kiselev, V. A. Savost’yanov, et al.,“Upgrading the Automatic Process Control Systems ofthe 800-MW Power Units at the Berezovo GRES-1 Dis-trict Power Station,” Elektr. Stn., No. 1, 49–52 (2004).

7. V. A. Bilenko, E. E. Mikushevich, D. Yu. Nikol’skii,et al., “Improvement of Systems for Automatically Con-trolling the Process Parameters of Power Units,” Tep-loenergetika, No. 10, 34–44 (2008) [Therm. Eng., No. 10(2008)].

838

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 838–845. © Pleiades Publishing, Inc., 2008.Original Russian Text © I.Z. Chernomzav, K.A. Nefedov, 2008, published in Teploenergetika.

Microprocessor-based systems for closed-loop con-trol of steam turbines are developed with the purpose ofsettling matters related to involvement of power units inefficient control of frequency in a united power grid.The main task of such control systems consists ofimproving the static and dynamic characteristics of tur-bines as controlled plants to obtain a better response tofrequency deviations and, consequently, to make themmore maneuverable. This task also has to be solved inview of the need to minimize frequency deviations in acomplex power grid featuring a variety of normal oper-ating conditions. Using microprocessor-based turbinecontrol systems on a wide scale is also advisable inview of the conditions of power grid operation underwhich deviations from their normal modes occur orwhen power system stability is lost. Deviations fromthe normal operating conditions of a complex powergrid are usually connected with the occurrence of activepower imbalances in its individual parts. Disconnectionof some region and local failures are the most commonfactors due to which frequency deviations occur.

The main task imposed on the power units operatingin such a system or near load centers in which an imbal-ance has occurred is to take an active part in compen-sating for the occurred imbalance of active power andin efficiently stabilizing the network frequency. Howrapidly the network frequency is restored depends onthe parameters of the power grid, as well as on the abil-ity of power units to promptly and adequately respondto frequency deviations. How efficiently this task issolved at the power unit level depends on the mainequipment’s dynamic and static characteristics and onthe selected setpoint parameters of the system forclosed-loop control of the frequency and power of theentire power unit.

Attempts to solve the problem of actively involvingpower units in selective primary control of network fre-quency were made after certain directive documentsappeared, among which was the Standard of the Sys-

tem-Operator – Centralized Dispatching Administra-tor (SO–CDA) of the Unified Energy Systems (theSO–CDA Standart) [1]. These documents specified cer-tain requirements for the systems used to control largeturbines and for the processes in accordance with whichthe power unit outputs must be changed in response tochanges in the network frequency. If we succeed inbringing power stations into compliance with theserequirements, this should allow us to reduce the proba-bility that an emergency situation may occur in powergrids and minimize possible damage inflicted to con-sumers.

The requirements specified in the SO–CDA Stan-dard demand that the turbine control systems mustallow a dead band to be set up (

±

10 mHz) and the droopto be adjusted in the online mode (in the range from 4to 6%). The parameters characterizing the response ofa power unit to a stepped change in the frequency mustbe as follows: 50% of the required change in the poweroutput must be achieved within 10 s and 100% of thischange, within 30 s with a 5% power margin, andwithin 2 min with a 12.5% margin. The most importantprerequisite for fulfilling the requirements of the SO–CDAStandard is that the turbine load characteristic should belinear, a condition that allows the same change in thepower output to be obtained in response to the same devi-ation of frequency in any range of loads. It is difficult tofulfill these requirements unless the turbine control systemis constructed with the use of microprocessors and unlessits hydraulic part is retrofitted.

ALTERNATIVE VERSIONS USING WHICH HYDRAULIC CONTROL SYSTEMS

CAN BE RETROFITTED

Interavtomatika specialists have developed the fol-lowing alternative versions for upgrading the hydrauliccontrol system of 300- and 800-MW turbines of Lenin-grad Metal Works (LMZ):

Improvement of Automatic Control Systems for Large-Capacity Steam Turbines

I. Z. Chernomzav and K. A. Nefedov

ZAO Interavtomatika, ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

Abstract

—We present the structures of microprocessor-based control systems we have developed for steamturbines. We also present the results from tests carried out on 300- and 800-MW power units with turbinesequipped with upgraded control systems, and these results confirm that this equipment complies with the require-ments the SO–CDA Standard places on selective primary control of the grid frequency.

DOI:

10.1134/S0040601508100042

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IMPROVEMENT OF AUTOMATIC CONTROL SYSTEMS 839

(i) an alternative in which the hydraulic elements aredisplaced to the maximum extent and with individualcontrol of each servomotor; and

(ii) an alternative in which hydraulic elements arepartially displaced.

These alternate versions of improving the steam tur-bine control systems are aimed at excluding certainhydraulic parts from operating at low pressure and con-taining mechanical links, the characteristics of whichvary during operation.

The scope of main changes made to the hydraulicpart of the turbine control system upgraded accordingto version 1 includes the following:

(i) the mechanical–hydraulic device for controllingthe rotation frequency has been replaced by an elec-tronic one;

(ii) the existing unit of speed governor slide valves(SGSVs) has been upgraded with retention of the func-tions of generating the pressure for cocking the safetycontroller’s slide valves, the control pressure for thestop valves, and the control pressure for the intermedi-ate slide valve (the SGSV unit as a hydraulic amplifierin the rotation frequency control loop has beenexcluded);

(iii) a toothed wheel is installed on the turbine shaftfor measuring the current rotation frequency and high-precision frequency rotation sensors are placed on afixed bracket;

(iv) in addition to a mechanical overspeed governor,the turbine is furnished with electronic overspeed pro-tection (an electronic overspeed governor);

(v) the turbine control mechanism’s electric motor isretained for remotely or automatically cocking theoverspeed governor slide valves (OGSVs), opening thestop valves when the turbine is started, and creating thepressure acting on the isolating slide valves of the ser-vomotors of the high- and intermediate pressure cylin-ders' (HPC and IPC) control valves only to perform theprotection function;

(vi) the intermediate slide valve is excluded from therotation frequency control loop and retained as a mem-ber that helps obtain the required response speed ofcontrol valves for closing when the protection comesinto action;

(vii) the electrohydraulic converter (EHC) isexcluded from the circuit for controlling the position ofcontrol valves; and

(viii) the servomotors driving the HPC and IPC con-trol valves are retrofitted so that electromechanical con-verters (EMCs) can be installed. Mechanical feedbackto the isolating slide valves is excluded.

Each servomotor driving the control valves of thehigh- and intermediate-pressure parts is furnished withposition sensors, which are required to perform posi-tioning functions. Control pressure is fed to each servo-motor of the discharge valve from the chamber underthe piston of the servomotor driving the IPC control

valve situated on the same side with respect to the tur-bine axis.

Thus, elements operating under a reduced pressureof control fluid, an area containing the majority ofdead-band sources of the control system, have beenexcluded from the control system’s hydraulic part andonly the actuating part remains in operation: the unit ofisolating slide valve and the control valve’s servomotor,an item which features the best combination of qualityindicators: a high moving force and small travelingtime.

The control pressure generated by the intermediateslide valve causes the isolating valve to remain in thesame position, which sits on the stop during normaloperation modes.

The EMCs are controlled using a special unit thatreceives the output signal from the microprocessor partof the control system. A change in the position of theisolating sleeve’s axle, which is made by means of theEMC, causes the servomotor to shift. Hence, the mov-able axle must take the same (shutoff) position understeady operating conditions irrespectively of the tur-bine load.

The list of functions imposed on the microprocessorpart of the control system includes the following:

(i) measuring the turbine shaft rotation frequency;(ii) generating the control deviations of rotation fre-

quency for the speedup governor and the rotation fre-quency governor;

(iii) generating the generalized setpoint for the posi-tion of control valves (

H

t

);(iv) generating the control deviations for the turbine

unit power output, the position of control valves, andthe pressure of live steam (

p

l.s

) upstream of the turbineto implement the functions of the turbine power con-troller (TPC);

(v) generating signals for the emergency controlsystem (ECS);

(vi) generating the control system for positioningthe servomotors;

(vii) carrying out diagnostics of the entire controlchannel of each servomotor, including the control unitand the EMC itself;

(viii) carrying out automatic parameterization of theextreme positions of servomotors; and

(ix) reciprocating the servomotors in an automatedmanner.

The function diagram of the turbine control systemincorporating a microprocessor part and a retrofittedhydraulic part with means for individually controllingthe servomotors of control valves is shown in Fig. 1a.

The resulting signal, which includes the frequencycontrol deviation generated by the frequency controllertaking into account the droop and the signals from theTPC and ECS, is a generalized signal assigning theposition of control valves. The nonlinear characteristics

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of valve position are specified as functions of the gen-eralized control signal and can be tuned, if necessary, toobtain a linear turbine loading characteristic. Each ser-vomotor is controlled by means of a positioning device,the output signal of which specifies a setpoint for theEMC control unit. Such a solution makes it possible tocontrol the position of control valves with high speedand accuracy and minimize or exclude completely theirpulsation.

The scope of retrofitting the hydraulic part of theturbine control system in accordance with version 2[this has been implemented in the 300-MW unit No. 8at the Konakovo district power station (DPS)] includesthe removal of the hydraulic links used to control theintermediate slide valve. The slide valve remains in thecontrol system loop for generating the control pressure(

p

cntr

) that determines the position in which the controlvalve servomotors must be placed. The intermediate

Rotationfrequency

measurement

Speedupgovernor

Rotation frequencygovernor

Control deviations of the turbinegenerator power output,

live steam pressure, and position of control valves

Turbine powercontroller

Automatic emergencycontrol system

Generation of the generalized

setpoint

Devices for positioningthe control valves

Diagnostics and initialization

of each EMCParameterization

of positionsensors

for each CV

EMCfor CV-1of HPC

CV-1of HPC

EMCfor CV-7of HPC

CV-7of HPC

EMCfor CV-A

of IPC

CV-Aof IPC

EMC

CV-B

for CV-Bof IPC

of IPC

(a)

Rotationfrequency

measurement

Speedupgovernor

Rotation frequencygovernor

Control deviations of the turbine generator power

output, live steam pressure, and position of control valves

Turbine powercontroller

Automatic emergencycontrol system

Generation of the generalized

setpoint

Device for positioningthe intermediate

slide valveDiagnosticsand initialization

of each EMCEMC

Intermediateslide valve

CV-1of HPC

CV-2of HPC

CV-7of HPC

CV-Aof IPC

CV-Bof IPC

(b)

Fig. 1.

Function diagrams of the control system. (a) Version 1 and (b) version 2; CV—control valve, HPC—high-pressure cylinder,IPC—intermediate-pressure cylinder.

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slide valve is controlled and placed in the required posi-tion by means of one EMC. The feedbacks of all servo-motors remain unchanged. The function diagram of thiscontrol system is shown in Fig. 1b (version 2). As inversion 1, this system uses the same algorithm for gen-erating the generalized setpoint. This setpoint is ful-filled precisely by properly positioning the intermediateslide valve. The required operational reliability of thecontrol system is achieved by furnishing the intermedi-ate slide valve with two position sensors, the output sig-nals of which are checked for validity, and the maxi-mum one of the two is used in the positioning algo-rithm. Such a refurbishment makes it possible toexclude the major fraction of the control system’s deadband, which is lumped in the complicated design of theintermediate slide valve. A shortcoming of this versionis that the microprocessor part of the control systemcannot be used to linearize the turbine loading charac-teristic. This can only be done by setpoint the mechan-ical part of the control system. The advantage of thisversion is that it is simple and cheap.

Version 1 was also used for retrofitting the 300-MWturbines of OAO Turboatom (see Fig. 1a). However, thedesign of Turboatom’s steam admission system, inwhich one servomotor of the high-pressure part is usedto drive three control valves, does not allow the advan-tages of this version to be used completely. A linearloading characteristic for the turbines of this series cantherefore be obtained only by properly adjusting theposition of control valves.

Figure 2 shows the linearized loading characteristicsof the 300-MW unit No. 5 at the Iriklinsk DPS, the 800-MWunit No. 2 at the Perm DPS, and the 300-MW unit No. 5at the Stavropol DPS. A comparison of the curves pre-sented in the figure shows the advantage of using ofindividual means for controlling the control valves ofturbines at the Iriklinsk and Perm DPSs, in which therequired linearity of the loading characteristics hasbeen obtained. The linear characteristic of the turbine atthe Stavropol DPS was obtained after resetpoint themutual positions of the valve stems and the servomotorof the high-pressure part.

For the turbine at the Konakovo DPS to be retrofit-ted in accordance with version 2, the mechanical linksbetween each valve and its servomotor have to beadjusted to make the loading characteristic linear.

The reliability of the microprocessor system is a fac-tor that guarantees that the turbine loading characteris-tic will be stably linear in version 1. As regards the ret-rofitting version in which one servomotor is used tocontrol three valves or when the intermediate slidevalve’s EMC is used to control servomotors, the linear-ity of the loading characteristic depends on how stablethe characteristics of the steam admission system’smechanical elements are.

INSTRUMENTATION AND CONTROL FACILITIES FOR CONSTRUCTING

THE MICROPROCESSOR PART OF THE CONTROL SYSTEM

The approach Interavtomatika specialists follow inconstructing the electronic speed governors for the fre-quency and power control system (FPCS) and the pro-cess control system of a power unit consists in usingunified instrumentation and control facilities, such as

(i) the TPTS controller produced at VNIIA underlicense by Siemens; or

(ii) the Siemens SIMATIC PCS7 controller.

The use of the TPTS controller for constructing con-trol system became possible after ZAO Interavtomatikaspecialists, working jointly with VNIIA specialists,developed dedicated modules with an advanced speedof response for implementing the functions of calculat-ing rotation frequency, frequency controller, controlvalve positioning, and automatic emergency control.These were used to construct and put into operation themicroprocessor parts of the control systems for three800-MW turbines at the Perm DPS and two 300-MWturbines of Turboatom at the Stavropol DPS and at thethermal power station (TPS) in the city of Aksu. EMCsare used in these projects for introducing electrical sig-nals into the hydraulic part of the control system. Thesame facility was used, in combination with electrohy-draulic converters, to construct the control system forthe K-110 turbine of LMZ, which is used as part of thePGU-325 combined-cycle plant at the Ivanovo DPS.

The SIMATIC controller was used to construct andput into use the FPCSs and microprocessor parts of theturbine control systems for 300-MW power units at theIriklinsk DPS (four units), at the Kirishi DPS (twounits), and at the Konakovo DPS (one unit). The func-tions of frequency calculation, controlling, positioning,and automatic emergency control, for which a high

12

3

3

290

250

210

170

13050 60 70 80

800

700

600

500

400

300Act

ive

pow

er f

or K

-300

-240

, MW

Generalized setpoint for the control valves, %

Act

ive

pow

er f

or K

-800

-240

, MW

Fig. 2.

Loading characteristics of turbines. (

1

) The K-300-240LMZ turbine at the Iriklinsk DPS, (

2

) the K-800-240 LMZ tur-bine at the Perm DPS, and (

3

) the K-300-240 Turboatomturbine at the Stavropol DPS.

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speed of response is required, have been implementedusing a dedicated FM-458 module.

ASSESSING THE DEAD BANDS OF THE TURBINE CONTROL SYSTEMS

The dead bands of control systems were estimatedafter the turbine control systems used in power unitsequipped with FPCSs or full-scale process control sys-tems had been retrofitted. To do so, frequency devia-tions at which the turbine has to be unloaded were sim-ulated in the 300-MW unit No. 1 at the Iriklinsk DPSduring its operation at the 300-MW load. Stepped devi-

ations in the frequency with amplitudes from 0.5 to10 mHz were simulated together with the correspond-ing reduction in the generalized setpoint for the controlvalves, and the following parameters were recorded:the pressure in the control stage chamber

p

c.c

, the live-steam pressure

p

l.s

, the positions of the control valvesCV-5 and CV-6, and the generator power output

N

. Wesee from the processes shown in Fig. 3 that the controlvalves respond to frequency deviations in the rangefrom 2 to 4 mHz. A noticeable change in the live-steampressure in the control stage chamber, as well as achange in the generator power output, occurs when thefrequency deviates by 6 mHz. A similar changeoccurred in the position of the high-pressure part’s ser-vomotors during the experiments in the 300-MW tur-bine of Unit 5 at the Stavropol DPS in response to fre-quency deviations with an amplitude of 5 mHz.

Tests for checking compliance with the SO–CDAStandard must prove that the power output shows anoticeable change in response to simulated deviation offrequency by 10 mHz with a droop of 6%. Figure 4shows an example of such process that was obtained inthe 800-MW unit No. 1 at the Perm DPS. The require-ments the SO–CDA Standard places on the dead bandare fulfilled for all the considered versions for retrofit-ting the turbine control systems.

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15:21:00 15:24:18 15:27:36 15:30:54 15:34:12 15:37:30 15:40:48 15:44:06 15:47:24 15:50:42 15:54:00

1 2 3 4 5 6 7

1

2

3

4

5

6

7

Time, h : min : s

0.5 mHz2 mHz

4 mHz

6 mHz

8 mHz

10 mHz

Fig. 3.

Estimation of the dead band on the running power unit No. 1 with a K-300-240 turbine at the Iriklinsk DPS. (

1

) Generalizedsetpoint for the control valve

H

t

, %; (

2

) active power of the generator, MW; (

3

) live steam pressure, MPa; (

4

) pressure in the controlstage chamber, MPa; and (

5

)–(

7

) positions of the high-pressure part’s control valves Nos. 5, 6, and 7, %.

02:46:53 02:48:40 02:50:26 02:52:13 02:53:59

5

15

35

505

465

425

N

df

df

, mHz

N

, MW

Time, h : min : s

Fig. 4.

Variation in the power output of the 800-MW powerunit No. 1 at the Perm DPS in response to simulated devia-tion of frequency

df

=

±

10 mHz.

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IMPROVEMENT OF AUTOMATIC CONTROL SYSTEMS 843

CHECKING THE OPERATION OF THE FREQUENCY CONTROL SYSTEM

WITH DIFFERENT DROOP VALUES

The SO–CDA Standard demands that the operationof a control system be checked by simulating a steppedchange in the frequency for two values of the controlsystem droop equal to 4 and 6%. It has been adoptedthat a stepped change in the frequency must have differ-ent signs and must consist of three steps, and that themaximum increment of power must be equal to

±

5% of

the turbine’s rated power. The dynamic and static errorwith which the setpoint is followed must lie within

±

1%(the specified range) of the power unit rated capacity.

The power unit response is checked in the upper,lower, and middle parts of the control range. Figure 5shows the transients obtained for the 300-MW turbineof Unit 5 at the Iriklinsk DPS during its operation at aninitial load of 226 MW. We see that the required changein the power output is obtained with the specified droop

78767472706866646260585654525048464442403836343230

26.225.825.425.024.624.223.823,423.022.622.221.821.421.020.620.219.819.419.018.618.217.817.417.0

7472706866646260585654525048464442403836343230

25.024.624.223.823,423.022.622.221.821.421.020.620.219.819.419.018.618.217.817.417.0

25.4694625556487418349280211142734

–65–134–203–272–341–410–479–548–617–686–755–824–893–962

–1031–1100

288284280276272268264260256252248244240236232228224220216212208204200

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288284280276272268264260256252248244240236232228224220216212208204200

296292 694

625

556487418

349280211142734

–65–134–203–272–341–410–479–548–617–686–755–824–893–962

–1031–1100

763832

1 2 3 4

1 2 3 4

18:06:28 18:10:15 18:14:02 18:17:49 18:21:36 18:25:24 18:29:11 18:32:58 18:36:45 18:40:32 18:44:20

(a)

–40 mHz –70 –1100

+40 +70 +110 mHz

1

2

3

4

Time, h : min : s

Time, h : min : s

(b)

–60 mHz –110–160

0 +60 +110 +160 mHz

1

2

34

Fig. 5.

Variations in the power unit output in response to stepped changes in the frequency and with different droop values. Droop, %:(a) 4 and (b) 6; (

1

)

N

, MW; (

2

)

df

, mHz; (

3

)

p

l.s

, MPa; and (

4

)

H

t

, %.

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value and with the simulated deviation of frequency inaccordance with the SO-CDA Standard.

ESTIMATING THE MANEUVERABILITY OF TURBINES WHEN FREQUENCY

DEVIATIONS OCCUR

The use of the microprocessor part of the controlsystem in combination with its retrofitted hydraulic partallows the control commands to be followed accuratelyand with high speed of response. This conclusion fol-lows from the tests carried out in some power unitsequipped with 300- and 800-MW LMZ and Turboatom

turbines, the results of which have confirmed that therequirements of the SO-CDA Standard are compliedwith [2]. Changing the turbine power in a fast and pre-cise manner allows its output to be brought within thespecified range of values irrespective of the sign withwhich the disturbance is applied; 50% of the requiredchange is achieved in 10 s, and 100% in 30 s. When anemergency deviation of the frequency occurs, the fullrequired change in the power output must be achievedin 2 min [1]. A typical example of the transient trig-gered when an emergency stepped change in the fre-quency by 12.5% occurs is given in Fig. 6, which showsthe curves obtained for the 800-MW unit No. 3 at thePerm DPS, at which the 100% change in the power out-put is achieved, in accordance with the requirements ofthe SO–CDA Standard, within 2 min.

PARTICIPATION OF POWER UNITS IN SPFC

Tests carried out during continuous operation of apower unit with a dead band equal to

±

10 mHz at a loadequal to its rated value make it possible to estimatewhether the requirements of the SO–CDA Standard canbe complied with. The transient curves shown in Fig. 7depict variations in the parameters of the 300-MW unitNo. 7 at the Iriklinsk DPS in an interval of time equalto 45 min. When actual deviations of the frequency inthe power grid occur both toward increasing anddecreasing with respect to the

±

10 mHz dead band,control commands for the turbine control valves aregenerated, and the boiler load setpoint is changed whenthe power controller is in operation. Displacements of

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5:00

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0:00

14:1

3:00

14:1

6:00

14:1

9:00

N

, MW

p

l.s

, MPa

Time, h : min : s

p

l.s

N

Fig. 6.

Transient change in the power output by 100 MW inresponse to a stepped change in the frequency.

3002

3001

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2999

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2997

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1

2

3

4

5

6

7

8

Time, h : min : s

+10 mHz

–10 mHz

Fig. 7.

Participation of power units in SPFC (

1

)

N

, MW; (

2

)

p

l.s

, MPa; (

3

)

H

t

, %; (

4

)

p

c.s

, MPa; (

5

) CV-5, %; (

6

) CV-6, %; (

7

) CV-7, %;and (

8

) turbine rotation frequency

n

, rpm.

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control valves Nos. 5 and 6, changes in the live steampressure, and, accordingly, in the generator power out-put are clearly recorded. The transients are stable, andthe parameters vary within the permissible limits;hence, the power unit can be involved in participationin SPFC.

Analysis of the results obtained from the tests of aturbine control system that incorporates a microproces-sor part and a hydraulic part retrofitted in accordancewith versions implying different degrees to which itsmechanical and hydraulic elements are displacedallows the following conclusions to be drawn.

(1) Retrofitting the control systems of turbines withindividually governing control valves in accordancewith version 1 is the optimal choice with respect to thefollowing criteria:

(i) the minimal dead band can be obtained;(ii) it offers the best conditions for making the load-

ing characteristic linear with the use of the micropro-cessor part;

(iii) it allows the maximum possible traveling speedof control valves to be obtained with the minimal over-shoot; and

(iv) it allows the oscillations of servomotors (valves)to be minimized or eliminated under steady operatingconditions.

(2) Retrofitting a control system in which one servo-motor is used to govern a group of control valves has allthe above-mentioned advantages except with the possi-bility of linearizing the loading characteristic using themicroprocessor part. There are also certain constraintson reciprocating the control valves.

(3) Retrofitting a control system equipped with anEMC-controlled intermediate slide valve does notallow a microprocessor system to be used for lineariz-ing the loading characteristic. The hydraulic linesthrough which signals from the intermediate slide valve(control pressure) are transmitted to the servomotors'shutoff valves impose limitations on the maximum pos-sible speed with which the servomotors can move. Despitethese constraints, all requirements of the SO–CDA Stan-dard, including those for the dead band, are fulfilled.

Work on putting into use the microprocessor parts ofthe turbine control system was carried out in parallelwith development of FPCSs or process control systems in11 power units. Tests for conformity with the SO–CDAStandard have by the present time been carried out in

nine power units, and the power stations have alreadyreceived certificates of conformance for them.

CONCLUSIONS

(1) The developed microprocessor parts of steamturbine control systems, taken in combination withtheir retrofitted hydraulic parts, make it possible tooperate with a dead band of

±

10 mHz and operativelychange the droop. The static and dynamic characteris-tics of a steam turbine equipped with such a control sys-tem comply with the requirements of the SO–CDAStandard.

(2) The developed versions for retrofitting thehydraulic part of a control system imply differentdegrees to which the hydraulic elements are displacedfor minimizing the dead band.

(3) As regards turbines the control valves of whichare individually governed, their loading characteristiccan be linearized in the microprocessor part of the con-trol system. When frequency deviations occur, the errorwith which the turbine power output is changed withboth signs does not exceed 1% of the rated power. If aturbine is equipped with servomotors that drive a fewcontrol valves, the mechanical links of this group ofvalves need to be specially adjusted to obtain a linearloading characteristic. If an EMC-driven intermediateslide valve is used to control the servomotors, all thecontrol valves must also be adjusted to obtain a linearloading characteristic.

(4) The tests carried out in accordance with the cer-tification program have shown that development ofmicroprocessor parts for the turbine control systems isthe necessary condition for bringing power units incompliance with the requirements of the SO–CDAStandard.

REFERENCES

1.

Norms in Accordance with Which the Power Units ofThermal Power Stations Should Participate in SelectivePrimary and Automatic Secondary Control of the Fre-quency: a Central Dispatch Board’s Systems Depart-ment Standard

(Moscow, 2005) [in Russian].2. V. A. Bilenko, A. D. Melamed, E. E. Mikushevich, et al.,

“Development and Application of Automatic Frequencyand Power Control Systems for Large Power Units,”Teploenergetika, No. 10, 14–26 (2008) [Therm. Eng.,No. 10 (2008)].

846

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 846–858. © Pleiades Publishing, Inc., 2008.Original Russian Text © V.A. Bilenko, E.E. Mikushevich, D.Yu. Nikol’skii, R.L. Rogachev, N.A. Romanov, 2008, published in Teploenergetika.

Systems for closed-loop control of process valuesare the basic element of facilities using which auto-matic control of power units is performed during theiroperation at working loads and during operations forstarting them up or shutting them down. Much attentionhas always been paid in Russian power engineering toactivities aimed at improving the configuration of pro-cess closed-loop control systems (CSSs) and adaptingthem for new process circuits and operating conditionsof power units. One factor that retarded progress in thisfield was the use of out-of-date analog controllers,facilities poorly adapted for possible extension of thefunctional capacities of CLCSSs. A changeover tomicroprocessor equipment and widespread use of distrib-uted microprocessor automatic process control systems(CLCSs) that have been seen in the last 10–15 years arethe factors due to which much improvement has beenmade in the function diagrams of CLCSs, they havebecome more reliable and immune to failures, and bet-ter quality of control processes has been achieved.

This paper presents the results obtained from workon developing and putting into use systems for closed-loop control of the main process values of Russianpower units, during which their monitoring and controlsystems were fully or partially upgraded on the basis ofprogramm instrumentation and control systems(I&CSs) developed by Siemens: TELEPERM XP-R,SIMATIC PCS7-PS, and SPPA-T3000. The main atten-tion is paid to the CLCSs of traditional power unitsequipped with once-through boilers. The analysis thathas been carried out was based on the experience wegained from activities on putting CLCSs in use in coal-fired units, among which were 800-MW units nos. 1and 2 at the Suizhong thermal power station (TPS) inChina and the Berezovo district power station (DPS),500-MW units nos. 7–10 at the Refta DPS, and 300-MWunits nos. 3 and 4 at the TPS of the city of Aksu inKazakhstan and unit no. 8 at the Zmievka TPS in theUkraine, and gas-and-oil-fired 800-MW units nos. 1

and 2 at the Perm DPS, 300-MW unit no. 5 at theStavropol DPS, units nos. 1–5 at the Iriklinsk DPS, unitno. 8 at the Konakovo DPS, unit no. 10 at the Sredneu-ral’sk DPS, and units nos. 2 and 4 at the Kirishi DPS.We are grateful to the management and leading special-ists of these power stations for creative participationand help in organizing these activities.

THE CAPABILITIES OF MODERN I&CS FOR IMPROVING THE CLCS OF POWER UNITS

Modern I&CSs, in particular, the above-mentionedmicroprocessor control systems of Siemens used atInteravtomatika, have advantages that allow the CLCSsof power units to be improved to an extent much greaterthan the level that can be achieved through the use oftraditional facilities and first-generation microproces-sor-based systems. The list of these advantagesincludes the following.

(1) The new equipment is extremely reliable and hasin-depth self-diagnostic features, properties due towhich complex, multiply connected, and fully variableCLCS structures can be constructed in such a way thata failure of their elements, especially an undetectableone, is an extremely unlikely event.

(2) The new equipment has highly developed basicsoftware, using which virtually any physically execut-able logic of automatic control with the required vol-ume of dynamic and logic processing can be imple-mented.

(3) the new equipment has facilities for comprehen-sively diagnosing the CLCS peripheral equipment, likesensors, drives, and actuators, which generate the nec-essary information about deviations that has occurredand allow the necessary changes to be made in theCLCS structure.

Improvement of Process Closed-Loop Control Systems for Power Units

V. A. Bilenko, E. E. Mikushevich, D. Yu. Nikol’skii, R. L. Rogachev, and N. A. Romanov

ZAO Interavtomatika (Interautomatika AG), ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

Abstract

—We describe the results of activities carried out at ZAO Interavtomatika (Interautomatika AG) onthe development and putting into use of improved systems for closed-loop control of the main process valuesof Russian power units equipped with once-through boilers. We also consider a general approach for improvingcontrol systems and describe specific technical solutions taken for furnishing the main technological items ofcoal- and gas-and-oil-fired power units with closed-loop control systems.

DOI:

10.1134/S0040601508100054

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(4) the new equipment allows a subject-orientedoperator interface to be developed, which includes thefollowing features:

(i) various forms of information indicating how wellthe CLCSs operate and possible malfunctions in theiroperation;

(ii) online and offline (postoperation) displaying ofcurves graphically illustrating trends in groups of inter-related process values, control elements positions, andinternal variables of CLCS algorithms;

(iii) online presentation of the function diagrams ofCLCS algorithms with the current values of their exter-nal and internal variables;

(iv) automatic generation of logs for the entire list ofevents related to the CLCS operation, including theactions of operative personnel on switching on/off theCLCSs or changing their configuration;

(v) construction of video frames with a combineduse of different forms in which data on the CLCS oper-ation is displayed;

(vi) construction of the man–machine interface insuch a way that operative or maintenance personnelhave the possibility to change the configuration ofCLCS within predetermined limits in order to ensure theiroperability when nonstandard situations occur; and

(vii) the availability of highly developed engineer-ing facilities that allow changes in the CLCS functiondiagrams and their video frames to be made in a rapidand efficient manner and download these corrections inthe I&CS in the online mode on the running equipment.

Thus, modern I&CSs offer possibilities for makingCLCS algorithms much more sophisticated and theprocedures for adjusting them considerably simpler, formonitoring the operation of controllers in clear form,and for correcting their operation when off-design situ-ations occur.

MAIN LINES OF ACTIVITIES FOR IMPROVING THE QUALITY OF CONTROL PROCESSES

The main tendency seen in the way in which theCLCSs of power units are improved consists of improv-ing the quality with which a power unit’s load and mainvalues are maintained with simultaneously minimizingthe volume in which operative personnel participate indirect control of both control elements and controllerssetpoints. First of all, this relates to the load controlrange: from 50 (40) to 100% for gas-and-oil-firedpower units and from 70 (60) to 100% for coal-firedones. It is already at this point that any change in theload should be carried out automatically. Among thefactors that generate the need to do so are that a powerunit involved in common primary frequency control(CPFC) must comply with certain requirements, thatthe actual load curve is essentially nonuniform, thatstringent commercial requirements are placed on theaccuracy with which it must be maintained (

±

1% of the

rated load), and that a large number of power units willin the future have to participate in the selective primaryand automatic secondary control of frequency (SPFCand ASFC, respectively) [1]. It should be pointed outthat the serious penalties power stations have to pay fordisconnection of power units generated the need to takemeasures for ensuring an automatic emergency powerunit unloading system (AEUS) be operable.

It is extremely important that these requirementsmust be fulfilled continuously during long-term opera-tion of a power unit. Therefore, all possible occurrencesof technological constraints or failures of individualitems of process equipment and functional failures ofCLCS peripheral equipment must be responded to withminimal possible disturbances to the power systemassignments and degradation in the quality with whichthe internal values of a power unit are maintained.

The following are the general avenues in which thefunctional capabilities of systems for closed-loop con-trolling the process values of power units are perfected.

(1) Automatically generating the optimal setpoint oftechnological values through the use of cascade closed-loop controllers, analog dependences of operating val-ues (vs. the load, pressure, etc.), signals bearing infor-mation on the quantitative composition of auxiliaryequipment (burners, mills, and fans), and logic condi-tions characterizing the operating regimes.

(2) Improving the control algorithms used in localsystems for closed-loop controling inertial process val-ues (primarily, temperatures) through the use of simpli-fied models of controlled sections. Not only does itallow PID and more complex control laws to beobtained in classic two-loop CLCSs, but it also allowsadditional control loops to be introduced, e.g., in localsystems for closed-loop control of temperatures bymeans of injections fed in between the sections ofsteam superheaters, or multiloop CLCSs to be con-structed by combining several local CLCSs when indi-vidual injections are taken out from operation.

(3) Neutralizing the mutual influence of localCLCSs by adding compensating branches (dynamicfunctions) in between them. The use of such solutionsallow control channels to be dynamically decoupledfrom each other and better quality of transients to beobtained for typical disturbances, primarily, whenchanges in the load occur. A correct choice of decou-pling methods, i.e., the ways in which compensatingbranches are connected, helps simplify the setpoint ofthe entire multiply connected CLCS of a power unit,which boils down in this case to a sequence of operationsfor adjusting and putting in operation local CLCSs with-out the need to use iterative procedures [3, 4].

One efficient way in which multiply connectedCLCSs comprising similar local CLCSs can be decou-pled consists of designing closed-loop controllers forthe total (or averaged) and differential deviations of thecontrolled quantities [5].

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(4) Automatically changing the structure of CLCScircuits when changes occur in the operating conditionsof the equipment, when “automatic process control isdisabled” states arise, or when functional failures ofCLCS peripheral equipment occur:

(i) replacing the main or additional values in accor-dance with logic conditions or by detecting the minimalor maximal deviations between their specified andactual values;

(ii) adding, excluding, or changing additional con-trol loops in local CLCSs; and

(iii) reconfiguring the structure of interconnectedlocal CLCSs, including the so-called reversal logic con-cept [6].

(5) Making wide use of means for automaticallytuning dynamic characteristics of local CLCSs (mastercontrollers, slave controllers, and differentiators) anddynamic function units inserted in between them takenin combination with using closed- and open-loop con-trol laws in accordance with which the control outputsare generated (in the first case, in response to changesin the operating conditions with the same configurationof the CLCS, and in the second case, when changes aremade in its configuration).

(6) Making CLCSs more immune to failures bytimely diagnosing the failures of sensors and actuatorsand choosing the appropriate configuration of a givenCLCS and/or the local CLCSs connected to it (see point 4).

MAIN SOLUTIONS TO THE CONFIGURATION OF CLCS FOR POWER UNITS EQUIPPED

WITH ONCE-THROUGH BOILERS

A power unit’s CLCS includes a unit part, whichperforms the functions of a frequency and power con-trol system (FPCS), and CLCSs for individual units ofthe boiler and turbine. The number of automatic con-trollers used in large power units with capacities of300-, 500-, and 800-MW runs as many as 100–200.Some of these controllers, primarily those for turbineand auxiliary equipment, have very simple single- ortwo-loop configurations (in the latter case, they use asupplementary signal for the position of a control ele-ment), and the development of such controllers usuallydoes not give rise to any essential problems. As regardsthe technological systems of a boiler, the majority haveto be furnished with complex CLCSs interconnectedwith one another and with the boiler and turbine powercontrollers (BPC and TPC), which are part of the fre-quency and power control system (FPCS) [1]. Below,we will address the problem of selecting the optimalstructural solutions for the CLCSs of the boiler as awhole and of its individual units, placing emphasis ononce-through boilers as apparatuses much more com-plex from the viewpoint of their control.

The outline function diagrams of CLCSs for a once-through boiler are shown in Fig. 1. A problem that has

always been of fundamental importance in constructingCLCSs for a once-through boiler is how to distributethe functions between the CLCSs for feed and fuel,namely, which will control the load and which will con-trol the temperature conditions along the boiler pathupstream of the first controlled injection [7, 8]. Accord-ing to the approach that was followed in the Russianpower engineering for a long time, the feed-water flow-rate controller was used as a load controller in coal-fired boilers (so-called scheme 1; see Fig. 1a), whereasthe fuel controller was used to perform these functionsin gas-and-oil-fired boilers (scheme 2; see Fig. 1b). Asis well known, the zone in which guaranteed steamsuperheating is ensured (in which the temperature mea-surement point has to be selected to control the water tofuel ratio) in the coal-fired once-through boilers of 500-and 800-MW power units is situated at a considerabledistance from the beginning of the steam–water path.Since this circumstance gave rise to certain difficultiesin controlling these boilers, a tendency emerged in the1980s and 1990s of using scheme 2 for coal-fired boil-ers, which, however, has not received wide use in prac-tice. It should be pointed out that thermal power sta-tions outside Russia also use two alternative solutionsfor the distribution of functions between the feed waterflowrate and fuel controllers. In Germany, a country inwhich once-through boilers have received the widestuse in Europe, scheme 2 is used irrespective of whichkind of fuel is fired. Power stations in the United States,the fraction of once-through boilers at which is smaller,usually apply scheme 1.

One important advantage of scheme 1 is that its useresults in more favorable dynamics of temperature sig-nals at intermediate sections of the boiler path in caseof disturbances in fuel flowrate as compared withchanging feedwater flowrate; this difference tends toincrease as the load decreases, a feature characteristicfor the majority of boilers. This advantage makesscheme 1 [8] considerably more profitable in terms ofthe quality with which a multiply connected CLCS con-trols the temperature of steam, power unit output, andpressure of steam upstream of the turbine as comparedwith scheme 2, especially for disturbances in the supplyof fuel, which cannot be intercepted by means of a sig-nal used as an indicator of fuel flowrate. As regardscoal-fired boilers, apparatuses in which disturbances inthe fuel feed channel occur in relatively frequent occa-sions, and the values of which do not always corre-spond accurately enough to variations in the signalreflecting the fuel flowrate, the dynamic advantages ofscheme 1 are obvious. An argument in favor of usingscheme 2 for coal-fired boilers is that disabling of auto-matic control for increasing process values, which ariserather frequently when dust systems (for boilers withdirect injection) or dust feeders (for boilers with anintermediate hopper) are shut down, can be taken intoaccount in a convenient manner. Scheme 2 generates aresponse to such disturbance by means of the initial

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structure of the boiler CLCS, whereas scheme 1 needs tobe reversed; i.e., the output from the fuel controller mustbe switched over to the feed-water flowrate CLCS.

The use of scheme 2 for gas-and-oil-fired boilerswas given preference in order to exclude unnecessaryinfluence of the control system on the flowrate of fuelas a consequence of sufficiently stringent requirementsplaced on the quality of the combustion process, on onehand, and since there are no special factors that would

cause the occurrence of fuel disturbances, on the otherhand. These arguments sounded convincingly becausepower units operated at that time predominantly in thebase load mode.

One more argument in favor of using scheme 2 forgas-and-oil-fired boilers is that most of these boilershave a two-flow steam–water path while beingequipped with only one control valve for controllingfuel flowrate. In this case, scheme 2 is implemented

Fig. 1.

Outline function diagrams of the CLCSs for coal-fired (a) and gas-and-oil-fired (b) once-through boilers. BLSA—Boilerload setpoint adjuster, FSA—fuel flowrate setpoint

G

f.ref

adjuster, FWSA—total feedwater flowrate setpoint

W

Σ

ref

adjuster, GAP—gas–air path, CEs—control elements, FDF—forced-draft fan, EF—exhaust fan, FGREF—flue gas recirculation exhaust fan,TFWP—turbine-driven feedwater pump, EFWP—electrically driven feedwater pump, CV—control valve, DS—dust system,SSHE—steam-to-steam heat exchanger, FCV—feed water control valve, and DC—dynamic function unit.

BLSA

FPCS

W

Σ

ref

FSA

G

f.ref

Fuel controller Feed CLCS

Generation

Controller Controllers

TFWP, EFWP

FCV

i

Dust system CMs

CLCS CLCS

Dust system CMs

CLCS of the GAP

Corrector Corrector

Air

Rare-

DC

DC

CLCS of livesteam

CLCS of the

CLCS of the

Temperature

EFD

i

FDF

i

Injection

CLCS of reheat steam

CLCS

Corrector

W

Σ

ref

of flowratedeviations

of

W

Σ

of

∆

W

i

of DS

1

of DS

2

of O

2

of

∆

t

f.g

Gene-

of setpointration faction

controller

controller

temperature

injectionoutlet temperature

outletinjection

corrector

of emergencyinjection

control valves

CLCSof SSHEbypass

of gas to fueloil pressure ratio

CV on thebypass

of SSHE

BLSA

FPCS

FSA

G

f.ref

Fuel controller Feed CLCS

Controller Controllers

CLCS of the GAP

Corrector Corrector

Air

DC

DC

CLCS of livesteam

CLCS of the

CLCS of the

Temperature

Injection

CLCS of reheat steam

CLCS

Corrector

of

W

Σ

of

∆

W

i

of O

2

of

∆

t

f.g

Rare-

controller

temperature

injectionoutlet

temperature

Controller

corrector

of emergencyinjection

control valves

Generation

of gas to fueloil pressure ratio

Temperaturecorrector

of setpoint

CorrectorFuel

Gas Fuel oil

Gas CV Fuel oil CVFDF

i

EFD

i

controller

of gasto fuel oil pressure

ratio

CLCSCLCS

Gene-ration

of setpointfaction

controller

Generatioof flowratedeviations

TFWP, EFWP

FCV

i

FGREF

i

of flue gasrecircu-lation

(a)

(b)

850

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directly: the controller of gas flowrate serves to controlthe load, and the device for controlling the flowrate offeedwater along the flow maintains its temperature con-ditions. If scheme 1 is used, the solution is not so seam-less: the load control function is imposed on the devicefor controlling the total flowrate of water in the flows;the function of maintaining the average temperatureconditions in the flow (e.g., the signals for the half sumof temperatures or the positions of injection valves) isimposed on the fuel flowrate controller; and the func-tion of controlling the difference between the indicatorsof temperature conditions, on the device for controllingthe difference of feedwater flowrates between theflows. For coal-fired boilers, the furnaces of which aresubdivided into two half-furnaces, and the flowrate offuel can be controlled individually in each of thesehalves, e.g., by separating the dust systems or dust feed-ers for the half-furnaces, the above-mentioned advan-tage of scheme 2 is not obtained.

Today, when the need has arisen to use power unitsunder essentially variable operating conditions, includ-ing their participation in CPFC and, very soon, in SPFCand ASFC, the approaches used previously have to berevised. Indeed, disturbances applied by changing theload are now becoming most essential and it is almostimpossible to keep the water-to-fuel ratio undisturbedduring them. The fact that the preferred method for cor-recting this ratio consists of changing the flowrate offuel makes the arguments in favor of using scheme 1more significant.

At the same time, most of the projects implementedby Interavtomatika specialists have been developed inaccordance with the approach adopted several decadesago: scheme 1 is used in all coal-fired power units andscheme 2 in all gas-and-oil-fired power units. Theabove-mentioned drawback scheme 1 has for coal-firedunits (frequently disabling automatic control for fuelflowrate need to be taken into account) has been over-come through the use of multiply verified structuralsolutions for taking “automatic control disabled” sta-tusesinto account, primarily by using the reversalarrangement; an example illustrating its operation isconstraints below. The positive results obtained fromputting scheme 1 in use, in particular, in the 500-MWpower units at the Refta DPS [9] and the 800-MW powerunits at the Berezovo DPS [10] have fully confirmed thatthe adopted decision was correct.

Whether the decision to use scheme 2 for gas-and-oil-fired units is correct or not is not so obvious. Indeed,the quality with which the temperature conditions weremaintained along the boiler path under such compli-cated conditions as tests for conformity with the Stan-dard of the System Operator – Centralized DispatchAdministration (SO–CDA) within the limits of emer-gency margin [1] or when the automatic emergencypower unit unloading system (AEUS) comes intoaction remained good for the majority of power facili-ties (examples will be given below). At the same time,

there were some cases, e.g., for PK-41 boilers, whichhave a remote transition zone, additional efforts onimproving the configuration of CLCS and carefullytuning them had to be taken to achieve acceptable qual-ity of control during operation under the above-men-tioned conditions, especially at low load. The use ofscheme 1 would in all likelihood make it possible toimprove the quality of control; however, in the opinionof the customers, such a considerable change in theapproach for boiler control may give rise to consider-able difficulties for the operating personnel, who havefor years been accustomed to another principle of con-trolling the process, in particular, due to the above-mentioned reasoning regarding the existence of twoflows of medium, in which the temperature conditionsmust be maintained, and that only one valve is availablefor controlling the supply of gas or fuel oil. This is whythe adopted scheme 2 was left unchanged.

IMPROVEMENT OF CLCSs FOR THE MAIN TECHNOLOGICAL SYSTEMS OF BOILERS

Generating the setpoints for water and fuel flow-rates.

The signal for the specified boiler load, which isin fact the setpoint value of the feedwater flowrate

W

Σ

ref

(see scheme 1 in Fig. 1a) or fuel flowrate (see scheme 2in Fig. 1b), is generated at the output of the boiler loadsetpoint unit (BLSU). When the power unit operates inthe range of working loads, the BLSU either passes theFPCS output signal or receives commands from theoperator. The setpoint value for the other main controloutput, i.e.,

G

f.ref

(scheme 1) or

W

Σ

ref

(scheme 2) is gen-erated in the corresponding unit: the fuel flowrate set-point unit (FSU) (see Fig. 1a) or feedwater flowrate set-point unit (FWSU) (see Fig. 1b).

These units perform the following functions:

(i) generating static characteristics for the setpointsignals for feedwater and fuel flowrates, which are non-linear in the general case;

(ii) changing this characteristics taking into accountthe current value of feedwater temperature

t

fw

;

(iii) generating a dynamic function to compensatefor the difference in the dynamics with which a signalcharacterizing the temperature conditions along theboiler path responds to disturbances in the feedwaterand fuel flowrates; and

(iv) adding the output signal from the temperaturemaster controller.

A CLCS of the supply of fuel in coal-fired boilers.

The problem of equipping the fuel feed unit of coal-fired boilers, primarily those with direct-injection dustsystems, had no finished solution in the Russian powerengineering until the mid-1990s. Interavtomatika spe-cialists have succeeded in solving this problem for coal-fired boilers equipped with different types of dust sys-tems:

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(i) boilers with hammer mills (the 500-MW powerunits at the Refta DPS and 300-MW power units at theTPS in the city of Aksu);

(ii) boilers with medium-speed mills (the 800-MWpower units at the Suizhong TPS); and

(iii) boilers with pulverizing fans (the 800-MWpower units at the Berezovo DPA and 200-MW powerunits at the Kharanor DPS).

The main solutions using which CLCS of the supplyof fuel for coal-dust boilers with direct injection of dustwere constructed are as follows.

(1) The fuel CLCS comprises a controller for thetotal flowrate of fuel and CLCSs for individual dustsystems (see Fig. 1a). The systems used in the P-57boiler for a 500-MW power unit can be subdivided forthe half-furnaces (their mutual influence is not verystrong), and individual fuel CLCSs are constructed foreach half-furnace comprising four dust systems. Suchdivision is not advisable for the P-67 and TPP-807 boil-ers of 800-MW power units, and the CLCSs of all eightdust systems are controlled from a common fuel con-troller. A similar solution, i.e., with a common fuel con-troller, is used for each shell of the PK-39 boiler oper-ating at a 300-MW two-boiler power unit, each fur-nished with four dust systems, and for the TPE-216boiler of a 200-MW power unit equipped with six dustsystems.

(2) The signal characterizing the total flowrate ofdust to the boiler (or to a half-furnace) is generated bymultiplying the total rotation frequency of raw-coalfeeders (RCFs) by the “calorific” indicator, an automat-ically calculated parameter that characterizes the qual-ity of fuel and is determined by currently integrating theratio of power unit output to the total RCF rotation fre-quency (without subdividing the boiler into half-fur-naces and shells). The weighed sum of this signal andfuel oil flowrate signal is used to form the control devi-ation for the fuel controller.

(3) Each dust system is equipped with its ownCLCS. Such a CLCS for hammer and medium-speedmills comprises two interconnected controllers: one forthe dust system load, which controls the RCF rotationfrequency and the other for the mill load, which adjuststhe flowrate of primary air. The air mixture controller,which is the dust system’s third controller, operates in awatchdog mode and usually does not participate in jointoperation with the other controllers that respond to theboiler load setpoint. To prevent the mill from becomingoverfilled when the primary air setpoint range isexhausted, the so-called local reversal logic is carriedout and the primary air controller begins to control thedust system load controller, causing the RCF rotationfrequency to decrease. The mill output watchdog con-troller’s coming into action is one more factor that mayimpose an upper limit on the dust system load. Theprinciple in accordance with which the CLCS of such adust system operates is described in detail in [9].

The CLCS for pulverizing fans also has two controloutputs: the RCF rotation frequency and the addition ofcold recirculation gases to the drying agent, a controlaction used for controlling the temperature of air mix-ture. Safe operation of the mill is ensured here bymeans of two watchdog controllers: one for the milloutput, and the other for a low temperature of air mix-ture, both generating commands for unloading the RCF.

(4) The fuel controller generates commands for thedust system load controllers, replacing the RCF set-point signals by the same setpoint. Once a limitation onincreasing the dust system load arises (when the localreversal logic or the watchdog controller comes intoaction), the fuel controller is disconnected from thisdust system and connected again after the fuel control-ler comes into action for the first time to decrease theload.

A stepped program is used to put the dust system inoperation; this program automatically brings the RCFrotation frequency to the mean value of this parameterfor the RCFs that are in operation and connects the dustsystem load controller to the fuel controller commands.

(5) Once the control ranges of all dust systemsswitched in operation in the automatic mode areexhausted (the most typical factor that may cause sucha situation to occur is emergency or forced tripping outof one or more dust systems), a “common reversallogic” is carried out; i.e., the output of the fuel control-ler is switched over to the BLSU (see Fig. 1a), i.e., forchanging the feedwater flowrate, which must bedecreased at the initial moment of time. Starting fromthis moment, the temperature master controller beginsto maintain the temperature conditions along the boilerpath through adjusting the feedwater flowrate, settingits value so as to put it in correspondence with the fuelflowrate existing in the boiler. If the boiler is subdividedinto two half-furnaces, the power unit output will bemaintained at the same level by controlling the secondhalf-furnace. However, the permissible difference of waterflowrates between the flows will impose a limitation onexcessive loading of the second half-furnace [9].

It is important to emphasize that, as is shown in [3],despite the difference in the dynamic characteristicswith which the temperature controlled by the tempera-ture master controller responds to disturbances in waterand fuel flowrates, dynamic characteristics of the mas-ter controller need not be changed after the commonreversal logic comes into action, provided that charac-teristics of the dynamic function unit generated as partof the FSU is properly chosen (see Fig. 1a).

A CLCS of the supply of fuel in gas-and-oil-firedboilers.

No difficulties with controlling the flowrate offuel are usually encountered in such boilers during thecombustion of gas or fuel oil. The use of the traditionalarrangement comprising means for controlling theflowrate of the appropriate kind of fuel and a watchdogcontroller for the minimal pressure supplemented witha pressure controller at the initial stages of starting pro-

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cess is quite sufficient for obtaining the required qualityof control.

The control of fuel flowrate during combined com-bustion of gas and fuel oil involves more complexity.Interavtomatika specialists use in their projects a uni-versal concept that supports different modes of com-bined combustion: with varying the flowrates of bothkinds of fuel and with varying the flowrate of only oneof them while the other remains fixed. If the flowratesof gas and fuel oil are varied jointly, a cascade control-ler is used, which controls the ratio of the pressures ofgas and fuel oil and serves to equalize the thermal loadsof burners firing different kinds of fuel irrespective ofthe number of burners that operate on each kind of fuel.The logic used in the scheme and special methods offollow-up allow a smooth changeover to be made fromone principle of controlling joint combustion of fuels toanother and to the firing of only one of them.

The widely used burners of AMAKS offer new pos-sibilities for controlling the supply of gas. Interavtoma-tika specialists have worked out and implementedseven projects for furnishing these boilers with CLCSs.A control shutter is installed on each burner. Initially,this shutter was intended for making the start-up pro-cess safe, but it turned out that this shutter can also beused to perform a number of tasks related to CLCs ofgas supply. For example, when the power unit operatesin the range of working loads, the list of these tasksincludes elimination of nonuniformities in the releaseof heat among the half-furnaces and redistribution ofgas flowrates between the tiers of burners to suppressthe emissions of nitrogen oxides. One decision thatturned to be especially efficient, taking into account thetasks of SPFC and ASFC, for which the power unit loadhas to be varied in a wide range without changing thenumber of burners, and which has been implemented inthe 300-MW power units at the Iriklinsk DPS, consistsof introducing a loop for maintaining the pressure ofgas downstream of the main gas valve at a level exceed-ing the minimum admissible pressure by partially clos-ing the control shutters of burners.

CLCS for feed-water flowrate.

Despite certainsimilarity that exists in the tasks that have to be solvedin controlling the feed-water units of different boilers inthe set range of their loads: two or four flows and oneor two turbine-driven feedwater pumps, the structure inaccordance with which the feed CLCS is constructedhas certain distinctive features depending on the spe-cific features of equipment that operates for a longperiod of time. Therefore, Interavtomatika specialists,on one hand, adhere in their projects to general solu-tions and, on the other hand, try to take into account thespecific features of the feeding system of each individ-ual power unit.

The list of general solutions includes the following.(i) The total flowrate of feedwater fed to the boiler is

controlled by means of the turbine-driven feedwaterpump (TFWP), whereas the difference between the

flowrate of water in a concrete flow and the mean flow-rate averaged over all flows of the boiler is controlledby means of the boiler feed-water controller. The use ofsuch a configuration makes it possible to decouple thecontrollers in dynamic processes, decrease the fre-quency with which actuators have to receive commandsto open/close and make the operation of the feedingunit more stable [5].

(ii) Efforts are taken to minimize the pressure differ-ence across the boiler feed water valve (BFV) andsimultaneously preserve the control margin for increas-ing the controlled parameter, the required pressure dif-ference across the injection valves, and the sufficientslope of the BFV controller when the TFWP operatingvalues approach the control range’s lower boundary.

(iii) The systems that have been developed incorpo-rate circuit solutions that take into account the occur-rence—in both general and dynamic modes only—ofconstraints for the minimum and maximum pressuresdownstream of the TFWP, for the maximum admissiblepressure difference across the BFV, and for the BFVand TFWP control ranges.

The general solutions are supplemented during thedesign stage and to a greater extent during the setpointstage taking into account the characteristics of the BFVand TFWR, possible discrepancy between the charac-teristics of BFVs in different flows, the availability andvalues of backlashes and excursions of valves, and theratios of their values for the BFV and TFWP, as well asother technological features of the feed unit and theboiler as a whole.

CLCS for the live-steam temperature.

This CLCSconsists of local CLCSs for injections and a tempera-ture master controller, all interconnected to form a cas-cade CLC structure. The main purpose of this system isto maintain the outlet stream temperature, and its aux-iliary purpose is to maintain the required control rangesfor the injection valves. The use of this approach elim-inates the need of operating personnel’s intervention inthe operation of the temperature CLCS.

Unfortunately, there are some factors that add diffi-culty to this problem.

(1) Operators try to reduce the flowrates of water forinjection in order to minimize the level of temperaturesalong the boiler path. This is especially important forequipment that has been in operation for severaldecades. Such a desire is fulfilled by partially taking theinjections out from operation or by bringing them in theclosed position (the opened valve with the closed gatevalve) with switching the valves controlling them tooperate in the watchdog mode.

(2) Process flows may be separated into severalbranches, usually, downstream of the built-in gatevalve; in this case, there is no option but to use a singlemaster controller for bringing the injections in two par-allel flows within the required range.

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(3) The injections are placed at the path cross sec-tions located in the zone of maximum heat capacity inthe entire range of loads or in a part of it, and also whenthe power unit operates with its high-pressure heatersdisconnected; as a result, the temperature upstream ofthe injections, and especially that downstream of them,cannot be used as controlled values.

The main solutions Interavtomatika specialists havedeveloped for constructing CLCS for controlling thelive steam temperature consists in the following.

(1) The temperature master controller and the con-trollers of all injections, including those operating inthe watchdog mode, are necessarily used and incorpo-rated into a single interconnected structure.

(2) A signal characterizing the position of one ormore valves on the injections situated along the flow ofmedium, which may be the valve position itself or thetemperature difference across the valve, is used as themain controlled variable for the injection controller orthe temperature master controller. The valve positionsignal is more preferable, especially for the first injec-tions along the flow of medium, which are located nearthe zone of maximum heat capacity. If the flows aresubdivided into several branches, a resulting signal isgenerated, which characterizes the position of injectionvalves in both the flows and is determined as the aver-aged value of control deviations between the positionsof valves. If the deviation between their positions and thesetpoint position is large, priority is given to the controldeviations of the valve that moves toward opening.

(3) Increasing, as far as possible, the number of tem-perature signals taken from the zone of guaranteedsuperheating, e.g., in between the steam superheater’ssections, that are used in the temperature master con-troller and injection controllers, irrespective of the timeconstants of the steam superheater sections that appearin this case.

(4) Applying a dynamically processed load signal tothe input of injection controllers (see Fig. 1) to obtain aleading response in the course of changing the powerunit output.

We can take as an illustration the CLCS for the firstinjection of the 500-MW power unit at the Refta DPS.Since this injection is beyond the confines of the guar-anteed superheating zone, there is no point of using thetemperature downstream of it in the CLC control. Atthe same time, this injection is the largest in capacityand plays a very important role in maintaining the tem-perature conditions along the path. A signal for the tem-perature of medium in between the steam superheater’sbanks, a location in which the level of temperatures cor-responds to the guaranteed superheating zone in theentire range of loads, was therefore used. The dynamiccharacteristics this signal shows in response to a distur-bance in injection are, of course, less favorable as com-pared with those of the temperature downstream of theinjection should it respond to such a disturbance; none-

theless, the quality with which the controller of thisinjection responded to disturbances in the steam–waterpath was found to be satisfactory. The main result weobtained from the use of this signal is that it allowed anefficient response to disturbances in fuel flowrate to beobtained, a property due to which the injection itselfcame into action in time to compensate for this distur-bance and, which is most important, the temperaturemaster controller, which used the signal for the positionof the first injection’s valve as the main one, changedthe fuel-to-water ratio.

CLCS for the gas–air path.

The lines in which theair supply CLCS and the rarefaction CLCS, systemsused in the gas–air path control system, are improvedfollow primarily from the need of obtaining good qual-ity of control in response to considerable changes in theload and comprise the following:

(i) generating a signal for air flowrate in accordancewith a calculation formula on the basis of signals for thepower of the forced draft fan and the pressure differ-ence across it; if it is not possible to use the latter signal(when there is no pressure gage at the forced draft fan’ssuction), the signal proportional to the square root ofthe air pressure upstream of the burners is used for thispurpose; a direct use of the air flowrate signal for CLCpurposes entails difficulties because the sensors that usethe pressure difference across constriction devicesoften give unreliable readings;

(ii) using dynamic function units that generate set-point signals for the air CLCS (Fig. 1), which cause theflowrates of fuel and air to vary in different waysdepending on the sign with which the load is changedto prevent O

2

concentration from dropping below thepermissible level;

(iii) making automatic operations for sequentiallyswitching one forced draft fan after another from onespeed to another;

(iv) applying a leading signal from the air supplyCLCS to the rarefaction CLCS; and

(v) augmenting the rarefaction CLCS (see Fig. 1)with a cascade controller for the difference of flue gastemperatures, the output signal from which is added tothe control deviation of guide vanes forced draft fansthrough their synchronization circuit (in accordancewith recommendations of some customers).

CLCS for the reheat steam temperature.

Thisgroup of controllers, which produce control commandsfor the emergency injection and bypass of the steam-to-steam heat exchanger, is constructed using the solutionssimilar to those employed in the CLCS for the livesteam temperature, in particular, addition of tempera-ture signals, construction of multiloop configurations,and use of simplified models of the controlled plant.

As regards the CLCS for the recirculation of fluegases, noticeable changes have recently occurred in theapproach for determining its functions. Earlier versionsof these functions incorporated the bringing of emer-

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gency injections into the CLCS range with keeping adependence of the controller values versus the load forsuppressing NO

x

(see Fig. 1). At present, many power sta-tions conduct operation in the entire range of loads withthe guide vanes of recirculation fans kept fully open.

EXAMPLES ILLUSTRATING THE OPERATION OF CLCSs OF THE PROCESS VALUES

OF POWER UNITS

CLCS of a coal-fired power unit.

Figure 2 showsan example illustrating the operation of the 500-MWpower unit No. 9 at the Refta DPS when a steady fuelcombustion mode experienced a fairly strong distur-bance due to the occurrence of both “local” reversalsand “common” reversal concept in one of the half-fur-naces. The initial event that caused these processes tooccur was deterioration in the quality with which fuelwas supplied and fired (and possibly in the quality offuel) in the entire boiler and especially in the half-fur-nace

B

. This deterioration manifested itself in that thepower unit output and the pressure of steam upstreamof the turbine showed noticeable drops, which causedthe flowrates of feedwater and fuel to increase consid-erably. The values by which both the main controlledflowrates to the boiler increased for the half-furnace

A

and flow

A

were almost the same; as regards the flow

B

,the signal characterizing the flowrate of fuel increasedto a degree much higher than did the signal for the flow-

rate of water. One of the dust systems used in the half-furnace

B

was shut-down as the RCF rotation frequencyincreased, which can be seen from the temporary dropthat occurred in the signal for the RCF’s total rotationfrequency (the fuel flowrate signal). This shut-downwas rapidly responded to by increasing the load of thedust systems that remained in operation, and thiscaused the occurrence of first “local” reversals and thenalso the “common” reversal for the half-furnace

B

,which can be seen from a drop in the flowrate of feed-water in the flow

B

. This drop, which lasted for 3–4 min,was caused by the action of the “local” reversal logic.This circumstance corroborates the conclusion accord-ing to which not only should further loading of the dustsystem be stopped when a constraint occurs for theflowrate of primary air to the mill, but its load must bereduced. During the first half of the above-mentionedinterval of time, the drop in the load of the half-furnaceand flow

B

was compensated for by an increase in theload of the half-furnace and flow

A

. However, once thedifference between the flowrates of water in the flowsreaches the maximum permissible value equal to150 t/h, the watchdog controller monitoring this differ-ence suspends further increase in the flowrate of feed-water in the flow

A

(and, consequently, the flowrate offuel in the half-furnace

A

), and the flowrate of waterbegins to decrease adequately to the decrease in theflowrate of feedwater in the flow

B

.

329348367386405

443462481500

540519

120139158177196215234

272291310

0.7

340

3541.1

259927082817292630353144325333623471

36893580

14001509161827271836194520542163

23812490

2272

37983900

230

250255260265270275280

290285

200205210215220225

235240245

295300

253

348367385405424443462481500

540519

120139158177196215234

272

310329

291

29.08.06 19:15:00 19:21:00 19:27:00 19:33:00 19:39:00

1

2

3

5 6

7

4

1 2 3 4 5 6 7 8

504

614636658680702724746768790

834812

350372304416438460482

526

570592

548

850

8

9

10

11

253

424

329348367386405

443462481500

540519

120139158177196215234

272291310

253

424

277284291298305

319326393

347

360

200207214221228235242

256263270

249

312

5

12

11

10

9

8

7

6

259927082817292630353144325333623471

36893580

14001509161827271836194520542163

23812490

2272

37983900

504

614636658680702724746768790

834812

350372304416438460482

526

570592

548

850

9 10 11

Fig. 2.

Transients triggered by the “common reversal” from fuel to water on the side

B

in the 500-MW coal-fired single unit No. 9at the Refta DPS (the P-57-11 boiler and the K-500-23.8-2 turbine). (

1

) Power, MW; (

2

) pressure upstream of the turbine, kg/cm

2

;(

3

) setpoint (reference signal) for the flowrate of feedwater in the leg

A

, t/h; (

4

) setpoint for the flowrate of feedwater in the leg

B

,t/h; (

7

) pressure in turbine strengthening line 1, kg/cm

2

; (

8

) position of turbine valves, mm; (

9

) calorific indicator; and (

10

) and (

11

)upper and lower permissible boundaries for the accuracy of maintaining the power, MW.

Time, h : min : s

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IMPROVEMENT OF PROCESS CLOSED-LOOP CONTROL SYSTEMS 855

Once the operating values of the dust systems for thehalf-furnace B had stabilized and, accordingly, once theflowrate of feedwater in the flow B had begun toincrease under the effect of the own temperature cas-cade controller, the flowrates of feedwater and fuel inthe flow and half-furnace A began to increase in thesame manner. As soon as the increase in the flowrate offeedwater in the flow B had caused the total flowrate ofwater for the boiler to reach the value corresponding tothe power controller’s setpoint, a further increase in theflow B’s flowrate began to entail not an increase, but adecrease, in the flowrates of water and fuel in the flowand half-furnace A. This process continued until theflowrates of feedwater in the flows became equal toeach other and the structure of the feed and fuel CLCSrestored in the initial form.

CLCS for a gas-and-oil-fired power unit. Figure 3shows examples illustrating the operation of the CLCSfor the 300-MW power unit no. 5 at the Stavropol DPSunder rather heavy operating conditions of the powerunit. All these experiments were carried out during theoperation of power unit on gas. The main emphasis hasplaced on the quality with which the live-steam temper-ature was maintained (the data are given as applied toone of the boiler’s flows).

The specific features with which the temperatureCLCS was constructed in this power unit are as follows.

Both the injections are constantly in operation. TheCLCS of the second injection has been implemented inaccordance with Interavtomatika’s standard two-loopcircuit containing a simplified model of steam super-heater. As regards the first injection, the temperaturedownstream of it could not be used for control pur-poses, since there are some operating conditions underwhich it falls in the zone of maximum heat capacity. Inaddition, other temperature measurements were alsounavailable. Therefore, the CLCS of the first injectionwas constructed in accordance with a single-loop cir-cuit with a combined PID controller. The proportionaland integral components of the control output are gen-erated from the signal corresponding to the positionindicator of the second injection’s valve, and the differ-ential component from the temperature of steamupstream of the second injection. A combination ofcontrol deviations in the positions of both the injectionswas used as the controlled variable of the temperaturemaster controller.

Attention should be turned to the fact that the exper-iments were carried out at different times: the tests ofthe AEUS (Fig. 3d) were carried out in spring of 2006when the system was commissioned, and the tests forcompliance with the SO–CDA Standard (Figs. 3a–3c)were carried out in the fall of 2006. The dynamic char-acteristics of the injection controllers and especially ofthe temperature controller were noticeably improved inthe course of operational setpoint that was carried outin the period of time between these dates, and this canbe estimated from the results that were obtained. The

maximum values by which the live steam’s outlet tem-perature deviated from its setpoint value during thesedisturbances are given in the table.

The maximum values by which the steam outlettemperature deviated when the power unit load was var-ied in the entire control range from 140 to 300 MW ata rate of 10 MW/min, during which the power outputdeviations were kept in the range ±1%, were rathersmall: 2.9°C toward increasing and 8.7°C towarddecreasing. The larger deviation toward decreasing thetemperature is due to the fact that the control ranges ofeach injection toward decreasing were exhausted for ashort time (for approximately 2 min in each of them).This is due to the fact that the setpoint position of injec-tion valves adopted at the majority of power stations isin the range from 20 to 40% both in order to decreasethe level of temperatures along the boiler path and dueto the fact that deviation of temperature toward decreas-ing is less hazardous than toward increasing, from thepoint of view of proximity to protection setpoints.

The values by which the outlet steam temperaturedeviated during the tests for checking whether thepower unit is ready to participate in SPFC within theemergency margin (see Figs. 3b and 3c) remainedwithin safe limits (not more than 8°C toward increasingand not more than 13°C toward decreasing) duringoperation at both load values despite the fact that thedisturbances had quite a considerable amplitude(±37 MW) and were applied with a period of 5 min,which was considered to be close to the possible reso-nance frequencies of the boiler’s temperature CLCSs.We also observe here that the control range towarddecreasing is exhausted, and even for a longer period oftime, but only for the second injection. The first injec-tion always remains within the permissible range andcomes into action almost simultaneously with the sec-ond one. The temperature master controller has a some-what increased dead band, a circumstance due to whichit does not come into operation during small distur-bances; at the same time, we see from the graphs thatthe temperature master controller comes into actionpromptly when tangible disturbances occur in the oper-ation.

Para-meter Fig. 3a Fig. 3b Fig. 3c Fig. 3d

∆t, °C –8.7 +2.9 –10.5 +0.3 –12.2 +7.8 0 +17.7

t, °C 536.3 547.9 534.5 545.3 532.8 552.8 545 562.7

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The value by which the outlet steam temperaturedeviates (toward increasing) when the AEUS discon-nects the TFWP at 100% load, which is the heaviest

version of emergency protection for the boiler’s tem-perature conditions (see Fig. 3d), is also quite accept-able and equal to 18°C. In this experiment, the time for

1

(a)21:20:00 21:22:30 21:25:00 21:27:30 21:30:00 21:32:30 21:35:00 21:37:30 21:39:59

Time, h : min : s

2 3 45 9

541247 74 168 185 244

527187 70 103 130 181

513127 66 37 76 124

49967 62 78 121 64

4857 58 –94 –34 4

1

2

3

4

5

9

1

09:35:00 09:38:59 09:41:15 09:44:23 09:47:31 09:50:39 09:53:47 09:56:55 10:00:03 10:03:09 Time, h : min : s

23 45

84185 161 559 262

78130 94 543 224

72175 33 527 186

6620 –31 511 140

6035 –95 495 110

1

2

3

4

5

(b)

250

190

130

70

10

10

10

Fig. 3. Transients in the 300-MW single unit No. 5 at the Stavropol DPS during operation on gas (the TGMP-314A boiler and theK-300-240-2 turbine). (a) Changing the power unit load from 140 to 300 MW at a rate of 10 MW/min (3.3%/min); (b) and (c) testsfor checking conformity to the SO–CDA Standard during SPFC within the emergency margin ±370 mHz (±37 MW) in the upperand lower part of the control range, respectively; and (d) operation of the AEUS after disconnection of the TFWP at a load of300 MW; (1) power, MW; (2) live steam temperature, °C; (3) output of the correcting controller of live steam temperature; (4) posi-tion of the second injection, %; (5) position of the first injection, %; (6) setpoint of fuel flowrate, thousand m3/h; (7) setpoint offlowrate of feedwater, t/h; and (9) and (10) upper and lower permissible boundaries for the accuracy of maintaining the power, MW.

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IMPROVEMENT OF PROCESS CLOSED-LOOP CONTROL SYSTEMS 857

which the ranges of both the injections are exhausted issomewhat longer and equal to around 5 min, afterwhich the temperature cascade controller brings both ofthem within the permissible range. As was indicatedabove, the operation in this mode had been testedbefore the controllers were finally adjusted. At present,with the new tuning parameters used in the injection

controllers and temperature cascade controller, both thetime for which the injection valves exhaust their controlrange and the value by which the temperature deviatesfrom its setpoint will be noticeably smaller. Such oper-ating conditions have not occurred since then.

Thus, the function diagrams of CLCSs developed atInteravtomatika allow both coal- and gas-and-oil-fired

1

14:03:45 14:06:30 14:09:34 14:12:29 14:15:24 14:18:20 14:21:15 14:24:10 14:27:0614:29:59 Time, h : min : s

23 45

73177 151 559 20

69122 87 543 162

6568 23 527 124

6113 –41 511 86

57–42 –105 495 48

1

2

3

4

5

(c)

77232 215 575 238

4

22:55:00 22:55:55 21:56:52 21:57:48 21:50:45 21:59:41 22:00:37 22:01:34 22:02:29 Time, h : min : s

26 71

63171 838 579 192

1117 748 553 117

–41–137 558 527 43

–91–291 367 501 32

–145–445 –173 475 107

1

2

3

4

5

115325 1128 605 267

6

7

5

216

159

71

16

104

334

3

75

69

63

57

52

81

(d)

Fig. 3. (Contd.)

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BILENKO et al.

power units to be operated in their load control rangesunder the heaviest disturbances both in the power andin the power system with almost no intervention byoperating personnel.

REFERENCES1. V. A. Bilenko, A. D. Melamed, E. E. Mikishevich, et al.,

“Development and Application of Automatic Frequencyand Power Control Systems for Large Power Units,”Teploenergetika, No. 10, 14–26 (2008) [Therm. Eng.,No. 10 (2008)].

2. V. A. Bilenko and I. A. Shavochkin, “An Analysis of theEffect from Introducing Complex Laws for Transform-ing Additional Signals in Multiloop Automatic ControlSystems of Power Units,” Teploenergetika, No. 4, 57–65(2006) [Therm. Eng., No. 4 (2006)].

3. V. A. Bilenko, N. I. Davydov, and V. Z. Chesnokovskii,“The Use of the Mixed Independence Principle in Mul-tiply Connected Automatic Control Systems of PowerUnits,” Teploenergetika, No. 10, 18–22 (1982) [Therm.Eng., No. 10 (1982)].

4. V. A. Bilenko, “Organization of Operations for TuningMultiple Connected Control Systems of Power-Generat-ing Equipment,” Teploenergetika, No. 11, 18–24 (1990)[Therm. Eng., No. 11 (1990)].

5. V. A. Bilenko and E. E. Mikushevich, “Selecting theStructure of Multiply Connected Similar Control Sys-

tems of Power Units and the Principles Used for TuningThem,” Teploenergetika, No. 10, 21–26 (1989) [Therm.Eng., No. 10 (1989)].

6. V. A. Bilenko and N. I. Davydov, “Reconfiguring Con-nected Two-Loop Automatic Control Systems of PowerUnits,” Elektr. Stn., No. 3, 33–36 (1984).

7. N. I. Davydov, A. S. Rubashkin, and M. D. Trakhten-berg, A Scheme for Closed-loop control of the Once-Through Boilers of 150-, 200-, and 300-MW PowerUnits (BTI ORGRES, Moscow, 1966) [in Russian].

8. V. A. Bilenko, N. I. Davydov, V. Z. Chesnokovskii, andN. P. Rosich, “An Analysis of the Dynamic Characteris-tics of a Multiply Connected System for Controlling thePower and Temperature of a Power Unit Equipped witha Once-Through Boiler,” Teploenergetika, No. 10, 11–17(1987) [Therm. Eng., No. 10 (1987)].

9. V. A. Bilenko, N. N. Derkach, E. E. Mikushevich, andD. Yu. Nikol’skii, “Development and Commissioning ofSystems for Controlling the Main Values of a Boilerwithin the Scope of the Process Control System of the500-MW Power Unit at the Refta District Power Sta-tion,” Teploenergetika, No. 10, 2–9 (1999) [Therm. Eng.,No. 10 (1999)].

10. V. V. Belyi, Yu. A. Kiselev, V. A. Savost’yanov, et al.,“Upgrading the Automatic Process Control Systems forthe 800-MW Power Units at the Berezovo District PowerStation,” Elektr. Stn., No. 1, 49–54 (2004).

859

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 859–867. © Pleiades Publishing, Inc., 2008.Original Russian Text © A.I. Gal’perina, L.L. Grekhov, V.Yu. Krylov, A.V. Mikhin, 2008, published in Teploenergetika.

Starting up of a modern power unit is the most com-plicated procedure of all its operating modes. This isbecause a large number of continuous and discrete con-trol operations have to be carried out in the course ofstarting processes, the equipment reliability criteria liein a narrow range, some items of equipment may beunavailable or fail during starting operations, and thelevel to which these operations are automated is ratherlow. The task ZAO Interavtomatika specialists setbefore themselves from the very beginning of theirwork has always been to essentially improve the levelto which domestically produced power units are fur-nished with automatic control systems through usingthe capacities available in modern instrument and con-trol systems (I&CSs).

PROBLEMS RELATED TO AUTOMATION OF STARTING MODES

The set of operations for starting a modern largepower-generating unit equipped with a once-throughboiler and designed to operate at supercritical parame-ters includes the following:

(i) checking the equipment and preparing it for starting;(ii) switching the auxiliary systems into operation;(iii) speeding up the main equipment;(iv) making switching operations in the process cir-

cuits when a transition is made from starting modes tosteady operating conditions; and

(v) generating startup setpoints for the main param-eters of equipment (the temperatures of live and sec-ondary steam, flowrates of water and fuel, live steampressure, etc.) and controlling them during the startingprocess in accordance with these setpoints.

Attempts to deeply automate starting operationswith the use of old (outdated) equipment were takenconstantly, but without great success, although theybrought some positive results. The problems encoun-tered in attempts to automate complex, long-term, and,as a rule, irregularly repeated processes with the use of

outdated relay equipment or logic control devices withfixed logic are mainly due to the following factors:

(i) these facilities have rather limited capacities forcreating complex and multioptional logic of devices forautomatically performing startup operations and auto-matic controllers able to adapt themselves to changingoperating conditions;

(ii) these facilities have poor flexibility for introduc-ing changes in the logic of automatic control devices,the need for which inevitably occurs during adjustmentwork, and require large manpower for making thesechanges;

(iii) the characteristics of equipment and actuatingelements, on the one hand, and the setpoints of analogautomatic control devices, on the other, are unstable;and

(iv) there is a lack of well-developed means for theoperator to monitor and correct the execution ofstepped programs and other algorithms for automati-cally starting equipment and systems.

The possibilities for automating power equipment ingeneral—and starting operations in particular—alteredfundamentally with the advent of microprocessor con-trol systems. The advantages of microprocessor controlsystems showed themselves most prominently as ameans for constructing comprehensive full-scale auto-mation systems.

THE POSSIBILITIES OF MODERN I&CS FOR AUTOMATING STARTUP MODES

In their projects for equipping power-generatingfacilities with automatic control systems, Interavtoma-tika specialists use microprocessor-based systems ofthe Siemens and Dukhov Research Institute of Automa-tion (VNIIA), which offer a full scope of propertiesrequired for applications in such a complex field aspower engineering:

(i) high reliability;

Automation of Operations for Starting Power Units Equipped with Once-Through Boilers

A. I. Gal’perina

a

, L. L. Grekhov

a

, V. Yu. Krylov

b

, and A. V. Mikhin

b

a

ZAO Interavtomatika, ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

b

Stavropol District Power Station, Solnechnodol’sk, Stavropol krai, 356127 Russia

Abstract

—An attempt is made to generalize the experience gained from solving some problems pertinent toarrangement of operations for starting a power unit.

DOI:

10.1134/S0040601508100066

860

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(ii) well-developed basic software, including com-ponents using which complex stepped programs andswitched-off logic automata can be constructed;

(iii) well-developed possibilities for diagnosing thestate of peripheral devices; and

(iv) an efficient operator interface.Central to successful automation of starting opera-

tions is using the above-mentioned properties of I&CSsto construct a set of automatic controllers and logic pro-grams with the use of stepped logic in the form ofstepped programs (SPs) and situation logic in the formof switched interlocks. The ability of automatic con-trollers to work in a wide range of operating conditionsis achieved by automatically changing the structure andsetpoints of controllers as changes occur in their oper-ating conditions and using devices for generating set-points (programming devices).

The use of starting automata depends to a consider-able extent on the possibilities available in the interfaceof an operator or a job-setter for monitoring, analyzing,and diagnosing the operating algorithms. For example,the control window of a stepped program presents fullinformation on the state of the program (the number ofthe step being executed, waiting time, and check timefor executing a step, a jump to another branch, etc.) andthe basic software of stepped programs makes it possi-ble to generate alarms when the time allotted for exe-cuting each stage of the program has been exceeded,when the conditions being checked are not fulfilled fora long period of time, and when other abnormalitiesoccur. When a delay in the execution occurs, the algo-rithm of the program can easily be called on the displaywith indicating the states of all inputs and signals indynamic form so that the factors caused the delay tooccur can be easily revealed.

Processes that cannot be represented as steps with aclear-cut sequence of technological operations are han-dled using situation algorithms, i.e., algorithms thatoperate in a watchdog mode anticipating the onset ofconditions under which certain actions must be taken.These algorithms differ from usual protective inter-locks in that they are more complex, have flexibleoptional logic, and that they can be switched on and offby the operator and by commands from upper-levelprograms.

The use of versatile microprocessor devices pro-vides the possibility to revise—and in many casesimprove—the technology in accordance with whichstarting operations are carried out, taking into accountmeasures for automating them. The use of startingautomata allows the following positive features to beobtained: the starting modes are carried out with goodrepetitiveness, the regular design sequence of opera-tions is guaranteed (irrespective of the individual fea-tures of the operator), the equipment reliability criteriaare fulfilled while the rates of heating and loading arekept within their rated limits, the values by which theparameters deviate from their normal levels (tempera-

ture excursions) are minimized, and fuel is rationallyused, since the starting mode is accurately conductedand any excessive forcing of the boiler is excluded.

BASIC SOLUTIONS FOR AUTOMATION OF STARTING OPERATIONS

Stable operation of control functions, their flexibil-ity, and the ability of certain algorithms to survive whenother algorithms fail—all these features are obtained byconstructing automation algorithms in accordance withthe hierarchical principle. According to this principle,each algorithm in charge of automatic control of anindividual equipment item and controlling of oneparameter or group of interrelated parameters is con-structed so that its operation is maximally independenton the operation of other algorithms. Separating func-tionally independent stages suitable for being indepen-dently controlled from the overall sequence of techno-logical operations is an important factor in this respect.

Experience gained from construction and adjust-ment of starting automata in very different types ofpower-generating equipment, including 800-MW coal-fired power units, made it possible to determine the typ-ical stages of starting operations that can be automatedas rather self-contained functions. The list of the maintypical enlarged operations carried out in the course ofstarting a power unit may include, e.g., the following:

(i) filling and starting the condensate path and thedeaerator;

(ii) starting the circulation system;(iii) starting the vacuum system and picking up vac-

uum;(iv) starting the feedwater path; filling, pumping,

and washing the boiler; and setting up the start-up flow-rates;

(v) starting the gas–air path and ventilating the fur-nace;

(vi) pressurizing the gas conduits and preparingthem for start-up;

(vii) start-up the boiler, controlling the flowrate offuel, and bringing the system to the kickoff parameters;

(viii) kicking the turbine, speeding it up for idle run-ning, connection to the network, and picking up the ini-tial load;

(ix) switching the low- and high-pressure regenera-tion systems in operation;

(x) controlling the power unit loading and heating inaccordance with the assigned starting schedule;

(xi) controlling the supply of fuel to the boiler(together with starting-up additional burners, switchingthe dust systems into operation, and making a transitionfrom starting fuel to main fuel);

(xii) controlling the discharges from the boiler’sstart-up unit and shifting to operation in the once-through mode;

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(xiii) switching from the starting electrically drivenfeedwater pump (EFWP) to the turbine-driven feedwa-ter pump (TFWP) (for the standard 300-MW powerunits); and

(xiv) change over for operation with the rated pres-sure upstream of the turbine and opening the built-ingate valve.

Each of the above-listed stages of the technologicalsequence in accordance with which a power unit isstarted up is of individual interest for being automated.This is because such factors as the time taken to carryout a stage, the large number of actions for makingswitching operations in the technological circuits andcontrolling the parameters, and the volume of parame-ters that have to be monitored place a considerable bur-den on the operating personnel and create conditionsunder which errors can potentially be committed anddeviations from the standard technology may occur. Anespecially difficult situation occurs when several paral-lel operations have to be done at the same time. Addi-tional operators are involved in such cases; however,this does not guarantee that no deviations will occurfrom the regular design process.

The problem of automating each of these operationshas successfully been solved in the projects of processcontrol systems (PCSs) Interavtomatika specialistshave developed for a large number of power units withcapacities ranging from 300 to 800 MW. The total vol-ume in which each particular power installation isequipped with automatic control system depends on the

composition of initial information adopted for theproject, the customer’s desire, and local conditions. Anexample of an enlarged structure of a set of automatafor controlling a power unit and their connections isshown in Fig. 1.

Of course, the different degrees to which powerunits, especially those commissioned 10–20 years agoor earlier, are equipped with sensors for remotely mon-itoring the parameters, with electrically driven valves,and remote control facilities, affect the depth to whichthese units are automated and the extent to which theoperation of starting automata depends on the operator.However, experience shows that in most frequent occa-sions the available scope of monitoring and controlfacilities is minimally sufficient for the majority of themost important automata. In some cases, Interavtoma-

SPs used in the SWfor FDMs

and furnaceventilation

SP for startingthe power unit

SP for preparingthe boiler

for starting

Providing adviceto the operatorfor starting-up

the burnersand starting

the dust systems

SP for startingthe turbine

SP for preparingthe turbinefor starting

SP for fillingthe CFWP

SPfor pumping

the boiler SPfor dust systems

SPfor openingthe MSV

SPfor the HSRCI

SP usedin the SWfor HPHs

SPs used in the SWfor ELPs, CPs,

and vacuum pickup

SP usedin the SWfor LPHs

Disconnectedinterlocks

for the boiler

Temperaturecascade controller

Loadprogrammer

Devicefor programmingthe temperatures

of primaryand secondary steam

Disconnected

Fuel controllers

Air and draft CS CSCS Controllers

interlocksfor the CFWP

controllers of the feed unit of the millof fuel oil

supplyof injectionsand bypasses

CS CSControllers

of the HSRCI of the turbinevalves

of levelsin the CFWP

Fig. 1.

Example of the structure of algorithms used in the power unit control system. FDMs—Forced draft machines, ELPs—ejectorlifting pumps, CPs—circulation pumps, MSV—main steam gate valve, HPH and LPH—high- and low-pressure heaters, HSRCI—high-speed reduction and cooling installation, CFWP—condensate-feedwater path, SW—software, CS— control system, andSP—stepped program.

Steam from turbine extractions

SE-8

To

T

fw

HPH-8

FromSE-7 SE-6

HPH-7 HPH-6

pumpsfeedwaterthe

boiler

Fig. 2.

Technological circuit of the HPH unit. SE-6–SE-8are steam extraction gate valves.

862

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Monitored conditions

Rates of risein

T

fw

and

p

HPH-8

are OK

Gate valve SE-8is openor

p

HPH-8

> 2

Rate of rise in

p

HPH-7

is OKand

p

HPH-8

–

p

HPH-7

> 2

Rate of rise in

p

HPH-6

is OKand

p

HPH-7

–

p

HPH-6

> 2

Gate valves SE-6, SE-7, and SE-8 are open

Finishingoperations

Partially open

Program steps

Preceding steps

YesNo

SE-8

Partially openSE-7

Partially openSE-6

No

No

No

No

Yes

Yes

Yes

Yes

Commands

Fig. 3.

Structure of the main function diagram used in the HPH starting program.

15

10

5

0

200

150

100

50

019:00 19:10 19:20 19:30 19:40 19:50

100%

75%

50%

25%

0

01:10:00HH:mm:ssMSK

°

C, kg/cm

2

Time,h : min

Fig. 4.

Variation of the parameters when the HPH is automatically switched on. (

1

) Temperature of feedwater downstream of theHPH; (

2

), (

3

), and (

4

) pressure of steam in of HPH-8, HPH-7, and HPH-6, respectively.

1

2

3

4

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tika specialists recommend, based on the results of pre-liminary examination of equipment, that some addi-tional measurements should be provided, the scope ofwhich is usually limited to not more than two to fivesensors, and that a few stop or control valves should befurnished with electric drives.

Satisfactory state of control actuators (when there isno flow in their closed state, backlash, or uncontrolledexcursion; when they have acceptable flowrate charac-teristics; etc.) is a factor essential for successful auto-mation of processes. Although a microprocessor-basedcontrol system may compensate for some drawbacks of

Waiting for the starting scheme heating criteria

Determining the type of starting.Selecting the setpoints for the type

of starting. Determiningthe necessary time delays

Opening the drains

Checking the HSR steam linesheating criteria

Preparation for kickingwithout IPC

Preparation for kickingwith IPC

Kicking, listening,and speeding up to 1000 rpm

Switching on the scheme for heatingthe HPC flanges and studs

(if necessary)

Not ready Ready

Manual selectionof the HRS heating mode

Increasing rotationfrequency to 2000 rpm

Preparing the schemefor supplying steam

from AH

Connecting the programmerfor finally heating the HRS

Waiting for the heatingof HRS

Waiting for expiration

Increasing rotation

Switching on the scheme

Waiting for connection

Opening the HPC CVs,

of time delay

frequency to 3000 rpm

for heating the IPC flangesand studs (if necessary)

to the network

closing the HSRCI,and closing the drains

With steam from AH Without steam from AH

IPC is connectedHSR heating is in progress

Fig. 5.

Flow chart of the turbine startup program. HSR—hot steam reheater, AH—auxiliary header, CV—control valve, HPC—high-pressure cylinder, IPC—intermediate-pressure cylinder, and HSRCI—high-speed reduction and cooling installation.

T

m, HPC

< 200

°

C

T

m, HPC

> 200

°

C

864

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control members by means of software, good control ofparameters can be obtained only if the control valvesare in a good condition.

EXAMPLES OF PUTTING STEPPED PROGRAMS INTO USE

The stepped program for switching-on the steamcircuits of high-pressure heaters (HPHs) can be takenas a typical example of putting such programs into use.One specific feature of this procedure is that the rate ofrise in the temperature of feedwater downstream of thelast HPH and the pressure of steam in each of themmust be monitored and maintained within the permissi-ble limits. In addition, a certain pressure differencemust be kept between the heaters to ensure normaloperation of cascaded spilling arrangement for drainingthe heating steam condensate. The technology forswitching the HPH into operation and the sequence ofoperations were modified in such a way that theyremain the same for any possible state of the powerunit. The stepped program for switching the HPH inoperation has been constructed so that it can be used notonly when the power unit is being started, but in anyother situation, e.g., for connecting the repaired HPHwhen the power unit is in operation. It should be bornein mind that the way in which the pressure in extrac-tions and, hence, the temperature of feedwater down-stream of the HPH rise in the course of starting a powerunit depends not only on the rate with which the gatevalves on the supply of steam to the HPH are opened,but also on the rate with which the power unit itself isloaded. The stepped HPH starting program monitorsthe rate of change in these parameters and suspends fur-ther opening of steam gate valves, irrespective of thefactors that caused the increase in the HPH loading rate.

Figure 2 shows a simplified technological circuit ofthe HPH unit, in which the main parameters that haveto be monitored during HPH loading are indicated, andFig. 3 shows the main function diagram of the HPHstarting program, which controls the permissible rate ofheating. The program has been constructed as asequence of cyclically repeated steps, in which com-mands are generated for partially opening the steamgate valves provided that the parameters being moni-tored lie within the permissible limits. The steam gatevalves are opened by applying control pulses of vari-able length depending on the degree of their beingopened that has already been reached. If the permissi-ble rates of heating are exceeded, further opening of thegate valves is suspended until a time coresponding tothe actual buildup of the parameters passes. The opera-tion of the program is finished after all steam gatevalves have been opened.

The curves in Fig. 4 illustrate the result of the oper-ation of the program for switching-on the HPH in thecourse of power unit starting (a power unit equippedwith a T-250/300 turbine was taken as an example). Theaverage rate of rise in the feedwater temperature wasaround 1.7

°

C/min, the maximum permissible value ofwhich is 2

°

C/min.

The stepped program for preparing the turbine forkickoff, speeding up the turbine to idle running mode,and making operations for picking up the initial loadafter the generator is connected to the network isanother typical example of means for automaticallystarting a turbine. When the execution of this programis in progress, all the turbine and pipeline heating crite-ria required to begin the turbine starting process aremonitored, switching operations that have to be madein accordance with the technology for heating pipelinesand assemblies are carried out, and the turbine rotor isspeeded up and held at an intermediate rotation fre-quency in accordance with the relevant manual. As arule, the algorithm is organized (on the request ofpower station personnel) so that, once the turbine rotorhas been initially kicked off and reached the minimalrotation frequency, the program waits for the operator’spermission to continue the operations (it is implied thatthe personnel has inspected the rotating turbine and lis-tened to it in situ). The operator confirms his or her per-mission by clicking the virtual pushbutton on the videodisplay. For the starting operations to be automated, thetechnology for starting a turbine from different thermalstates has been brought as far as possible to a commonstandard and the remaining differences have been takeninto account in the stepped program in the form ofbranches, which perform different technological opera-tions based on the results of checking criterial condi-tions. The differences in the starting parameters ofsteam, which depend on the turbine’s thermal state, arehandled by means of a live-steam temperature pro-grammer, which generates an setpoint for the kickoffparameters (a description of this device is given below).

3000

2000

1000

2:10 2:20 2:30 2:40

Time, h : min

rpm

1

2

Fig. 6.

Turbine speedup process in the course of starting a500-MW power unit. (

1

) Setpoint of the speedup controllerand (

2

) turbine rotation frequency.

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The outline flowchart of the turbine startup programis shown in Fig. 5, and Fig. 6 shows an example how theturbine of a 500-MW power unit is speeded up to theidle running mode.

Heating up the turbine in the course of its loading isamong the most important stages of the power unitstarting process. The temperature controllers receivesetpoints from the temperature programmer, a specialalgorithm that calculates this setpoint taking intoaccount not only the turbine’s thermal state and thestandard starting flowchart, but also constraining fac-tors: the relative expansions of rotors and the differenceby which the actual temperature of steam lags behindits assigned value.

The temperature programmer generates the setpointin a stagewise manner:

(i) before the turbine startup is commenced, the pro-grammer monitors its temperature state, generates, andcontinuously corrects the setpoint for the kickoffparameters of steam;

(ii) at the moment the turbine is kicked off, the pro-grammer fixes the setpoint and maintains it at a con-stant level until the generator is connected to the net-work;

(iii) after the generator is connected to the network,a specified time delay is counted for the period of time

during which the initial load is taken and the parametersare stabilized (in some specific situations, there may beno such a delay); and

(iv) after the time delay is over, the programmerbegins to increase the setpoint for the temperature con-trollers with a rate determined by the specified startingflowchart; the increase in the setpoint is terminatedonce the rated value is achieved.

As the increase in setpoint is in progress, the pro-grammer monitors the constraining criteria (this is usu-ally the relative expansion of the rotor) and suspends itsoperation if a hazardous level is reached. In addition, toprevent the occurrence of thermal shocks, the program-mer temporarily suspends its operation if the actualtemperature of steam considerably lags behind itsassigned value or if large temperature discrepanciesoccur between different legs of steam lines. The resultfrom calculation of the turbine rotor’s thermallystressed state can be used for controlling the rate ofincrease in the setpoint.

The function diagram of the algorithm for generat-ing a setpoint for the temperature controllers is shownin Fig. 7, and Fig. 8 shows an example illustrating howthe live-steam temperature programmer operates in thecourse of starting a 500-MW power unit. The suspen-sions in the setpoint that are seen on the graph are due

Signs of the turbinestartup commencement

Thermal stateof the turbine

Sign of connectionto the network

Reliability criteria(relative expansionand temperatureof the rotor)

Actual steamtemperaturesSign of turbinedisconnection

Waiting for turbinestartup.Generating the setpoint

for turbine kickoff parameters

Fixing the initial setpoint

Waiting for connectionto the network

Smoothly increasingthe setpoint to the ratedlevel with suspending

the process if constraintsemerge

Retaining the setpointuntil the turbineis disconnected

Setpoint selection block

Setpoint for the temperature

controller

s

Fig. 7.

Flow chart of the temperature programmer algorithm.

866

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to the above-mentioned technological constraints (inparticular, due to the fact that the relative expansion ofthe high-pressure rotor reached the limit specified forthe programming device).

It should be pointed out that the temperature pro-grammer only generates a setpoint for the controllers.Whether the setpoint from the programmer is succes-sively executed depends on the operation of injectioncontrollers themselves and the boiler load program-ming and controlling devices, which must conduct theboiler operation in such a way that the temperature con-trollers were within their control ranges.

The transition from the starting EFWP to the TFWPis a short but important stage of the power unit startingprocess. The operating personnel have always encoun-tered difficulties in carrying out this operation. A cir-cumstance that adds difficulty to the control of this pro-cess is that the usual skills of manual control are notapplicable for fine adjustment of parameters using theinterface of video displays. Equipping the power unitwith facilities for carrying out this stage in a fully auto-matic manner makes it possible to relieve considerablepart of the burden placed on the operators, exclude theoccurrence of errors, and conduct the stage withoutconsiderable fluctuations in the parameters. An exam-ple illustrating the operation of the device for imple-menting automatic changeover from the EFWP to theTFWP in the 300-MW power unit at the Stavropol dis-trict power station (DPS) is shown in Fig. 9.

The top level in the hierarchy of a power unit’s start-ing automata incorporates devices that are very impor-tant and complex in adjustment: the boiler load pro-grammer and coordinating programs for controlling theburners and/or dust systems and changeover from one

kind of fuel to another. The complexity of these algo-rithms stems primarily from the fact that they can betried out and adjusted only when the lower-level autom-ata are fully available; unfortunately, the adjustment ofthe latter often takes a long period of time because start-ing operations are infrequent and the periods betweenthem are long. In addition, a tight dispatch schedule,which gives no time margin for doing adjustment work,frequently does not allow the personnel to use thoserare starting modes in full extent. Only in individualcases do power station personnel agree, with reluc-tance, to continue work on adjusting novel and complexautomata and controllers after the previously intro-duced scope of automatic control facilities has beenadjusted, preferring to work in the old fashion. None-theless, the tasks of furnishing a boiler with systems forautomatically carrying out its loading process have suc-cessfully been implemented in many Interavtomatikaprojects. We can mention as examples the 200-MWgas-fired power unit at the Surgut GRES-2 DPS, the300-MW gas-and-oil-fired power unit at the StavropolDPS, the 800-MW coal-fired power units at the Bere-zovo DPS, and other power-generating plants. It shouldbe pointed out that the task of performing fully automaticcontrol of fuel supply in starting a coal-fired boiler and mak-ing a transition from starting fuel to coal dust has not hith-erto been advanced to the point of being ready for regularuse in any power unit. Only automata for carrying out anumber of individual operations or stages of these com-plex procedures have been implemented.

CONCLUSIONS

(1) The experience gained from work on automatingcomplex technological systems of power units andstages of their starting processes testifies that the task ofautomating the starting operations can be successfullysolved in almost any power unit. The possible extent towhich a power unit can be automated depends on thetechnical state of equipment, the degree to which thepower unit is furnished with facilities for remote con-trol and monitoring, and the desire of the customer.

(2) How successfully the starting processes are auto-mated depends on how rationally the entire set of oper-ations is subdivided into individual self-containedstages, how optimally the starting functions are distrib-uted among the automatic controllers and stepped andsituation logic programs, and how their interaction isorganized.

(3) A carefully worked out operator interface, whichmust have such features as consistency of control, con-venience, clarity, and possibility of easily analyzing thecurrent state of algorithms and factors caused delays intheir execution, is of utmost importance for successfulintroduction of starting automata.

(4) The sequence in which starting algorithms areadjusted must be constructed so that automatic control-lers and situation logic automata should become ready

500

400

300

200

100

003:00 05:00 06:00 07:00 08:0004:00

Time, h : min

MW,

°

C

1

2

3

Fig. 8.

Operation of the live-steam temperature program-mers in the course of starting a 500-MW power unit.(

1

) Programmer’s setpoint, (

2

) generator power output, and(

3

) temperatures of steam in legs

A

and

B

.

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first, then local stepped programs, and then coordinat-ing upper-level programs.

(5) The results obtained from the work Interavtoma-tika specialists have carried out for furnishing powerunits with capacities ranging from 300 to 800 MW withautomatic control systems have confirmed that themajority of starting automata can be implemented andcan show stable operation.

REFERENCES

1. A. G. Sviderskii, Kh. Kherpel, and V. L. Kishkin, “Tech-nical Facilities for Automation of Power IndustryPlants,” Elektr. Stn., No. 1, 7–12 (2004).

2. V. A. Bilenko, “Functional Capacities of Modern Pro-cess Control Systems for Thermal Power Stations and aNew Level of Automation,” Elektr. Stn., No. 1, 13–18(2004).

3. V. V. Belyi, Yu. A. Kiselev, V. A. Sevast’yanov, et al.,“Upgrading the Process Control Systems of the 800-MW Power Units at the Berezovo GRES-1 DistrictPower Station,” Elektr. Stn., No. 1, 49–54 (2004).

4. L. L. Grekhov, V. A. Bilenko, N. N. Derkach, et al., “TheProcess Control Systems of the 500-MW Power Unit atthe Reftinsk District Power Station,” Elektr. Stn., No. 5,51–68 (2002).

05:25:51 05:27:28 05:29:07 05:30:46 05:32:24 05:34:03 05:35:40

700

560

420

280

140

0

350

280

210

140

70

3

2

4

1

5

3

2

Time, h : min : s

Fig. 9.

Variation of the parameters during the transition from the EFWP to the TFWP. (

1

) Flowrate of water to the boiler, t/h;(

2

) pressure downstream of the EFWP, kg/cm

2

; (

3

) pressure downstream of the TFWP, kg/cm

2

; (

4

) flowrate of water downstreamof the EFWP, t/h; and (

5

) flowrate of water downstream of the TFWP, t/h.

868

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 868–876. © Pleiades Publishing, Inc., 2008.Original Russian Text © V.A. Bilenko, O.A. Manevskaya, A.D. Melamed, 2008, published in Teploenergetika.

A system for automatically controlling the fre-quency and power (FPCS) of a PGU-450 combined-cycle power unit operating as part of the full-scale auto-matic process control system of Unit 1 at the Kalinin-grad TETs-2 cogeneration station was developed andcommissioned in March of 2006.

1

According to the RAO Unified Energy Systems ofRussia’s (RAO EES Rossii) Order No. 524 dated Sep-tember 18, 2002, participation of power stations incommon primary control of network frequency (CPFC)must be considered one of the most important condi-tions for connecting a power unit to electric networks.On June 2, 2006, tests for estimating the preparednessof the power unit for participation in CPFC were car-ried out with a view to check whether this FPCS meetsthe requirements of the above-mentioned order.

At present, no requirements are imposed on com-bined-cycle plants for their participation in selectiveprimary and automatic secondary control of the powernetwork frequency (SPFC and ASFC). Nonetheless, theresults obtained from the above tests make it possible toanalyze whether the combined-cycle power plant (CCPP)can achieve the indicators established for solving thesetasks and, accordingly, to estimate the prospects for partic-ipation of such CCPs in SPFC and ASFC.

MAIN EQUIPMENT OF THE 450-MW UNIT 1 AT THE KALININGRAD TETS-2

COGENERATION STATION

A combined-cycle installation as a controlled objecthas features that distinguish it considerably from thetraditional power units. This circumstance predeter-mines the peculiarities of CCPPs in solving such powersystem tasks as primary and secondary control of fre-

1

The term “automatic power control system” is widely used alongwith the term FPCS adopted in this paper.

quency and power. The basic circuit of a heat-recoverytype CCPP, the category to which the PGU-450 powerunit at the Kaliningrad TETs-2 cogeneration stationbelongs, is schematically shown in Fig. 1.

The binary combined-cycle installation of theKaliningrad TETs-2’s PGU-450T power unit com-prises two GTE-160 gas turbines of Leningrad MetalWorks (LMZ) with an adjustable inlet guide vanedevice (IGVD), the outlet diffuser of which is con-nected to P-96 boilers of the Podolsk Machinery Con-struction Works, and an LMZ T-150-7.7 steam turbine.

The GTE-160 gas-turbine unit (GTU) is a single-shaft turbine set operating in accordance with the sim-ple gas-dynamic cycle with the initial gas temperatureequal to 1060

°

C and the temperature of gas at the tur-bine outlet equal to 544

°

C. The electric power outputthe GTU generates under the design external conditionsand at an efficiency of 33.8% is equal to 150 MW.

Individual boilers are installed downstream of eachGTU used in the PGU-450T power unit. Gases leavingthe gas turbine (GT) flow into P-96 two-pressure drumheat-recovery boilers (HRBs). Each boiler compriseshorizontally arranged heating surfaces and two high-and low-pressure steam-generating circuits with steamdrums and natural circulation in the evaporating cir-

Results from Tests of the System for Automatically Controlling Frequency and Power of the PGU-450 Power Unit at the Kaliningrad TETs-2 Cogeneration Station

V. A. Bilenko, O. A. Manevskaya, and A. D. Melamed

ZAO Interavtomatika, ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

Abstract

—The structure of the system and the results of tests for checking the preparedness of the power unitfor common primary control of the network frequency are described. An analysis of the results is presented, andan assessment is made of whether the PGU-450 unit can participate in selective primary and automatic second-ary control of frequency and power.

DOI:

10.1134/S0040601508100078

GT1

GT2

HRB1

HRB2

ST

Fig. 1.

Basic configuration of a heat-recovery type CCPP.

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cuits. No means are used to control the pressure andtemperature of steam in the boilers during their opera-tion in the working range of loads; the boilers aredesigned for operation at sliding parameters of steam,which depend on the temperature and flowrate of gasesentering into the boilers from the gas turbines, as wellas on the steam turbine’s operating conditions.

Steam from the high- and low-pressure steam super-heaters enters into the high-pressure cylinder and thechamber between the 16th and 17th stages of the steamturbine (ST). The T-150-7.7 steam turbine is equippedwith three controlled steam extractions and has an elec-tric power output of 161.6 MW when running in therated condensing mode and 128.6 MW when running inthe rated cogeneration mode. The parameters of steamin the turbine steam path are given below.

The turbine comes as a single-shaft two-cylindermachine with throttle steam admission and is designedto operate at sliding parameters of steam in both the cir-cuits. The turbine is used for directly driving an Elek-trosila TFG–160-2U3 generator and for supplying heatto consumers.

CONSIDERATION OF THE SPECIFIC TECHNOLOGICAL FEATURES OF THE PGU-450T

UNIT IN SETTLING THE MATTERS OF AUTOMATIC CONTROL OF FREQUENCY

AND POWER IN THE POWER SYSTEM

One important peculiarity of gas turbines and,accordingly, of a CCPP as a whole is that their effi-ciency shows a rather essential dependence on the tem-perature of gases at the turbine inlet, a circumstancethat generates the need to strictly maintain the ratedtemperature of gases.

Parameters of steam in the high-pressure circuit upstream of the high-pressure cylinder’s stop valves:

rated/minimum admissible pressure

2

, MPa (kg/cm

2

)

7.225(73.65)3.8(39.0)

rated/maximum temperature,

°

C

512.7/545

rated/maximum/minimum admissi-ble steam flowrate

2

, t/h

453.6/525/130

Parameters of steam in the low-pressure circuit:

rated/minimum admissible pressure

2

, MPa (kg/cm

2

)

0.534(5.44)/0.47(4.70)

rated/maximum temperature,

°

C

221.7/250

rated/maximum/minimum admissi-ble flowrate

2

, t/h

85.8/150/40

Steam pressure downstream of the high-pressure cylinder, MPa (kg/cm

2

)

0.167 (1.70)

Cooling water temperature,

°

C

24.4

Design pressure in the condenser, MPa (kg/cm

2

)

0.00843 (0.09190)

The working range of gas turbine loads is that inwhich the temperature of gases remains unchanged.The required temperature is maintained by jointlyadjusting the flowrate of fuel (gas or diesel fuel) and thecompressor’s IGVD turning angle, which determinesthe flowrate of air to the combustion chamber. There-fore, the lower boundary of the working power rangedepends on the moment at which the IGVD closes. Thelower boundary value for the GT-160 gas turbine run-ning under the design external conditions is equal toaround 60%.

Another condition that determines the workingrange of loads during operation on gas is the moment atwhich the combustion chamber shifts from the opera-tion in the diffusion mode to the premixing mode,which allows nitrogen oxide emissions to be efficientlysuppressed. According to the experience gained withthe operation of the GT-160 units installed at theSeverozapadnaya cogeneration station in St. Petersburgand the Kaliningrad TETs-2 cogeneration station, the loadat which this transition is made is somewhat lower thatcorresponding to the fully closed position of the IGVD.

As the GT load reduces after closing the IGVD, thetemperatures of gases at the inlet to the gas turbine andat the outlet from it decrease fairly rapidly. As the tem-perature of gases at the GT outlet decreases, so does thetemperature of steam at the steam turbine inlet, forwhich a low-temperature protection is installed with asetpoint equal to 440

°

C. Hence, only an insignificantreduction in the gas turbine load with respect to theworking range’s lower boundary can be permitted, belowwhich its load cannot be reduced, no matter whether it isfor participation in primary control of the frequency or forthe purposes of emergency load shedding.

Thus, the boundaries of the working load range forCCPPs are as follows:

(i) the lower boundary of loads corresponds to thepower output of the unit (half unit) when the gas tur-bines (one or both) operate with their IGVDs beginningto open; and

(ii) the upper boundary of loads corresponds to themaximum power output at which the power unit canrun under current weather and process conditions.

The characteristics of the GTs depend considerablyon the ambient temperature. As this temperatureincreases, the upper and lower boundaries of the work-ing load range decrease (as the ambient air temperatureincreases by 1

°

C, the maximum possible load of oneGTs drops by around 0.5 MW), and the temperature ofgases at the GT output and the temperature of steam atthe steam turbine inlet that correspond to these bound-aries increase. As the environmental temperaturedecreases, the opposite change is observed: the loadrange boundaries increase, and the temperature of gasesat the GT output and the temperature of steam at the STinlet that correspond to these boundaries decrease.

It is often indicated in the literature that the CCPPsteam turbines should operate at sliding pressure with

2

When operating with one HRB.

870

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the valves kept fully open, a mode considered to be themost economically efficient one. However, such anapproach runs counter to the requirements of Rules ofTechnical Operation, according to which each turbinemust participate in primary control of the network fre-quency in accordance with its static characteristic, forwhich a certain valve displacement margin should beavailable. Therefore, the valves are kept in some inter-mediate position so that a certain control margin isretained. Such operating conditions are maintainedeither directly through the use of a device for control-ling the specified position of valves or indirectly bymeans of a device controlling the pressure of steamupstream of itself, the setpoint to it being either con-stant or depending on the load. If a change in the CCPPload is not connected with participation in primary con-trol of the frequency, and if no special requirements areplaced on the speed of load variation, such a change iscarried out only by adjusting the gas turbines, whereasthe steam turbine follows the change in steam outputand takes a new load with the inertia constant of theheat-recovery boilers, the time constant of which is onthe order of a few minutes. When the ST operates in apurely condensing mode, the loads of the turbines oper-ating within the CCPP are interrelated: the ST load isapproximately equal to half the total load of the gas tur-bines. For a number of reasons, operation with equal loadsis most preferable for gas turbines. Thus, when the CCPPequipment operates in full composition (two GTs and oneST), all the turbines run with approximately the sameloads, and when only one GT is in operation (the CCPPoperates in the half-unit configuration), the GT load is afactor of 2 larger than the ST load.

If the ST operates in a cogeneration or combinedmode, its electrical load will be less than half the totalload of the gas turbines and it will depend on the frac-tion of district heating load being generated.

Unlike traditional power units equipped with steamturbines, the initial change of load in which is carriedout by adjusting the steam turbine valves and is limitedonly by the possibilities of their displacement, the ratewith which the load of gas turbines can be varied islimited by strict temperature conditions and must beobtained by synchronously changing the positions ofthe GT control valves and IGVD of its compressor. Itshould be pointed out, however, that the rate with whichthe GT fuel valves and the steam turbine valves are dis-placed may be sufficiently high, whereas the IGVDs ofgas turbine compressors (in particular, those, of GT-160turbines) are as a rule driven by means of a usual servomotor with a constant traveling speed. Therefore, thefollowing limitations are imposed on the GT load vari-ation rate for the GT-160 unit:

(i) via the GT power setpoint channel (manually orautomatically from the unit-level process control sys-tems (PCSs)) at a level of 11 MW/min; and

(ii) when the turbine speed governor is in operation,at a variable upper limit, which depends on the control

deviation and the duration of the transient, with themaximum possible value equal to 38 MW/min.

The GT-160 turbine, which is manufactured underlicense from Siemens, comes with basic software forthe electrical part of the GT control system. The above-mentioned setpoints are part of this software and cannotbe changed. The adopted constraints have in all likeli-hood been substantiated from the considerations ofinadmissible rise in the temperature of gases caused byan increase in the load, because the change in air flow-rate may in this case be insufficiently fast to follow thechange in the fuel flowrate. As regards decreasing theload, in particular, emergency load shedding, the addi-tional dynamic variation in the temperature towarddecreasing is the only relevant factor here, which influ-ences the service life of the turbine metal.

THE FPCS HARDWARE

The FPCS has been constructed within the frame-work of the instrumentation and control (I&C) facilitiesof the power unit’s process control system on the basisof the TPTS-51 hardware manufactured at the DukhovAll-Russia Research Institute of Automation (VNIIA)under license from Siemens. In addition, there are localPCSs that are supplied completely with process equip-ment. Among them are the electrical parts of controlsystems (EPCSs) for the steam and gas turbines. Theselocal systems have been integrated in the power unitprocess control system in different ways: the steam tur-bine’s EPCS is constructed using the same equipmentas the power unit process control system, whereas theEPCSs of each gas turbine are made as independentsystems constructed using the Siemens SYMADYNI&C system. Data exchange between the power unitprocess control system and EPCS of the steam turbineis made using digital bus, while that with the EPCSs ofgas turbines is carried out via wired connectionsthrough the I/O devices of both the systems. The secondmethod is preferable from the point of view of the speedwith which signals are transmitted; however, it has dis-advantages in terms of the accuracy with which analoginformation is exchanged, because the analog-to-digital(digital-to-analog) converters of the I/O devices intro-duce certain errors. Along with the signals required foroperation of the interconnected control algorithms thatrun in different types of I&C system, the scope of dataexchange also includes signals using which the localPCSs of gas turbines communicate with the operator’sinterface-level process control system of the CCPP, whichis constructed using the Siemens OM-650 system.

A point of fundamental importance is that theEPCSs of gas turbines incorporate an electronic speedgovernor, whereas the ST rotation speed governor hasremained a mechanical-hydraulic device and has notbeen included in the steam turbine’s EPCS.

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MAIN FUNCTIONAL AND ALGORITHMIC SOLUTIONS FOR CONSTRUCTING THE FPCS

The automatic frequency and power control systemfor the PGU-450 power unit (Fig. 2) incorporates a unitpart and FPCSs for each of the turbines. The unit part com-prises the power unit’s power output controller and adevice for generating a reference signal for the unit’s totalpower output

N

Σ

ref

, which consists of two components:(i) a frequency corrector (FC), which generates a

setpoint for the unit’s power output for the primary fre-quency control channel; and

(ii) a setpoint rate-of-change limiter (SRL), whichgenerates a setpoint for the planned component ofpower

N

pl.ref

, which characterizes tertiary control of thefrequency.

In the general case, a channel for secondary controlof frequency with its own SRL should be added to thesetpoint generation structure.

3

The unit frequency corrector uses the median meanvalue of the measured rotation frequencies of three tur-bines.

The automatic frequency and power control systemfor the gas turbine, which is constructed on the basis of

the SIMADYN I&C system, has a fairly complex struc-ture using which different schemes for controlling thefrequency and power of GTs can be implemented. LMZspecialists have developed and put into use a versionclosest to similar Russian solutions. A simplified struc-ture of this version is shown in Fig. 2. A gas turbine’sFPCS comprises a GT load controller itself, a turbinespeed governor, frequency correctors (FC1 and FC2 inFig. 2), and a SRL. It is exactly this SRL that performsthe above-mentioned limitation of the rate of change inthe GT load at a level of 11 MW/min.

As was already mentioned, the steam turbine is stillcontrolled in the traditional way, i.e., by means of amechanical-hydraulic speed governor and an electroniccontroller producing commands for the turbine controlmechanism (TCM). A specific feature pertinent to thecontrol of the steam turbine used in a binary CCPP isthat two TCMs are used for the high-and low-pressurevalves and that each TCM is furnished with its ownelectronic controller comprising, as a minimum, chan-nels for controlling the pressure and the position ofvalves. The circuits through which the high- and low-pressure valves are controlled in the hydraulic part areinterconnected, a circumstance that gives rise to someproblems in adjusting the electronic controllers for thehigh- and low-pressure loops. At present, all LMZ tur-bines manufactured for combined-cycle power units,starting from the K-110-6.5 turbine for Unit 1 at theIvanovo DPS, come with electronic speed governors,

N

GT2

Simulator

Power unit

SRL

FC

SRL GT3 Controller

FC3

FC2

Hydraulic ST

GT2 speedGT1 load

FC1

GT1 speed

CVs of GT1CVs of GT2 CVs of ST

Σ

Σ

ΣΣ

Σ

Σ

++

+

+

+

–

–

–

–

–

–

–

–+

+

+

+

+ –

Σ

of frequencydeviations

N

GT1

N

GT1.ref

N

TS

f

ref

f

f

ref

f

N

pl.ref

N

Σ

.

output controller

SRL GT1

N

Σ

.ref

controller

governor

governor

N

GT1

N

GT2.ref

N

GT1

f

ref

ff

ref

f

GT2 speedgovernor

speed governor

for the pressureor position

of HP valves

TCM

Fig. 2.

Function diagram of the FPCS for the PGU-450 unit. CVs—Control valves; HP—high pressure.

f

ref

f

3

V. A. Bilenko, A. D. Melamed, E. E. Mikushevich, et al., “Devel-opment and Application of Automatic Frequency and Power Con-trol Systems for Large Power Units,” //

Teploenergetika

, No. 10,14–26 (2008) [

Therm. Eng.

, No. 10 (2008)].

872

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equipment in which there are no hydraulic connectionsbetween the systems for controlling high-and low-pres-sure loops.

Control of high-pressure valves plays the main rolein controlling the frequency and power. Therefore, onlythe controller producing commands for the high-pres-sure valves is shown in Fig. 2 and only its operation isanalyzed below.

To avoid a situation in which the high- and low-pres-sure controllers may block the operation of the STspeed governor, a frequency corrector is included in thestructure (FC3).

In accordance with the above-described approachfor controlling the PGU-450 unit’s power output, theunit’s power controller (UPC) produces control outputsonly to the gas turbines. The function diagram in accor-dance with which the UPC is constructed and its inter-connections with the FPCSs of gas turbines are shownin Fig. 3. The unit’s power controller comprises fouralgorithmic units:

(i) a unit for generating imbalance of the totalpower;

(ii) analog correcting PI controllers for controllingthe power output of each GT (two units); and

(iii) a scheme for parallel synchronization of GTs,which serves to equalize the gas turbine power outputsprovided that there are no technological constraints.

The UPC circuit also makes it possible to apply theoutput signal to the steam turbine (the dashed line inFig. 2). At present, such a possibility has not been putinto use due to the following reasons.

(1) The ST high- and low-pressure control valvesare interconnected as to their hydraulic circuits, a factordue to which partial closing of the high-pressure con-trol valves might cause the low-pressure control valvesbecoming fully closed during tests at low loads.

(2) The ST speed governor is implemented in thehydraulic part of the turbine control system; accord-ingly, it is not possible to connect this governor to theoutput of a device simulating frequency deviations, noris it possible to operatively change the ST droop (the STdroop remains equal to its value that was set up duringthe initial adjustment of the turbine’s hydraulic controlsystem.

(3) The speed with which responses to disturbancesare generated is slower in the case of using the turbinecontrol mechanism than it is in the case of using theST’s hydraulic speed governor.

The question of whether or not it is advisable to usethe common-unit FPCS for controlling the TCM can berevised after a hydraulic ST control system is retrofittedto become an electrohydraulic one.

Certain modifications had to be made in the FPCS ofthe PGU-450 unit for carrying out tests to ascertainwhether it conforms to the requirements of commonprimary control of frequency. Specifically, a device forsimulating frequency deviations was added to the FPCScircuit (see Fig. 2), the output signal of which is appliedto the inputs of the following devices to bring the testconditions maximally close to actual frequency devia-tions in a power system:

(i) the unit’s frequency corrector;(ii) the GTs’ individual frequency correctors; and(iii) the GTs’ speed governors.As was shown above, the current FPCS has been

configured so that the steam turbine changes its poweroutput in step with the rate at which the steam output ofboilers is increased. For this reason, the role of the unitcontroller consists in forcing the change in the GTs’power output to temporarily compensate for the delaywith which the ST power output is changed. Thus,when a change occurs in the network frequency, the FCof the GT’s power controller causes the latter to change

Correcting power

Generation

Scheme for parallel

FPCS of GT1

TPTS51

for the power unit'stotal output

controller ofsynchronization

of correctingcontrollers

FPCS of GT2

Correcting power controller of

GT2GT1

of control deviation

SIMADIN

TPTS51

SIMADIN

Fig. 3.

Function diagram of the power unit output controller.

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RESULTS FROM TESTS OF THE SYSTEM FOR AUTOMATICALLY CONTROLLING 873

the GT power output in accordance with the FC droopand the correcting signal from the unit’s power control-ler causes the GT’s power controller to additionally(temporarily) change the GT power output, thus com-pensating for the delay with which the ST power outputis changed.

ORGANIZATION AND PERFORMANCE OF TESTS

The tests were carried out in accordance with theMethodical Guidelines on Checking the Readiness ofThermal Power Stations for Primary Control of the Fre-quency in the Unified Energy System of Russia, a doc-ument attached as Appendix 1 to UES’s Order No. 524dated September 18, 2002. Checks of the automatic fre-quency and power control system were carried out nearboth the lower and upper boundaries of the power unit’sworking range.

The tests were carried out with two droop values: 6and 4%. A pair of experiments was carried out in boththe lower and upper parts of the power unit’s controlrange (toward increasing and decreasing the load) foreach droop value. The droop values were specified forthe gas turbine speed governors and for three frequencycorrectors: the unit FC and the gas turbine FCs.

The frequency deviation values were taken equal to

±

285 mHz for the 6% droop and

±

219 mHz for the 4%droop. These disturbances correspond to the power out-put deviation equal to 45 MW or 10% of rated power forthe PGU-450 power unit taking into account the 10-mHzdead band of the primary controllers.

The dead bands of the primary speed governors ofGT1 and GT2, the frequency correctors of GT1 andGT2, and the unit frequency corrector were increasedbefore the tests so as to make the dead band from therotation frequency sensor equal to

±

0.070 Hz.The conditions under which the experiments near

the control range’s lower boundary were carried outwere as follows:

(i) both the gas turbines operated when their IGVDsbegan to open; the power unit’s base load was equal to330 MW; and both the GTs operated at almost the sameloads (the difference was around 2.5 MW); and

(ii) the ST’s high-pressure control valves wereopened to 95–99% of the control range and operated forautomatically maintaining the pressure of high-pres-sure steam at the turbine inlet, and the ST’s low-pres-sure control valves were opened to 24–37% of the con-trol range and operated for automatically maintainingthe pressure of low-pressure steam at the turbine inlet.

The conditions under which the experiments nearthe control range’s upper boundary were carried outwere as follows.

(1) Both the gas turbines and the steam turbine ranwith their outputs close to the rated power values, andthe power unit’s base load was equal to 390 MW. Adecision was taken during the tests to depart from the

base load equal to 400 MW, since a fairly high temper-ature of outdoor air of around 17

°

C caused the IGVDsof both the GTs to fully open as their load wasincreased, and the devices for controlling the maximumtemperature of gases at the GT outlet, which wereimplemented in the SIMADYN-based control systemsof each GT, began to unload the turbines, so that theload did not increase to the required value.

(2) The loads with which both the GTs operated dur-ing the tests were, as during the tests at the controlrange’s lower boundary, almost the same, differingfrom each other by around 2.5 MW.

(3) The ST’s high-pressure control valves wereopened to 95–99% of the control range and operated forautomatically maintaining the pressure of high-pres-sure steam at the turbine inlet, and the ST’s low-pres-sure control valves were opened to 31–44% of the con-trol range and operated for automatically maintainingthe pressure of low-pressure steam at the turbine inlet.

The setpoint for the pressure controller of high-pres-sure steam was varied in accordance with variations ofthe base load in order to keep the high-pressure controlvalves in a position close to full opening. The control-lers operated in the automatic mode, because the powerstation personnel worried that the levels in the drumsmight become unstable during the tests.

TEST RESULTS

The accuracy with which an FPCS operates isregarded as satisfactory if the power unit output is

within the range

±

1% with respect to its assignedvalue. The parameters used as criteria for numericallycharacterizing a transient are the interval of time fromthe moment a disturbance was applied to the moment atwhich the power changes by 50% of the required valueand the interval of time from the moment a disturbancewas applied to the moment at which the power unit out-put fits into the permissible band determined by theaccuracy with which the FPCS maintains the power

(

±

1% ), i.e., when it changes by 90% of therequired value.

As an illustration, we present the curves of tran-sients obtained in the tests carried out near the lower(Fig. 4) and upper (Fig. 5) boundaries of the controlrange for a droop of 6%. The quantitative values of theadopted criteria are given in Table 1.

The characteristics we obtained from these tests ofthe power unit’s FPCS were found not to be fully incompliance with the requirements for CPFC. Theserequirements (which were specified in UES’s OrderNo. 524 dated September 18, 2002) demand that 50%deviation must be achieved within the first 10–15 s and90% deviation must be achieved for gas-and-oil-firedpower units within 300 s. Hence, we see that the periodof time for which the initial deviation is achieved isapproximately a factor of 2 longer than its permissible

Np.unom

Np.unom

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4

11:10:01 11:15:44 11:21:26 11:27:08 11:32:51 11:38:33 11:44:13

Time, h : min : s

267 1

360180 160 160 360

34060 140 140 340

32060 120 120 320

300180 100 100 300

280300 80 80 280

1

2

3

4

5

380300 180 180 380

6

7

5

360

340

320

300

280

380

3

160

140

120

100

80

180

4, 5

2

3

5

1

4

Fig. 4.

Experiments near the control range’s lower boundary with the GT droop equal to 6%. (

1

) Power unit’s total output, MW; (

2

)and (

3

) upper and lower boundaries of the accuracy with which a power output must be maintained, MW; (

4

) and (

5

) GT1 and GT2power outputs, MW; (

6

) ST power output, MW, and (

7

) frequency deviation, mHz.

4

13:14:01 13:19:40 13:25:20 13:31:00 13:36:41 13:42:21 13:47:50

Time, h : min : s

267 1

420180 180 180 420

40060 160 160 400

38060 140 140 380

360180 120 120 360

340300 100 100 340

1

2

4

5

440300 200 200 440

6

7

5

420

400

380

360

340

440

3

180

160

140

120

100

200

4

3

5

1

4

5

6

1

Fig. 5.

Experiments near the control range’s upper boundary with the GT droop equal to 6%. The notation is the same as in Fig. 4.

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RESULTS FROM TESTS OF THE SYSTEM FOR AUTOMATICALLY CONTROLLING 875

value, whereas the final deviation is achieved within aperiod of time much shorter than the required one (75 sinstead of 300 s).

That the power output varies almost linearly and theresults obtained from individual tests with a distur-bance equal to 5% of load allows the conclusion to bedrawn that it is possible to extrapolate the obtainedresults for the indicators of selective primary control ofnetwork frequency (SPFC), because a change in thepower unit load depends primarily on the permissiblerate with which the GT load can be varied. It followsfrom this (Table 2) that the indicators for SPFC withinthe normal margin (at a 5% disturbance) will be as fol-lows: the 50% deviation is achieved for approximately15 s, and the 90% deviation for 33 s. The values of boththese indicators are somewhat larger than the standardones (10 and 30 s, respectively), though only insignifi-cantly. The requirement imposed on the initial changein power for SPFC within the emergency margin (a12.5% deviation of power) will not be fulfilled either (adeviation by 50% will be achieved in approximately38 s); however, no problems will occur with respect tothe total duration of the transient, which must notexceed 2 min: the 90% deviation will be achieved inapproximately 1 min 22 s (see Table 2).

The obtained indicators can be improved whenactual deviations of frequency occur in the power sys-tem owing to the fact that the steam turbine’s hydraulicspeed governor will participate in responding to fre-quency disturbances. This improvement will alwaystake place when the frequency increases, a situation inwhich the steam turbine load has to be reduced, andalso when the frequency decreases if the turbine valvesare not fully open in the initial state. The characteristicsof the steam turbine will be improved for the task of pri-mary control of frequency, and its role will be estimatedduring tests when an electrohydraulic ST control sys-tem is installed instead of the hydraulic one that hasexisted to date at the Kaliningrad TETs-2 cogenerationstation. Another means using which the PGU-450Tindicators for primary control of frequency can beimproved consists of taking a signal from the unit’spower controller to control the steam turbine.

The above-mentioned methods through which theindicators characterizing primary control of frequencycan be improved with the use of a steam turbine whenit is necessary to increase the power unit load (i.e.,when the frequency decreases) are only possible if anST control range toward increasing is available; i.e., ifthere is a sufficient margin for shifting the turbinevalves toward opening.

It also follows from the test results that no problemsarise for the PGU-450T unit with fulfilling the require-ments for automatic secondary frequency control. Themaximum rate of change in the load equal to 4%/min,i.e., 18 MW/min, which is required in accordance withthe SO–CDA Standard, can be achieved by changingthe gas turbine load alone via the common-unit control

channel, the limitation for which is equal to22 MW/min for two GTs. When only one GT is in oper-ation, this limitation is equal to 11 MW/min, whereasthe required rate of change in the half-unit’s load isequal to 9 MW/min.

Thus, the results from the tests that have been car-ried out on the FPCS of the PGU-450 unit for compli-ance with the CPFC requirements (with a disturbanceequivalent to 10% of rated load) and the extrapolationof the obtained results for estimating whether therequirements of the SO–CDA Standard for SPFC (fromthe point of view of control dynamics) and ASFC arefulfilled allow us to draw the following conclusionsregarding the possibility of fulfilling these require-ments for the PGU-450 unit and other combined-cycleplants with a similar structure.

(1) The requirements for ASFC and the dynamiccharacteristics of CPFC and SPFC are fulfilled com-pletely within the emergency margin (12.5%) withrespect to the total time of the transient.

(2) The tests carried out on CCPPs equipped with SThydraulic speed governors have shown that the indica-tors characterizing the dynamics of SPFC within the

Table 1. Results of tests for checking the preparedness forCPFC

Droop, %

Mean time for achieving 50% of the required change in power, s

Mean time for achieving 90% of the required change in power, s

experiment standard experiment standard

Near the control range’s lower boundary

6 30.5 10…15 75 300

4 31 10…15 61 300

Near the control range’s upper boundary

6 29 10…15 62 300

4 32 10…15 60 300

Table 2. Results from extrapolation of experimental data forestimating the preparedness for SPFC

Indicator

Mean time for achieving 50% of the required

change in power, s

Mean time for achieving 90%

of the required change in power, s

During normal disturbance (5% of rated power unit output)

Standard 10 30

Extrapolation 15 33

During emergency disturbance (12.5% of rated power unit out-put)

Standard 15 300

Extrapolation 38 82

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normal margin with regard to the time for which half ofthe required change in the power must be achieved (theinitial part of the transient) and the total time of the tran-sient are fairly close to the standardized values and mustapproach the standardized values or even outperform themduring actual participation of CCPPs in frequency control,as well as in experiments with CCPPs equipped with elec-tronic steam turbine speed governors.

(3) The indicators characterizing the dynamics ofCPFC and SPFC within the emergency margin are con-siderably inferior to the standardized values withrespect to the time for which half of the required changeof power has to be achieved (by factors of 2 and 3.5,respectively). This is due to the fundamental constraintsimposed on the possible rate of change in the gas tur-bine load. The values of these indicators can beimproved to some degree during actual participation ofCCPPs in frequency control. Assessment of whether aconsiderable improvement can be made in the indica-tors of CCPPs equipped with electronic steam turbinespeed governors requires special investigation.

At present, two new CCPPs—namely, the PGU-325installation of Unit 1 at the Ivanovo DPS and the PGU-450installation of Unit 3 at Mosenergo’s TETs-27 cogener-ation station, the structures of which are similar to thatof Unit 1 at the Kaliningrad TETs-2 cogeneration sta-tion and which are equipped with LMZ steam turbinesand Interavtomatika process control systems—havebeen furnished with electronic steam turbine speedgovernors. There are plans according to which the STcontrol systems used in the PGU-450 power unitsinstalled at the Kaliningrad TETs-2 cogeneration sta-tion and at the Severozapadnaya cogeneration station inSt. Petersburg have to be retrofitted with the use of elec-tronic speed governors. The LMZ management intendsto supply all new steam turbines for similar CCPPs onlywith electronic speed governors. Hence, those in chargeof working out plans for the participation of CCPPs insystem-wide control of frequency may use, as a firstapproximation, the assessments of the quality of tran-sients expected in the case of using electronic ST speedgovernors.

As was mentioned above, no requirements are cur-rently placed on combined-cycle plants for their partic-ipation in ASFC and SPFC. All the above-mentionedstandardized indicators characterizing the dynamics of

transients have been determined for gas-and-oil-firedpower units. Nonetheless, the CCPP being consideredsuccessfully meets the requirements, in particular,those for SPFC within the emergency margin, exceptwith the dynamics of the transient in its initial part.Gas-and-oil-fired power units satisfy the requirementsfor SPFC within the emergency margin. However,whereas no problems arise with meeting these require-ments in the initial part of the transient, the require-ments for the time within which the process has to becompleted can only be met by considerably forcing theboiler, which gives rise to certain difficulties (see Foot-note 3). In our opinion, it is advisable—from the pointof view of solving power grid challenges—that CCPPsnot be barred from participation in SPFC but be used insuch a way that the advantages of CCPPs and traditionalpower units can be rationally combined, and also in thedistribution of power backups. It follows from this thata special document similar to that available for the tra-ditional thermal power stations has to be developed thatwould specify the norms according to which CCPPsshould participate in ASFC and SPFC.

CONCLUSIONS

(1) A system for controlling the frequency and powerof a power unit has been installed in the PGU-450 powerunit at the Kaliningrad TETs-2 cogeneration station aspart of the power unit’s process control system and hasbeen constantly used since March of 2006.

(2) At present, the PGU-450-based Unit 1 at theKaliningrad TETs-2 cogeneration station fully meetsthe requirements for ASFC and also the dynamic char-acteristics of CPFC and SPFC within the emergencymargin with regard to the total duration of the transient.

(3) The existing constraints on the rate of change inthe GT power output do not allow the requirements forCPFC and SPFC within the emergency margin to befulfilled in the initial part of the transient.

(4) The obtained results reflect a number of advan-tages of CCPPs from the point of view of their partici-pation in SPFC; this makes it advisable to develop aspecial document (similar to the SO–CDA Standard forthe traditional power units) that would specify thenorms according to which CCPPs should participate inSPFC and ASFC.

877

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 877–885. © Pleiades Publishing, Inc., 2008.Original Russian Text © I.Z. Chernomzav, D.A. Zhezherya, R.V. Mukharryamov, A.A. Perezhogina, 2008, published in Teploenergetika.

The GTE-110 gas turbine unit (GTU) of OAO SaturnResearch and Production Association is the first Russianpower-generating installation intended for use as part of dif-ferent combined-cycle power plants (CCPPs): 325- and170-MW heat-recovery CCPPs and a 420-MW CCPP thegases from which are discharged into a power-generat-ing boiler for afterburning. The prospects for the use ofGTE-110 units stem from the need to technically refitpower units that are already in operation and construct-ing new power units. In its technical characteristics, theGTE-110 unit is one of the best GTUs: the temperatureof gases at the turbine inlet is equal to 1210

°

C, and theGTU efficiency is equal to 35%. This installation fea-tures the lowest specific consumption of metal relativeto similar indicators of other gas turbines for closepower capacities. The turbine’s flow-path part com-prises four stages; its air-cooling system has a branchedconfiguration with the use of an air–water heatexchanger for additional cooling of air. A 15-stagecompressor is installed on the common shaft, the com-pression ratio of which is equal to 14.75 at rated powerand design parameters of outdoor air. An inlet guidevane device (IGVD) is installed upstream of the com-pressor, which serves to extend the range in which reli-

able operation of the compressor is ensured andimprove the economic indicators of the CCPP duringoperation at partial loads by maintaining the tempera-ture of flue gases at its rated level.

The GTE-110 gas turbine unit is furnished with anair-cooled T3FG-110-2MU3 generator, which comeswith an STS-2E-220-1900-2.5UKhLCh thyristor exci-tation system connected in accordance with a self-exci-tation arrangement.

The technological structure of the GTE-110 unitincorporates around ten subsystems, which must becontrolled in a coordinated manner to organize normaloperation of the entire GTU. The GTE-110 unit isequipped with a modern microprocessor-based processcontrol system (PCS) developed at ZAO Interavtoma-tika, which solves the tasks pertinent to monitoring andcontrol of the GTU [1]. The function diagram illustrat-ing how this APCS interacts with all systems of GTE-110 is shown in Fig. 1.

The list of PCS functions includes the following:(i) automatic control of the parameters of GTE-110,

including rotor rotation frequency, temperature of gasesdownstream of the turbine, and electric power output;

The System for Automatically Controlling the Processes in a GTE-110, Russia’s First High-Temperature Large-Capacity

Gas Turbine

I. Z. Chernomzav, D. A. Zhezherya, R. V. Mukharryamov, and A. A. Perezhogina

ZAO Interavtomatika, ul. Avtozavodskaya ul. 14/23, Moscow, 115280 Russia

Abstract

—The tasks imposed on the control of the GTE-110 gas turbine unit are considered together with theresults of experiments carried out at a test rig and on the PGU-325 combined-cycle power plant at the Ivanovodistrict power station.

DOI:

10.1134/S004060150810008X

PCS of the PGU-325

PCS of the GTE-110 unit

TSD GeneratorExcitation

power unit

systemCompressor

and BGGas turbine

control and protections

Pneumaticcontrol

Group of fuel devices

Lubricationsystem

Cooling

system

Gas

stationwater preparation

Fig. 1.

Interaction of the PCS with the systems of the GTE-110 unit. TSD is the thyristor starting device and BG is the barring gear.

878

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(ii) technological protections of the GTE-110 unit;(iii) automatic control of fuel supply when the tur-

bine is started up and reaches the nominal rotation fre-quency;

(iv) discrete control performing logic algorithmswhen the GTE-110 is started up and shut sown in nor-mal and emergency modes;

(v) automated control of all auxiliary equipmentduring startup, shutdown, and normal operation; and

(vi) control of electrical equipment.

GTE-110 CONTROL TASKS AND THEIR IMPLEMENTATION

A gas turbine unit is a complex plant from the pointof view of controlling it. The processes in a gas turbineoccur fairly rapidly, and several actuating mechanismshave to be controlled simultaneously under all operat-ing conditions. The PCS of a gas turbine serves to per-form the following functions:

(i) the operation of protections and interlocks andautomatic switching of backup auxiliary equipment;

(ii) closed-loop control of parameters;(iii) automatic logic control and process interlocks,

including automated control of process units, automaticdevices and functionally interconnected groups of pro-cess equipment, and control performed in accordancewith sequential logic dependences, including step-by-step programs;

(iv) remote control;(v) emergency and warning alarms;(vi) data presentation; monitoring, recording, and

archiving the parameters and state of equipment; and(vii) recording of emergency situations.The gas turbine startup and shutdown processes are

carried out using the following stepped programs: a gasturbine startup and shutdown program, a gaseous fuel

control program, a liquid fuel control program, and aprogram for switching on the gaseous-fuel-fired chan-nel of the central zone.

The PCS incorporates the following devices usingwhich a gas turbine’s main parameters are controlled: afuel feed regulator; a fuel consumption programmingdevice; a device for controlling frequency and power; adevice for controlling the temperature downstream ofthe turbine, which generates commands for the IGVD;function units for generating setpoint for flowrates andpositions of valves for gaseous and liquid fuel; and alimiting controller of temperature.

The PCS for the GTE-110 unit incorporates around70 protections, which generate commands for shuttingdown the turbine if emergency conditions occur.

Gas Turbine Stepped Control Programs.

The gasturbine startup–shutdown program serves to control thesequence of operations and monitor the gas turbineparameters. It is used for automatically starting the tur-bine, monitoring the starting process and canceling it ifmalfunctions occur, shutting down the turbine when theoperator trips it out, and connecting and disconnectingthe preselected fuel system during startup and shut-down operations (in this case, the correspondingstepped program for gaseous or liquid fuel is started).

The gaseous (liquid) fuel control program serves tocontrol the sequence of technological operations thatare carried out when the turbine is started, runs in thenormal mode, and is shut down during the operation onthe selected kind of fuel. This program includes opera-tions for controlling the components of the gaseous(liquid) fuel system both when the turbine is started andwhen the supply of gaseous (liquid) fuel is terminated.

Figure 2 shows the function diagram illustratinghow the control of GTE-110 systems is organized.

Control of Fuel Flowrate in the GTU.

The flow-rate of fuel is controlled by adjusting the position ofvalves in the pilot and central zones.

Stepped program for starting/shutting downthe GTE-110 unit

Stepped program for controlling Stepped program for controllingthe system of gaseous fuel the system of liquid fuel

Mechanisms Controllers Logic control Mechanismsof the gaseous

fuel systemof the GTE-110

unitof GTE-110

systems of the liquid fuel system

Fig. 2.

Function diagram illustrating the control of GTE-110 systems.

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THE SYSTEM FOR AUTOMATICALLY CONTROLLING 879

These controllers include the following elements:

a unit of main controllers

, which comprises poweroutput and frequency control loops;

limiting controllers

, including a device for control-ling the temperature of gas downstream of the turbine;a maximum power controllers, the limiting setpoint ofwhich depends on the outdoor air temperature and pres-sure; and a controllers for the minimal flowrate of fuelto the combustion chamber; and

a unit for generating the assigned flowrate of fuel

,which serves for distributing the fuel among the valvesof the central and pilot zones; the minimal flowrate offuel through the central zone channel depends on theoutdoor air temperature, and the maximal flowrate offuel through the pilot zone channel depends on the out-door air temperature and on the IGVD turning angle.

The fuel flowrate programming device serves togenerate the assigned flowrate of fuel when the gas tur-bine is started. When the gas turbine engine runs in anormal operation mode, the assigned flowrate of fuel isgenerated by means of the rotation frequency or poweroutput controller depending on the operating mode.When any parameter participating in the algorithms oflimiting controllers (the temperature of gas down-stream of the turbine, electric power output, or flow-rate) goes beyond the permissible threshold, the unit oflimiting controllers comes into action and remains sountil the parameter that went beyond the threshold isreturned within the permissible limits.

Devices Controlling Rotation Frequency andPower.

The gas turbine is speeded up by means of athyristor starter to 2600 rpm, after which the frequencycontroller comes into action and brings the rotation fre-quency to 3000 rpm.

After the generator is synchronized with the powernetwork, the power controller comes into action with anassigned value of power output equal to 4 MW. Furthercontrol of power unit loading is carried out using apower setpoint adjuster. Commands from the unit-levelpower controller or from the operator may switch thepower setpoint adjuster used in the GTE-110 unit tooperate in the automatic mode, in which it will receivea reference signal for the ultimate power output fromthe unit-level power controller.

If the “Normal Shutdown” signal is ON, the gas tur-bine stepped startup–shutdown program generatescommands to the power setpoint adjuster in response towhich it generates an ultimate setpoint equal to 1 MWand the operator selects the rate of change in the set-point (from 1 to 7 MW/min). Once the electric poweroutput reduces to 1 MW, the generator is switched-offfrom the network and shifts to run in the idle mode. Theturbine cools down for 10 min, after which its valvesare automatically closed, and the rotor runs down untilit stops completely.

The frequency controller can be set up for coming intoaction when the rotation frequency is below 700 rpm.

Emergency shutdown of the turbine can be done byclicking on the virtual pushbutton on the operator’scontrol console or pressing the button on the standbycontrol console; these operations cause the stop andcontrol valves to close.

A device for controlling the temperature of gasesdownstream of the turbine by controlling the IGVD

serves to adjust the turn angle of the GTE-110 unit’sinlet guide vanes for setting up the flowrate of airrequired for obtaining the necessary temperature ofgases upstream of the boiler (when the GTE-110 unitoperates as part of the PGU-325 combined-cycle plant).A PI-controller of the IGVDD turning angle is used toplace the inlet guide vane in the required positiondepending on the control diviaction between theassigned and current temperatures of gases downstreamof the turbine.

The mutual influence of the gas temperature con-troller generating commands for the IGVD and the tem-perature limiter is excluded by setting the first one tooperate with a setpoint for the temperature of gasesdownstream of the turbine reduced by 7

°

C.

The technological protections

operating in thePCS serve to perform the following functions:

(i) carrying out diagnostics of the input analog anddiscrete signals;

(ii) changing the structure in accordance with whichprotection signals are generated when failures of sen-sors occur;

(iii) generating virtual jumpers for enabling and dis-abling protections;

(iv) indicating the state of protections (enabled/dis-abled); and

(v) presenting information on the state and opera-tion of protections on video displays for the operator.

The operation of some protections can be checkedon the running equipment, among which are those foroverspeed, no-burning, low lubrication pressure, andhigh temperature of gases downstream of the turbine.The other protections can be checked on the stoppedGTE-110 unit by simulating the conditions underwhich they must come into action.

A new computer program has now been developedusing which all protections can be checked on thestopped turbine. The checking algorithm simulates sig-nals the values of which correspond to their emergencylevels. Since some protections have to be checked atlower values of their emergency setpoints, the algo-rithm has facilities for appropriately reducing theamplitude of the simulated signal. Once a protection’scoming into action is checked the record of, the simu-lated signal in the log is released.

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STRUCTURE OF THE PCS FOR THE GTE-110 UNIT

The idea of constructing the PCS for the GTE-110unit on the basis of the unified domestically producedinstrumentation and control systems became realityafter Interavtomatika and Dukhov VNIIA specialistsjointly developed a number of high-speed controllers.The new TPTS-52.1724-01 module makes it possible toenter information from three electromagnetic rotationfrequency sensors, calculate it in each channel alongwith checking its validity, determine the mean valuefrom three frequency values, and generate setpoints forthe rotation frequency. All tasks are calculated with acycle of less than 10 ms. Being part of the system, thismodule obeys the laws in accordance with which theI&CS is constructed and can be made redundant anddiagnosed as any other module. An electronic rotationfrequency governor has been constructed and the func-tions of an automatic emergency control system (ECS)have been implemented on the basis of this and a num-ber of other modules that were developed [2].

The technical structure of the PCS is shown in Fig. 3. Itincorporates a lower, or controller, level, which consistsof three cabinets that receive and process informationand run the entire volume of direct digital control, pro-tections, interlocks, automatic controllers, and logicprograms.

The gas turbine and compressor are controlled withthe use of nonstandard actuating mechanisms that arenot typical for the Russian power engineering. Theseare furnished with equipment for monitoring the integ-rity of control circuits, the state of which is displayedfor the operator in video frames. The PCS incorporatesa cabinet for controlling these actuators and a 24-Vpower supply cabinet.

The I&CS, also includes cabinets housing IT14vibration sensors, sensors for special measurements,spark protection units for the circuits of a number ofsensors, a turbine speedup limiter, and a 220-V powerdistribution cabinet.

The upper level of the PCS, which consists of oper-ator workstations, performs the following functions:

Fig. 3.

Structure of the PCS for the GTE-110 unit.

Standby control console 30CWS01 with additional

volume of functions Matrix

Workplace of an electrician

Ink jet

Laser jet printer

printer

Turbine

Workplace of a process

engineer

Redundant system bus CS275

Power supplies

220/380 V AC

220 V DC

+24 B

+24 B

Power supply cabinet

Cabinet of inter-

relaysposing

Cabinet of inter-

relaysposing

Mar-

shalling

cabinet

Additional relay

cabinet

for controlling

nonstandard

actuators

Additional power

supply cabinet

Power supplies

220/380 V AC

220 V DC

+24 B

+24 B

Gas preparation station and monitoring

of additional parameters

printer

U/I U/I U/I U/I U/I U/I

U/I U/I

AS 220 EA RS485 AS 220 EAAS 220 EA

A

B

U/I U/I

GE

GE GE

GE

GE

GE

EE

EEEE

EE

EE

EE

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THE SYSTEM FOR AUTOMATICALLY CONTROLLING 881

(i) online monitoring and control of technologicalprocesses;

(ii) process and functional alarms;(iii) archiving, logging, and presentation of techno-

logical processes in graphic form; and(iv) calculation tasks.Operator workstations perform the main functions

of online monitoring and control with use of necessaryvideo frames. Each video frame contains, along with astatic part, dynamic elements that represent the analog anddiscrete signals indicating the state of equipment itemsbeing monitored and controlled. As an example, Fig. 4shows the video frame for controlling the GTE-110 unit.

The indication displayed on the screen reflects theoperation of process equipment and informs the opera-tor of the state of the monitoring and control system.

New technical equipment on the basis of theSPPA-T3000 controllers are supposed to be used forfurther development of the PCS for GTE-110 units [3].

The experience Interavtomatika specialists have gainedfrom their activities on other equipment, e.g., the PCSfor the PGU-450 combined-cycle power plant, con-firms that such a shift does not require much effort.

RESULTS FROM TESTS OF THE PCS OF THE GTE-110 UNIT DURING INDEPENDENT

OPERATION

Speeding Up and Loading the GTE-110 Unit.

The curves shown in Fig. 5 illustrate how the gas tur-bine is sped up to the idle running mode and subse-quently loaded to 110 MW. The curves are given for thefollowing parameters:

(i) the rotor rotation frequency;(ii) the temperature of gases downstream of the turbine;(iii) the position of the control valves in the first and

second channels;(iv) the generator power; and

Plant ESP A P D F V Graphs ACS SP Menu

Vertical-wise GTU

cleanair

BG1–BG ON

2–BG OFF

1–frequency 1 ON2–frequency 2 ON

IGVD REF

from CWTP

FDU

to the atmosphere

Rep

Rep

to the atmosphere

BG ON

ON and OK

Disengaged

IGVD

CC

deg

I

BG

A

to HRB-11

P1out;

P2out;

kPa

kPa N

drive

kPa

from GT-11 oil supply system

removal of cooling water

Tg

out

Tg

out

REF

supply of coolingwater

11MBY00ER00

CC

Rep

11MBK05CH001

11SDN2OAN001 11MBK05CH002

–36

0.00

–0.01

deg

MW

20

–16

MW

A

P

21 deg

11MBKO5EKOO1

11MBKO5EKOO1

11MBKO5EKOO1

11MBO5CE012

11MBV50CP001

11PCM39CT00

11MBA10DG001

11MBA10AA801

11MBV40CT001

11MBV40CP001

Rep

17

11MBV

41AP001 41AP002 41AP003

11PCM11AA001

MW

11PCM10CP002 11PCM10CT00211PCM20CP001 11PCM10AA001

GTU

–11

MW

deg

P

í

deg

í

í

MW

è

è è

deg

í

?

11PCM10CP001 11PCM10CT001

11PCM23AA801

11MBY20DS001

11MBR20CT903A

11MBA10AA801

% n

P

N

ù

GT

–11

MW

è

%

MW

11PCN39CF901

11PCM39AA801

11MBR20CP001

11MBR20CP002 11MKA10CE001

11MKA00FE001

11HHS22AN001

11HHS21AN001

11HHS22AN001

11HHS21AN001

T

P

11HHS21CT001

11HHS21CP001

11MBS05AN001

11MBS05AN002

T

P

è

P

%

GT

–11

Fig. 4.

Video frame for controlling the GTE-110 unit used as part of the PGU-325 unit No. 1.

882

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(v) the power of the thyristor starting device.The gas turbine is started in a fully automated man-

ner from a single pushbutton. Typically, the turbinestarting process comprises the following stages:

(i) the gas turbine is sped up by means of a thyristorstarting device to a rotation frequency of 700 rpm andventilated at this frequency for 10 min;

(ii) the rotation frequency is increased to 900 rpm,after which fuel is admitted to the combustion chamber;

(iii) the rotation frequency is increased further usingthe thyristor starting device and fuel flowrate program-ming device; and

(iv) the thyristor starting device and then the fuelflowrate programming device are disconnected whenthe rotation frequency reaches 2600 and 2850 rpm,respectively, after which the rotor speed governor isswitched into operation, which brings the turbine rota-tion speed to a level of 3000 rpm.

Prior to starting up the turbine, the IGVD is closed,which causes the temperature of gases downstream ofthe turbine to rise to 480

°

C for a short time when fuelis admitted to the combustion chamber.

Once the rotation frequency reaches 2900 rpm, theIGVD is forcedly opened and the temperature dropsvery rapidly to 210

°

C. After the rotation frequency hasreached 3000 rpm and the turbine has been heated for10 min, the generator is synchronized with the powersystem and picks up the initial load. The rate withwhich the GTE-110 unit is brought to the nominalpower level is set by the operator on the rate-of-powersetting device. This rate is equal to 7 MW/min for nor-mal operating conditions. The ultimate power level isset up in accordance with the load curve.

The combustion chamber of GTE-110 consists oftwo zones: a pilot zone and a central zone. The unit isbrought to run in the idle mode and its load is picked up

to around 20 MW using the first channel of the combus-tion chamber (the pilot zone). To increase the load fur-ther, the second channel (the central zone) has to be putin operation, which is switched on in a stepped mannerto obtain stable combustion. The central channel isswitched on and off automatically with the use of astep-by-step program.

The Static Characteristic of GTE-110.

The gasturbine’s static characteristic was determined on therunning equipment after the generator had been con-nected to the network and picked up the initial loadequal to 4 MW. The gas turbine load was increased byincreasing the setpoint (reference value) of rotation fre-quency. The reverse branch was obtained by decreasingthe setpoint rotation frequency. The maximum deviationbetween these values was equal to 1.15, or

±

0.575 rpm. Itfollows from this that the maximum dead band is equalto

±

9.6 mHz and lies in the middle of the load adjust-ment range and the control droop is equal to 4.96%.

Tests of the Limiting Gas Temperature Control-ler.

The controller for limiting the temperature of gasdownstream of the turbine was checked by abruptlyclosing the IGVD to cause the temperature of gasesdownstream of the turbine rising above the limitingvalue, which was set at a level of 470

°

C during the test.A change in the gas temperature downstream of the tur-bine by 13

°

C above the limiting value was recordedduring the test, which nonetheless was lower than theprotection setpoint (+30

°

C with respect to the limitingtemperature). The results of these tests are shown inFig. 7. The limiting controller partly closed the controlvalve to maintain a specified temperature equal to470

°

C. After the IGVD had returned in the initial posi-tion, the temperature of gases reduced and the controlvalve opened to its initial position.

GTE-110 Loading and Unloading Processes.

Fig-ure 8a shows the GTE-110 loading process, whichcomprises the following stages:

(i) the operation of the pilot zone with the IGVDheld in the open state; the GTE load is slowly increasedfrom 12 to 18 MW during this mode (section

A

);

45004000350030002500200015001000500

0

480

400

320

240

160

80

009:49 09:57 10:05 10:13 10:21

Heating in the idlemode

Operation

n,

rpm

N

, kW

N

, MW

ϕ, %

Τ

, °

C

t

, h : min

1

2

3

4

5

6

I II

in the network

Fig. 5.

GTE-110 starting process. (

1

) TSD power, kW; (

2

)rotor rotation frequency, rpm; (

3

) temperature of gasesdownstream of the turbine,

°

C; (

4

) and (

5

) turning angle ofthe control valves in the 1st and 2nd channels, %; (

6

) gener-ator power, MW; (

I

) synchronization; and (

II

) connection ofthe central gas channel.

140

120

100

80

60

40

20

0 10 20 30 40 50 60 70 80 90 100

Freq

uenc

y in

crem

ent,

rpm

∆

=

±

0.575 rpm

N

e

, MW

Fig. 6.

Static characteristic of the GTE-110 unit.

Automatic startup

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Vol. 55

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THE SYSTEM FOR AUTOMATICALLY CONTROLLING 883

(ii) automatic connection of the central zone withthe IGVD held open, after which the power output isincreased to 30 MW; the flowrate of fuel admitted to thecombustion chamber is increased abruptly in order toswitch on the central zone and maintain stable combus-tion; the amplitude of this stepped increase depends onthe outdoor air temperature; that the power increasedby 30 MW and the temperature of gases downstream ofthe turbine rose by 75% testifies that the combustionprocesses in the combustion chamber’s central zone arestable (section

B

);(iii) switching over the IGVD to operate in the auto-

matic mode (section

C

);(iv) loading the GTE-110 unit with the device for

controlling the temperature of gases downstream of theturbine (by adjusting the IGVD) switched into opera-tion until the temperature of gases reaches its ratedvalue equal to 513

°

C (section

D

);(v) loading the power unit while maintaining the

temperature of gases at a level of 513

°

C using thedevice for controlling the temperature of gases down-stream of the turbine by adjusting the IGVD (section

E

);and

(vi) operation at the specified level of power withmaintaining the temperature of gases at a level of513

°

C using the device for controlling the temperatureof gases downstream of the turbine by adjusting theIGVD (section

F

).The GTE-110 unloading process is shown in

Fig. 8b. It comprises the following stages:(i) the power unit operates at the specified level of

power with maintaining the temperature of gases at alevel of 513

°

C using the temperature controller adjust-ing the IGVD (section

I

);(ii) the GTE-110 unit is unloaded while maintaining

the temperature of gases at a level of 513°C with thetemperature controller acting on the IGVD switched in

operation (this is possible until the load is reduced to60 MW) (section II);

(iii) further unloading of the GTE-110 unit causesthe temperature of gas to decrease, because the IGVDis on its lower limit and cannot maintain the tempera-ture of gases at the specified level (section III);

(iv) the IGVD is switched over to operate in theremote control mode and opened, causing the tempera-ture of gases downstream of the turbine to drop to310°C (section IV);

50

4030

20100

–10–20–30–40

500490480470460450440430420410

16:48:00 16:50:53 16:53:46 16:56:38

ϕIGVD, degϕCV, %

Time, h : min : s

T, °C

1

2

3483°

Fig. 7. Checking the operation of the limiting temperaturecontroller producing commands for the control valve. (1)IGVD turn angle, deg; (2) turn angle of the second chan-nel’s control valve, %; and (3) temperature of gases down-stream of the turbine, °C.

100

80

60

40

20

0

–20

–40

600

500

400

300

200

100

0

–100

–20012:21:36 12:27:22 12:33:07 12:36:00

ϕIGVD, degϕCV, %N, MW T, °C

Time, h : min : s(a)

100

80

60

40

20

0

–20

–40

600

500

400

300

200

100

0

–100

–20013:22:05 13:24:58 13:27:50 13:30:43 13:33:36

ϕIGVD, degϕCV, %N, MW T, °C

Time, h : min : s(b)

V

IV

1

3

4

5

2

I II III IV

A

B C

D E F

1

2

3

4

5

Fig. 8. Automatic loading of the GTE-110 unit with main-taining the temperature of gas downstream of the turbine ata level of 513°C during the operation at loads of (a) higherand (b) lower than 60 MW. (1) IGVD turn angle, deg; (2)and (3) turn angles of the control valves of the first and sec-ond channels, %; (4) Ne, MW; and (5) temperature of gasesdownstream of the turbine, °C.

884

THERMAL ENGINEERING Vol. 55 No. 10 2008

CHERNOMZAV et al.

(v) the power unit is further unloaded to 30 MW, andthe central zone is automatically swetched-off with theIGVD held open (section V); and

(vi) the GTE-110 unit operates using the pilot zonewith the IGVD held open (section VI).

RESULTS OF TESTING THE PCS OF THE GTE-110 UNIT DURING

ITS OPERATION AS PART OF THE PGU-325 COMBINED-CYCLE

POWER PLANT

The PCS has been put into use in two GTE-110 gasturbines supplied from Saturn Research and ProductionAssociation and used as part of the pilot PGU-325 com-bined-cycle power plant at the Ivanovo DPS. The PCSof the first gas turbine was adjusted in February andMarch, and that of the second gas turbine, in May of2007. The processes used to control the gas turbineoperating as part of the PGU-325 plant are similar tothose used to control the gas turbine operating in anindependent mode with the switched-on device for con-

trolling the temperature of gases downstream of the tur-bine by adjusting the IGVD. The PGU-325 unit hasnow been used in a half-unit configuration due to thelimited volume in which gaseous fuel is supplied to theIvanovo DPS.

In what follows, we consider how two GTE-110 gasturbines, one of which operates on gaseous fuel and theother on liquid fuel, and a K-110-6.5 steam turbine arejointly loaded. The curves in Fig. 9 show the increase inthe power output of the PGU-325 unit power when gasturbines Nos. 1 and 2 are loaded.

When gas turbine No. 1 is loaded from 90 to106 MW, the temperature of gases is stabilized bymeans of the controller, which controls the IGVD posi-tion toward opening from 57 to 92%. The trend seen inthe IGVD motion corresponds to the power builduppattern; as this takes place, the temperature of gasesdownstream of turbine No. 1 is established at the spec-ified level equal to 517°C. The moment at which theloading of turbine No. 2 begins is shifted in time by16 min with respect to the loading of turbine No. 1.

140

120

100

80

60

40

700

640

580

520

460

400

110

88

66

44

22

020:11:15 20:14:30 20:21:01 20:27:31

1

2 3

4

5

6

7

11MBA10CG801 XQ0111MBR20CT903A XQ0111MKA10CE901 XQ0110MKA10CE901 XQ0112MBA10CG801 XQ0112MBR20CT903B XQ0112MKA10CE901 XQ01

PI of GT1 IGVDT G dwnst. GT1 on GF

N GEN STN GEN GT11

PI of GT2 IGVD; 20T G dwn GT2 on LFN GEN GT12;

40400

00

40400

0

92515.5104.5

93.69973.628523.53107.64

140700110110140700110

%CMWMW%CMW

28.08.2007

28.08.2007

28.08.2007

20:36:03

20:08:00

20:37:16

01.574

Sc Signal code Text LL Value UL Unit of meas Time

Beginning of range

End of range

Step

ϕIGVD, deg T, °C N, MW07.03.2008 13:26:11

Time, h : min : s

Fig. 9. Loading of the gas turbines and the steam turbine of the PGU-325 power unit. (1), (2) and (3) Power outputs of the gas tur-bines Nos. 1 and 2 and the steam turbine, MW; (4) and (5) IGVD turn angle of turbines Nos. 1 and 2, %; and (6) and (7) temperatureof gases downstream of the turbine, °C.

THERMAL ENGINEERING Vol. 55 No. 10 2008

THE SYSTEM FOR AUTOMATICALLY CONTROLLING 885

The temperature of gases downstream of turbineNo. 2 is maintained by means of the temperature con-troller acting on the IGVD of this turbine. The way inwhich the IGVD position is changed from 42 to 74% isalso close to the pattern of change in the power output.

In both cases, the temperature controllers generatedcommands for increasing the flowrate of air to maintainthe specified temperatures of gases downstream of tur-bines Nos. 1 and 2. The specified value of temperaturefor turbine No. 2 was established at a level of 527°C.

Figure 9 also shows how the steam turbine is loadedto a power of 93.5 MW under steady operating condi-tions of the PGU-325 power unit.

The above processes through which the load of boththe GTE-110 units is controlled and the temperature ofgases is maintained downstream of the turbines operat-ing as part of the PGU-325 combined-cycle power plantat the Ivanovo DPS are stable and have been imple-mented with good quality.

CONCLUSIONS(1) The algorithms for closed-loop and logic con-

trol, including protections, and step-by-step programsthat have been developed allow the GTE-110 unit to beautomatically started and run reliably in the entirerange of loads during its operation on gaseous and liq-uid fuel, and they also allow the unit to be shut down innormal and emergency modes.

(2) The test results have confirmed that the PCS ofthe GTE-110 unit meets the modern requirements forthe control of frequency and power:

(i) the control system droop is equal to around 5%;(ii) the dead band is less than ±10 mHz; and

(iii) the static characteristic of the control system islinear in the entire range except with the region inwhich the central zone of the combustion chamber isswiched-on.

(3) The developed algorithm of the power controllertaken in combination with the algorithm for start-up/shut-down of the central zone allows the gas turbineload to be controlled in the entire working range.

(4) The temperature controller generating controlcommands for the IGVD stably maintains the specifiedtemperature of gases downstream of the turbine, thussupporting normal operating conditions of the steamturbine used as part of the PGU-325 unit.

(5) The interaction between the operation of thetemperature controller producing commands for theIGVD and the operation of the limiting temperaturecontroller producing commands for the control valvehas been checked. The algorithm that controls jointoperation of these controllers excludes their mutualinfluence.

REFERENCES1. A. Ya. Kopsov, A. P. Livinskii, V. V. Lysko, et al., “The

Automated Process Control System of the Rig for Test-ing the GTE-110 Unit,” Elektr. Stn., No. 7, 27–31(2003).

2. I. Z. Chernomzav and K. A. Nefedov, “Improvement ofAutomatic Control Systems for Large-Capacity SteamTurbines,” Teploenergetika, No. 10, 27–33 (2008)[Therm. Eng., No. 10 (2008)].

3. A. G. Sviderskii and Kh. Kherpel’, “New TechnicalFacilities for Equipping Power Industry Plants withAutomatic Control Systems,” Teploenergetika, No. 10,9–13 (2008) [Therm. Eng., No. 10 (2008)].

886

ISSN 0040-6015, Thermal Engineering, 2008, Vol. 55, No. 10, pp. 886–893. © Pleiades Publishing, Inc., 2008.Original Russian Text © K.A. Molchanov, V.P. Strashnykh, D.A. Zhezherya, O.A. Manevskaya, 2008, published in Teploenergetika.

The use of training simulators in power engineeringfor training the operative personnel is no longer a nov-elty. That their use is extremely efficient and necessaryis pointed out in [1, 2]. Many power stations have pur-chased and put into use training simulators for bothindividual technological items and entire power units.Training simulators are used for carrying out training tocope with emergency situations, to educate personnel,and to hold competitions of operators. All these instal-lations, except that for the Sochi thermal power station(TPS), are power units constructed in accordance withthe traditional technology.

At the same time, the areas in which Russian powerengineering has been developed in recent years involvethe use of combined-cycle power units, a technologythat allows high-efficiency values to be obtained thatcannot be achieved in traditional power units and makethe power-generation cycle much more friendly to theenvironment. Only a few power stations running inaccordance with a combined (steam–gas) cycle are nowin operation in Russia (not taking into account Unit 3 atMosenergo’s TETs-27 cogeneration station: theSeverozapadnaya cogeneration station in St. Peters-burg, the Sochi thermal power station, the KaliningradTETs-2 cogeneration station, the Ivanovo districtpower station, and some others. This is very little incomparison with the total number of traditional powerunits in Russia.

Since the combined-cycle technology has onlybegun to come into use in Russia, the problem of train-ing skilled personnel has gained special importance.The problem of training workers and maintaining theirknowledge and skills has become especially relevant asadvanced high-efficiency process control systems(PCSs), facilities allowing a high level of automation tobe achieved, are put into use. The personnel control thetechnological process through an PCS. On one hand,

this automated system, as it were, guards the operator,performing the major part of operations for monitoringand controlling the process, but on the other hand, highdemands are placed on the skills of the personnel whooperate with this system. Keeping an eye on how theautomated technological process proceeds becomes themain function of the operating personnel; therefore, theworkers must have a good understanding of the processand its control algorithms. Of course, high levels ofskill can be gained in the course of long-term work withequipment; however, this takes a long time and involveshigh costs, all the more so because the cost of an erroroften turns to be very great. The only exit from today’ssituation of power facilities suffering from a shortage ofskilled workers can be seen in the development of full-scale training simulators for operating personnel capa-ble of fully replicating both the technological processand the man–machine interface together with the con-trol algorithms used in the PCS. It is such a trainingsimulator that has been developed and put in operationin Unit 3 at OAO Mosenergo’s TETs-27 cogenerationstation. Such training simulator is especially badlyneeded for the shift operators encountering modernpower unit control systems for the first time. The use ofa training simulator allows a trainee to try to carry outany operating modes and switching operations, gainskills in handling the PCS, take a look at picturesclearly showing the principles in accordance withwhich the process systems operate, and “feel” thepower unit, all in a quiet environment and without fearof inflicting damage on the equipment.

The operator interface, PCS algorithms, technologi-cal equipment, and processes had all to be modeled fordeveloping a full-scale training simulator.

It should be pointed out that the different technolog-ical systems of the training simulator were started inparallel with—and sometimes even earlier than—simi-

The Full-Scale Training Simulator for Educating the Operative Personnel of the PGU-450 Unit at OAO Mosenergo’s TETs-27

Cogeneration Station

K. A. Molchanov

a

, V. P. Strashnykh

b

, D. A. Zhezherya

a

, and O. A. Manevskaya

a

a

ZAO Interavtomatika, ul. Avtozavodskaya 14/23, Moscow, 115280 Russia

b

OOO ENIKO TSO, sh. Kashirskoe 31, Moscow, 115409 Russia

Abstract

—We describe the full-scale training simulator for the PGU-450 combined cycle power plant, aninstallation combining an actual automatic process control system and a detailed physical model of processequipment that was developed in Russia for the first time and had been put in operation before the power unitwas started.

DOI:

10.1134/S0040601508100091

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THE FULL-SCALE TRAINING SIMULATOR FOR EDUCATING 887

lar systems put into operation in the power unit that wasconstructed. Thus, it was the first time in the work ofInteravtomatika that the most complicated and impor-tant algorithms were elaborated on a simulator and thenon field equipment.

SHORT DESCRIPTION OF THE SIMULATED PLANT

The simulated plant can be subdivided into two sub-systems:

(i) Unit 3 (PGU-450) at the TETs-27 cogenerationstation, including its main and auxiliary equipment; and

(ii) the automated process control system developedon the basis of the SPPA-T3000 instrumentation andcontrol system (I&CS).

The PGU-450T power unit is composed of twoGTE-160 gas turbines, each furnished with its own P-107heat-recovery boiler (HRB) comprising two steam-pressure loops, and a T-150-7.7 cogeneration steam tur-bine. Gas is used as main and standby fuel, and dieselfuel is used as emergency fuel.

The GTE-160 gas turbine unit, referred to hence-forth as the GTU, is a single-shaft turbine set operatingwith an initial temperature of gas upstream of the tur-bine’s first stage equal to 1060 and 544

°

C at the turbineoutlet (under the design ambient conditions). The GTUelectric power output reaches 155.3 MW at an effi-ciency of 34.12% under such conditions.

The P-107 heat-recovery boiler produced at PodolskMachinery Construction Works (ZiOMAR) has a towerarrangement and comprises two steam-generating cir-cuits of high and low pressure with steam drums andforced circulation in evaporating loops. The low-pres-sure drum is equipped with a built-in deaerator.

The T-150-7.7 steam turbine, which has twocogeneration extractions, serves for directly driving aTFG-160-2U3 generator and supplying heat for districtheating purposes. The turbine rated power output isequal to 161 MW during operation in the nominal con-densing mode and 129.0 MW in the nominal cogenera-tion mode; the rated heat load is equal to 358 MW at adesign outdoor air temperature equal to –2

°

C.The experience gained from the development of a

full-scale training simulator for the power unit at theSochi TPS [3] made it possible to increase the volumein which the plant was simulated and extend the set offunctions solved on the simulator developed for theTETs-27 cogeneration station. In particular, all processequipment, including the gas turbines and the steamturbine, has been simulated.

The SPPA-T3000 I&CS, the latest product of Sie-mens, is a further development of the widely usedI&CSs TELEPERM ME, TELEPERM XP, andTELEPERM XP-R. The combined engineering andoperator interface of the SPPA-T3000 is shown in Fig.1. The controller level is constructed on the basis ofSIMATIC S7, a piece of equipment by Siemens that is

always being developed and is well known in Russia.The hardware of the upper level and the software of theentire I&CS are new products developed as successorsof the above-mentioned versions of the TELEPERMI&CS and the power engineering version of the soft-ware used in SIMATIC PCS7 PS; however, the archi-tecture of the new products, as well as the objectivesand capacities laid down in them, differ fundamentallyfrom their predecessors.

The automated plant has the following quantitativecharacteristics as applied to the training simulator:

Input signals:

FUNCTIONAL AND HARDWARE IMPLEMENTATION OF THE TRAINING

SIMULATOR

As was indicated above, the training simulator com-prises a model of technological equipment and a modelof a system for automatically controlling the technolog-ical processes in this equipment. Figure 2 shows thestructural–functional diagram of the equipment used inthe PCS training simulator.

The PCS model developed at Interavtomatika com-prises a set of solutions aimed at making the trainingsimulator as similar as possible to the actual PCS in theupper level, which comprises network exchange facili-ties and operator interface, and in the lower level, atwhich controllers operate.

The upper level of the simulator’s PCS is equivalentto the upper level of the power unit’s PCS. It was fur-nished with an SPPA-T3000 application server and twodouble-screen operator workstations constructed on thethin-client principle absolutely identical to those usedin the power unit. Such a solution allows the work-places at the training simulator to be made 100% repli-cas of those at the power unit.

The structure of the automation servers with I/Odevices used in actual PCS has been fully repeated inthe simulator in the form of software emulation ofphysical devices.

The training simulator comprises nine automationservers. The S7-417H controllers, the software ofwhich completely replicates the control algorithmsused in the controllers of the actual PCS, represent allthese servers. The model of the gas turbine control sys-tems (the high-speed control loop) has been imple-

analog

1188

binary

607

Output binary signals

21

Control valves

55

Shut-off valves

360

Controllers with an analog output

14

Auxiliary mechanisms

78

Solenoid valves

42

888

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MOLCHANOV et al.

mented in full scope, but is incorporated in the techno-logical plant model to improve the computational char-acteristics.

The inputs and outputs of interfacing devices, whichare emulated by means of software, communicate withthe models of sensors and actuators, which run on theinstructor’s workstation. Data exchange between thetechnological model and the PCS model is carried outin accordance with the OPC protocol.

The approach according to which the PCS model isconstructed as the SPPA-T3000 system combined withemulation of controllers makes it possible to obtain anPCS model the processes in which are equivalent tothose in the actually existing system. On one hand, thetraining simulator has operator and engineering inter-faces fully replicating the actual ones; on the other, ithas the same dynamic characteristics as the actual PCS.Owing to these features, the operating personnel can betrained not only to work with the technological equip-ment, but also to learn how the PCS works in differentsituations.

ENIKO TCO specialists have developed a model oftechnological equipment that covers the main and aux-iliary heat-generating, mechanical, and electricalequipment of the power unit. All the main componentsof equipment are simulated in full scope on the basis ofphysical principles. Some items are simulated in thevolume sufficient for acquiring skills in carrying outcontrol and analyzing the situations that occur in thisequipment.

An important advantage of the adopted method forsimulating technological processes is that it uses asmall quantization interval (around 100 ms), a featurethat allows transients in low-inertia control loops, suchas gas and steam turbine speed governors, feed control-lers, etc., to be adequately represented. In particular,self-oscillations (if any) triggered by a single switchingof pulsed controllers, the minimum duration of which isusually around 200 ms, are simulated with the requiredaccuracy.

Operations for controlling the training simulatorand streamlining the training process are carried outfrom the instructor’s workplace.

ViewApplications Selected Window Search HelpMode

@

T S B O ACS ESPDP

Designation

Project type Circuit editor GT-31 ESP- display

Project EditViewVersionAdditionally Administration Help

NameGT-31 startup/Hierarchy of Unit 3

System

Starting function

Speed governor

Power regulator

Gas temp. reg.

Power regulato

Gas temp. reg.

GT reg. error

GT-31

Scheme Indication of GT operation

of protections is in operation

shutdown progra

Fire protection;

Select GT-31

Operated ErrorCompensated

Setpoint

Loading rate

Power

Switch

GT-31 air systemfrom GT-1 ATP

IGVD

Open comm.

Nam

Start

Start

Right CC

@

GT-31

of GTprotections

ResetOperated

Gasmain fuel

Reset;

Active

G B Pulsation to

521C

for T fl.g

11 MW/min;

deviationfor frequency;

on frequency corrector;

on liquid fuel

on gaseous fuel;

T gas dwnstr. turb. power525 111

0.0

12

120

0

0

GT-31 gaseous fuel

1008Control of TSD-31

3110

GT-31in CC

0

151

21

38438

–0

9.9

330

HRB-31

30Mbar20Mbar

30Mbar20MbarLeft CC

GT-31 diesel fuel

Open comm.Off comm.

Off comm.

Change of statDesignation State Date of beginning Date of end.Time of ending Priority

Closed

Dif. mode

BlockAcknow

P/CType of indic. ledgement of signalFile View Help

Tag

SPPPS

SChange of statChange of stat

Time of endingClosedOpen

Current user: User 1. Operating mode, built-in design disconnected

53

is in operation

is in operation

is in operation

is in operation

is in operation

HRB-31 startup enabled

GT-31 startup enabled

30HAD12AA30PCB53AA

30PAH15AA

35VG385632008/03/1334NC40528

35VE415676

2008/03/13

2008/03/1303:17:47, 9903:16:56, 76

03:26:50, 73

A

10

Fig. 1.

Engineering and operator interfaces of the SPPTA-T3000 system.

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THE FULL-SCALE TRAINING SIMULATOR FOR EDUCATING 889

MODEL OF THE PCS

The PCS model has been constructed using theSIMIT basic software developed at Siemens. This com-puter program emulates the operation of automationservers (controllers with physical I/O devices) andserves as a link between the PCS upper level and thetechnological process. Not only the controllers and I/Omodules, but also the PCS control algorithms, i.e., theentire lower controller level, can be simulated using thissoftware. Owing to this software, the application serverof SPPA-T3000 communicates with the emulators ofautomation servers as with actual controllers.

Apart from communication with the upper level, theSIMIT software simulates the operation of mechanismsand shutoff and control valves and communicates withthe subsystem simulating the technological process.This subsystem has been developed on the basis of spe-cial software built around the kernel Graphic InterfaceWorkshop (GIW) software system. This kernel GIWsoftware is augmented with dedicated models of tech-nological systems developed using computer-aideddesign (CAD) tools.

MODEL OF THE PROCESS EQUIPMENT

Design documents for the process equipment,equipment drawings, and technical certificates serve assources of input data for developing a model of process

equipment. The list of these input data includes thelengths, diameters, and wall thickness of tubes; the geo-metrical dimensions of heat transfer surfaces and tanks;the parameters of throttling devices; the nameplatecharacteristics of electrical equipment; design calcula-tions; and the like. Measurements on actual equipmenthave sometimes to be carried out due to the lack of nec-essary data in the documents to obtain the geometricalcharacteristics.

The basic method using which the physical pro-cesses going in technological systems are simulatedconsists of solving the differential equations thatdescribe material, energy, and mechanical balances inthe system being simulated, which are supplementedwith closing relations and thermodynamic properties ofthe media being considered.

The integrated model for the training simulator ofthe power unit at Mosenergo’s TETs-27 cogenerationstation was constructed using the computer-aideddesign systems of the following models (Fig. 3):

(i) automatic control systems;

(ii) thermal-hydraulic systems; and

(iii) electrical processes.

The models of the high-speed gas turbine controlloops transferred from the PCS, the logic of switchingoperations in electrical circuits, the algorithms of elec-trical protections, etc. are the entities that were simu-

Regular SPPA-T3000 Emulation of automation

Workstation of the powerInstructor:

Instructor's

@

PCS model

Model

unit operator–regularthin clients

server servers (controllers,inputs/outputs,

of ACS algorithms)

Assignment of externalconditions models of valves,

gate valves, and motors;assignment of equipment failures

workstation

M

TCP OPC

of the technologicalprocess

execution

1…5

Emulationof T3000n

Fig. 2.

Functional diagram of technical facilities of the PCS training simulator.

890

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MOLCHANOV et al.

lated using the tools for computer-aided design of auto-matic control systems.

Among the entities the models of which are devel-oped using the tools for computer-aided design of ther-mal-hydraulic systems are the technological systemsand equipment the operating principles of which arebased on mass, momentum, and heat transfer phenom-ena, and on the processes through which the kineticenergy of medium is converted into mechanical workand vice versa. Systems incorporating pipelines; shut-off, control, and safety valves; pumps; heat-transferequipment, turbine stages, and vessels with level maybe part of this category.

Central to the system of basic equations for most ofthe equipment being simulated (except with the modelsof vessels with level) is the modeling of compressiblemedium described by four conservation equations for ahomogeneous steam–water mixture and noncondens-

able gases. The heat carriers being simulated are mod-eled taking into account heat transfer to the structuralelements and medium in the surrounding premise. Themomentum conservation equation is considered in a 1Dapproximation taking into account the convective com-ponent and limitation of the coolant flow velocity forthe velocity of sound. This model can describe thedynamics of processes in steam paths with high fluidflow velocities.

Vessels with a level of medium and devices in whichsteam is separated and condensed are simulated using anonequilibrium model; i.e., water can be in superheatedstate and steam can be in a state subcooled to saturation.The liquid and steam–gas phases lie below the level,and the steam and gas phases are above the level.

The main equations of conservation are supple-mented with closing relations, among which are thosefor calculating heat-transfer coefficient, hydraulic

Tst

2 deg

1ivd119

Partial gas pressure, PaPartial steam pressure,PaWater pressure, PaGas enthalpy, J/kg

Water enthalpy, J/kg

Gas temperature,

°

C

Four-phase tank (J3M0100001)

Enthalpy of steam above the level, J/kg

Water temperature,

°

C

Temperature of steam above the level,

°

C

Water density, kg/m

3

Mean temper. of mixture above the level,

°

C

Steam density above the level, kg/m

3

Gas density, kg/m

3

Density of mixture under the level, kg/m

3

Volume balances

Velocity of steam above the level, kg/m/s

Decrease command

Decrease2.5

Voltage fitting

1

2

3

1ivd220

1ivd1211ivd_in_bvd1

33NB10B01

15

1ivd120

Abs

2.5as4

as3

as5

as60.05

0.05

0.01

Decrease command

of AS

of ASIncrease

SAT1

10

1121

as12

as17

as13

Enthalpy of steam under the level, J/kg

Temperature of steam under the level,

°

C

Steam density above the level, kg/m

3

Gas velocity, kg/m/s

Water velocity, kg/m/sVelocity of steam under the level, kg/m/s

Volume of steamGas velocity, kg/m/s

under the level, m

3

actual mass, kgmass of steam

3BA bus

above the level, m

3

above the level, kg

UT1

AT1

3BA bus

1ivd219

3122EA2

Synchronoscope

Fig. 3.

Working windows of the software for simulating technological processes. CAD systems for the models of: (1) Automaticcontrol systems, (2) thermal-hydraulic systems, and (3) electrical processes. AS—automatic synchronizing device

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THE FULL-SCALE TRAINING SIMULATOR FOR EDUCATING 891

resistances, and corrections for the normal characteris-tics of equipment depending on the parameters ofmedium, flow modes, and geometrical characteristics.

The systems and equipment in which electric poweris generated and consumed are simulated using com-puter-aided design tools for electrical processes. Thelist of such systems includes synchronous generators,asynchronous motors, transformers, and switchingdevices.

A synchronous generator is modeled using Park–Gorev’s classic equations, which allow the electricalprocesses in a synchronous machine to be described bymeans of differential equations with constant coeffi-cients. The model describes both steady processes andtransients with sufficient detail.

INSTRUCTOR INTERFACE AND ORGANIZATION OF TRAINING PROCESS

The scope of instructor duties includes providingmethodological and technological support for thetrainee. The instructor’s workplace, which is essentiallya system for controlling the training simulator, com-

prises a set of facilities for changing the operating con-ditions of equipment, introducing various failures, and alter-ing the characteristics of technological equipment. Theexternal view of the instructor interface is shown in Fig. 4.

The training process is organized as follows. Thestate corresponding to the specified training problem isloaded, and the required changes in the initial condi-tions, including external ones, are made through thecontrol system. The instructor may create new trainingproblems or modify the existing ones. For example, theinstructor interface makes it possible to introduce vari-ous kinds of failures of process and peripheral equip-ment, such as degradation in the throughput capacity ofpumps, change in the tightness of a path and heat-trans-fer coefficients in heat exchangers, seizure of controlvalves, loss of control by a gate valve, etc. The instruc-tor does not inform the trainee about his or her actionsor the failures that were introduced, thus making animpression of working on actual equipment andprompting the trainee to show his or her quick operat-ing wits. The system is designed so that the current statecan be saved at any moment of time for further analysisor for using it as an initial state in the training process.

5

Aut.Synchronization

GT2

Supply on section

ST

Drain on the filter of

ControlON

Accelerated

0

External conditions

Outdoor air temperature,

°

COutdoor air pressure, kPaOutdoor air humidity

External grid frequency

T ret.net.wat.P suct.net.w.pmpP suct.net.wat.

T suct. net.wat.

P ret.net.wat

OFF

P unit aux.head.fr.st.head.

T unit aux.head.fr.st.head

P pr.circ.wat.c2 to cndP circ.wat.c1 to cool.twr.P circ.wat.c2 to cool.twr.

T mkp.wat.mains to c.s1P mkp.wat.mains to c.s1T mkp.wat.mains to c.s2

ON

Supply

Supply

No control;

err(No supply)

State of: GT32Stage bearing

Generator bearing on the turbine side

Heat release in bearings0–normal operation 100–maximum failure

No supply

State of filters

No supplyNo control First ST bearing

Second ST bearing

Third ST bearing

Third ST bearing

Generator bearing on the exciter side

No supply

synchr.

HP CEP

Drain on HP-1 CEP

Drain on the filter of HP CEP

Drain on HP-1 CEP

Drain on HP-1 CEP

Drain on the filter of HP CEP

GT1

heating

50 100

0 50 100

0 50 100

0 50 1000

50 1000

50 1000 50 100

0

0

0

0

0

0

33NB11K184

33NB11K182

33NB11K184

33NB12K186

33NB12K188

33NB21K184

33NB21K171

No supply

onsection

0 50 100Valve flowrate

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0 50 100

0 0

on section

OFF

0 50 100

T pr.circ.wat.c1 to cndP pr.circ.wat.c1 to cnd

T pr.circ.wat.c2 to cnd.

Compressor bearin

No supply

Pulled-off stateLocal controlNo control

Throughput

"Switch off" protection

for signal

min max100

tst(Pulled-off state)loc(Local control)No supply

32

3232

32

0

0

0

0

Valve flowrate

30MAD11Q

30MAD11Q

30MAD11Q

30MAD11Q

P1 2

Fig. 4.

Operator interface of the instructor.

892

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No. 10

2008

MOLCHANOV et al.

The following modes of power unit operation havebeen tried out on the simulator and are recommendedfor using as training problems:

(i) preparing the power unit for starting and startingit from any initial thermal state under the specifiedexternal conditions;

(ii) connecting the second steam turbine to the con-tinuously operating first one;

(iii) carrying out planned shutdown of the powerunit without cooling down the equipment and withcooling down of the heat-recovery boiler, steam lines,and steam turbine;

(iv) shutting down one gas turbine while leaving thesecond one in operation;

(v) shutting down the power unit in an emergencymanner;

(vi) running the power unit in its controlled loadrange, including the cogeneration mode, under differ-ent external conditions and with different states of com-mon-station systems;

(vii) changing the composition of operating auxil-iary equipment in the power unit, e.g., connecting thecogeneration plant, disconnecting a pump, etc.; and

(viii) running the power unit in off-design situations(when any sensor or controller fails, when any protec-tion comes in action, when deviation occurs from nor-mal operation of the condenser makeup plant, mainpump, or any oil cooler of the steam turbine).

Instructor’s interface is also required for carryingout the duties of a machine walkdown operator; in thiscase, the instructor manually controls the valves ondemand of the trainee.

USING THE SIMULATOR FOR ADJUSTING COMPLEX PCS ALGORITHMS

It was for the first time at the TETs-27 cogenerationstation that Interavtomatika specialists gained the pos-sibility of trying out logic and closed-loop algorithmsbefore the first operations for starting the plant werecommenced. With the simulator at hand, it became pos-sible to adjust such key algorithms as stepped programsfor starting and shutting down the oil system of gas tur-bines, the system for supplying gas and diesel fuel, thesystem for suppressing the emissions of nitrogenoxides, and the program for starting and shutting downthe entire gas turbine units. In addition, a program forautomatically selecting the backup equipment for thedrain pumps of delivery water heaters was checked; dif-ferent schemes for controlling the level in the high- andlow-pressure drums of heat-recovery boilers, as well asmany other things, were tried out. The tuning parame-ters determined in the course of adjusting the plant onthe simulator were set up as starting ones immediatelybefore adjusting the actual plant. That the algorithmswere tried out on a model before putting them into usemade it possible to check and, if necessary, correct the

control logic beforehand and accomplish the adjust-ment work within a considerably shorter period of time.

In addition, especially complicated algorithms werefirst elaborated on the simulator and then transferredinto the actual PCS.

It should be pointed out that the values of setpointsrefined on the field equipment were very close to thoseselected during the adjustment on the simulator. Thismeans that the PCS and the technological equipmentwere initially modeled with high accuracy. Such a goodaccuracy was obtained due to the fact that the modelwas constructed on the basis of not only design, but alsoexperimental data that were obtained on similar powerunits (Units 1 and 2 at the Severozapadnaya cogenera-tion station and Unit 1 at the TETs-2 Kaliningradcogeneration station during starting, shutdown, andother transient modes of their operation. Specialistsfrom the ENIKO TSP and Interavtomatika have beenconducting work at the TETs-27 cogeneration stationon studying the processes in the actual plant and refin-ing the model since the time the trial startups werebegun until the present time.

Analyzing accidents that have happened and work-ing out skills in controlling a power unit under emer-gency conditions for the future is one more field inwhich the simulator can be used. Carrying out such ananalysis is possible since the PCS and plant modelshave been constructed with high static and dynamicaccuracies. As an example, Fig. 5 shows how the levelof water in the high-pressure drum changes with timewhen the power unit is shut down in an emergencymanner due to the fact that the electrically driven feed-water pump stopped and no backup power supply wasavailable for starting up the standby pump (one gas tur-bine and the steam turbine were in operation when thisdisconnection occurred). It can be seen from the graphthat the dynamic picture of the transient in the fieldplant is almost identical with that of the process repro-duced on the simulator.

It should be specially emphasized that the technol-ogy ENIKO TSO and Interavtomatika specialists use inworking out training simulators allows full-scale engi-neering simulators to be constructed before the powerunit itself is commissioned, a circumstance especiallyimportant for new types of power units for which noexperience is available in both personnel training andengineering support for adjustment and commissioningwork. In addition, the use of this simulator enables thepersonnel of the instrumentation and control (I&C)department to develop algorithms by testing and adjust-ing them on the simulator, after which these algorithmsare transferred to the field plant. The personnel of theI&C department becomes much less afraid of introduc-ing different improvements in the power unit, an envi-ronment in which better efficiency of the PCS isobtained in the final analysis.

At present, Unit 3 at Mosenergo’s TETs-27 cogen-eration station is passing pilot commercial operation

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THE FULL-SCALE TRAINING SIMULATOR FOR EDUCATING 893

and operational adjustment activities are being con-ducted on it. Data required for refining the dynamiccharacteristics of the model are collected as differentoperating modes are elaborated in the power unit.

In view of the fact that a power-generating unit builtaround a combined cycle plant will soon be commis-sioned at Mosenergo’s TETs-21 cogeneration station,the operating personnel of this station were forwardedfor training on the TETs-27 station’s training simulatorand have successfully passed the training course.

An independent team of experts has tested the sim-ulator and confirmed that it is technically equipped at ahigh level. The commission of experts has drawn a pos-itive conclusion and issued a certificate of conformancewith the Norms for Suitability of Software Tools forTraining Power Engineering Personnel.

CONCLUSIONS

(1) The full-scale training simulator of Unit 3 (PGU-450)at Mosenergo’s TETs-27 cogeneration station, whichwas commissioned in August of 2007, differs fromthose existing at present in that it comprises, along witha physical model of the power unit, the actual set ofalgorithms and the actual operator interface.

(2) The fact that the model of the technological pro-cess runs with a small quantization interval (around100 ms) and that the quantization intervals with which

the control algorithms are executed are the same as inthe actual PCS allows low-inertia processes like con-trolling the rotation frequencies of steam and gas tur-bine rotors, controlling feedwater flowrate, etc. to besimulated with high accuracy. This circumstance placesthe training simulator at the same level as the latestachievements in the field of development of educatingsystems.

(3) That the training simulator was available for usebefore and during adjustment activities was a circum-stance that allowed the operating personnel to betrained in advance and the most complicated controlalgorithms to be checked and preliminarily adjusted.

REFERENCES

1. S. I. Magid,

Theory and Practice of Constructing Train-ing Simulators for Thermal Power Stations

(MEI, Mos-cow, 1998) [in Russian].

2. V. A. Rubashkin, “Training the Operative Personnel asthe Most Efficient Way of Excluding the Consequencesof Accidents,” in

Proceedings of the Seventh All-RussiaConference of Managers of Educational Institutions inPower Engineering and RAO UES of Russia’s PersonnelTraining Departments, Omsk, 2006.

3. V. A. Chernakov, A. G. Sviderskii, V. P. Strashnykh,et

al., “Commissioning the Full-Scale Computer-AidedTraining Simulator at the Sochi Thermal Power Station,”Avtom. v Promyshl., No. 6, 152–156 (2006).

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32, 4

1

2

,

3

,

4

Fig. 5.

Transients during emergency shutdown of the power unit caused by disconnection of EFWP. (

1

) Gas turbine power output,MW; rotation frequency of, 10

–2

rpm: (

2

) steam turbine; (

3

) gas turbine; (

4

) steam turbine on the simulator; (

5

) level of water in theHP drum, cm; and (

6

) level of water in the HP drum on the simulator, cm.

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