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SPEEDTRONIC™ MARK V STEAM TURBINECONTROL SYSTEM

INTRODUCTIONThe SPEEDTRONIC Mark V is the latest ver-

sion of GE’s long series of highly reliable electro-hydraulic control (EHC) systems for steam tur-bines. Its heritage consists of a long list ofsuccessful control systems, including the first EHCMark I steam turbine control built in the 1960s,and the SPEEDTRONIC Mark I-IV gas turbinecontrol. The Mark V continues to combine thebest turbine and generator design engineeringwith the latest electronic controls engineering toprovide a modern, yet experienced controls pack-age (Figure 1).

The Mark V is the third generation of triple-redun-dant microprocessor-based turbine controls that orig-inated in 1982, with the Mark IV1 and was followed in

1987, with the DCM2. GE has an installed base of over 1,000 running triple-redundant, steam and gasturbine control systems. The Mark V family of tur-bine controls for the 1990s, offers a common controlarchitecture for small, medium, and large steam tur-bines, turbine-generator monitoring systems, genera-tor excitation systems, and gas turbine controls.

Some of the features are:• Common Architecture, Maintenance, and Spare

Parts between steam turbine, gas turbine,and other controls

• Very flexible, PC-based operator interfacewith Color Monitor and Logging Printer withalarm log, event log, historical trip log, etc.

• Common operator training and controls for steamand gas turbines in combined-cycle STAGTM

plants• Full Turbine-Generator Monitoring for all sizes

of turbines can be included• High Resolution Time Tags including 1 ms time

tags of contact inputs• New Communication Links to plant controls• Distributed Multiprocessor Control in each con-

troller for maximum processing capability• Enhanced Diagnostics that can isolate a fault to

the card level in any of the triple-redundantcontrollers

• On-Line Repair of the triple-redundant con-trollers

• Standard built-in Synchronizing CheckProtection

• Fully Digital Valve Positioning to provide amore linear response of the steam turbine

• Direct Interface to Turbine Devices, includingproximity monitoring equipment

• Compact Packaging in half the cabinet size ofthe previous control system

CONTROL SYSTEM HISTORYFrom their introduction in the late 1800s,

steam turbines were governed by mechanicalhydraulic control (MHC) systems. Speed was con-trolled by a flyweight governor of James Watt her-itage, signals were transmitted by levers and linksor hydraulic pressure signals, and motive power tocontrol steam valves was provided by low-pressure

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J. Kure-JensenGE Power SystemsSchenectady, NY

W. BarkerGE Power SystemsSchenectady, NY

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Figure 1. SPEEDTRONIC™ Mark V steam turbine control cabinet

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hydraulics. Refined to the utmost, this technologywas used through the mid-1960s, to control suchsophisticated units as double-extraction industrialturbines, large double-reheat fossil units, and thefirst nuclear units incorporating pressure controls for BWRs. The complexity of these later controlsclearly showed that a new technology was needed.

ANALOG CONTROLSGE introduced the electro-hydraulic control

(EHC) system for steam turbines in the 1960s.The first medium-size unit went into service in1961, and the first large reheat unit in 1968. Theproportional controls used analog circuitry withdual redundancy for speed control and singlechannel for other controls. The logic and protec-tive system was implemented with relays.

The original Mark I system consisted of discretecomponent analog circuitry. In the 1970s, thesecircuits were modernized to take advantage of inte-grated circuitry (IC) technology as well as solidstate logic circuits for some of the protection andlogic. This resulted in the EHC Mark II, which hadmany IC components and a new cabinet arrange-ment, while the subsequent Mark III, used only onsmall- and medium-sized turbines, employed ICsthroughout and also included electronic speedsensing and microprocessors for automation.

A major improvement for both medium andlarge steam turbine controls was a reduction in

component count with a resultant increase in relia-bility. The EHC Mark II version for large steam tur-bines, in addition to integrated circuits, also intro-duced triple-redundant protection systems for thefunctions that can cause a turbine trip, resulting infurther improvement in running reliability by virtu-ally eliminating spurious forced outages.

The associated high-pressure hydraulic system,using 1600 psig (110 bar) fire-resistant fluid, hasundergone gradual improvement through theyears. The basic technology is still in use for thenew electro- hydraulic controls.

The history of analog controls, as well as thenew digital controls, is summarized in Table 1.

The reliability of EHC systems developedaccording to a classic learning curve shown inFigure 2. The step change in reliability realizedwith the EHC Mark II is attributed to two factors:the superior reliability of integrated electronicsand the introduction of triple-redundant protec-tion logic described above.

DIGITAL CONTROLSWhile GE steam turbines were being shipped

with these EHC systems through the mid-1980s, in the early 1980s, GE’s Gas Turbine Division intro-duced the very successful triple-redundant digitalcontrol system – the SPEEDTRONIC Mark IV.The first triple-redundant steam turbine controlsystem for utility turbines, the DCM system, was

Table 1PROGRESS OF STEAM TURBINE ELECTRONIC CONTROLS

System EHC MK I ECH MK II EHC MK III* DCM/MK III+ ST MK VIntroduced 1961 1970 1980 1986 1991

Total Shipped 190 290 120 27/44 55(Approx.)

Control Discrete Integrated IntregratedSolid State Circuits & Circuits & TMR Micro-Processors/single

Discrete Micro-processors

Protection Relays Relays Relays TMR Micro-Processors/single

Display Analog Meters Digital Meters Digital Meters Color CRT& Lights & Lights & Lights

Operator Inputs Pushbuttons and Dials Touch Panel Cursor or Touch

Fault Tolerance Dual Redundant Dual Redundant Single Channel TMR (2/3 Voting) with SiftSpeed Control Speed Control Control & (Software Implemented Fault

Protection Tolerance)/Single

Sequencing/ N.A. N.A. Limited Micro-processorsAutomation Micro-Processor

*Used only for small and medium size steam turbines

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shipped in 1987, building on gas turbine experi-ence, including the use of many of its electronicsmodules, and developing it further with SoftwareImplemented Fault Tolerance (SIFT). A compan-ion single-channel system, the Mark III Plus,aimed at the smaller industrial units, was firstshipped in 1988.

Some of the benefits from the new digital sys-tems are flexibility and greater precision of ofthe benefits from the new digital systems are flex-ibility and greater precision of controls becausefunctions are determined by software rather than hardware, CRT operator interface, data linkinterface to plant level control systems, and on-line repair capability for triple-redundant sys-tems, providing further improvement in reliability.

The new SPEEDTRONIC Mark V SteamTurbine Control System is developed from thislong evolution of electronic steam turbine con-trols. It is available in both triple-redundant MarkV TMR and single-channel Mark V Simplex con-trol systems, the only difference being the twoadditional controllers in the TMR design.

STEAM TURBINE UNIT CONTROLS

The main functions of a modern steam turbinecontrol system are:

• Speed and acceleration control during start-up• Initialization of generator excitation• Synchronization and application of load in

response to local or area generation dispatchcommands

• Pressure control of various forms: inlet,extraction, back pressure, etc.

• Unloading and securing of the turbine• Sequencing of the above functions under

constraint of thermal stress• Overspeed protection during load rejection

and emergencies• Protection against serious hazards, e.g., loss

of lube oil pressure, high exhaust tempera-ture, high bearing vibration

• Testing of steam valves and other importantprotective functions

Additional control and monitoring functionsare also required in most applications, such as:

• Monitoring and supervision of a large num-

Figure 2. Control system reliability, PH is forced outage rate based on period hours; MWW is megawattweighted

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ber of pressures, temperatures, etc., to pro-vide guidance and alarms for operators

• Start-up and monitoring of turbine-genera-tor auxiliaries such as lube oil, hydraulic, andsteam seal systems

• Display, alarm, and recording of the abovefunctions and data

• Diagnosis of turbine or generator problems• Health check and diagnostics of the elec-

tronic system itselfIt is characteristic of the first group of functions

that they must be performed with high controlbandwidth, or with very high reliability, or both, toensure long-term reliable operation and service ofthe turbine. It is for these reasons that GE has,from the very beginning of turbine technology,designed and provided the controls and protec-tion for its units, starting with the MHC systems acentur y ago and continuing with the newSPEEDTRONIC Mark V control system.

For the new all-digital systems, GE has definedthe first group of functions as a “Turbine UnitControl System." These functions, together withthe input and output devices (I/O) required, areincluded in all control systems which are an inte-gral part of steam turbines supplied by GE.

A characteristic of the unit control system isthat all essential turbine control and protectionfunctions are included to allow a unit to operatesafely even if other supporting systems should fail.Another characteristic is that the “control point”interface (i.e., the interface between the turbine and the control system) remains in GE’s scope,while interface to plant controls can be made at“data point” level, which does not include criticaland rapidly varying commands and feedback sig-nals, and therefore, is a more suitable point ofinterface to possible non-GE controls. Yet anothercharacteristic of unit control functions is that theymust be performed either continuously or veryfrequently to provide satisfactory control. Datasampling and processing of control algorithms upto ten times per second are used for many unitcontrol functions.

The second group of functions can be per-formed less frequently (i.e., every few seconds ormore), and turbine operation may be continued,in most cases, during short-term interruptions inthe monitoring functions as long as the “unit con-trol” is performing correctly.

The second group of functions includes mostof what used to be called “TSI,” for TurbineSupervisory Instrumentation, which we now pre-

fer to call TGM, for Turbine Generator Moni-toring. The TGM functions can be included in theMark V systems, or they may be integrated intothe plant control system. For small- and medium-sized units, the TGM functions can be incorporat-ed without significant extra hardware, and forlarge units, additional cabinets are needed. Thesecabinets can be mounted either at the turbineand generator or in an equipment room, and they can interface with a common Mark V operatorinterface.

The philosophy applied to steam turbine con-trol systems has developed over time, and it issummarized in Table 2.

A block diagram of the protective system of theMark V is shown in Figure 3. The left-hand sideshows the various trip inputs entering throughredundant paths. At the extreme right is the out-put to the emergency trip system (ETS), ahydraulic pressure signal, which will cause rapidclosure of all steam admission valves when depres-surized. The critical inputs to the ETS can be test-ed on-line, one at a time, with the help of the lock-out valves located immediately to the left of thefinal output to the ETS. This diagram shows thestandard offering with an all-electronic overspeedtrip. Optionally, a system with a mechanical over-speed governor can be supplied.

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Table 2STEAM TURBINE CONTROL PHILOSOPHY

1. Clear separation between control and pro-tection shall be provided.

2. Controls comply with IEEE 122 standard.(e.g., can reject rated load without causinga turbine trip.)

3. A protection system backup is provided forall control functions.

4. A double set of steam valves is provided forall major admissions; one set for controlsand one set for protection.

5. Protection (trips) are classified accordingto criticality: vital to have conceptual redun-dancy and for triple redundant systems.

6. Controls use two out of three redundancyfrom sensor to actuator for all vital andimportant functions.

7. A single failure in the controls will notcause a shutdown. It will cause a diagnosticalarm, and it is repairable on-line.

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Figure 3. Turbine protection system

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SPEEDTRONIC MARK VCONTROL CONFIGURATION

Figure 5 shows the configuration for theSPEEDTRONIC Mark V triple modular redun-dant (TMR) control system for a medium to largesteam turbine with redundant operator interfaces. The core of this system is the three identical con-trollers called <R>, <S>, and <T>. All critical con-trol algorithms, protective functions, and sequenc-ing are performed by these processors. In sodoing, they also acquire the data needed and gen-erate outputs to the turbine. Protective outputsare routed through the <P> module consisting oftriple redundant processors <X>, <Y>, and <Z>,which also provide independent protection forcertain critical functions such as overspeed.

The three control processors, <R>, <S>, and<T>, acquire data from the triple-redundant sen-sors as well as from dual or single sensors. Ageneric complement of sensors is described inTable 3. The actual number of sensors willdepend on turbine type. All critical sensors forcontinuous controls, as well as protection, aretriple-redundant. Other sensors are dual or singledevices fanned out to all three control processors.The extremely high reliability achieved by TMR

control systems is due in considerable measure tothe use of triple sensors for all critical parameters,as it was first demonstrated with the triple-redun-dant protection system of the EHC Mark II.

MARK V ELECTRONICSAll of the microprocessor-based controls have a

modular design for ease of maintenance. Each module or controller contains up to five cards,including a power supply. Multiple processorsreside in each controller which distribute the pro-cessing for maximum performance. Individualprocessors are dedicated to specific I/O assign-ments, application software, communications, etc., and the processing is performed in a real-time,multi-tasking operating system. Communicationbetween the controller’s five cards is accomplishedwith ribbon cables and gas-tight connectors. Thiseliminates the traditional computer backplane.Communication between individual controllers isperformed on high-speed Arcnet links.

Figure 4 shows the standard microprocessormodule.

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Figure 4. Mark V controller moduleCGRI219A

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PRIMARY CONTROLLERS<R><S><T>

The three controllers <R>, <S>, and <T>, shownin Figure 5, are physically separate and indepen-dent modules that contain all control and protec-tion hardware and software. A failure in any of the

three controllers is automatically diagnosed to thecard level and displayed as an alarm message.Maintenance personnel can power down theappropriate controller and replace the defectivecard while the turbine is on-line. Redundant sen-sors are used in control and trip protection systems

Table 3DIGITAL CONTROLS REDUNDANCY

Analog Use Digital Use

2/3 2/3Speed pickups Control Low bearing oil pressure TripEOS pickups and/or Low shaft pump pressure TripMain steam pressure trip Low vacuum, each hood TripHot or cold reheat pressure Low hydraulic fluid pressure Trip

Thrust bearing wear Trip

LVDT CV #1-4 IV #1/2 Control Exhaust thermostat each hood TripL-1 thermostat (for units w/bypass) Trip

HP 1st stage temperature Alarm/tripHP last stage temperature Alarm/trip

2/2 2/2Thrust bearing wear Trip Low ETS pressure Cross trip

(or 2/3 if practical) Low lube oil level (option) Trip

1/2 1/2Differential expansion Aut. Turb. Start None

(ATS)

All ATS temperatures & press ATSBearing oil temperature

1/1 1/1Eccentricity Preroll check Numerous contacts fanned out to R, S, & TBearing vibration Trip for testing and plant interface.Shell expansion Monitor/alarmCT and PT’s (3) Control/PLU/

load hold

Bearing oil pressure Numerous contact inputs to C for alarm,SS header pressure & temp Preroll monitoring, and ATS checks and holds.Hydr. fluid pressure & temp check

First stage pressure Control

Line frequency Control Customer trips.H2 pressure ATS loadGenerator field I & V holdH2 cooler inlet temp Preroll checkH2 cooler outlet temp Load holdSCW outlet temp Load holdL-1 temp Monitor/alarmUnit load demand Coord. cont. input

to provide a “total system” fault-tolerant design. As a result, diagnostics are able to distinguish betweenredundant sensor failures and electronics failures.

Three basic forms of voting are used in the con-trol. Figure 6 shows how the first form of voting,the software implemented fault tolerance (SIFT),works. At the beginning of each computing timeframe, each controller independently reads its sen-sors and exchanges this data with the data fromthe other two controllers. The median value ofeach analog input is calculated in each controllerand then used as the resultant control parameter for that controller. Diagnostic algorithms monitora predefined deadband for each analog input toeach controller, and if one of the analog inputsdeviates from this deadband, a diagnostic alarm isinitiated to advise maintenance personnel.

Contact inputs are voted in a similar manner.Each contact input connects to a single terminalpoint and is parallel wired to three contact inputcards in the voted contact input module. Eachcard optically isolates the 125 V dc input, and thena dedicated 80196 processor in each card timestamps the input to within 1 ms resolution. Thesesignals are then transmitted to the <R>, <S>, and

<T> controllers for voting and execution of theapplication software. This technique eliminatesany single point failure in the software voting sys-tem. Redundant contact inputs for certain func-tions such as low lube oil pressure are connectedto three separate terminal points and then individ-ually voted. With this SIFT technique, multiplefailures of contact or analog inputs can be accept-ed by the control system without causing an erro-neous analog or trip command from any of thethree controllers as long as the failures are notfrom the same circuit.

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Figure 5. TMR system with redundant communicationsGT21460

Figure 6. Software implemented fault tolerance(SIFT)

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Figure 7. Hardware voting of analog outputsGT21461

Figure 8. Hardware voting of logic outputs

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A second form of voting is hardware voting ofanalog outputs. As illustrated in Figure 7, threecoil servo valves on the steam valve actuators areseparately driven from each controller, and theposition feedback is provided by three LVDRs.The normal position of each steam valve is theaverage of the three commands from <R>, <S>,and <T>, respectively. The resultant averaging cir-cuit has sufficient gain to override a gross failureof any controller, such as a controller outputbeing driven to saturation. Diagnostics monitorthe servo coil currents and the D/A converters inaddition to the LVDRs.

The third form of voting for the trip solenoidsis discussed under OVERSPEED.

OVERSPEEDThe <P> protective controller contains three

independent cards <X>, <Y>, and <Z> with theirown processors and power supplies. This separateset of triple-redundant electronics with its associat-ed three separate speed pickups replaces themechanical overspeed governor. <R>, <S>, and<T> use the first three pickups for speed controland the primary overspeed protection, while <X>,<Y>, and <Z> monitor the second set of threepickups for emergency overspeed protection(Figure 3).

In addition, the <X>, <Y>, and <Z> cards con-tain separate relay drivers and magnetic relays thatperform a final contact vote prior to driving theturbine trip solenoids. Diagnostics monitor thestatus of the output ports, relay drivers, and relaysto initiate maintenance alarms if a failure occurs.Standard on-line and off-line primary and emer-gency overspeed trip tests are built in to facilitatetesting all hardware and software. Figure 8 illus-trates hardware logic voting of an output fromeach of three controllers.

SYNCHRONIZINGAutomatic synchronization is performed by the

<X>, <Y>, and <Z> cards in conjunction with the<R>, <S>, and <T> controllers. The controllersmatch speed and voltage and issue a command toclose the breaker based on a predefined breakerclosure time. Diagnostics monitor the actual break-er closure time and self-correct each command.Redundant sets of primary and backup phase-slipwindows eliminate the need for the traditional GXSsynchronizing check relay in the generator controlcabinet. Another feature is the ability to synchro-nize manually via the Mark V operator interface

instead of using the traditional synchroscope onthe generator protective cabinet. Operators canchoose one additional mode of operation by select-ing the monitor mode, which automatically match-es speed and voltage, but waits for the operator toreview all pertinent data on the CRT display beforeissuing a breaker close command.

POWER LOADUNBALANCE – PLU

Large steam turbine applications use anothermodule similar to <P> which is designated <PLU>for power load unbalance. This provides powerload unbalance protection and interface to thefast closing feature on control and intercept valvesvia three independent cards <U>, <V>, and <W>.

COMMON I/O <C>A significant amount of I/O on turbines and

generators is used only for monitoring. This non-redundant I/O is monitored by the <C> module.For example, thermocouples can be used for con-trol and protection or just for monitoring.Thermocouples which are used for rotor stress cal-culations are connected directly to the <R>, <S>,and <T> controllers, while thermocouples that areused for monitoring only, e.g., the thrust bearingoil drain temperature, connect to <C>.

OPERATOR INTERFACE <I>The interface work station <I> consists of a PC,

color monitor, cursor positioning device, key-board, and printer. It can be used as the sole oper-ator interface or as a local maintenance work sta-tion with all operator control and monitoringcoming from communication links with a plantdistributed control system (DCS). Figure 9 showsthe operator interface schematically.

Operators use the monitor, cursor positioningdevice, and keyboard. The keyboard is not neces-sary. However, the keyboard is convenient foraccessing displays with dedicated function keysand adjusting setpoints by entering a numericvalue such as 1,000 rpm rather than issuing amanual raise/lower command. Set point andlogic commands require an initial selection, suchas the command to engage the turning gear,which is followed by a confirming execute com-mand. The monitor is available in various sizesand types, and it can be used for desktop mount-ing, packaged as a drop-in insert for a controlroom console, or mounted in a separate free-standing cabinet. The keyboard is primarily used

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for maintenance such as editing application soft-ware or alarm messages. Figure 10 shows one exam-ple of operator interface.

The standard logging printer is a 150-cps (char-acters per second), dot matrix printer with alarmlogging, event logging, historical trip log, userdefined log, and the ability to copy any screen.Each alarm and event is logged with a high-resolu-tion time tag including contact inputs to within 1ms. Separate alarm queues are maintained for tur-bine-generator system alarms and internal diagnos-tic alarms. A new alarm initiates an audible alarmand drives a contact output which is connected tothe plant alarm bus. If a trip occurs, the historicaltrip log captures all key control parameters andalarm messages at the time of the trip and at severaltime intervals preceding the trip. This data islogged on the printer.

The <I> processor is located external to thecontrol cabinet, and it communicates with the<C> controller via an Arcnet communication link.Eight Mark V turbine controls of any type, includ-ing gas turbines for combined-cycle applicationsor EX2000 generator excitation systems in any

combination, can be monitored by a single <I>,or multiple <I>s can be provided for redundancy.A typical application has a Mark V main turbinecontrol, Mark V Turbine-Generator MonitoringSystem with historical database, and an EX2000Generator Excitation System communicating ona local high-speed Arcnet communication link toany combination of local interface stations.Monitoring and control of this localized systemfrom a plant DCS is facilitated via various types ofcommunication links.

This makes it possible to include the controland monitoring of a steam turbine in the centralcontrol room supported by the DCS.

<I> is an open architecture, AT compatible PCwhich runs a real-time, multi-tasking operating sys-tem called IDOS. The system runs in protectivemode with DOS running as one of 32 tasks undera scheduler. The PC supplied with each applica-tion is of the type 486 DX to provide a responsiveinterface with a screen update time within one sec-ond.

MEMORYMemory is located in the individual controllers

and in the <I> processor. Controllers haveEPROM for fixed memory, RAM for volatile mem-ory, and EEPROM for permanent storage of up-to-date application software. Changes to sequenc-ing, I/O assignments, gains, etc. can be madefrom <I> and stored in the individual controller’sEEPROM. Changes to control constants such asgains and offsets can be made while the turbine ison-line by entering a security code. However,changes to application software are restricted tooff-line maintenance. The hard disk in <I> has acopy of all application software and display infor-mation. Alarm messages can be added andchanged. Text for existing displays can bechanged or new displays can be created. I/O tagnames can be added or changed.

The memory system is illustrated in Figure 11.

BACKUP INTERFACEA small backup interface is provided on the

cabinet door. It uses a liquid crystal display withtwo lines of 40 characters per line to display keycontrol parameters and alarms. In addition, it canbe used to issue operator commands. A secondbackup interface can be provided for remotemounting via an RS422 connection.

An emergency stop pushbutton is located onthe door. It has a latching contact, and it must beturned and pulled to reset. Loose emergency stop

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Figure 10. Typical operator interfaceRDC26449-04-07

Figure 9. Mark V operator interfaceGT21463

pushbuttons can be provided for remote mount-ing. All emergency stop pushbuttons are hard-wired in series with the trip solenoids. Diagnosticsmonitor the trip circuitry and initiate a separatetrip in the application software.

HISTORYMost turbine controls transmit data to a DCS

which provides a historical database. Mark V sys-tems can provide their own historical databasewhich can store up to one month of data on-lineand archive data older than one month. A singlehistorian can provide historical trending for up toeight small units of any type including generatorexcitation systems.

COMMUNICATIONThe open architecture of the <I> processor

facilitates a wide range of communication links.The Mark V’s internal Arcnet communication linkis isolated from external communication links atthe <I> processor. An RS232 link with Modbusprotocol can be provided for general compatibili-ty with most DCSs, and Arcnet and Ethernet com-munications are supported. GE’s Message ServiceProtocol (TCP-IP) can be used on a variety oflinks including RS232 and Ethernet to communi-cate individual time tags for alarms and eventsand to receive the time from the DCS.

Since a single <I> can be used to communicatewith one or multiple units, the communicationwith the DCS can support one or multiple units.Control of multiple units over a single communi-cation link generally dictates faster communica-tion links with more sophisticated protocols suchas Ethernet with TCP-IP. Redundant communica-tion links are available in various levels such asredundant <I>s or redundant <I>s with redundantcommunication modules within the Mark V.

DIRECT SENSOR INTERFACEThe Mark V I/O is designed for direct interface

to turbine and generator devices such as thermocou-ples, RTDs, and vibration sensors. Direct monitoringof these sensors eliminates the cost and potentialreliability factors associated with interposing trans-ducers and instrumentation. In addition, all of theresultant data is visible to the operator from theMark V interface and from the DCS via the commu-nication link. Typical Mark V steam turbine controlsprovide direct interface to Proximitors* for vibrationprotection and axial position for thrust wear, differ-ential expansion, and eccentricity via a referenceprobe and key phasor. Monitoring of shell expan-sion is available via an LVDT input.

POWERMark V steam turbine controls come with stan-

dard redundant 115/230 V ac inputs and a 125 Vdc input. The electronics run on the highest buswith diagnostics monitoring the actual voltage lev-els of each bus, as well as any possible grounds onthe 125 V dc bus, if used. An internal power distri-bution module fuse isolates the resultant 125 V dcand feeds it to individual power supplies located ineach controller. Diagnostics monitor each internalfeeder, and LEDs are located next to each fuse toprovide additional maintenance assistance.

CONTROL CABINETThe control cabinet (Figure 12) carries the

CSA and UL labels. It can be provided as a NEMA1 convection-cooled enclosure for mounting in an air-conditioned room or in NEMA 12 or NEMA 4enclosures with air purifiers or additional coolingas required. Cabinets have front access only withtop and/or bottom cable entrances and have aheat dissipation of 800 watts. All electronics mod-ules are mounted on a common base with ribboncable connections between modules.

High level field wiring runs vertically in theright-side wire channel, and then horizontally tothe contact input/output modules at the bottomof the cabinet and to the power distribution mod-ule. Low level wiring runs vertically in the left-sidewire channel where the shield ground bar is locat-ed, and then horizontally to the low level terminalboards. Filters are located on circuit boards wherethe terminal boards are mounted to provide EMI,RFI, surge, and noise decoupling to the case.

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Figure 11. Mark V memory schematicGT21464

SUMMARYThe SPEEDTRONIC Mark V steam turbine

control is the GE control system for the 1990s. It isjointly engineered by turbine control engineeringbased in Schenectady, New York, and electricalcontrols engineering based in Salem, Virginia.The resultant product reflects years of experiencein providing high-performance turbine-generatorsets with integrated control systems. This is exem-plified by a track record of no forced outagesoccurring in a DCM triple-redundant control sys-tem due to the electronics or its related redun-dant sensors. The Mark V is designed to build onthis experience and to be the platform for imple-menting new features resulting from projects cur-rently underway at GE Corporate Research andDevelopment. This will keep GE and its customersat the forefront of technology and leaders in theirrespective markets.

REFERENCES1. Johnson, D., Miller, R.W., and Rowen, W.I.,

“SPEEDTRONIC™ Mark V Gas TurbineControl System,” GE Power Generation PaperGER-3658A, 1991.

2. Dombrosky, J., Kure-Jensen, J., Westphal, B.,and Drummond, T., “Turbine Digital Controland Monitoring (DCM) System,” ASME, 88-JPGC/Pwr-33, 1988.

3. Kure-Jensen, J., and Hanisch R., “Integration ofSteam Turbine Controls into Power Plants,” 89JPGC 863-2 EC, 1989.

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Figure 12. Typical cabinet layout (TMR with acand dc power)

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© 1996 GE Company

LIST OF FIGURES

Figure 1. SPEEDTRONICTM Mark V steam turbine control cabinetFigure 2. Control system reliability, PH is forced outage rate based on period hours; MWW is megawatt

weightedFigure 3. Turbine protection systemFigure 4. Mark V controller moduleFigure 5. TMR system with redundant communicationsFigure 6. Software implemented fault tolerance (SIFT)Figure 7. Hardware voting of analog outputsFigure 8. Hardware voting of logic outputsFigure 9. Mark V operator interfaceFigure 10. Typical operator interfaceFigure 11. Mark V memory schematicFigure 12. Typical cabinet layout (TMR with ac and dc power)

LIST OF TABLES

Table 1. Progress of Steam Turbine Electronic ControlsTable 2. Steam Turbine Control PhilosophyTable 3. Digital Controls Redundancy

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J. Kure-JensenJens Kure-Jensen is Technical Leader of Steam Turbine Development

for GE Power Generation’s Steam Turbine Design and DevelopmentEngineering in Schenectady, New York. GE Power Generation producessteam turbine from 10 to 1300 MW ratings.

Previous to his present position, Kure-Jensen managed several engi-neering units engaged in development of advanced turbine componentsand controls. Before joining GE, he worked for a European turbine sup-plier.

A list of figures appears at the end of this paper

W. BarkerWalter Barker currently works in Turbine Controls Marketing, GE

Drive Systems Sales.He joined GE’s Speed Variator Department in Erie, Pennsylvania in

1969, as a Control Systems Engineer on adjustable speed dc drives. In1971, he transferred to GE Drive Systems in Salem, Virginia where hewas a Controls Systems Engineer on Gas Turbine and Steam TurbineControls. From 1988 until mid-1992, he was a Sales ApplicationEngineer.