Gas Turbine Operation

g GE Energy Services

MS9001EA Gas Turbine

Operations Training Manual

ENEL

Ras Laffan, Qatar

Turbine Numbers T9E152, T9E154, T9E155 & T9E160

Tab 1 Gas Turbine Overview MS9001EA Gas Turbine Functional Description 9E Description MS9001E Gas Turbine Fundamentals A00203

MS9001EA Cross Section

9001E Cross Section

Tab 2 MS6001B Gas Turbine Unit Description Gas Turbine Arrangement (ML 0406) 91-104E8224 Gas Turbine Compressor Rotor Assembly 9EA CPSR Gas Turbine, Turbine Rotor Assembly 9EA TURB Variable Inlet Guide Vane Arrangement (ML 0811) 91-172D7245 First-Stage Nozzle 9EA NZ1 Second-Stage Nozzle 9EA NZ2 Third-Stage Nozzle 9EA NZ3 No 2 Bearing Arrangement 9EA BRG2 Turbine Control Device System Description (Typical) A00079 Schematic Diagram – Turbine Control Devices (ML 0415) 356B2601 Tab 3 Inlet and Exhaust Systems System Description (Typical) AEIS 5166

Schematic Diagram – Inlet and Exhaust Flow (ML 0471) (Typical) 351B7195

Schematic Diagram – Inlet Air Heating (ML 0432) 239C7268 Tab 4 Lubricating Oil System System Description LubeOil Schematic Diagram – PP Lube Oil (ML 0416) 202D8427 Tab 5 Hydraulic Supply System System Description HydOil Schematic Diagram – PP Hydraulic Supply (ML 0434) 356B2725 Tab 6 Trip Oil System System Description TripOil Schematic Diagram – PP Trip Oil 91-316352 Tab 7 Gas Fuel System Fuel Gas Control System GASSTD00 Schematic Diagram – PP Fuel Gas (ML 0422) 356B2265 Schematic Diagram – PP Fuel Purge (ML 0477) 91-315296 Moog Servo Valve Assembly MOOG2

saratchandranm

Highlight

g GE Energy Services Tab 8 Cooling and Sealing Air System System Description CoolSeal Schematic Diagram – PP Cooling and Sealing Air (ML 0417) 239C7408

Turbine Cooling Arrangement

9EA Turbine Cooling

Tab 9 Cooling Water System Cooling Water System Description CoolWater Schematic Diagram – PP Cooling Water (ML 0420) 360B1319 Tab 10 Compressor Water Wash System Compressor Water Wash System Description WW5146 Schematic Diagram – PP Wash System (ML 0442) 356B2267 Gas Turbine Compressor Washing GEK 110220A Field Performance Testing GEK 28166A Tab 11 Starting System System Description (Typical) SS0418 Schematic Diagram – Starting Means (ML 0421) 356B2630 Tab 12 Inlet Guide Vane Control System Guide Vane Control System Description GEK106910 Schematic Diagram – IGV (ML 0469) 91-242B9854 Tab 13 Heating and Ventilating System System Description VH5166 Schematic Diagram – Heating and Ventilation (ML 0436) 91-313088 Tab 14 Fire Protection System Fire Protection System Description FP5166 Schematic Diagram – Fire Protection System (ML 0426) 356B2647 Schematic Diagram – Gas Detection (ML 0474) 91-317644 Tab 15 SPEEDTRONICTM Mark V Control Control Hierarchy 91-318940 Gas Turbine Operator Commands A00052A Fundamentals of Mark V Control System A00023A Mark V Turbine Control System GER 3658D Turbine Control Users Manual GEH 5979D SPEEDTRONICTM Mark V Annunciator Troubleshooting Chart GEK 107359 Tab 16 Gas Turbine Operation GE Gas Turbine Performance Characteristics GER 3567H Unit Operation / Turbine UOGTNODLN1 Tab 17 Reference Drawings Device Summary (ML 0414) 372A8094 Piping Symbols 277A2415G Glossary of Terms C00023 Basic Device Nomenclature A00029B International Conversion Tables GEK 95149C

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1 GAS TURBINE FUNDAMENTALSA00203

GAS TURBINE FUNDAMENTALS

Figure 1

Model Series 9001ESimple-Cycle, Single-Shaft Heavy-Duty Gas Turbine

id0002

GENERAL

Figure 1 depicts a General Electric simple–cyclesingle–shaft, heavy–duty gas turbine. It is an inter-nal combustion engine which produces energythrough a cycle similar to the Otto or Diesel cycles inthat the three cycles consist of the same four stages:compression, combustion, expansion, and exhaust.There are, however, differences in the details of thethree cycles which are worth examining.

The Otto Cycle

In the Otto Cycle, Figure 2, the compression stroke(from 1 to 2) is followed by combustion of constantvolume (2 to 3) resulting in increased pressure. Thepressure causes expansion (3 to 4) with exhaust tak-ing place between points 4 and 1.

3

2

1

4

P = PRESSUREV = VOLUME

V

P

Figure 2 Otto Cycle

id0021

The Diesel Cycle

The Diesel Cycle, Figure 3, is similar, except thatcombustion takes place at a constant pressure (2–3).This is accomplished by injecting fuel at a rate suffi-cient to compensate for the volume change. Expan-sion and exhaust then take place as it does in the OttoCycle.

Figure 3 Diesel Cycle

32

1

4


V

P

id0022

The Brayton Cycle

In both the Otto and Diesel cycles a loss occurs dueto the pressure drop involved in the exhaust stroke.This loss is avoided by creating a cycle in which theexhaust stroke is longer than the compressionstroke, thus allowing the working fluid to be ex-panded to atmospheric pressure. Such a cycle hasbeen devised, and is called a Brayton Cycle (Figure4). It is also called a Constant Pressure Cycle sincecombustion and exhaust both take place at constant

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2GAS TURBINE FUNDAMENTALS A00203

pressure. When the Brayton Cycle is worked out fora steady–flow process, we have the simple gas tur-bine cycle.

32

1

4


V

P

Figure 4 Brayton Cycle

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In the simple gas turbine cycle, combustion and ex-haust occur at constant pressure and compressionand expansion occur continuously, rather than inter-mittently as in the Otto or Diesel cycles. This meansthat gas turbine power is continuously available,whereas in a reciprocating engine power takeoff isavailable only on the expansion stroke. Figure 5schematically represents the hardware necessary forthe cycle. The points on Figures 4 and 5 are consis-tent. At point 1, air enters the compressor (c). Thehigh pressure compressor discharge air at point 2 ismixed with fuel in the burner (b). The product of thiscontinuous combustion at point 3 enters the turbine(t), and is expanded to atmospheric pressure (point4). The turbine provides the horsepower to drive thecompressor and load (in this case, a generator).

GEN

FUEL

AIR

2 3 4

c t

b

c = COMPRESSORb = BURNERSt = TURBINE

1

Figure 5 Fundamental Gas Turbine

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GENERAL DESCRIPTION

The Model Series 9001E gas turbine is a 3000–rpm,single–shaft, simple–cycle power package that basi-cally requires only fuel and fuel connections, gener-ator breaker connections, and an AC–power sourcefor turbine start–up. The MS9001E is also availablein a combined–cycle configuration for applicationsutilizing a Heat Recovery Steam Generator or simi-lar device.

GAS TURBINE UNIT

The gas turbine unit consists of a 17–stage axial–flow compressor and a 3–stage power turbine. Eachsection, compressor rotor and turbine rotor, is as-sembled separately and then joined together.Through–bolts connect the compressor rotor wheelsto the forward and aft stubshafts. The turbine rotoralso utilizes through–bolt construction with spacerwheels between the first– and second–stage and thesecond– and third–stage wheels.

The assembled rotor is a three–bearing design utiliz-ing pressure–feed elliptical and tilt–pad journalbearings. The three–bearing design assures that ro-tor–critical speeds are above the operating speed andallows for optimum turbine bucket/turbine shellclearances.

TURBINE COMPONENTS –OVERVIEW

The major components of the gas turbine are the ro-tor components, primarily the axial flow compres-sor and the turbine wheels; the stationarycomponents, primarily the compressor casings, tur-bine shell, and nozzles; and the combustion compo-nents.

Casings

The casings make up the structural backbone of thegas turbine. This structure supports the rotating ele-

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3 GAS TURBINE FUNDAMENTALSA00203

ments through its bearing housings, functions as apressure vessel to contain the turbine’s workingfluids of compressed air and combustion gases, andprovides a surface of revolution for the blading tooperate while maintaining minimum radial and axialclearance and, therefore, optimum performance.

Compressor

The function of the axial flow compressor is to fur-nish high pressure air to the combustion chambersfor the production of the hot gases necessary to oper-ate the turbine. Since only a portion of its output isused for combustion the compressor also serves as asource of cooling air for the turbine nozzles, turbinewheels, transition pieces, and other portions of thehot–gas path.

Air enters the inlet of the multistage compressorwhere it is compressed from atmospheric pressure toapproximately 8.95 to 12.92 bar (130 to 185 psig),depending on frame size. This gives a CompressorPressure Ratio of approximately 10:1 to 13.5:1,

C.R. �Atmos Press� Compressor Disch Pressure

(Atmospheric Pressure)

again dependent on frame size. The air which con-tinuously discharges from the compressor willoccupy a smaller volume at the compressor dis-charge than at the inlet and, due to heating duringcompression, will have a temperature of 315°C to360°C (600°F to 680°F).

Turbine

The turbine wheels are an area of primary impor-tance because they are the point at which the kineticenergy of the hot gases is converted into useful rota-tional, mechanical energy by the turbine buckets.This produces the power necessary to meet the loadrequirements and drive the axial–flow compressor.

Nozzles

General Electric turbines are of the impulse or high–energy stage design (i.e., pressure and heat conver-sion in the nozzle). The high pressure drop across thenozzle imparts a high velocity (kinetic energy) to thecombustion gases. This energy is directed to thebuckets which use this energy to rotate the shaft,driving the axial compressor and load.

Combustion System

The overall function of the combustion system is tosupply the heat energy to the gas turbine cycle. Thisis accomplished by burning fuel mixed with com-pressor discharge air. The combustion gases are thendiluted with excess air to achieve the desired gastemperature at the inlet of the first–stage turbinenozzle.

The combustion system consists of a number of sim-ilar combustion chambers. Compressor dischargeair is distributed to these chambers where it is bledinto a cylindrical combustion liner. Fuel is injectedinto the forward end of the liners where it mixes withthe compressor discharge air and combustion takesplace, thereby creating hot gases with temperaturesin excess of 1650°C (3000°F) in the flame zone. Aswell as being used for combustion, the relativelycool compressor discharge air acts as a blanket toprotect the liners from the heat of combustion. Inaddition to cooling the combustion liners, compres-sor discharge air mixes with the combustion gasesdownstream of the combustion reaction zone, cool-ing and diluting the gases which now pass throughtransition pieces to the turbine first–stage nozzle.The amount of air necessary to cool the liner walland dilute the hot gas to the temperature desired atthe first–stage nozzle is about four times that re-quired for complete combustion; this “excess air” inthe turbine exhaust makes it possible to install auxil-iary burners in a Heat Recovery Steam Generator ifso desired.

The schematic operation of the single–shaft simple–cycle gas turbine may be seen in Figure 6.

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4GAS TURBINE FUNDAMENTALS A00203

Figure 6 Simple–Cycle Gas Turbine Operation

TORQUEOUTPUTTO DRIVENACCESSORIES

TORQUEINPUTFROMSTARTINGDEVICE

ATMOSPHERICAIR

COMPRESSOR

FUEL

ROTOR

COMBUSTIONCHAMBER

HOT GASES

EXHAUST

TORQUEOUTPUTTO DRIVENLOAD

TURBINE

COMPRESSEDAIR

IGNITION(FOR STARTUP)

id0020

GE Power Systems Training

GE Power Systems

1 TURBINE CONTROL DEVICESC00079

TURBINE CONTROL DEVICES

MS7001EA

GENERAL DESCRIPTION

The turbine control devices are all of the controlcomponents, sensors, and transducers used tomonitor and control the operation of the flange-to-flange gas turbine. The devices are located inthe inlet and exhaust plenums and mounted onthe gas turbine unit, with functions includingthe following:

a. temperature measurement

b. vibration detection

c. speed measurement

d. flame detection

e. combustion ignition

FUNCTIONAL DESCRIPTION

Inlet Plenum

The devices mounted in the forward wall of the in-let plenum are the compressor inlet temperaturethermocouples (CT–IF–1, 2), and are used as an in-dication of the ambient temperature to the com-pressor inlet.

Exhaust Plenum

The devices mounted in the exhaust plenum are theturbine exhaust control and protection thermocou-ples (TT–XD–1 thru 18), and the primary functionis to provide turbine exhaust temperature measure-ments 360° around all ten (10) combustors. Se-lected groupings of six (6) thermocouples are wired

to the three (3) <RST> controllers in the Speedtron-ic control panel to provide temperature inputs to thecombustion monitor and exhaust temperature con-trol, alarm, and trip functions.

Flange–to–Flange Gas Turbine

The remaining devices mounted on the turbine it-self are grouped in the following categories:

Bearing Vibration Detection – using veloc-ity (seismic) type sensors:

#1 Bearing Housing – (39V–1A, 1B)

#2 Bearing Housing – (39V–2A)

#3 Bearing Housing – (39V–3A, 3B)

These devices function are to monitor and protectthe turbine rotor and bearings from excessivevibration and damage.

Turbine Shaft Speed Detection – usingmagnetic type pickups:

Forward Compressor Stub Shaft –(77NH–1, 2, 3)

This function is to provide a speed signal referencefor the Speedtronic controls during start–up, load-ing, and shutdown of the turbine unit.

Temperature Detection – using precisionthermocouples:

Compressor discharge – (CT–DA–1, 2)

This function provides a compressor dischargetemperature corrected reference for Pcd bias con-trol during IGV operation and speed control.

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2TURBINE CONTROL DEVICES C00079

Turbine Wheelspaces as:

First stage aft outer (TT–WS1AO–1, 2)

First stage forward inner (TT–WS1FI–1, 2)

First stage forward outer (TT–WS1FO–1, 2)

Second stage aft outer (TT–WS2AO–1, 2)

Second stage forward outer (TT–WS2FO–1, 2)

Third stage aft outer (TT–WS3AO–1, 2)

Third stage forward outer (TT–WS3FO–1, 2)

Turbine inner barrel (TT–IB–1)

This function is to protect the turbine hot sectionparts such as nozzles, buckets, and wheels fromdamage due to excessive temperatures duringstart–up, normal operation, and shutdown.

Flame Detection–using ultraviolet radiationtype sensors:

flame detectors (28FD–2, 3, 7, 8) in com-bustors # 2, 3, 7, 8

This function is to indicate the presence of flame inthe combustors during turbine start–up and normaloperation.

Combustion Ignition–using devices as:

spark plugs (95SP–1, 10) in combustors #1 & 10

ignition transformers (95TR–1, 10)mounted on turbine base

This function is to light–off the combustors and es-tablish combustion during turbine start–up.

SPECIAL CUSTOMER OPTIONS

Bearing Vibration Monitoring – using prox-imity (non–contacting) type position sensors:

#1 Bearing Housing – (39VS–11, 12) [ra-dial] & (96VC–11, 12) [axial]; (77RP–11)[key phasor]

#2 Bearing Housing – (39VS–21, 22, 23,24) [radial]

#3 Bearing Housing – (39VS–31, 32)[radial]

Bearing Metal Thermocouples

The turbine unit journal and thrust bearings areequipped with bearing metal thermocouples em-bedded into the bearing babbitt metal with thefunction to monitor the “actual” bearing tempera-tures during operation and give an alarm indica-tion if the metal temperature is too high. Thisfunction is to protect the turbine bearings and ro-tor journal surfaces from overheating and failure(i.e. “wiped”). The thermocouples are placed inthe following locations:

#1 main journal bearing – (BT–J1–1A, 1B,2A, 2B)



Thrust Bearing – Active Lands – (BT–TA1–1A, 1B, 2A, 2B)

Thrust Bearing – Inactive Lands – (BT–TI1–1A, 1B, 2A, 2B)

Turbine Performance Monitor

The compressor inlet bellmouth area has total pres-sure probes included as well as an RTD mounted tomonitor the compressor performance during tur-bine unit operation. The compressor inlet pressureand temperature values must be measured in orderto perform this function. The system includes thefollowing equipment:

a. Inlet plenum RTD (CT–IF–3/RTD)

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3 TURBINE CONTROL DEVICESC00079

b. Total and static pressure probes

c. Performance monitor manifold with valving& condensate drain traps

d. Pressure transducers to measure:

inlet air total pressure (96CS)

bellmouth differential pressure (96BD)

barometric pressure (96AP)

compressor discharge pressure (96CD–2)

exhaust pressure (96EP)

inlet filter differential pressure (96TF)

The above pressure transducers are mounted on theperformance monitor manifold, that is located off–base in close proximity to the turbine compartmentinlet and exhaust plenums. The pressure sensinglines are run from the plenums to the monitor man-ifold connections for the transducers.

General Electric CompanyOne River RoadSchenectady, NY 12345


GE Power Systems

4TURBINE CONTROL DEVICES C00079

GE Power SystemsGas Turbine

AIES5166August 1996

These instructions do not purport to cover all details or variations in equipment nor to provide for every possiblecontingency to be met in connection with installation, operation or maintenance. Should further information be desired orshould particular problems arise which are not covered sufficiently for the purchaser’s purposes the matter should bereferred to the GE Company. 1994 GENERAL ELECTRIC COMPANY

Inlet and Exhaust Systems

I. INTRODUCTION

Gas turbine performance and reliability are a function of the quality and cleanliness of the inlet air enteringthe turbine. Therefore, for most efficient operation, it is necessary to treat the atmospheric air entering theturbine and filter out contaminants. It is the function of the air inlet system with its specially designed equip-ment and ducting to modify the quality of the air under various temperature, humidity, and contaminationsituations and make it more suitable for use in the unit.

Hot exhaust gases produced as a result of combustion in the turbine are cooled and attenuated in the exhaustsystem ducting before being released to atmosphere. These exhaust emissions must meet certain environ-mental standards of cleanliness and acoustic levels depending on site location.

The noise generated during gas turbine operation is attenuated by means of absorptive silencing material anddevices built into the inlet and exhaust sections which dissipate or reduce the acoustical energy to an accept-able level.

II. AIR INLET SYSTEM

A. General

The air inlet system consists of a multi–stage filter house and support structure, inlet ducting system, andinlet plenum leading to the compressor section of the turbine.

Inlet air enters the inlet compartment and flows through the ducting, with built–in acoustical silencer andtrash screen, to the inlet plenum and then into the turbine compressor. The elevated intake arrangementprovides a compact system and minimizes the pickup of dust concentrated in the air near the ground.

All external and internal surface areas of the inlet system are stainless steel or coated with a protectivecorrosion inhibiting primer or galvanized for corrosion protection.

The general arrangement of the inlet compartment with respect to the gas turbine inlet plenum is shownon the mechanical outline drawing in the Outlines and Diagrams tab of this manual.

System DescriptionGas Turbine

2

B. Inlet Compartment Description

The inlet filtration compartment and its integrated support structure sit on a separate foundation just up-stream of the control compartment. The system has been sized for additional airflow due to the use offiltered air for compartment pressurization and exhaust frame cooling. The compartment has two–sided,arrowhead design feeding a clean air plenum. The clean air plenum has an aft outlet flange which con-nects to the inlet ducting.

The inlet filter compartment contains three stages of inlet air filtration. The first stage consists of a mois-ture separator. The second and third stages consist of a pre–filter and a high efficiency filter respectively.

C. Inlet Air Treatment Equipment

1. Weather Hoods

The air intakes at each end of the compartment are fitted with large weather hoods. These hoodsminimize the ingestion of water into the inlet compartment during rainy conditions.

2. Moisture Separator

The moisture separator is a PVC drift eliminator designed to eliminate 90% of 50 micron particlesand above. This stage uses a series of bends in the flow path to coalesce the moisture from the flow.It is positioned such that water droplets will form and roll down the weather hoods.

3. Pre–Filter

The pre–filters are installed directly in front of the high efficiency filters. They are a low grade syn-thetic material designed to remove large particles and resist the effects of moisture. This extendsthe life of the final filter. The pre–filter is typically replaced three or four times before a high effi-ciency filter.

4. High–Efficiency Filters

The high–efficiency barrier filters use a special media to achieve good collection efficiency for allparticles, including those smaller than 1 micron. The panel filters contain a depth loading media.Particles are actually trapped within the body of the media itself.

High–efficiency filters have an initial pressure drop which depends upon their construction, instal-lation and the quantity of air passed through each filter element. Filters normally use pleated mediain order to increase the available surface area; this decreases pressure drop and increases dust hold-ing capacity. As dust is accumulated, pressure drop rises. The rise is relatively slow at first, but in-creases more rapidly as the filter nears the end of its useful life. A typical design would have a newand clean pressure drop of about an inch of water; the final pressure drop depends upon a trade offbetween filter life and gas turbine performance. General Electric recommends a final pressure dropof 2.5 inches of water as a good compromise for panel filters.

D. Operation and Maintenance

For additional information on the operation and maintenance of the inlet filtration system, refer to themanufacturer’s operation and maintenance manual contained in this section. If specific recommendedmaintenance and inspection schedules are not included as part of the manufacturer’s manual, refer to thesection on Inlet Air System Maintenance in the Inspection and Maintenance volume.

Gas TurbineSystem Description

E. Inlet Ducting and Silencing

The inlet air ductwork system contains the compressor noise silencing and connects the inlet compart-ment to the compressor inlet plenum. It consists of 2 inlet plenum extensions, a transition duct, an acous-tically treated expansion joint, a 90 degree elbow, 8 feet of parallel baffle silencing and horizontal un-lined ducting that connects to the filter house.

The inlet silencer consists of an acoustically lined duct containing silencing baffles constructed of a lowdensity insulating material which is encapsulated by perforated sheet steel. The acoustic lining in thewalls of the silencer duct and the walls of the ducting downstream of the silencer have a similar construc-tion. The vertical parallel baffle is specifically designed to eliminate the fundamental compressor toneas well as attenuating the noise at other frequencies.

There is a stationary trash screen within the elbow duct which can be accessed for cleaning and inspec-tion through a removable panel on the side of the elbow.

The horizontal ducting has flanged connections on top to allow filtered air to be pulled off for compart-ment pressurization and exhaust frame cooling.

The inlet ducting makes use of materials and coatings in their construction which are designed to makethem maintenance free. The entire system has been constructed from 304 stainless steel. The perforatedsheet is also stainless steel for corrosion resistance.

III. EXHAUST SYSTEM

The exhaust system is the system of ductwork that directs the gas turbine exhaust gases from the power tur-bine exit to the atmosphere. The system is thermally insulated to maintain structural and exterior paint integ-rity while providing personnel protection. It is acoustically insulated to maintain guaranteed overall gas tur-bine noise levels. This configuration consists of the exhaust plenum, plenum top and side covers, anexpansion joint, a horizontal transition duct, a horizontal silencer, an up elbow, an exhaust stack, and a raindamper mounted in the stack.

Refer to the “Mechanical Outline, Gas Turbine and Load” drawing, in the Outline and Diagrams tab for de-tails of the configuration.

IV. PLENUM

The plenum captures the exhaust gas leaving the gas turbine and directs it radially away from the turbine.The top and side covers close the opening on the top and non–discharge side of the plenum. These openingsprovide directional options for exhaust gas flow in other configurations. The plenum is welded in place toan extension from the turbine base. It encloses the turbine exhaust frame, diffuser and turning vanes. Ther-mocouples, mounted in the plenum, provide exhaust gas temperature feedback to the SPEEDTRONIC�

Mark V control system.

V. EXPANSION JOINTS

Exhaust system expansion joints allow for the thermal growth of adjacent steel duct components while main-taining the integrity of a leak free flowpath. One joint is supplied with this system, located between the ple-num and the lateral transition duct.


4

VI. TRANSITION DUCTS

Transition ducts provide a gradual change in flowpath cross–section between major exhaust system compo-nents to help minimize total system pressure drop.

VII. SILENCER

The silencer is a parallel baffle design where the exhaust gasses pass between the horizontally mounted si-lencer panels before entering the atmosphere. The panels contain sound absorbing ceramic fiber fill encasedin perforated metal lagging. The panel thickness and length is sized to absorb enough of the high and lowfrequency sound energy from the exhaust to meet overall gas turbine noise level guarantees.

VIII. ELBOW

Once the exhaust gas passes through the silencer, it flows into the elbow and is directed up into the exhaststack.

IX. EXHAUST STACK

The exhaust stack is a hollow duct welded to the top of the elbow. It is designed to release exhaust gasesto the atmosphere well above ground level at a velocity suited for the proper dispersal of combustion prod-ucts. Provisions for collecting exhaust gas samples are built into the stack. Sampling ports are accessiblefrom the ground level via an arrangement of ladders and platforms.

X. RAIN DAMPER

A rain damper is mounted in the stack to prevent water from entering the horizontal ductwork. The damperis an electrically driven device. The damper consists of a gutter system with a stack–mounted drain pipe thatruns to the ground.

g GE Power Systems

LUBRICATION SYSTEM 1. GENERAL The lubricating requirements for the gas turbine power plant are furnished by a common forced feed lubrication system. This lubrication system, complete with tank, pumps, coolers, filters, valves and various control and protection devices, furnishes normal lubrication and absorption of heat rejection load of the gas turbine. Lubricating fluid is circulated to the three main turbine bearings and to the turbine accessory gear. Also, lubricating fluid is supplied to the starting means torque converter for use as hydraulic fluid as well as for lubrication. Additionally, a portion of the pressurized fluid is diverted and filtered again for use by hydraulic control devices as control fluid. Major system components include:- a. Lube reservoir in the accessory base. b. Main lube oil pump (shaft driven from the accessory gear). c. Auxiliary lube oil pump. d. Emergency lube oil pump. e. Pressure relief valve VR 1 in the main pump discharge. f. Lube oil heat exchangers. g. Lube oil filters. h. Bearing header pressure regulator VPR2. Lube oil temperatures are indicated on the thermometers which are located in the bearing header and the oil tank. For turbine starting, a maximum of 800 SSU is specified for reliable operation of the control system and for bearing lubrication. Lubricating fluid for the main, auxiliary and emergency lube pumps is supplied from the reservoir, while lubricating fluid used for control is supplied from the bearing header. This lubricant must be regulated to the proper, predetermined pressure to meet the requirements of the main bearings and the accessory lube system, as well as the hydraulic control and trip circuit. All lubricating fluid is filtered and cooled before being piped to the bearing header. 2. FUNCTIONAL DESCRIPTION a. Lubricant Reservoir and Piping The reservoir and sump for the lubrication system is the 3300 gallon (12491 litres) tank which is fabricated as an integral part of the accessory base. Lubricating fluid is pumped from the reservoir by the main shaft driven pump (part of the accessory gear) or auxiliary or emergency pumps to the bearing header, the accessory gear and the hydraulic supply system. After lubricating the bearings, the lubricant flows back through various drain lines to the lube oil reservoir. The total system capacity is approximately 4000 gallons (15000 litres). All lubricant pumped from the lube oil reservoir to the bearing header flows through the lube oil heat exchangers to remove excess heat and then through the cartridge type filters.

g GE Power Systems Filtration of all lube oil is accomplished by filter vessels installed in the lube oil system just after the lube oil heat exchangers. Two (dual) coolers and filters are used with a transfer valve installed between the coolers and filters to direct oil flow through either cooler or filter and into the lube oil header. The dual lube oil filters have removable 5-micron (nominal) synthetic media filter elements. A differential pressure gauge indicates the filter pressure drop. There is also a pressure switch (63QQ-1) which signals when the differential pressure reaches the recommended level for element change. Lubricant from the No. 1 turbine bearing assembly is piped through an internal drain line to the lube oil reservoir. Drain from the other turbine bearing assemblies is piped to an externally routed drain header that interconnects the accessory base and turbine base. The lube oil drain flows forward through this common drain header to the lube oil reservoir. A lube oil level gauge and alarm system, a hermetically sealed float arm operated device, is mounted to the side of the lube oil reservoir above the maximum expected level of the lube oil. The float mechanism energizes an annunciator circuit of the turbine control panel, through a dial gauge and switches, to operate an annunciator drop and an audible alarm if the liquid level rises above or drops below a predetermined level. A lubricant drain connection is located on the side of the accessory base to drain the lube oil reservoir. Note: The oil level gauge indicates F (Full) or E (Empty) before the annunciator alarm is sounded. The lubricant oil system is vented through a mist eliminator. This device removes oil mist from the air before it goes to the atmosphere. b. Standby Heaters During standby periods the lubricating fluid is maintained at a viscosity proper for turbine start up by heaters installed in the lube oil reservoir. Temperature switches sense reservoir fluid temperature and control the heaters to maintain fluid temperature to achieve allowable viscosity. Another temperature switch senses reservoir temperature and will not permit the turbine to be started if the fluid temperature drops below that to maintain the viscosity required for start up. c. Lubricating oil pumps Lubrication to the bearing header is supplied by three lube oil pumps:- 1. The main lube oil supply pump is a positive displacement type pump mounted in and driven by the accessory gear. 2. The auxiliary lube oil supply pump is a submerged centrifugal pump driven by an ac motor. 3. The emergency lube oil supply pump is a submerged centrifugal pump driven by a dc motor. 1. Main Lube Oil Pump The main lube oil pump is built into the inboard wall of the lower half casing of the accessory gear. It is driven by a splined quill shaft from the lower drive gear. The output pressure to the lubrication system is limited by a back pressure valve to maintain system pressure.

g GE Power Systems 2. Auxiliary Lube Oil Pump The auxiliary lube oil pump is a submerged centrifugal type pump driven by an ac motor. It provides lubricant pressure during start up and shutdown of the gas turbine when the main pump cannot supply sufficient pressure for safe operation. Operation of this pump is as follows:- a. The auxiliary lube oil pump is controlled by a low lube oil pressure alarm switch (63QA-I). This switch causes the auxiliary pump to run under low lube oil pressure conditions as is the case during start up or shutdown of the gas turbine when the main pump, driven by the accessory drive device. does not supply sufficient pressure. It also indicates an alarm condition on the annunciator panel. b. The auxiliary pump continues to operate until the turbine reaches approximately 95 percent of operational speed. At this point. the auxiliary lube pump shuts down and system pressure is supplied by the shaft driven, main lube oil pump. During the turbine starting sequence the pump starts when the start signal is given. The control circuit is through the normally closed contacts of pressure switch 63QA-l. The pump will run until the turbine operating speed is reached (operating speed relay 14HS picks up), even though the lube oil header is at rated pressure and the pressure switch (63QA-1) contacts have opened. When the turbine is on the shutdown sequence, this pressure switch will signal for the auxiliary pump to start running when the lube oil header pressure falls to the point at which the contacts of the switch are set to close. 3. Emergency Lube Oil Pump The emergency lube oil pump is a dc motor driven pump of the submerged centrifugal type. This pump supplies lube oil to the main bearing header during an emergency shutdown in the event the auxiliary pump has been forced out of service because of loss of ac power, or for other reasons. It operates as follows:- a. This pump is started automatically by the action of pressure switch 63QL-1 whenever the lube pressure in the main bearing header falls below the pressure switch setting. b. If the auxiliary lube oil pump should resume operation, the emergency pump will be stopped by pressure switch (63QL-1) when the header pressure exceeds the setting of the switch. c. Should the auxiliary pump fail during the shutdown sequence, because of an ac power failure, or any other cause, the emergency lube oil pump will be started automatically by the action of low lube oil pressure switch 63QL-l and continue to run until the turbine shaft comes to rest. d. Test Valve - Low Lube Oil Pressure - Emergency Pump Start A test valve, mounted on the gauge cabinet, provides the means of checking automatic start up of the emergency lube oil pump and pressure switch 63QL-1. This can be done while the unit is operating nor-mally on the main lube oil pump. The test valve is normally closed and maintains lubricating system pressure on the switch. When per-forming a test, the test valve should be opened gradually to lower lubricating system pressure in the tub-ing to the switch. This provides the means of checking the pressure points at which the switch operates to start the pump. Upon closing the test valve, lube oil pressure is returned to normal and the pump should stop as a result of the restoration of pressure on the 63QL-l switch.

g GE Power Systems e. Test Valve For Low Lube Oil Pressure - Auxiliary Pump Start A gauge mounted test valve is also used to provide the means of checking the automatic operation of the auxiliary lube oil pump and pressure switch 63QA-l while the unit is operating normally on the main lube oil pump. The test valve is installed in the tubing at the switch and is normally closed holding the lube system pressure on the switch. When performing a test, the test valve should be opened gradually to lower the lube oil system pressure on the switch. This oil pressure is indicated on a gauge connected into the pressure line. The gauge provides a means of checking the pressure point at which the switch operates and starts the pump running. When the oil pressure falls to the setting of switch 63QA-1, this pump is started. f. Heat Exchangers All lubricant pumped from the lube reservoir to the bearing header flows through either of the dual lube oil heat exchangers to remove excess heat. The dual heat exchangers have a transfer valve between them which directs oil solely through either of the two heat exchangers. This permits the heat exchangers to be operated singly so that one heat exchanger can be removed for servicing without shutting down the turbine. See section below on oil filters with regard to operating the transfer valve. g. Oil Filters Filtration of all lube oil is accomplished by a five-micron (nominal), synthetic media element filters installed in the lube oil system just after the lube oil heat exchanger. Two (dual) filters are used with a transfer valve installed between the filters to direct oil flow through either filter and into the lube oil header. Only one filter will be in service at a time, thus cleaning, inspection. and maintenance of the second one can be performed without interrupting oil flow or shutting the as turbine down. By means of the manually operated transfer valve, one filter can be put into service as the second is taken out without interrupting the oil flow to the main lube oil header. The transfer of operation from one filter to the other should be accomplished as follows:- 1. Open the cross fill valve and fill the standby filter until a solid oil flow can be seen in the flow sight glass in the filter vent pipe. This will indicate a "filled" condition. 2. Operate the transfer valve to bring the standby filter into service. 3. Close the cross fill valve. A differential pressure gauge is connected across the filters to indicate when the filter element needs replacement. Filters should be changed when the differential pressure gauge indicates a differential pressure of 15 psi (103.47 kPa). Pressure switch 63QQ-l is provided to alarm at a differential pressure of 15 psi (103.47 kPa), indicating that a change of filter is required. h. Pressure Regulation Two regulating valves are used to control lubrication system pressure. A back pressure relief valve, VR 1, limits the positive displacement main pump discharge header pressure and relieves excess fluid to the lube oil reservoir. The lube oil pressure in the bearing header is maintained at approximately 25 psig (172.36 kPa) by the diaphragm operated regulating valve, VPR2. The diaphragm valve is operated by sensing fluid pressure in the bearing header.

g GE Power Systems j. Pressure And Temperature Protective Devices The condition of low lubricating oil pressure is detected by a pressure switch that opens after a decrease of line pressure to a specified value and trips the unit. Pressure switches 63QT-2A and transmitter 96QT-2A installed in the turbine bearing feed piping shut the turbine down if the lubricant pressure drops to an unacceptable level. Likewise, temperature switches 26QT-IA and -26QT-IB are installed in the lubricating fluid header piping and cause the unit to trip should the temperature of the lubricant to the bearings exceed a preset limit. Before this limit is reached, switch 26QA-l in the piping will cause an alarm.

g GE Power Systems

HYDRAULIC SUPPLY SYSTEM 1. GENERAL Fluid power, required for operating the control components of the gas turbine fuel system and the inlet guide vane system is provided by the hydraulic supply system. This fluid furnishes the means for opening or resetting the fuel stop valves, in addition to the variable turbine inlet guide vanes and the hydraulic control and trip devices of the gas turbine. Major system components include the main hydraulic supply pump, an auxiliary supply pump, the system filters, an accumulator assembly, and the hydraulic supply manifold assemblies. 2. FUNCTIONAL DESCRIPTION Regulated and filtered lube oil from the bearing header of the gas turbine is used as the oil supply to provide the high pressure fluid necessary to meet the hydraulic system requirements. A pressure compensated variable displacement pump, driven by a shaft of the accessory gear, is the primary pump that pumps oil from the lube system to the hydraulic supply manifold. An auxiliary motor driven hydraulic pump is also provided as the backup to the primary pump. The fluid supply for these hydraulic pumps is taken from the bearing lube oil header, this fluid having been filtered previously. Hydraulic oil, pressurized by the hydraulic pumps, is controlled by pressure compensators, VPR3−1 and VPR3−2 built into the pumps. The action of the compensator varies the stroke of the pump to maintain a set pressure at the pump discharge. The auxiliary hydraulic pump operates whenever the main hydraulic pump pressure output level is inadequate for turbine operation, such as during start up or low speed conditions. When the main pump is operating and it fails to maintain adequate pressure, the condition will be sensed by pressure switch 63HQ−1, and the auxiliary pump will be started by a signal from this switch. Hydraulic fluid is pumped to the hydraulic supply manifold. This manifold is an enclosure designed to provide a means of interconnecting a number of small components. Contained within the manifold assembly are relief valves, air bleed valves, and check valves. Each pump has a pressure compensator built into it which regulates pressure. There are also relief valves, VR21−1 and VR22−1, which will relieve pressure should the pressure regulator fail. Check valves VCK3−1 and VCK3−2 prevent oil from flowing into the out of service pump. The check valves also keep the hydraulic lines full when the turbine is shut down. The air bleed valves vent any air present in the pump discharge lines. From the output connections of the manifold assembly the high pressure fluid is piped through the system filters (FH2−1 and FH2−2) and now becomes a high pressure control fluid. The hydraulic supply system filters prevent contaminants from entering the control devices of the inlet guide vane system, the fuel control servovalves and other hydraulic devices. Only one filter is in service at any time during system operation. The dual filter assembly, complete with cross fill valve and transfer valve, is provided to permit changeover to the second filter without interrupting the operation of the system. A differential gauge is provided to indicate the oil pressure drop across the filters. When the gauge indicates a pressure differential of 60 psid (413 kPad), or annually (whichever occurs first) the filter cartridge should be replaced. There is also a differential pressure switch, 63HF−1, which alarms at high differential pressure.

g GE Power Systems The following procedure should be used when transferring from one filter to the other : 1. Open the air bleed valve on the unused filter. 2. Open the cross fill valve. 3. When oil with air comes out of the air bleed, operate the transfer valve. 4. Close the cross fill valve. 5. When no air is contained in the oil coming from the air bleed, close the bleed valve. A hydraulic accumulator assembly, having two accumulators, is also connected in the high pressure line of the hydraulic supply system to absorb any severe shock that may occur when the supply pumps are started. In addition. the accumulator supplies the necessary transient demands for operation of all of the hydraulic control and protection components required in the control and protection of the gas turbine. The output of the hydraulic supply system is a high pressure control fluid, a primary hydraulic interface between the turbine control and protection system and the fuel system servovalves that control or shut off fuel. This high pressure supply fluid is also used as the hydraulic fluid in the variable inlet guide vane actuating cylinders and IGV control system.

g GE Power Systems

TRIP OIL SYSTEM 1. GENERAL The gas turbine protection systems consist of a number of primary and secondary systems. several of which operate at each normal start up and shutdown. The other systems and components are strictly for abnormal and emergency operating conditions requiring shutdown of the turbine. The trip oil system is the primary protection interface between the turbine control and protection system circuits (SPEEDTRONIC Control System) and the components on the turbine which admit or shut off fuel to the turbine. The system contains devices which are electrically operated through the turbine control panel by SPEEDTRONIC signals as well as others that are completely mechanical devices that operate directly on the turbine components totally independent of the turbine control panel. 2. FUNCTIONAL DESCRIPTION a. General Low pressure oil, taken from the turbine lube oil system, is used in the trip oil system. Lube oil is passed through a piping orifice to become the trip oil (OLT). The orifice is located in the pipe running from the bearing header supply to the trip oil system. This orifice is sized to limit the flow of lube oil into the trip oil system and ensure an adequate capacity for all tripping device operations without causing a starvation of the lube oil system when the trip oil system is activated. The devices that cause a turbine shutdown through the trip system do so by dumping fluid pressure from the system either directly or indirectly through electrohydraulic dump valves, 20FG-1 or 20TV-1. When oil in the trip oil line is dumped, fuel stop valves close by spring return action. When the turbine is started the dump valves are energized to reset at the desired point in the starting sequence permitting oil pressure to open the fuel stop valves and inlet guide vanes. The fuel stop valves remain open until some trip action occurs or until the unit is shut down. An orifice is installed in the trip oil lines to the liquid fuel stop valve to permit operation. Since inlet guide vane activation is also part of the trip oil system, the orifice will permit inlet guide vane operation when the fuel system is in its tripped state. Pressure switches 63HG−1, 63HG−2 & 63HG−3 monitor trip oil pressure to the liquid fuel system. If the pressure to the fuel system becomes too low for reliable operation, the switch will trip the unit and cause annunciation of low trip oil pressure. 1. Fuel Gas Stop Ratio Valve Solenoid Valve (20FG-1) Liquid fuel solenoid dump valve 20FG-1 is a spring biased spool valve which relieves trip oil pressure causing the liquid fuel stop valve to trip shut. The dump valve is energized to run and de-energized to trip from the SPEEDTRONIC panel. Since this dump valve is spring biased to trip, it protects the turbine during all normal situations as well as those times when loss of dc power occurs.

2. Variable Inlet Guide Vane System 3.

The modulated inlet guide vane system is activated by the action of the trip oil system using low pressure trip oil (OLT) in conjunction with high pressure oil (OH) from the hydraulic supply system. Electronic

g GE Power Systems control signals activate and position the inlet guide vanes, both during normal operation and under trip conditions, through the action of servovalve 90TV-1, hydraulic dump valve VH3, position sensors 96TV−I and 96TV−2 and hydraulic activating cylinder ACV 1. During normal operation trip oil (OLT) is pressurized and dump valve VH3 is energized which allows hydraulic oil from the hydraulic supply system to flow through servovalve 90TV-1. The controlled, or modulated, position of inlet guide vane servovalve 90TV-1 determines the flow of hydraulic oil through the servovalve and dump valve VH3 to the inlet guide vane hydraulic actuator ACV 1. The hydraulic pressure applied to the actuator determines the position of the inlet guide vane control ring. In a trip condition trip oil is dumped by action of dump valve 20TV-1. This causes inlet guide vane dump valve VH3 to move to the dump position by action of the spring return feature thereby dumping actuator cylinder oil which closes the inlet guide vanes. When the turbine is at rest, the inlet guide vane angle position is at the designed closed position. This closed guide vane angle is the position established to limit the air flow through the compressor during the turbine accelerating and decelerating sequence.

MOOG2 9/97

SUPPLY PRESSURE

FILTERED 1st STAGE SUPPLY PRESSURE

1st STAGE CONTROL PRESSURE

CONTROL PORT PRESSURES

RETURN PRESSURE

INTERNAL DRAIN PRESSURE

Servovalve OverviewMoog CONTROLS

TORQUE MOTORPERMANENT

MAGNET

COILS

TOP POLE PIECE

ARMATURE

FLEXURE SLEEVE

BOTTOM POLE PIECE

FLAPPER

NOZZLEFILTER

MOTORSHIM

END CAP

ORIFICE, INLET

FEEDBACKSPRING

SPOOLSTOP

BUSHING(SLEEVE)

SPOOL(SLIDE)

ORIFICE,RETURN

BODY(HOUSING)

DRAIN1350 PSI

LVDTTO < RST >

g GE Power Systems

COOLING AND SEALING AIR SYSTEM 1. GENERAL The cooling and sealing air system provides the necessary air flow from the gas turbine compressor to other parts of the gas turbine rotor and stator to prevent excessive temperature build up in these parts during normal operation and for sealing of the turbine bearings. Atmospheric air from off base centrifugal type blowers is used to cool the turbine exhaust frame. Cooling and sealing functions provided by the system are as follows: a. Sealing of the turbine bearings. b. Cooling of internal turbine parts subjected to high temperature. c. Cooling of the turbine outer shell and exhaust frame. d. Providing an operating air supply for air operated valves. The cooling and sealing air system consists of specially designed air passages in the turbine casing, turbine nozzles and rotating wheels, piping for the compressor extraction air and associated components. Associated components used in the system include: a. Turbine Exhaust Frame Cooling Blowers b. Air Filter (with poro-stone element) c. Pressure Gauge d. Dirt Separator 2. FUNCTIONAL DESCRIPTION a. General Air from the axial flow compressor, extracted from several points, is used for sealing the bearings, cooling turbine internal parts and to provide a clean air supply for air operated control valves. Compressor extraction air is also used for pulsation protection of the compressor during turbine start up and shut down. Bearing sealing air is extracted from the fifth stage of the compressor. Internal cooling air is extracted from the discharge of the compressor including the internal flow of cooling air through the turbine rotating and stationary parts. Air used in cooling the turbine external casing is ambient air supplied by off base motor driven blowers. b. Bearing Cooling and Sealing Cooling and sealing air is provided from two connections on the compressor casing at the fifth stage and is piped externally to each of the three turbine bearings. Orifices in the air lines to the turbine bearings limit the flow of air and the pressure to the proper value. The centrifugal dirt separator located in the fifth stage piping removes any particles of dirt or foreign matter that might be injurious to the bearings. This pressurised air cools and seals the bearings by containing any lubricating fluid within the bearing housing that otherwise might seep past the mechanical seals. Air is directed to both ends of each bearing housing providing a pressure barrier to the lubricating fluid. After performing this function, the air is vented via the oil drain passage from the No. 1 and No. 3 bearings while air from the No. 2 bearing is vented to atmosphere.

g GE Power Systems c. Exhaust Frame and Turbine Shell Cooling Cooling of the exhaust frame and turbine shell is accomplished by two electric motor driven, centrifugal blowers, 88TK-1 and 88TK-2, which are mounted external to the turbine. An inlet screen is provided with each blower and the discharge of each passes through a back draft damper (check valve), VCK7-1 or VCK7-2 before entering openings in the exhaust frame outer sidewall cavity. The cooling air flow splits, with part of the air passing along and cooling the turbine shell and the other portion flowing through the exhaust frame strut passages. The air flow through the struts divides, with a portion directed through passages to cool the third stage turbine aft wheelspace and the remainder flowing into the load shaft tunnel where it discharges through a duct to atmosphere. Air for cooling the exhaust frame and turbine shell is normally provided by the two blowers operating simultaneously in parallel. Each blower has a pressure switch, 63TK-l or 63TK-2, to sense blower discharge pressure. If one of the blowers should fail, the loss of blower discharge pressure will cause contacts of the respective 63TK pressure switch to close and an alarm will be annunciated. The turbine will continue to run with the other blower providing cooling air at a reduced flow rate. If both blowers should fail, the turbine will be shut down in a normal shutdown sequence. d. Pulsation Protection The pressure, speed and flow characteristics of the gas turbine compressor are such that air must be extracted from the 11th stage and vented to atmosphere to prevent pulsation of the compressor during the acceleration period of the turbine starting sequence and during deceleration of the turbine at shutdown. Pneumatically operated 11th stage air extraction valves, controlled by a three way solenoid valve, are used to accomplish the pulsation protection function. Eleventh stage air is extracted from the compressor at four flanged connections on the compressor casing. Each of these connections is piped through a normally open, piston operated, butterfly or vee ball type valve, VA2-1, VA2-2, VA2-3, and VA2-4, to the turbine exhaust plenum. Limit switches 33CB-1, 33CB-2, 33CB-3, and 33CB-4 are mounted on the valves to give an indication of valve position. Compressor discharge air controlled by solenoid valve 20CB-1 is used to close the compressor bleed valves. Air from 11th stage compressor discharge is piped to a porous air filter which removes dirt and water from the compressor discharge air, by means of a continuous blowdown orifice, before the air enters solenoid valve 20CB. From the solenoid valve, the air is piped to the piston housings of the four extraction valves. During turbine startup, 20CB-1 is de-energised and the 11th stage extraction valves are open allowing 11th stage air to be discharged into the exhaust plenum thereby eliminating the possibility of compressor pulsation. Limit switches, 33CB-1 through 33CB-4, on the valves provide permissive logic in the starting sequence and ensure that the extraction valves are fully opened before the turbine is fired. The turbine accelerates to full speed and when the generator circuit breaker closes, the 20CB-1 solenoid valve is energised to close the extraction valves and allow normal running operation of the turbine. When a turbine shutdown signal is initiated and the generator circuit breaker is opened, 20CB is de-energised and 11th stage air is again discharged into the exhaust plenum to prevent compressor pulsation during the turbine deceleration period. e. Pressurized Air Supply Compressor discharge air is also used as a source of air for operating various air operated valves in other systems. Air for this purpose is taken at the discharge of the compressor and is then piped to the various air operated valves.

g GE Power Systems f. Water Wash Provisions When water washing the gas turbine compressor or turbine section, it is important to keep water out of the components that are actuated by compressor discharge air and out of the turbine bearings. To prevent water from entering these components and the bearings, isolation valves are provided in the sealing lines to the No. 1, No. 2, and No. 3 bearings, and in 20CB-1 and 96CD-1A 1B and 1C feed lines. During normal operation of the gas turbine, all isolation valves are to be open. Before initiating water wash, the isolation valves must be closed and the drain and air separator blowdown valves opened. At the conclusion of the water wash, the isolation valves must be opened and the drain and separator blowdown valves closed to allow normal operation of the turbine.

g GE Power Systems

COOLING WATER SYSTEM 1. GENERAL The cooling water system is designed to accommodate the heat dissipation requirements of :- 1. Lube Oil System. 2. Atomizing Air System. (if liquid fuel is used) 3. Turbine Support Legs The cooling water system comprises both on base and off base mounted components. The on base components include the lube oil heat exchangers, atomizing air precooler, flow regulating valves, orifices and isolating valves. Included in the off base components is a water to air fin-fan cooling module and a cooling water pump skid comprising pumps, valves and various flow control devices. 2. ON BASE COOLING WATER SYSTEM The cooling water is circulated through the system by a centrifugal type pump. After absorbing the heat rejected by the lube oil and atomizing air heat exchangers and the turbine support legs, the cooling water flows to the off base mounted finned tube heat exchanger. The cooling water circuits for the lube oil heat exchanger and atomizing air precooler each have a temperature actuated three way valve installed in the cooling water supply line. Valve (VTR-l) is provided for the lube oil heat exchangers and valve (VTR-2) is provided for the atomizing air precooler. This type of valve, which controls cooling water flow to the heat exchanger, has a manually operated device which can be used to override the thermal element. The manual override device should be used only when the thermal element of the valve is inoperative, and Gas Turbine operation is required. Valves (VTR-l) and (VTR-2) automatically control the flow of cooling water passing through the heat exchangers. The valves respond to temperature changes in the atomizing air compressor inlet line and the lube oil feed header. These changes are sensed by a control bulb connected to each valve. Each bulb contains a thermal sensitive liquid which expands when heated. This generates pressure within the bulb. The pressure is transmitted through a capillary tube to a bellows arrangement which positions the valve plug to control the flow of cooling water through the related heat exchanger. The valves are closed during turbine start up and will start to open as the temperature of the sensed fluid approaches the control setting. Valve (VTR-2), installed in the cooling water line to the atomizing air pre-cooler, has a small bypass orifice drilled into the valve body to ensure that the pre-cooler is flooded at all times. Isolating valves are installed in the cooling water piping to the lube oil heat exchangers to enable the exchangers to be serviced. Valves are not installed in the piping to the atomizing air pre-cooler due to the severe consequences of inadvertently shutting off cooling water flow to this component. 3. CORROSION INHIBITOR In order to reduce the corrosive properties of water it is necessary to add a corrosion inhibitor to the cooling water system.


WW5146February 1997


Gas Turbine Compressor Water Wash System

I. GENERAL

Gas Turbines can experience a loss of performance during operation as result of deposits of contaminants oninternal components. The deposits of atmospheric contaminants on compressor parts occurs with the ingestionof air.

The ingested air may contain dirt, dust, insects and hydrocarbon fumes. A large portion of these can be re-moved before they get to the compressor by inlet air filtration. The dry contaminants that pass through thefilters as well as wet contaminants, such as hydrocarbon fumes, have to be removed from the compressor bywashing with a water-detergent solution followed by a water rinse.

A. On-Base Supplied Equipment

The on-base turbine equipment supplied with this compressor/turbine wash system consists of pipingfrom the purchaser’s connection(s) on the base, motor operated water injection valve(s), and the appropri-ate spray manifold(s). In addition, there are purchaser connections in the drain lines from the inlet plenum,combustion area, exhaust frame and the exhaust plenum.

B. Off-Base Equipment

The off-base portion of the water wash system, known as the water wash skid, contains both a water tankand a detergent tank. The schematic for the water wash skid is included in the Reference Drawings sectionof this manual.

The water tank is equipped with electric heaters and temperature sensors to maintain proper water temper-atures.

The skid is equipped with a centrifugal water pump motor (88TW–1) and a venturi used with the waterpump to mix detergent solution.

All equipment is made of corrosion resistant material. All devices are set to give proper temperature, pres-sure and flow. The settings for these devices can be found in the device summary for the correspondingsystem. Customer-supplied piping is required from the skid to the turbine base. Also included on the skidare the various control panels to initiate wash and to manually start/stop the appropriate devices.


2

C. Functional Description

During the washing operation, water or wash solution is delivered through customer piping to the gas tur-bine in the proper mix ratio. The wash water solution is delivered to the turbine unit at the proper pressure,temperature and flow rate to wash the gas turbine compressor. Refer to the system schematic in the Refer-ence Drawing section for proper pressure(s), temperature(s), and flow rate(s) for this gas turbine.

1. System Requirements

Water used for washing turbine parts should be reasonably clean so that it does not cause fouling orcorrosion in itself. Distilled or deionized water is recommended. Water quality requirements are listedin Table 1 of GEI–103623. Oily or varnished oil deposits on internal gas turbine parts require that adetergent solution be used during the washing operation. The detergent shall meet the requirementsof GEI–103623, Appendix 1.

2. Compressor Washing Frequency

The frequency of compressor washing depends upon the severity and type of atmospheric contamina-tion which fouls the compressor and reduces performance. The recommended method for establish-ing the frequency is to monitor gas turbine performance, comparing the routine performance with thebaseline performance to observe the trends.

The comparison will show performance trends. If the performance has fallen significantly, and com-pressor fouling is suspected, it must be verified by visual inspection. This visual inspection shouldinclude inspection of the compressor inlet, bellmouth, inlet guide vanes and the first and possibly thesecond stage of the compressor blades.

Note: Inspection should be made for the source of the oily deposits. If pos-sible, corrective action should be taken.

D. Washing System Operation

1. General

Water washing should be scheduled during a normal shutdown, if possible. This will allow enoughtime for the internal machine temperature to drop to the required levels for the washing. The time re-quired to cool the machine can be shortened by maintaining the unit at crank speed. During this cool-ing of the turbine, the wash water is to be heated to the proper level.

2. Mandatory Precautions

Before water washing of the compressor begins, the turbine blading temperature must be low enoughso that the water does not cause thermal shock.


3

CAUTION

The differential temperature between the wash water andthe interstage wheelspace temperature must not be greaterthan 120°F (67°C) to prevent thermal shock to the hot gasparts. For wash water of 180°F (82.2°C), the maximumwheelspace temperature must be no greater than 300°F(148.9°C) as measured by the digital thermocouple read-out system on the turbine control panel.

To reduce this difference, the wash water may be heated and the turbine kept on crank until the wheel-space temperatures drop to an acceptable level. The wheelspace temperatures are read in the controlroom.

CAUTION

If, during operation, there has been an increase in exhausttemperature spread above the normal 15°F to 30°F (8.3°Cto 16.6°C), the thermocouples in the exhaust plenumshould be examined. If they are coated with ash, the ashshould be removed.

Radiation shields should also be checked. If they are not radially oriented relative to the turbine, theyshould be repositioned per the appropriate drawing. If the thermocouples are coated with ash, or ifthe radiation shields are not properly oriented, a correct temperature reading will not be obtained.

If neither of the above conditions exists and there is no other explanation for the temperature spread,consult the General Electric Installation and Service Engineering representative.

WARNING

The water wash operation involves water under high-pressure. Caution must be exercised to ensure theproper positioning of all valves during this operation.Since the water may also be hot, necessary precau-tions should be taken in handling valves, pipes, and po-tentially hot surfaces.

Note: Before water washing the compressor, inspect the inlet plenum and gasturbine bellmouth for large accumulations of atmospheric contami-nants which could be washed into the compressor. The deposits can beremoved by washing with a garden hose.


4

3. Water Wash Procedures

The next sections set forth procedures for performing the following type(s) of washing:

1. Off-Line Compressor Wash

2. On-Line Compressor Wash

To perform the type(s) of washing designed for this particular unit, refer to the system schematic inthe Reference Drawings Section and the device summary to verify the wash system equipment fur-nished. Follow the steps outlined in the appropriate section(s) below.

a. Off-line Compressor Wash Procedure

(1.) On the water wash skid, in the Annunciator/Control Panel, the following settings must beinitiated:

(a.) Water Temperature Setpoint switch to “Hot.”

(b.) Operation Selector switch to “Manual.”

Note: It will take approximately 9–15 hours for the water to heat up to theproper washing temperature.

(2.) Make certain the turbine is shut down.

(3.) Select the Water Wash control display on the turbine control panel CRT Select OFF-LINEWATER WASH ON.

At this time, the turbine is prohibited from firing.

(4.) If a unit is equipped with off–base atomizing air compressor, the compressor should be deen-ergized during the wash and rinse cycles.

(5.) Open inlet guide vanes, if applicable.

(6.) Close flame detector valves or blank–off. Water will foul the flame scanners and make start-ing difficult.

(7.) When regenerators are present, the gfas–side face must be covered and kept dry during com-pressor washing to prevent wetting regenerator deposits. THese deposits may change formwhen wet and bvecome extremely difficult to remove. Leave access doors open while crank-ing to provide an air exhaust path.

(8.) Fuel manifold drains are to remain closed during wash to prevent water from entering. Openduring dry cycle.

(9.) Place the Master Select Switch in the CRANK position.

(10.) Initiate a turbine START signal.


5

(11.) The turbine will accelerate to full continuous cranking speed. The cranking motor will main-tain the unit on crank for the cooldown cycle until the stop signal is given.

(12.) The cooldown procedure must be continued until the wheelspace temperatures are within120°F (48.9°C) of the wash water temperature.

Note: The turbine may be allowed to cool down on turning gear, if time per-mits.

(13.) During the crank cycle, manually place the following in the positions indicated and in theorder listed:

(a.) The flow through the false start drain valves (VA17) must be diverted from the sludgetank to a wash water effluent tank on turbines that operate on liquid fuel or have thecapability to.

Note: The false start drain flow or any flow that goes normally to the sludgetank must be diverted from its “normal” path into the sludge tank, intothe wash water effluent drain to prevent an overflow of the sludge tank.In addition, the false start drain effluent should be visible to evaluatethe effectiveness of the wash cycle. On gas-only machines, there will beno sludge tank; only a wash water effluent tank.

(b.) Arrange any valves in the exhaust plenum drain piping to divert effluent from thesludge tank to the waste water tank. Open the main wash water drain valve at the bottomof the exhaust plenum.

(c.) Open the inlet plenum drain valve.

(d.) Close valve installed in the AD-2 line supplying compressor discharge aire to the falsestart drain valves and open downstream drain.

(e.) Switch the motor controller for the turbine exhaust frame cooling fan motors, 88TK–1and 88TK–2 in the manual “ON” position (if provided).

Note: This step is necessary to prevent water wash from entering the exhaustframe cooling system during the wash cycle.

The atomizing air system is isolated in the following manner (if provided):

(f.) Close butterfly valve on inlet side of atomizing air system from AD–8 line.

(g.) Open all low point drains in the atomizing air lines.

(h.) Open the atomizing air separator drain valve (if provided).

(i.) Open vent line on inlet side of CA2, booster atomizing air compressor.

(j.) Open switch at the motor control center for 88AB; the drive motor for the booster atom-izing air compressor, CA2.

The cooling and sealing air circuitry is isolated in the following manner:


6

(k.) Close valve in the bearing sealing air supply line from extraction air.

(l.) Close AD–1, AD–2, AD–3, AD–4, and if provided, AD–6, AD–7 & AD–10.

(m.) Close valve in the bleed air lines from extraction air.

(n.) Open separator drain valve on bearing sealing air line, if provided.

(o.) Open needle valve upstream of WW9 connection for drainage during the wash cycle(low point drain on AD–3), if provided.

(p.) Open low point drain on bearing sealing air line, if provided.

(q.) If the turbine has a self-cleaning inlet filter, close the block valve and open the drainvalve on the self-cleaning inlet filter air line.

(14.) The water wash skid should now be checked for operational readiness. Determine if the fol-lowing conditions exist:

(a.) The water tank is full.

(b.) The detergent tank is full.

(c.) The water temperature is at the required level.

(d.) The valve on the main wash pump suction side is open.

(e.) The shutoff isolation valve in the water supply line to the skid is closed. This is doneto prevent unheated water from entering the water tank once a wash is initiated.

(15.) To minimize thermal shock to the hot gas path parts the operator must verify that all turbinewheelspace temperatures have cooled to within 120°F (48.9°C) [300°F (148.9°C) maxi-mum] of the wash water temperature. This is accomplished by monitoring the temperatureindicator on the turbine panel.

(16.) For the proper detergent/wash ratio, refer to the detergent manufacturer’s instructions or thecompressor cleaning information in the Maintenance volume of this service manual.

(17.) Open the water wash valve 20TW–1 at the compressor using the push button 20TW–1/PB.This push button is located near the 20TW–1 valve.

(18.) Allow the turbine to reach crank speed.

(19.) Initiate the appropriate devices on the water wash skid. The following devices can be manu-ally started by using the respective push buttons in the motor control panel:

(a.) Start the main wash pump (88TW–1)

(b.) Open detergent isolation valve (ball valve) on line between the venturi and detergenttank.


7

(c.) While monitoring the flow meter, adjust the flow metering valve (globe valve betweenventuri and flow meter) as necessary until the proper detergent/water mix ratio is ob-tained. Refer to detergent manufacturer’s recommendations.

(d.) Apply the solution at crank speed for three to five minutes, initiate the turbine stop sig-nal, continue spraying during coastdown until the solution is no longer drawn into thecompressor inlet.

(e.) Close water wash valve 20TW–1 using the push button station 20TW–1/PB.

(f.) Close detergent isolation valve. (This valve should be closed at all times, except whenbeing used to add detergent.)

(g.) Shut off the main wash pump.

(20.) Allow the turbine to soak for approximately 20 minutes.

(21.) After the soak time is complete initiate a turbine START signal.

(22.) Open the water wash valve, 20TW–1, using the push button station 20TW–1/PB at the tur-bine.

(23.) Allow the turbine to reach full continuous crank speed.

(24.) Start the water pump (88TW–1) on the skid. Rinse the compressor with clear water from theskid with the main wash pump. Rinse the compressor for 15–20 minutes.

Note: Experience will determine the proper time intervals for the variouswash operations or whether repetition of the above procedure is neces-sary to restore lost performance.

(25.) After rinsing is complete, initiate a turbine STOP signal and close water wash valve20TW–1 using push button station 20TW–1/PB.

(26.) Shut off the main wash pump and return all valves on the skid to their normal position(s).

(27.) Allow the gas turbine to drain and dry for about 20 minutes including coastdown time.

(28.) Open fuel manifold drains and open all low point drains in atomizing air system, fuel systemand purge system.

Note: The interconnecting piping is often the low point trap and this pipingmust be drained by removing drain plugs or parting pipe flanges. Thelow point can be in the interconnecting piping or the manifold itself de-pending on the piping design and location of the gas valves. Additional-ly, lower combustion can flexible hoses may trap water and may requireflange disassembly to remove water at these locations.

Following water wash and rinse cycles, the dry–out crank cycle shouldcontinue until no water is observed draining from any low point drain.


8

(29.) After the turbine has stopped and drying time is complete, initiate a turbine START signalwith the master operation selector switch in the CRANK position.

(30.) Allow the turbine to accelerate to crank speed.

(31.) Allow the turbine to dry for about 20 minutes at crank speed.

(32.) Initiate a turbine STOP signal.

(33.) If applicable, close inlet guide vanes.

(34.) If applicable, reenergize off-base atomizing air compressor and remove regenerator cover.

(35.) Close fuel manifold drains.

CAUTION

It is important that the line that allows waste fuel to drain to the sludge tank bekept open after water washing and during normal turbine startup and operation,so that fuel or water which may accumulate in the exhaust plenum can continu-ously drain out of the plenum. Accumulation of waste fuel in the exhaust ple-num is potentially hazardous.

(36.) Open the hand valves or remove blank-off plates on flame detectors.

(37.) Return the following manual valves to their previous position in the order listed:

(a.) Return the three-way false start drain valve, combustion system and turbine shellvalves from water drain to fuel drain (if installed).

(b.) Rearrange valves installed in the exhaust plenum drain piping to divert effluent fromthe wash water tank to the sludge tank (if applicable).

(c.) Close the inlet plenum drain valve (if provided).

Note: This is important to prevent intake of dirt etc., into the compressor.

(d.) Open valve installed in the AD-2 line supplying compressor discharge air to the falsestart drain valves.

(e.) Switch the motor controller for the turbine exhaust frame cooling fan motors 88TK-1and 88TK-2, into the “AUTO” mode (if provided).

The atomizing air system is reenergized in the following manner:

(f.) Open valve on inlet side of atomizing air system from AD-8 line.

CAUTION

It is critical that this valve be opened to prevent damage to the turbine.

(g.) Close all low point drains in the atomizing air lines.


9

(h.) Close the atomizing air separator drain valve (if provided).

(i.) Close vent line on inlet side of CA2, booster atomizing air compressor (if provided).

(j.) Close switch at the motor control center for 88AB; the drive motor for the booster atom-izing air compressor CA2.

The cooling and sealing air circuitry is reengaged in the following order:

(k.) Open valve in the bearing sealing air supply line AE-5 from extraction air (if provided).

CAUTION

It is critical that this valve be opened to prevent damage to the turbine.

(l.) Open valves in all compressor discharge pressure transducer supply lines (AD-4).

CAUTION

It is critical that this valve be completely opened to prevent damage to the tur-bine.

(m.) Open AD-1, AD-3, AD-6, AD-7 and AD-10 (if provided).

CAUTION

In configurations where AD-6 is used to supply the purge air system, it is criti-cal that this valve be opened to prevent damage to the turbine.

(n.) Open valves or remove blank-off plate in the bleed air lines (AE-##) from extractionair.

CAUTION

It is critical that these valves be opened to prevent damage to the turbine.

(o.) Close separator drain valve on bearing sealing air line (if provided).

(p.) Close needle valve upstream of WW9 connection (low - point drain on AD–3), if pro-vided)

(q.) Close low - point drain on bearing sealing air line, if provided.

Note: Allow the water to drain from the lines while the above restorations arebeing performed.

(r.) If the turbine has a self-cleaning inlet filter, open the block valve and close the drainvalve on the self-cleaning filter air line.

(38.) Press the Off–Line Water Wash OFF softswitch on the water wash control display.


10

Note: When the OFF–LINE WATER WASH OFF is selected, the permissiveis in place to allow the turbine to fire and the permissive is removed toallow the 20TW–1 valve to be opened.

(39.) Place the Master Operation Switch in the AUTO or REMOTE mode.

(40.) In the annunciator/control panel on the skid, set water temperature setpoint to “COLD” andthe Operation Selector switch to “AUTO.”

(41.) Initiate a turbine START signal within 24 hours after completion of the DRY cycle and allowit to accelerate to, and remain at, full speed for a minimum of five minutes.

(42.) The gas turbine is now available for commercial service and may be loaded.

Note: Check for air leakage from all drains.

b. On-Line Compressor Wash Procedure

(1.) General

The on-line compressor wash system allows an operator to water wash the turbine compres-sor without having to shut down the turbine. The method of washing is similar in many waysto the off-line system. Both systems use the same pump, 88TW–1, and piping to supply highquality wash solution to the compressor. When the supply pipe reaches the vicinity of theturbine base, it splits into two branches, one for the off-line system and one for the on-linesystem. Each branch contains a stop valve, flow control orifice, manifold(s) and spraynozzles.

There are significant differences, though, between the two systems. The on-line wash solu-tion requirements differ from that of off-line and must meet the requirements of both Table1 and Appendix 1 of GEK–103623 for on-line washing. The on-line system uses ambienttemperature water versus the 180°F (82.2°C) water used for the off-line system. And finally,the on-line system proceeds automatically after it is manually initiated; whereas, the off-linesystem is a totally manual process.

Note: When using a detergent solution for on-line washing, it is recom-mended that the wash be followed by enough rinse water to remove thedetergent residue from the wash nozzles at the spray manifold. This willprevent the detergent solutions from drying and clogging the nozzles.

(2.) Preparation

(a.) Turbine must be running at full speed and not in the process of shutting down.

(b.) Compressor inlet temperature must be greater than 50°F (10°C). Refer to TIL1153–3for information on cold weather on–line water wash

(c.) Set the inlet guide vanes to 81° or greater.

(d.) Reduce load by 5% if operating at base load.


11

(e.) Units operating with water or steam injection for NOx control or power augmentationmust reduce water or steam injection to 3% maximum of compressor inlet flow.

(3.) Operation

The on-line water wash is initiated from the turbine control panel. The operator selects theWATER WASH manual control display on the panel CRT and then presses the ON-LINEWATER WASH ON Softswitch. From that point on, the wash cycle is totally automatic. Thenormal sequence of events which occur are as follows:

(a.) Operator selects ON LINE WATER WASH ON.

(b.) Water pump, 88TW–1, turns on.

(c.) Solenoid valve 20TW–3 begins to open 3 seconds after the water pump turns on.

(d.) Flow switch 80WW–1 indicates that water has begun to flow and it starts the wash peri-od timer, L2WWP. The message COMP WATER WASHING is displayed on the nor-mal CRT display.

(e.) L2WWP times out typically after 30 minutes, and 20TW–3 begins to close.

(f.) 88TW–1 turns off 10 seconds after L2WWP times out.

The wash period time, L2WWP, is initially set for 30 minutes. The operator, though, shouldmeasure the effectiveness of the wash at various timer settings and adjust it accordingly.

At sites where there are multiple turbines, one water wash skid is shared by all the turbines.The controls are designed so that only one turbine compressor can be washed at a time. Ifa compressor is being washed, either on-or off-line, and a request is inadvertently made towash another compressor, the request will be blocked and the alarm WATER WASH SKIDIN USE will occur on the turbine control panel.

The operator must be aware of the position of the two selector switches on the ANNUNCIA-TOR/CONTROL PANEL which is located on the water wash skid. One switch is the WA-TER TEMP SETPOINT, 43WK–1, and the other is the OPERATION SELECTORSWITCH 43WK–2. These switches are used when performing an off-line wash and theyneed to be returned to their proper positions when the off-line wash is completed.

The WATER TEMP SETPOINT switch has two positions, HOT and COLD. In the COLDposition, the temperature setpoint for the water tank heaters, 23WK–1, –2, –3 is 65°F(18.3°C). This is the correct position for on-line washing. In the HOT position, the tempera-ture setpoint is 178°F (81°C). This is the correct position for off-line washing. When the op-erator decides to perform an off-line wash, he should select the HOT setpoint around thesame time he gives the turbine a shutdown command. This will give the water time to heatup while the turbine is shutting down and cooling down. When the off-line wash is com-pleted, he should select the COLD setpoint again.

The OPERATION SELECTOR SWITCH also has two positions, MANUAL and AUTO-MATIC. The operator should select MANUAL whenever he selects HOT on the WATERTEMP SETPOINT switch. When the switch is in the manual position, all turbines areblocked from performing an on-line wash. This is done to prevent inadvertently using up


12

the hot water for an on-line wash instead of the off-line wash it was intended for. When theoff-line wash is completed, the operator should select AUTOMATIC again. This is the cor-rect position for on-line washing.

(4.) Permissives

In order to perform an on-line compressor wash, certain permissives must be satisfied. Thesepermissives can be divided into two groups; turbine permissives and water wash skid per-missives.

There are two turbine permissives:

(a.) The turbine must be operating at full speed and not in the process of shutting down.

(b.) The compressor inlet air temperature must be greater than 50°F (10°C).

If either of these permissives are not satisfied when an on-line wash is requested, the alarmWATER WASH INHIBITED will occur on the turbine control panel.

The water wash skid permissives are:

1. Only one compressor can be washed at a time.

2. All alarms on the annunciator control panel must be reset.

3. The water temperature must be above 50°F (10°C).

4. The water in the tank must be above a minimum level.

5. After the water pump, 88TW–1, is turned on, the pump inlet and discharge pressuresmust be satisfactory.

6. The flow switch relay, 83WW, must indicate water flow exists.

The logic elements for all of the skid permissives are contained in the ANNUNCIATOR/CONTROL PANEL which is located on the skid. If one or more of the skid permissives arenot satisfied, the appropriate alarm will occur on the ANNUNCIATOR/CONTROL PANELand also the alarm WATER WASH SKID TROUBLE: TRIP will occur on the turbine controlpanel. If the latter alarm occurs, the operator must go to the water wash skid, investigate andcorrect the problem, and then reset all alarms on the ANNUNCIATOR/CONTROL PANEL.Then he can attempt to initiate the wash again from the turbine control panel.

GEK 110220aRevised May 2002


Gas Turbine Compressor Water Wash System

These instructions do not purport to cover all details or variations in equipment nor to provide forevery possible contingency to be met in connection with installation, operation or maintenance. Shouldfurther information be desired or should particular problems arise which are not covered sufficiently forthe purchaser's purposes the matter should be referred to the GE Company.

© 2002 GENERAL ELECTRIC COMPANY

GEK 110220a Gas Turbine Compressor Water Wash System

I. GENERAL

Gas turbines can experience a loss of performance during operation as result of deposits of contaminantson internal components. This loss is indicated by a decrease in power output and an increase in heat rate.The deposits of atmospheric contaminants on compressor parts occurs with the ingestion of air.

The ingested air may contain dirt, dust, insects, and hydrocarbon fumes. A large portion of these can beremoved before they get to the compressor by inlet air filtration. The dry contaminants that pass through thefilters as well as wet contaminants, such as hydrocarbon fumes, have to be removed from the compressorby washing with a water-detergent solution followed by a water rinse.

A. On-Base Supplied Equipment

The on-base turbine equipment supplied with this compressor wash system consists of piping fromthe purchaser's connection on the base, air operated water injection valve(s), and the appropriate spraymanifold(s). Drains from the inlet plenum, combustion area, exhaust frame, and the exhaust plenumare also provided. In addition, there are purchaser connections in these drain lines. The schematic forthis on-base water wash equipment is located in the Reference Drawing sections of this manual.

B. Off-Base Equipment

The off-base portion of the water wash system, known as the water wash skid, contains both a watertank and a detergent tank. The water tank is equipped with temperature sensors and electric heatersto maintain proper water temperatures. The skid is equipped with a centrifugal water pump motor(88TW-1) and a venturi used with the water pump to mix detergent solution. Also included on the skidare the various control panels to initiate wash and to manually start/stop the appropriate devices. Allequipment is made of corrosion resistant material. The schematic for the water wash skid is includedin the Reference Drawings section of this manual.

All devices are set to give proper temperature, pressure, and flow. The settings for these devices canbe found in the device summary for the corresponding system.

C. Functional Description

During the washing operation, water or wash solution is delivered through customer piping to the gasturbine in the proper mix ratio. The wash water solution is delivered to the turbine unit at the properpressure, temperature, and flow rate to wash the gas turbine compressor. Refer to the system schematicin the Reference Drawing section for proper pressure(s), temperature(s), and flow rate(s) for this gasturbine.

1. System Requirements

Water used for washing turbine parts should be reasonably clean so that it does not cause foulingor corrosion in itself. Distilled or deionized water is recommended. Water quality requirementsare listed in Table 1 of GEK-107122 (Latest Revision). Oily or varnished oil deposits on internalgas turbine parts require that a detergent solution be used during the washing operation. Thedetergent shall meet the requirements of GEK-107122 (Latest Revision), Appendix 1.

2

Gas Turbine Compressor Water Wash System GEK 110220a

2. Compressor Washing Frequency

The frequency of compressor washing depends upon the severity and type of atmospheric con-tamination that fouls the compressor and reduces performance. The recommended method forestablishing the frequency is to monitor gas turbine performance, comparing the routine perfor-mance with the baseline performance to observe the performance trends.

If the performance has fallen significantly, and compressor fouling is suspected, it must be verifiedby visual inspection. This visual inspection should include the compressor inlet, bellmouth, inletguide vanes and the first and, possibly, the second stage of the compressor blades.

NOTE

Inspection should be made for the source of the oily deposits. If possible, correc-tive action should be taken.

D. Washing System Operation

1. General

a. Off-line Water Wash

Off-line water washing should be scheduled during a normal shutdown, if possible. This willallow enough time for the internal machine temperature to drop to the required levels for thewashing. The time required to cool the machine can be shortened by maintaining the unit atcrank speed. During this cooling of the turbine, the wash water may be heated to the properlevel.

Refer to GEK-107122 (Latest Revision) for gas turbine compressor liquid washing recom-mendations

b. On-line Water Wash

The period between off-line water washes can be extended via frequent on-line washing.When the compressor is suspected of being heavily fouled, an off-line wash should be per-formed.

The on-line compressor wash system allows an operator to water wash the turbine compres-sor without having to shut down the turbine. The method of washing is similar in many waysto the off-line system. Both systems use the same pump, 88TW-1, and piping to supply highquality wash solution to the compressor. When the supply pipe reaches the vicinity of theturbine base, it splits into two branches, one for the off-line system and one for the on-linesystem. Each branch contains a stop valve, flow control orifice, manifold(s) and spray noz-zles.

There are significant differences, though, between the two systems. GE recommends againstthe use of detergents during on-line washing, while the use of detergents during off-line wash-ing are encouraged. The on-line wash water requirements differ from that of off-line washsolution and must meet the requirements of Table 1 of GEK-107122 (Latest Revision) foron-line washing. Finally, the on-line system proceeds automatically after it is manually initi-ated; whereas, the off-line system requires operator intervention before and after the wash.

3


NOTE

When using a detergent solution for on-line washing, it is recommended that thewash be followed by enough rinse water to remove the detergent residue from thewash nozzles at the spray manifold. This will prevent the detergent solutions fromdrying and clogging the nozzles.

2. Mandatory Precautions

Before water washing of the compressor begins, the turbine blading temperature must be lowenough so that the water does not cause thermal shock.

CAUTION

The differential temperature between the wash water and the interstage wheelspacetemperature must not be greater than 120�F (67�C) to prevent thermal shock to thehot gas parts. The maximum wheelspace temperature as per TIL 1196–1 must beno greater than 150�F (65.5�C) as measured by the digital thermocouple readoutsystem on the turbine control panel.

To reduce this difference, the wash water may be heated and the turbine kept on crank until thewheelspace temperatures drop to an acceptable level. The wheelspace temperatures are read inthe control room.

CAUTION

If, during operation, there has been an increase in exhaust temperature spreadabove the normal 15�F to 30�F (8.3�C to 16.6�C), the thermocouples in the ex-haust plenum should be examined. If they are coated with ash, the ash should beremoved.

Radiation shields should also be checked. If they are not radially oriented relative to the turbine,they should be repositioned per the appropriate drawing. If the thermocouples are coated withash, or if the radiation shields are not properly oriented, a correct temperature reading will not beobtained.

If neither of the above conditions exists and there is no other explanation for the temperaturespread, consult the General Electric Service Engineering representative.

***WARNING***

THE WATER WASH OPERATION INVOLVES WATER UNDERHIGH-PRESSURE. CAUTION MUST BE EXERCISED TO EN-SURE THE PROPER POSITIONING OF ALL VALVES DURINGTHIS OPERATION. SINCE THE WATER MAY ALSO BE HOT,NECESSARY PRECAUTIONS SHOULD BE TAKEN IN HAN-DLING VALVES, PIPES, AND POTENTIALLY HOT SURFACES.

4

Gas Turbine Compressor Water Wash System GEK 110220a

NOTE

Before water washing the compressor, inspect the inlet plenum and gas turbinebellmouth for large accumulations of atmospheric contaminants that could bewashed into the compressor. The deposits can be removed by washing with agarden hose.

5


GE Power Systems

General Electric CompanyOne River Road, Schenectady, NY 12345518 • 385 • 2211 TX: 145354

6


Revised January 1997GEK 28166A


Field Performance Testing Procedure

GEK 28166A Field Performance Testing Procedure

2

TABLE OF CONTENTS

I. GENERAL 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

II. PURPOSE OF TEST 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

III. TEST PROCEDURE 3. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A. Fuel Consumption 4. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

IV. EVALUATION 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

V. CONCLUSION 6. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

GAS TURBINE PERFORMANCE DATA 7–11. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FIGUREFigure 1. Gas Flow Measurement Instrumentation 5. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Field Performance Testing Procedure GEK 28166A

3

I. GENERAL

This instruction specifies the methods and equipment to be used during field performance tests of heavy-dutygas turbines using station instrumentation. It applies only to turbine generator power plants.

II. PURPOSE OF TEST

The primary purpose of the test shall be the measurement of turbine or generator output and fuel heat con-sumption at one or more load conditions.

Sufficient supporting data shall be recorded to enable the “as tested” performance to be corrected to the stan-dard conditions so that an accurate comparison may be made between tested and base line machine capabilityand heat rate at specified conditions.

The attached data sheets should be used to record the test data. They are designed to provide the informationrequired to evaluate the aero-thermodynamic performance of the gas turbine only. Any other operating datashould be taken separately to prevent interference with the timing required for the performance test.

III. TEST PROCEDURE

These testing procedures are patterned after those specified and described by the American Society of Me-chanical Engineers Power Test Code PTC-22-1966, “Gas Turbine Power Plants,” with the following addi-tions and/or exceptions. Figures in parentheses refer to the relevant paragraph in the code. Past experiencehas shown that a gas turbine operator and four (4) test assistants are required for testing. One day of setuptime and one day of testing are usually needed per machine.

A test point will consist of four sets of instrument readings taken at 10-minute intervals over a 30-minutetime span after steady-state conditions have been established (3.12).

The machine will be considered to be in a steady-state condition when turbine wheelspace temperatures donot change more than 5°F (2.77°C) in 15 minutes prior to the test point.

Past experience has shown that test points for gas turbines that cover longer than a half-hour time span areapt to experience changes in inlet air temperatures, which change the operating characteristics of the powerplant and make the test less accurate.

Speed measurements may not be required when a single-shaft generator drive unit is connected into a largepower system. When the power system is small or frequency variations of more than 0.5% occur, then turbinespeed (or frequency) must be measured by an electronic tachometer or equivalent.

Average generator output must be measured by a polyphase watt-hour meter (4.24).

Load is to be calculated by carefully timing, with stopwatch or equivalent, a fixed number of disc revolutionsthroughout the test point, averaging those times and calculating the resulting average power output by apply-ing the appropriate factor (pri. Kh) stamped on the face of the meter.

Power Ouput� n revolutionsSec. for n rev.

� Pri Kh � (3, 600/1, 000)

where;


4

Pri Kh � PTR� CTR� meter K

PTR� Potential Instrument Transformer Ratio

CTR� Current Instrument Transformer Ratio

Ideally, the total number of disc revolutions should be counted for the entire test point. This is, however, atedious task and seldom worthwhile. Instead, a count of 20 revolutions should be made continuouslythroughout the point with the only interruption being the recording of the elapsed time for each group ofrevolutions.

Gas turbine exhaust temperature will be measured by the unit control thermocouples mounted in the exhaustplenum (4.56).

It is essential that the temperature-indicating system be adjusted and calibrated in place with a known milli-volt source prior to the test so that it reports reliable data. If more than 25% of the control thermocouplesare inoperative, the performance test should not be conducted.

When liquid-in-glass manometers are used, bores of smaller than 5/16 inch (0.079 cm) will be permitted(4.59).

Barometric pressure at the gas turbine site shall be measured with a mercury or aneroid barometer. A mini-mum reading accuracy of 0.01 inch (0.03 cm) Hg is required (4.65).

As stated in paragraph 5.33 of the code, inlet air relative humidity has negligible effects on power output andheat consumption. It will therefore be ignored for performance evaluation.

A. Fuel Consumption

For units designed to burn more than one type of fuel, liquid fuel generally yields higher test accuracyand repeatability and should therefore be preferred. If there is a choice of liquid fuels, lighter fuels yieldmore accurate test results.

1. Liquid Fuel

Liquid fuel flow is to be measured by a positive displacement meter which has been calibrated. Thetotal fuel consumed during the exact 30-minute test as measured with a stopwatch must be recorded.The fuel temperature at the meter must also be measured.

A sample of the fuel consumed during the test must be taken for laboratory measurement of higherheating value (HHV) and specific gravity. The lower heating value (LHV) will be determined bythe method specified in paragraph 4.45 of PTC 22-1966.

If the fuel is drawn from a large storage tank, a single sample will suffice for several test points;however, if variations in fuel characteristics are suspected, a fuel sample should be taken for eachtest point. Fuel samples of one pint are sufficient for HHV and specific gravity measurement.


5

The heat consumption will be calculated using

Heat Consumption (Btu/hr)� gal/min� 8.33 lb/gal (H2O)� Specific Gravity (Oil) at metering temp.� Heating Value * Btu/lb� 60 min/hr.

2. Gas Fuel

Gas fuel is to be measured with a flat-plate orifice installed in accordance with ASME or AGA stan-dards. See Figure 1. The upstream pressure will be measured with a precision test gauge, the pres-sure drop with a manometer, the gas temperature with a thermometer or thermocouple.

A gas sample must be taken from the fuel system during the test for laboratory measurement of high-er heating value and specific gravity. A ratio (HHV/LHV) of 1.11 will be used to calculate the lowerheating value.

Calculation of gas flow will be done in accordance with ASME or AGA standards as described inASME PTC 19.5; 4-1959 or AGA Report #3.

Inlet air temperature will be measured with at least two thermometers or thermocouples installedin the inlet plenum near the gas turbine compressor inlet. The compressor inlet air temperature mustbe measured with an accuracy of ±1.0°F (.5°C) (4.55).

Figure 1. Gas Flow Measurement Instrumentation.

Gas

Flow

D. Pipe inside diameter

d. Orifice diameter

Pressure connections shownas flange taps. List taplocation on front of sheet.Give dimensions if notflange taps.

Indicate manometer typeand fluid used for ∆ Pmeasurement; mercury,water, or mercury with scalein water.

5 to 10 D

Thermometer well

D d

∆ P

*Use HHV or LHV as specified by rating.


6

If waste heat recovery equipment is used, turbine exhaust static pressure at or near the gas turbineflange must be measured using at least four-disc type static pressure probes.

When the tests are performed at “Base” and “Peak” mode, the gas turbine control system must beadjusted to operate at the correct average gas turbine exhaust temperature for the test conditions,as defined by the appropriate control curve.

IV. EVALUATION

Test results are based on the averaged data taken during the test. The averaged results are corrected tothe standard conditions using the appropriate correction curves for the installation. Performance as indi-cated by determining the heat rate based on the test results is defined by:

Heat Rate�Heat Consumption

Power Output

When decisions are required based on test results, one should recognize the tolerance due to measure-ment uncertainties associated with each particular test result.

The tolerances around the test results are defined as twice the estimated standard deviation (2 Σ), com-puted from the tolerances associated with each measured test parameter and the influence of that parame-ter on the calculation of the corrected test results.

The resulting performance tolerances of a single unit station instrumentation test, when performed asdescribed in this document are

Power output: ± 3.01%

Heat rate (oil fuel): ± 2.09%

Heat rate (gas fuel): ± 2.32%

V. CONCLUSION

This procedure may be used to periodically measure unit performance in order to establish trends andto determine the effectiveness of compressor cleaning. This data should be retained for historical refer-ence.


7

GAS TURBINE PERFORMANCE DATA

CUSTOMER___________________________________________________

STATION______________________________________________________

Unit ID Date

Gas Turbine S/N Operating Mode

Generator S/N Data Page

Fired Hours Test Number

Fired Starts

Reading Number 1 2 3 4

Starting Time of Reading ______ ______ ______ ______

Ambient Condition

Compressor Inlet Temp. °F ______ ______ ______ ______

______ ______ ______ ______

______ ______ ______ ______

______ ______ ______ ______

______ ______ ______ ______

______ ______ ______ ______

Barometric PressureInches of Mercury ______ ______ ______ ______

Compressor DischargePressure PSIGUnit Gauge ______ ______ ______ ______

Precision Gauge ______ ______ ______ ______

Fuel Measurement - Oil*

Fuel Meter Reading - Gal. ______ ______ ______ ______

Elapsed Time - Min. ______ ______ ______ ______

Fuel Temperature °F ______ ______ ______ ______

Fuel Meter Type & S/N______________________________________

Lube Oil

Turbine Header Temp. °F. ______ ______ ______ ______

Lube Oil Tank Temp. °F ______ ______ ______ ______

Recorded By ______________________________________

*For Gas Fuel use data under Fuel Consumption

WhenApplicable


8


CUSTOMER___________________________________________________

STATION______________________________________________________

Unit ID Date

Gas Turbine S/N Operating ModeGenerator S/N Data Page

Test Number



Wheelspace Temperatures °FComp. Disch. Left ______ ______ ______ ______Comp. Disch. Right ______ ______ ______ ______

1st Stage Forward ______ ______ ______ ______

1st Stage Forward ______ ______ ______ ______

1st Stage Aft ______ ______ ______ ______1st Stage Aft ______ ______ ______ ______

2nd Stage Forward ______ ______ ______ ______

2nd Stage Forward ______ ______ ______ ______

2nd Stage Aft ______ ______ ______ ______

2nd Stage Aft ______ ______ ______ ______3rd Stage Aft ______ ______ ______ ______

3rd Stage Aft ______ ______ ______ ______

3rd Stage Forward ______ ______ ______ ______

3rd Stage Forward ______ ______ ______ ______

Exhaust Temperatures - Control T/C °F1. ______ ______ ______ ______2. ______ ______ ______ ______3. ______ ______ ______ ______4. ______ ______ ______ ______5. ______ ______ ______ ______6. ______ ______ ______ ______7. ______ ______ ______ ______8. ______ ______ ______ ______9. ______ ______ ______ ______10. ______ ______ ______ ______11. ______ ______ ______ ______12. ______ ______ ______ ______

Exhaust Average Electrical ______ ______ ______ ______

Calculated ______ ______ ______ ______

Recorded By ______________________________________


9


CUSTOMER___________________________________________________

STATION______________________________________________________

Unit ID Date



Test Number



Turbine Panel Board

Set Point ______ ______ ______ ______

VCE ______ ______ ______ ______

Generator Panel Board

Megawatts ______ ______ ______ ______

Record WHM Time on Pg. 10WHM (sec/20 rev) ______ ______ ______ ______

Megavars ______ ______ ______ ______

Generator Voltage, KV

Phase 1-2 ______ ______ ______ ______

Phase 2-3 ______ ______ ______ ______

Phase 3-1 ______ ______ ______ ______

Generator Amperes, KA

Phase 1 ______ ______ ______ ______

Phase 2 ______ ______ ______ ______

Phase 3 ______ ______ ______ ______

Excitation Voltage ______ ______ ______ ______

Excitation Amperes ______ ______ ______ ______

Frequency, Hertz ______ ______ ______ ______

Recorded By ______________________________________


10


CUSTOMER___________________________________________________

STATION______________________________________________________

Unit ID Date



Test Number

Power Measurement (Cont’d)

WHM (Sec/20 Revs.) Begin Test

End Test

Repeatedly Time 20 Revolutions of Watt Hour Meter Disc

During Entire Test Period Pri Kh Factor

1) ______ 2) _______ 3) _______ 4) _______

5) _______ 6) _______ 7) _______ 8) _______

Auxiliary WHM (Sec/Rev.)

1) _______ 2) _______ 3) _______ 4) _______

Pri Kh Factor

Comment/Calculations

Recorded By ______________________________________


11


CUSTOMER___________________________________________________

STATION______________________________________________________

Unit ID Date


Generator S/N Test Number

Data Page

Fuel Gas Flow (Record data every two minutes)

Time Pressure ∆ P Temp

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

__________ __________ __________ __________

Pipe Size Pressure Tap Location

Orifice Size Pressure Measured Upstream or

Downstream of Orifice

Fuel Heating Value

Specific Gravity

*See Figure 1, Gas Flow Measurement Instrumentation

Recorded By ______________________________________


GE Power Systems

Iss. Date 11/77Reformat 1/93


April 1998Replaces VARIGV00

GEK106910


Variable Inlet Guide Vane System

I. GENERAL

Variable compressor inlet guide vanes (VIGV) are installed on the turbine to provide compressor pulsationprotection during startup and shutdown and also to be used during operation under partial load conditions.The variable inlet guide vane actuator is a hydraulically actuated assembly having a closed feedback controlloop to control the guide vanes angle. The vanes are automatically positioned within their operating rangein response either to the control system exhaust temperature limits for normal loaded operation, or to thecontrol system pulsation protection limits during the start-up and shutdown sequences. On DLN units, theIGV angle is modulated to control air flow to the combustors for DLN operation modes.

II. GUIDE VANE ACTUATION

The modulated inlet guide vane actuating system includes the following components: servo valve 90TV,position sensors (LVDT) 96TV-1 and 96TV-2, and hydraulic dump valve VH3. These are shown on the tripoil and IGV schematic diagrams in Volume III. When the inlet guide vane dump solenoid valve 20TV in thetrip oil circuit is energized, its drain ports are blocked thus allowing the trip oil to operate the dump valveVH3. Actuation of the dump valve allows hydraulic oil to flow through servo valve 90TV. Control of 90TVwill port hydraulic oil through the dump valve to operate the variable inlet guide vane actuator.

For normal shutdown, inlet guide vane actuation is the reverse of the startup sequence; the compressor bleedvalves will open when the generator breaker is opened. The inlet guide vanes will ramp to the full closedposition as a function of temperature corrected speed.

In the event of a turbine trip, the compressor bleed valves will open and the inlet guide vanes will ramp tothe closed position as a function of temperature corrected speed.

III. PULSATION PROTECTION CONTROL

The inlet guide vanes are automatically positioned during a start-up and a shutdown sequence to avoid gasturbine compressor pulsation. The pulsation limit is expressed as a function of IGV angle and correctedspeed, shown by the broken line on Figure 1. Corrected speed is a compressor design parameter that is a func-tion of the actual running speed of the compressor and the inlet air temperature. The control system utilizesthe measured variables of turbine speed and ambient temperature to determine the IGV angle and automati-cally modulate them to that position.

GEK106910 Variable Inlet Guide Vane System

2

Corrected Speed %(TNHCOR)

1000 Load

%100

Full Open (Max. Angle)

Minimum Full Speed Angle

RotatingStall

Region

IGV

Ang

le D

egre

es (

CS

RV

PS

)

Figure 1. IGV Angle vs Corrected Speed and Load.

Variable Inlet Guide Vane System GEK106910

3

IV. EXHAUST TEMPERATURE CONTROL

For applications such as a regenerative cycle or where there is a steam generator (boiler) in the gas turbineexhaust, it is desirable to maximize the exhaust temperature. The control program for such turbines includesan exhaust temperature control which automatically holds the IGV at a minimum angle during part-load op-erations. A switch is provided to permit the operator to select this mode of operation.

V. OPERATION

During a normal start-up, the inlet guide vanes are held in the full-closed position (see the Control Specifica-tions in this service manual for settings) until the proper temperature-corrected speed is reached. At this time,the guide vanes will begin to open. A graphic representation of this action is shown in Figure 1. The compres-sor bleed valves, which must operate in conjunction with the VIGVs to maintain compressor surge marginduring startup, will close when the generator breaker is closed.

When the VIGV temperature control mode is not activated, the guide vanes are held at the minimum full-speed angle until the simple cycle VIGV exhaust temperature is reached. This temperature is the constantCSKGVSSR. As the exhaust temperature rises, a value computed as the product of constant CSKGVTPGtimes the difference between the actual exhaust temperature TTXM and CSKGVSSR is added to the mini-mum angle, causing the VIGVs to open until they reach the maximum angle. This sets a minimum load whichthe unit must reach before the VIGVs are allowed to open. This is necessary to avoid combustion resonanceand must not be changed.

For applications which require part load exhaust temperature control operation, the guide vanes are switchedto the “IGV temp control On” with a soft switch. In this mode the VIGVs remain at the minimum full operat-ing position until the base exhaust temperature limit is reached. At this point, they begin to open to hold theexhaust temperature at this limit until they are full open when the exhaust temoerature control reverts to fuelmodulation. In order to keep the fuel control and IGV control from trying to act simultaneously, a fuel controlbias is added to keep the fuel line slightly above the VIGV line. This bias is the product of constantCSKGVBG times the difference between the maximum VIGV angle (constant CSKGVMAX) and the VIGVreference CSRGV. This bias becomes zero when the VIGVs are fully open and the fuel temperature controltakes over.

The operator can activate or deactivate the VIGV temperature control mode at any time via the panel softswitches. The control system will automatically reprogram the VIGVs to the correct position at a controlledrate. Manual open/close soft switches are provided to allow the operator to manually position the VIGVsbetween the minimum full speed angle and full Open. This control should only be used in special circum-stances to limit the travel (amount opened). The manual control is limited to command an angle only whenless than that being called for by the automatic control system. In normal operation, the manual control isset at full open. For applications requiring steam turbine warmup, the operator can select a desired exhausttemperature and the IGV’s will modulate to achieve the setpoint. Refer to the control sequence program fora detailed representation of the VIGV software.

VI. FAULT PROTECTION

The guide vane protection system will trip solenoid valve 20TV, initiate a fast normal shutdown and annunci-ate if there is low hydraulic supply pressure, or the LVDT feedback is different from command, or IGV posi-tion trouble is indicated. Should the inlet guide vane system be tripped under and one of the above conditions,the SPEEDTRONIC sequencing logic generates a signal which is used in the start check circuit to preventany attempt to restart the turbine prior to eliminating the cause for the trip.


GE Power Systems

GEK 106910 Variable Inlet Guide Vane System

The primary IGV fault signal is generated by the “IGV not following CSRGV” algorithm, L86GVT. Thisalgorithm compares the difference between the VIGV position feedback CSGV and the reference signalCSRGV to generate alarm signal, L86GVA if the IGV is not following the reference within the value ofLK86GVA1 given in the Control Specifications Settings. The alarm signal is annunciated if the differencepersists for time LK86GVA2 specified in the Control Specifications Settings. During part speed operation,a trip signal L86GVT is generated if the VIGV position feedback CSGV does not agree with the speed refer-ence CSRGV within the value of LK86GVT1 and for a time of LK86GVT2 given in the Control Specifica-tions Settings. Trip signal L86GVT will deenergize 20TV, trip the turbine and annunciate an alarm. Duringfull-speed operation, trip logic L4GVTX will alarm and trip the turbine if the VIGV feedback CSGV fallsbelow a minimum allowable full-speed value LK4IGVTX.


August 1996VH5166


Ventilation and Heating System

I. GENERAL

A pressurized ventilation system is incorporated into the accessory, turbine, load and load gear, and gas valvecompartments (enclosures) to dissipate heat from these areas and prevent sand and dust from entering them.Heaters are also installed in the accessory and turbine compartments for humidity control. Pressurized air,provided by duct–mounted motor driven fans, is fed to each compartment through an overhead duct that ex-tends from the inlet filter compartment with separate entrance ducting extending to each of the enclosures.The system and its ducting arrangement are shown in the schematic diagram following this article.

Gravity–operated inlet dampers and CO2 latched outlet dampers (for the accessory, turbine, and loadcompartments) are used in the system to automatically provide a tight enclosure when the fire protection sys-tem is activated. The gravity–closing outlet dampers are normally held open by fire extinguishing agentpressure–operated latches which must be manually reset after damper release. When the agent is discharged,pressure on the latch forces a piston against a spring, moving a locking lever which releases the latch allowingthe damper to close.

II. FUNCTIONAL DESCRIPTION

A. Pressurizing Duct and Fans

The compartments use thermally insulated panels and roofs and are both pressurized and cooled withinlet air circulated by the motor driven pressurizing fans. Two centrifugal fans driven by AC motors88PF–1 and 88PF–2 are installed in the ventilation ducting next to the inlet filter compartment. One fanis selected as the “lead” fan. The second is sequenced as the “standby” fan. If the selected lead fan failsto operate as sensed by pressure differential switches 63AT–1 and 63AT–2, the standby fan will start.The switches are provided with the pressurizing fans. Fan operation is controlled by temperatureswitch 26BT–2 mounted in the turbine compartment. The selected lead fan is running duringturbine operation and during turbine shutdown when residual temperatures in the compartmentexceed the setting of 26BT–2. The pressurizing fans take filtered air from the inlet filtercompartment to pressurize and ventilate each of the gas turbine unit compartments. A gravityactuated damper is placed in the ducting immediately downstream of the inlet filter housing.

For humidity control during periods of shutdown, the pressurizing fan motors are equipped with heaters23PF–1 and 23PF–2.

Gas Turbine System Description

2

B. Accessory Compartment

Pressurized cooling air is piped from the main overhead ducting and brought into an inlet opening in theforward section of the compartment roof. Air entering the accessory compartment passes through agravity–actuated damper, which closes when the pressurizing fan is not operating. The pressurized airflows through the compartment collecting heat and is vented to atmosphere at an exit duct opening inthe aft section of the roof. When the cooling air is discharged from the compartment, it passes througha normally–open CO2–actuated damper located at the exit vent opening.

Heater 23HA–3 provides heating for humidity control during periods when the turbine is not operating.The heater is energized when the temperature in the accessory compartment drops below the setting of26HA–3.

C. Turbine Compartment

The flow of pressurized cooling air enters the turbine compartment in the same manner as the accessorycompartment. A fire protection system involving gravity–actuated dampers and CO2–actuated damperssimilar to that in the accessory compartment is also provided.

Thermostat 26BT–1 activates an alarm should the turbine compartment temperature exceed the switchsetting. Proper attention should be given to this condition.

Heater 23HT–3 provides heating for humidity control during periods when the turbine is not operating.The heater is energized when the temperature in the turbine compartment drops below the setting of26HT–3.

D. Load and Load Coupling Compartment

The load and load coupling is contained in its own enclosure and is located between the exhaust plenumand the generator. This separate compartment has its own roof section, side panels, and access door.Pressurized ventilating air is blown down through a duct in the roof into the aft end of the compartment.As in the accessory and turbine compartments, the pressurized cooling air enters the load compartmentthrough a gravity actuated damper, circulates through the compartment, and exits through a CO2 actu-ated damper.

Thermostat 26VG–1 activates an alarm should the load compartment temperature exceed the switch set-ting. Proper attention should be given to this condition.

E. Gas Valve Compartment

The gas valve compartment is similarly ventilated with pressurized ventilating air. As with the compart-ments described above, the pressurized cooling air enters the gas valve compartment through a gravityactuated damper and picks up heat as it circulates through the compartment. However, since there is nofire protection system for the gas valve compartment, the cooling air exits through a gravity actuateddamper.

F. Generator Compartment

Refer to material after the tab entitled Generator support Systems for information concerning the turbinegenerator cooling system.


October 1996FP5166


Fire Protection System

I. GENERAL INFORMATION

The carbon dioxide fire protection system used for the gas turbine unit extinguishes fires by reducing theoxygen content of the air in the compartment from an atmospheric normal of 21% to below the level neces-sary to support combustion (normally 15%). To reduce the oxygen content, a quantity of carbon dioxide(C02) equal to or greater than 34% of the compartment volume is discharged into the compartment in oneminute and, recognizing the reflash potential of combustibles exposed to high temperature metal, an ex-tended discharge is provided to maintain an extinguishing concentration for a prolonged period to minimizepotential reflash conditions.

The fire protection system design conforms to the requirements specified in NFPA Pamphlet 12– Standardon Carbon Dioxide Extinguishing Systems.

II. FUNCTIONAL DESCRIPTION AND SYSTEM OPERATION

To gain a better understanding of the fire protection system, a brief description of its operation and distinctivefeatures is provided in the following paragraphs. Refer to the fire protection system schematic diagram (MLI0426) following this article.

The fire protection system is comprised of a distribution system of piping for the delivery of C02 from a lowpressure storage tank to the required gas turbine compartments in the event of a fire. This low pressure stor-age tank is usually located on an off–base skid and maintains saturated liquid carbon dioxide at a storagepressure of 300 psig (2069 kPa) at 0 F (–18 C) by means of a refrigeration compressor. The fire protectionsystem control panel is usually mounted on the off–base skid (or in the turbine control room if requested).The interconnecting field piping, which is usually supplied by the installer, delivers the C02 from the off–base skid to the gas turbine compartments, where it connects to the on–base piping that distributes the C02into the compartments through nozzle orifices.

Two separate distribution systems are used: an initial discharge and an extended discharge. Within a fewseconds after actuation, sufficient C02 flows from the initial discharge system into the gas turbine compart-ments to rapidly build up an extinguishing concentration (normally 34%). A C02 concentration (usually30%) is then maintained by the gradual addition of more C02 from the extended discharge system compensat-ing for compartment leakage. Carbon dioxide flow rate is controlled by the size of the orifices in the dis-charge nozzles in each compartment for both the initial and extended discharge systems. The orifices forthe initial discharge system permit a rapid discharge of C02 to quickly build up an extinguishing concentra-tion. Orifices for the extended discharge system are smaller and permit a relatively slow discharge rate to

Gas Turbine System Description

2

maintain an extinguishing concentration over a prolonged period of time (based on the turbine frame size’semergency roll down and cool down periods) to minimize the likelihood of a fire reigniting.

Each gas turbine unit has one zone of fire protection, with the zone consisting of an initial and an extendeddischarge. This single zone fire protection system will discharge C02 into all compartments of the turbinebeing protected, regardless of which compartment the fire was detected. This zone protection/detection isachieved by using separate A and B loops of heat–sensitive fire detectors. Each fire detector is wired intothe fire protection control panel in such a way that both an A and B detector in that particular zone must betripped in order for C02 to be discharged. Strobes and horns, as well as C02 warning signs, are strategicallypositioned on the outside and/or inside of the appropriate compartments to warn personnel of C02 discharge.

Should a fire occur in one of the protected gas turbine compartments, the contacts of the heat–sensitive firedetectors will close and complete an electrical circuit that energizes and opens solenoid valves 45CR–1Aand –2A (zone 1 initial and extended discharge), which are located in the Pilot Control Cabinet. Actuationof the solenoid valves allows C02 from the storage tank to pressurize the pistons of that particular zonesinitial and extended discharge pilot operated selector valves located on the C02 discharge manifold. Carbondioxide then flows from the storage tank through the initial and extended discharge selector valves into thepiping distribution system and into the compartments of the particular zone.

The system may also be manually actuated by means of the manual toggle switches (43CP–1A for zone 1)located on the outside of the Electrical Control Cabinet or by the manual pilot valves located in the Pilot Con-trol Cabinet. If customer requested, there may also be manual release switches mounted on the enclosureexternal walls of the protected zone. These devices, which will normally have 43CP nomenclature (refer tothe system schematic), are equipped with a pin which must be pulled before the push button can be depressedto activate the system and discharge the C02. Actuation of the system, either automatically or manually, willtrip the turbine to shut off, shut down the ventilation system, and cause the discharge of C02.

For the purposes of maintenance on the fire protection system or the gas turbine itself, the accidental dis-charge of C02 can be prevented by either closing the main shut off valve located on top of the storage tankor by closing the ball valve/limit switch (33CL–1A) located in the Pilot Control Cabinet. If customer re-quested, there may also be manual lockout switches (which will normally have 43CL nomenclature)mounted on the enclosure external walls of the protected zone for remote lockout of C02 discharge.

Initial and extended discharge timers, 2CP–1A and –2A (zone 1), are located on the control panel in the Elec-trical Control Cabinet and control the length of time the solenoid valves are energized and thus the C02 dis-charge time (these times are factory set– refer to MLI A068 for the specific times). After C02 discharge, thesetimers should be reset by depressing the timer reset button (86FP–1A for zone 1) located on the outside ofthe Electrical Control Cabinet (this will also serve to shut off the alarms). Predischarge timers (which areusually factory set for a suggested 30 seconds to allow personnel to evacuate the compartments, but can bechanged in the field if required) are also located on the control panel and control the time between the detec-tion of the fire and the activation of the solenoid valves.

NOTE

If the carbon dioxide system is to be effective, the compartment panels must be inplace and the compartment doors closed. There is sufficient C02 in the system tocompensate for leakage through ventilation openings which are not closed by pres-sure operated dampers and unavoidable cracks in the package lagging. There isnot enough to allow for uncontrolled escape of C02 through open panels or doors.

System Description Gas Turbine

3

* * * WARNING * * *

Carbon dioxide, in a concentration sufficient to extinguish fire,creates an atmosphere that will not support life. It is extremely haz-ardous to enter the compartments after the CO2 system has beendischarged. Anyone rendered unconscious by CO2 should be res-cued as quickly as possible and revived immediately with artificialrespiration. The extent and type of safeguards and personnel warn-ings that may be necessary must be designed to meet the particularrequirements of each situation. It is recommended that personnel beadequately trained as to the proper action to take in case of such anemergency.

III. INSTALLATION, MAINTENANCE, AND TESTING

For installation, inspection, and maintenance of the fire protection system, refer to the vendor instructionsfollowing this text. For fire protection/detection system testing instructions, refer to MLI 0113, and the C02Concentration Test instructions following this text.

Index Date Description

A 27/08/01 First issue

STATE OF MODIFICATIONS

GE Energy Products - EuropeRAS LAFFAN

GAS TURBINE & AUXILIARY EQUIPMENTCONTROL HIERARCHY

REF : 91-318 940 REV : C SECTION 01 PAGE : 1/3Ce document, propriété exclusive de GE Energy ProductsFrance SNC, est strictement confidentiel. Il ne peut être

communiqué, copié, ou reproduit sans son autorisation écrite.

This document, sole property of GE Energy Prudcts France SNC,is strictly confidential. It must not be communicated, copied or

reproduced without our written consent.

B 29/01/02Added Arcnet optical links.

Replaced coax cable by optical fiber for UDH, and added hubs.Added one time synchro signal for redundancy.

C 18/03/02 Added hardwired link between GCP & DCS.

PL

AN

T L

EV

EL

CE

NT

RA

L C

ON

TR

OL

RO

OM

The PLANT LEVEL manages all the high voltage and production activities. The plant level concerns the plant equipment and is essentially ensured by the DCS (Distributedcontrol System) with all operator workstations, VDUs and printers located in the Central Control Room.

The UNIT LEVEL, in each individual unit, drives and monitors the complete unit in its border, and creates control orders to and monitoring of the dedicated level. The unitlevel is ensured by the Operator Interfaces located in the Local Control Room and concerns the Gas Turbine equipment.

The DEDICATED LEVEL is the set of individual monitoring and control, this is the lowest man/machine interface and operates on and with field equipment included in theFIELD LEVEL such as drives, instruments, etc. The dedicated level is performed by the cubicles located in the Local Control Room.

Function of links : Monitoring (status, alarm, analog measurements) Monitoring & operating, i.e. command issuing, is possible. Control, monitoring and operating : the respective controlsystem provides apart from monitoring and operating facilitiesalso control functions, i.e. the analog and binary signalprocessing.

A

B

C

Type of links :ARCNET LINKHARDWIRED LINKMODBUS LINKETHERNET NETWORK (GSM PROTOCOL)TIME SYNCHRO NETWORK (IRIG-B)

RAS LAFFANGAS TURBINE & AUXILIARY EQUIPMENT

CONTROL HIERARCHY

91-318 940 rev CSheet 2

X.THIRIET18/03/02

GE Energy Products - Europeg

B

TNT

Compressor washing skid

HMI Server for units11,12,13,14

GT

11

TRESpeedtronic Mark V

TEX

Excitation &protection

cubicle

<C>

TGU

Gas turbine & associated equipment

TEX/TEV

Generator & breaker

C C C

<D>TRE

Displacementmeasurement

rack

HMI Server for unit 12Viewer for units 11,13,14

GT

12


TEX


cubicle

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Generator & breaker

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HMI Server for unit 13Viewer for units 11,12,14

GT

13


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cubicle

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TGU


TEX/TEV

Generator & breaker

C C C

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rack

HMI Serverfor units 11,12,13,14

GT

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cubicle

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TEX/TEV

Generator & breaker

C C C

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rack

TNT


IRIG

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Master Clock

Opticalmodem

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Opticalmodem

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OPTICAL FIBER LINK

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* Optical converters for Ethernet link are supplied by Customer

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CUSTOMER'S D.C.S.

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* Optical fibers between GE and DCS are supplied by Customer.

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The PLANT LEVEL manages all the high voltage and production activities. The plant level concerns the plant equipment and is essentially ensured by the DCS (Distributedcontrol System) with all operator workstations, VDUs and printers located in the Central Control Room.

The UNIT LEVEL, in each individual unit, drives and monitors the complete unit in its border, and creates control orders to and monitoring of the dedicated level. The unitlevel is ensured by the Operator Interfaces located in the Local Control Room and concerns the Gas Turbine equipment.

The DEDICATED LEVEL is the set of individual monitoring and control, this is the lowest man/machine interface and operates on and with field equipment included in theFIELD LEVEL such as drives, instruments, etc. The dedicated level is performed by the cubicles located in the Local Control Room.

UN

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LO

CA

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Function of links : Monitoring (status, alarm, analog measurements) Monitoring & operating, i.e. command issuing, is possible. Control, monitoring and operating : the respective controlsystem provides apart from monitoring and operating facilitiesalso control functions, i.e. the analog and binary signalprocessing.

A

B

C

Type of links :ARCNET LINKHARDWIRED LINKMODBUS LINKETHERNET NETWORKOPTICAL FIBER LINK

RAS LAFFANGAS TURBINE & AUXILIARY EQUIPMENT

CONTROL HIERARCHY

91-318 940 rev CSheet 3

X.THIRIET18/03/02

GE Energy Products - Europeg

EMERGENCYPUSH BUTTON

HMIServerPRINTER

TRE

Speedtronic Mark V

TEX


cubicle

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Gas detectionrack

TCA

Air filtercontrolpanel

TNT

Compressorwashing

control panel

TPT

GT&AUX firefightingpanel

TGU


TEV

Generator & breaker

TGR

Oil mist eliminator

TCA

GT & Generator air filter

TNT


TPT

GT detection & release

Gas Turbine level

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Gas metering

TPG

Final gas separators Vent & shut off valves

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Gas compartment

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GE Power Systems

1 GAS TURBINE OPERATOR COMMANDSA00052 REV A

GAS TURBINE OPERATOR COMMANDS

INTRODUCTION

Issuing the command to start a unit generally in-volves selecting a fuel, selecting a mode of opera-tion, initiating a unit start, synchronizing andloading the unit. After selecting an operating modeand initiating a unit start, the unit can be synchro-nized manually or automatically and loaded manu-ally or automatically.

After the unit has reached full speed no load (FSNL),the unit may be transferred from operation on onefuel to another. Some units have the option of operat-ing on a fuel mix, though mixed fuel operation mustbe done within certain parameters.

Before or after the unit has been started, one of sev-eral automatically controlled load setpoints can beselected, e.g., BASE, PEAK, PRE–SELECT.

OPERATING MODECOMMANDS

MODE OF OPERATION

OFF

CRANK

FIRE

AUTOMATIC

REMOTE

A normal unit shutdown is initiated by selecting theSTOP command, after which the unit will be un-loaded automatically and decelerated in a mannerwhich reduces the turbine’s thermal stresses gradu-ally; this is a “fired shutdown”. The unit will then beplaced “ON COOLDOWN” automatically.

If desired, the unit can be taken “OFF COOL-DOWN” after an appropriate period of time haspassed by using the COOLDOWN OFF or RATCH-

ET OFF command. If at zero speed, the unit can beplaced “ON COOLDOWN” by using the COOL-DOWN ON or RATCHET ON command.

“OFF” OPERATING MODE

The “ OFF” mode is usually selected by the operatorafter a unit stop has been initiated or completed andthere is no anticipated need to start the unit; the OFFcommand prevents “inadvertently” starting of theunit. OFF cannot be selected while the unit is start-ing or running. A unit start cannot be initiated fromthe OFF mode; this is an unalarmed start–check per-missive. When OFF mode is selected, the statusmessage field will display either “ON COOL-DOWN” or “OFF COOLDOWN”.

“CRANK” OPERATING MODE

The “CRANK” mode is usually selected when theunit is to be rotated at or near its purge speed withoutadmitting fuel to the combustion chambers. Exam-ples of such instances include axial–compressorcleaning, “forced” cooling of the unit or heat recov-ery steam generator or shaft rotation after a failure ofthe unit to go on cooldown after a shutdown or trip.With the CRANK mode selected and the unit at zerospeed, the status message field will display either“READY TO START” or “NOT READY TOSTART”. If the unit is “READY TO START”, a unitstart must be initiated in order for the unit to becranked. After a unit start has been initiated, the sta-tus message field will display “CRANKING” whilethe unit remains in CRANK mode. CRANK modecannot be selected any time after the unit has fired.Exercise caution if it is necessary to crank the unitfor extended periods of time or several times in suc-cession so as not to damage the starting means. Afterstarting the unit in CRANK mode it can be acceler-ated to full speed no load (FSNL) by selectingAUTO, or FIRE and then AUTO.

“FIRE” OPERATING MODE

The “FIRE” mode is selected when it desired to“fire” the unit (admit and ignite fuel) but not bring itto full speed. This may be useful to dry the unit aftera water wash if it is not going to be operated withinthe next 12 hours, to do start checks, or to straightena bowed rotor. When a unit start is initiated after theFIRE mode has been selected, the status messagefield will display “STARTING”, then “FIRING”,and after flame has been initiated, “WARMINGUP”. Once flame has been initiated, fuel flow willremain at the pre–set warm–up value. Since the unitis not self–sustaining at low speeds, the startingmeans will continue to provide torque to the unit.Exercise caution if it is necessary to run the unit atFIRE for extended periods of time so as not to dam-age the starting means. After starting the unit inFIRE mode it can be accelerated to full speed no load(FSNL) by selecting AUTO.

“AUTO” OPERATING MODE

The “AUTO” mode is the normal mode of operationselected when a unit is to be started from the localoperator interface and brought to full speed. Afterselecting the AUTO mode, the status message fieldwill display either “READY TO START” or “NOTREADY TO START”, indicating whether or not allthe unit start–check permissives have been satisfied.After a unit start has been initiated, the status mes-sage field will display “STARTING”, “FIRING”,“WARMING UP”, “ACCELERATING”, and then“FULL SPEED NO LOAD” or “SYNCHRONIZ-ING” and “LOADING”, depending on whether au-tomatic synchronization has been selected. WhenAUTO is selected and the generator panel is in theAuto Synch mode, the unit will crank, fire, acceler-ate, synchronize automatically, and load to SpinningReserve if no other load command is given. Spin-ning Reserve is a pre–selected load level stored as acontrol constant in the SPEEDTRONIC Mk Vsoftware. Once the unit attains full speed, no modebelow AUTO may be selected unless a unit STOPhas been initiated.

“CABLE REMOTE” OPERATINGMODE

Selecting the “CABLE REMOTE” mode allows theplant’s central control system (DCS or SCADA) tosend certain commands to the SPEEDTRONICMark V panel. If “CABLE REMOTE” has not beenselected, the plant control may only monitor theMark V, not issue commands. Information displayedin the status message field will be the same as that forAUTO mode operation. The CABLE REMOTEmode may be selected at any time and operation maybe switched back and forth from CABLE REMOTEto AUTO while the unit is running. The switchingfrom CABLE REMOTE to AUTO and back must bedone from the local panel. Personnel must remem-ber that when CABLE REMOTE is selected, the lo-cal is still able to issue commands to the controlpanel; control does not transfer to the plant control.

COOLDOWN CYCLECOMMANDS

TURBINE COOLDOWN

COOLDOWN ON (RATCHET ON)

COOLDOWN OFF (RATCHET OFF)

“COOLDOWN ON”

COOLDOWN ON or RATCHET ON is used duringunit cooldown to prevent rotor bow. If the rotor wasto remain stationary after being shutdown, the upperhalf of the rotor would tend to get warmer than thelower half and the rotor would bow. This could causea vibration problem during a subsequent start–up ormight prevent the rotor from turning at all. The larg-er units, Model Series 7 and 9, utilize the COOL-DOWN ON command which puts the units on “slowroll”, a constant rotation at low rpm. Model Series 5and 6 units utilize the RATCHET ON commandwhich rotates the shaft 56° every three minutes. Themajor difference between the large and small Model

GE Power Systems


Series is the type of torque convertor used. The unitwill be on COOLDOWN or RATCHET any time itis at zero speed, unless COOLDOWN OFF orRATCHET OFF has been selected. When the 14HRzero speed relay picks up after a unit shutdown, theunit goes on slow roll or ratchet automatically, nooperator initiation required. While on slow roll orratchet, the ac–powered lube oil pump will operate,providing both lubrication and the “muscle” neededfor rotor rotation. A unit should remain on the cool-down cycle, slow roll or ratchet, for a minimum of12 hours after a shutdown. It is preferable to leavethe unit on the cooldown cycle continuously unless alengthy shutdown is anticipated. It is suggested theunit be put on the cooldown cycle prior to a start–upafter an extended period of no rotation.

“COOLDOWN OFF”

“COOLDOWN OFF” or “RATCHET OFF” willterminate the cooldown cycle. Model Series 7 and 9will not accept a COOLDOWN OFF until 12–14hours after the unit has been shutdown.

GAS TURBINE UNITCOMMANDS

UNIT START

START

FAST LOAD START

FAST START, FAST LOAD(MS5001, MS6001 OPTION)

UNIT STOP

STOP

“START” COMMAND

The START command is used to initiate the startingsequence when the CRANK, FIRE, AUTO, or RE-MOTE mode is selected. With auto–synch selectedand the unit in AUTO mode, a START commandwill bring the unit from zero speed to Spinning Re-serve with no other operator input; if BASE is se-lected, the unit will go from zero speed to base loadwith no other operator input. If the generator breakerhas opened for some reason, automatic synchroniza-tion may be re–initiated by selecting START again.

“FAST LOAD START” COMMAND

When a FAST LOAD START is used to start the unitin AUTO with automatic synchronization selectedat the generator panel, the unit will come up to fullspeed at its normal rate of acceleration, but once thegenerator breaker closes, the machine is loaded at amuch higher rate than normal, approximately eighttimes the automatic loading rate. This makes mega-watts available very quickly but subjects the unit tohigh levels of thermal stress. FAST LOAD STARTshould be used only when necessary as it has a nega-tive impact on the machine’s maintenance intervals.If FAST LOAD START has been selected mistaken-ly when initiating a start, it may de–selected by se-lecting the normal START command.

“FAST START, FAST LOAD”COMMAND

When a FAST START, FAST LOAD is used to startthe unit in AUTO with automatic synchronizationselected at the generator panel, the unit will come upto full speed at an accelerated rate and, when thebreaker is closed, the machine will load at a higherrate. The fast start results from a shorter warm–upperiod from the diesel engine starting device, if soequipped, a shorter warm–up period for the gas tur-bine after firing and a steeper acceleration curvebringing the unit to full speed. The unit then loads atthe fast load rate. The FAST START, FAST LOADhas even more of a negative impact on the machine’s

maintenance intervals than FAST LOAD STARTand should be used judiciously. If FAST START,FAST LOAD has been selected mistakenly wheninitiating a start, it may de–selected by selecting thenormal START command. The FAST START,FAST LOAD is an option available only on ModelSeries 5 and 6 machines.

“STOP” COMMAND

A “STOP” command will initiate a unit shutdownsequence. The turbine speed reference will be re-duced at the normal automatic loading, and, henceunloading, rate. This will unload the unit until, in thecase of a generator drive application, the generatorbreaker opens on “reverse power”. The unit will thenbe at approximately 100% speed and a fired shut-down sequence will be initiated. A fired shutdownsequence reduces fuel flow at a set rate and causesthe unit to decelerate. The unit is decelerated untilthe flame becomes unstable at which point fuel flowis stopped; this occurs at approximately 30% speed.The fired shutdown sequence reduces the thermalstresses on the unit which would be caused by stop-ping fuel flow abruptly. On machines equipped withthe hydraulic ratchet cooldown, when the rotorreaches zero speed (14HR), the hydraulic ratchet se-quence is automatically initiated. On machinesequipped with the slow roll cooldown, when the ro-tor reaches approximately 30–50 rpm the slow rollsequence is automatically initiated. A STOP com-mand may be aborted prior to high speed relayL14HS drop–out by giving a START command.

GAS TURBINE LOADCOMMANDS

In the absence of having selected either of the com-mands listed below, if the gas turbine is started inAUTO with automatic synchronization selected atthe generator panel, the unit will automatically loadto a point known as “SPINNING RESERVE”. Thisis usually a nominal megawatt setting, e.g., four me-

gawatts, that is used by the control system as a refer-ence in the absence of any other setting. The unit willremain at SPINNING RESERVE until another loadcommand is given or until a RAISE or LOWER loadcommand is given. SPINNING RESERVE is a site–adjustable setting determined by control constantLK90SPIN.

LOAD SELECTION

PRE–SELECT

BASE

PEAK

PRESELECTED LOAD

When “PRESELECTED LOAD” is selected, theunit will automatically load or unload at the auto-matic loading rate until the preselected load output isattained. The preselected load is a megawatt settingthat is site–adjustable by changing control constantLK90PSEL. Once the preselected load level is at-tained, fuel flow will be controlled to maintain thatmegawatt output until another load command is giv-en or until a RAISE or LOWER load command isgiven.

BASE LOAD

When “BASE LOAD” is selected, the unit will load(or unload from PEAK) at the normal loading rateuntil the unit goes on exhaust temperature control; atthis point, the unit is at its nominal rated power out-put for the ambient conditions. When the unit is onexhaust temperature control, fuel flow is regulatedto provide the maximum power for the ambientconditions without “overfiring” the machine. It isimportant to note that as ambient conditions change,primarily compressor inlet temperature, the unit’spower output will change. Once at BASE LOAD,the unit will remain there until another load com-mand is given or a LOWER load command is given.After selecting BASE LOAD, the automatic loadingor unloading of the unit may be aborted by giving aRAISE or LOWER load command.

GE Power Systems


PEAK LOAD

“PEAK LOAD” is an option and, when selected, theunit will load at the normal loading rate until the unitgoes on peak exhaust temperature control. Similar tooperation on BASE, as ambient conditions change,primarily compressor inlet temperature, the unit’spower output will change. When operating onPEAK, the unit is operating at a firing temperatureabove its design limit; unit output is increased with aconsequent reduction in the machine’s maintenanceintervals. A rule of thumb is one hour of PEAK op-eration is equivalent to six hours of BASE operation.Once at PEAK LOAD, the unit will remain there un-til another load command is given or a LOWER loadcommand is given. After selecting PEAK LOAD,the automatic loading or unloading of the unit maybe aborted by giving a RAISE or LOWER load com-mand.

SPEED/LOAD CONTROLCOMMANDS

SPEED/LOAD CONTROL

RAISE

LOWER

RAISE SPEED/LOAD

When selected, a “RAISE” command will incre-ment the turbine speed reference TNR. With thegenerator breaker open, selecting RAISE will in-crease the unit’s speed. With the generator breakerclosed and the unit on droop control, selectingRAISE will increase the unit’s load. SelectingRAISE is the manual means of increasing the unit’sspeed or load.

LOWER SPEED/LOAD

When selected, a “LOWER” command will decre-ment the turbine speed reference TNR. With thegenerator breaker open, selecting LOWER will de-crease the unit’s speed. With the generator breakerclosed and the unit on droop control, selectingLOWER will decrease the unit’s load. SelectingLOWER is the manual means of decreasing theunit’s speed or load.

GOVERNOR COMMANDS

GOVERNOR

DROOP

ISOCH

DROOP GOVERNOR

“DROOP” control is the usual governor commandfor most generators connected to a utility grid; this isa ‘load–sharing’ governor. Droop speed control is aproportional control, changing called–for fuel flow(FSR) in proportion to the difference between actualturbine speed and the speed reference. Any changein actual speed (grid frequency) will cause a propor-tional change in unit load. If the entire grid systemtends to be overloaded, grid frequency (or speed)will decrease and cause an FSR increase in propor-tion to the droop setting. If all units have the samedroop, all will share a load increase equally. Loadsharing and system stability are the main advantagesof this method of speed control.

ISOCHRONOUS GOVERNOR

Selecting “ISOCHRONOUS” will force the unit tomaintain rated speed/frequency and provide asmuch power as required up to the turbine’s firingtemperature limit (temperature control). The iso-chronous governor setpoint is fixed at 100% speed;any deviation will integrate the fuel command in a

direction to reduce the speed error to exactly zero. Ifthere were two isochronous governor machines onthe same system, they would have a tendency tofight each other as each would attempt to hold aslightly different speed. The isochronous governoris a proportional plus reset, or integrating, controller.The reset action allows it to integrate out any steadystate speed error, providing a steady state droop of 0percent.

FUEL COMMANDS

FUEL SELECTION

GAS

DIST

MIX

HEAVY

For single fuel applications, there is obviously nofuel selection needed. However, many machinescome equipped for dual fuel operation, the dual fuelsprimarily being natural gas and liquid fuel. The liq-uid fuel is usually a distillate known as Number 2burner fuel, 2–D diesel fuel, 2–GT gas turbine fuel,high speed diesel, etc. These are the fuels specifiedby “GAS” and “DIST”, respectively.

Some applications may use heavier liquid fuelsknown as crudes and/or residuals, e.g., 3–GT gasturbine fuel, 4–D diesel fuel, marine diesel fuel (lowspeed diesel), No. 4 burner fuel, light residual oil,No. 6 burner fuel, bunker C, etc. These heavier fuelsrequire special fuel handling equipment such asheaters and water wash skids to make the fuel easy tohandle and suitable for use in a gas turbine. General-ly, the higher the fuel number, the less volatile thefuel and the more on–site processing it needs beforeit is suitable for use. Heavy liquid fuels usually re-quire that start–up of the gas turbine be done onanother fuel and transfer to “HEAVY” after fullspeed has been attained.

There are also applications that use lighter liquidfuels such as kerosene or naphtha. Kerosene is alsoknown as 1–D diesel fuel, 1–GT gas turbine fuel orJP5, Jet A and is generally more expensive than thenumber 2 distillates. Naphtha may also be known asO–GI gas turbine fuel or JP–4, Jet B and is more vol-atile than the number 1 and 2 distillates. Naphthafuel generally requires forwarding equipment or anadditive due to its low lubricity.

Some gas fuel applications may be dual gas applica-tions, using some sort of gas generated by an on–siteprocess as the secondary gas fuel. These applica-tions are usually in processing plants such as refiner-ies or chemical plants.

When running a dual–fuel gas/distillate machine,the machine is able to start on either fuel and switchto the alternate fuel after full speed has been at-tained. If running on gas and the gas supply pressurefalls below a pre–set level, the control system willautomatically switch to the liquid fuel; the transferfrom liquid to gas must always be initiated by the op-erator. Many dual–fuel machines can run at “MIX”,a combination of the two fuels. This must be donewithin certain parameters such as being above aminimum load and minimum flow requirements foreither fuel.

BACKUP OPERATOR INTERFACECOMMANDS

STARTING PROCEDURE

Step 1: Mode Select To “AUTO”

• Press function key “F1” for MODE SELECToptions.

• Use the arrow (< >) keys to point to “AUTO”.

• Press the “ENTER” key. An asterisk (*) will ap-pear beside “AUTO”.

GE Power Systems


Step 2: Master Control “START” Signal

• Press function key “F2” for MASTER CON-TROL options.

• Use arrow (< >) key to point to “START”.

• Press “ENTER”. An asterisk (*) will appear be-side “START”.

• Press the “RAISE” key. The signal “L1X” willchange to a “1”, indicating the start sequence isin progress.

• Press the “NORMAL” key. Check “TNH” toconfirm that turbine speed is increasing, indicat-ing shaft rotation.

Step 3: Load Selection To Base Load

• Press funtion key “F5”.

• Use arrow (< >) keys to point to “BASE”.

• Press the “ENTER” key. An asterisk (*) will ap-pear beside “BASE”.

STOP PROCEDURE

Normal Stop Command

• Press the function key “F2”.

• Use arrow (< >) keys to point to “STOP”.

• Press the “ENTER” key. An asterisk (*) will ap-pear beside “STOP”.

• Press the “RAISE” key. The signal L94X willchange to a “1”, indicating the stop sequence isin progress.

The STOP sequence is fully automatic from thispoint. No other commands are required. The STOPprocedure may be aborted by initiating a START.

AUXILIARIES CONTROL

Cooldown On

• Press function key “F15” (press down on the“SHIFT” and “F5” keys simultaneously).

• Use the arrow (< >) keys to point to “CD_ON”.

• Press the “ENTER” key. An asterisk (*) will ap-pear beside “CD_ON”.

• Press the “RAISE” key. The cooldown sequencehas been initiated. At the appropriate time thenecessary systems (lube oil, hydraulic oil andstarting means systems) will be activated to sup-port rotor cooldown activities.

Cooldown Off

• Press function key “F15” (press down on the“SHIFT” and “F5” keys simultaneously).

• Use the arrow (< >) keys to point to “CD_OFF”.

• Press the “ENTER” key. An asterisk (*) will ap-pear beside “CD_OFF”.

• Press the “RAISE” key. Rotor cooldown opera-tion will now stop and the support systems forthis cooldown will be shut down automatically.This includes the lube oil going to the bearings.

GE Power Systems

1 FUNDAMENTALS OF SPEEDTRONIC MARK V CONTROL SYSTEM

A00023 rev.A 8/16/93

FUNDAMENTALS OF SPEEDTRONIC MARK V CONTROL SYSTEM

SPEEDTRONIC Mark V Control contains a num-ber of control, protection and sequencing systemsdesigned for reliable and safe operation of the gasturbine. It is the objective of this chapter to describehow the gas turbine control requirements are met,using simplified block diagrams and one–line dia-grams of the SPEEDTRONIC Mark V control,protection, and sequencing systems. A generatordrive gas turbine is used as the reference.

CONTROL SYSTEM

Basic Design

Control of the gas turbine is done by the startup, ac-

celeration, speed, temperature, shutdown, andmanual control functions illustrated in Figure 1.Sensors monitor turbine speed, exhaust tempera-ture, compressor discharge pressure, and other pa-rameters to determine the operating conditions ofthe unit. When it is necessary to alter the turbine op-erating conditions because of changes in load or am-bient conditions, the control modulates the flow offuel to the gas turbine. For example, if the exhausttemperature tends to exceed its allowable value for agiven operating condition, the temperature controlsystem reduces the fuel supplied to the turbine andthereby limits the exhaust tempera-ture.

TEMPERATURE

SPEED

TO CRT DISPLAY

FUEL

TO TURBINE

FSR

FUELSYSTEMMINIMUM

ACCELERATIONRATE

STARTUP

SHUTDOWN

MANUAL

TO CRTDISPLAY

TO CRT DISPLAY

VALUESELECTLOGIC

Figure 1 Simplified Control Schematic

id0043

Operating conditions of the turbine are sensed andutilized as feedback signals to the SPEEDTRONICcontrol system. There are three major control loops –startup, speed, and temperature – which may be incontrol during turbine operation. The output of thesecontrol loops is connected to a minimum value gatecircuit as shown in Figure 1. The secondary control

modes of acceleration, manual FSR, and shutdownoperate in a similar manner.

Fuel Stroke Reference (FSR) is the command signalfor fuel flow. The minimum value select gate con-nects the output signals of the six control modes tothe FSR controller; the lowest FSR output of the six

GE Power Systems

2FUNDAMENTALS OF SPEEDTRONIC MARK V CONTROL SYSTEM

A00023 rev. A 8/16/93

Figure 2 Block Diagram – Control Schematic

TTXM

TTRX

FSRSU FSR

MIN

FSRACC

FSRMAN

FSRSD

FSRN

FSRT

TNRI

TNR

FSRSU

FSR

TNH

TNHAR

FSRMIN

LOGIC

CQTC

FSRACC

LOGIC

FSRC

FSR

FSRMIN

FSRSD

FSRMANLOGIC

FSRC

TNHAR

FSRMIN

FSRN

LOGIC

TNH

TNHCOR

CQTC

<R><S><T>START-UPCONTROL

<R><S><T>ACCELERATIONCONTROL

<R><S><T>MANUAL FSR

<R><S><T>SHUTDOWNCONTROL

FSR

GATE

SPEED CONTROL <R><S><T>LOGIC

LOGIC

LOGIC TNRI

PR/D

TEMPERATURE CONTROL

LOGIC

<R><S><T>

<R><S><T>

FSRT

<R><S><T>LOGIC

FSR

TTXM

TTRX

TTXD

FSR

TTXD

96CD

TNH

TNR

MEDIAN

id0038V

ISOCHRONOUSONLY

77NH

QTBATCQC

A/D

A/D

TBQATCQA

TBQBTCQC

GE Power Systems


A00023 rev.A 8/16/93

control loops is allowed to pass through the gate tothe fuel control system as the controlling FSR. Thecontrolling FSR will establish the fuel input to theturbine at the rate required by the system which is incontrol. Only one control loop will be in control atany particular time and the control loop which iscontrolling FSR will be displayed on the CRT.

Figure 2 shows a more detailed schematic of thecontrol loops. This can be referenced during the ex-planation of each loop to show the interfacing.

Start–up/Shutdown Sequence and Control

Start–up control brings the gas turbine from zerospeed up to operating speed safely by providingproper fuel to establish flame, accelerate the turbine,and to do it in such a manner as to minimize the lowcycle fatigue of the hot gas path parts during the se-quence. This involves proper sequencing of com-mand signals to the accessories, starting device andfuel control system. Since a safe and successfulstart–up depends on proper functioning of the gasturbine equipment, it is important to verify the stateof selected devices in the sequence. Much of thecontrol logic circuitry is associated not only with ac-tuating control devices, but enabling protective cir-cuits and obtaining permissive conditions beforeproceeding.

General values for control settings are given in thisdescription to help in the understanding of the oper-ating system. Actual values for control settings aregiven in the Control Specifications for a particularmachine.

Speed Detectors

An important part of the start–up/shutdown se-quence control of the gas turbine is proper speedsensing. Turbine speed is measured by magneticpickups and will be discussed under speed control.The following speed detectors and speed relays aretypically used:

–L14HR Zero–Speed (approx. 0% speed)

–L14HM Minimum Speed (approx. 16%speed)

–L14HA Accelerating Speed (approx. 50%speed)

–L14HS Operating Speed (approx. 95%speed)

The zero–speed detector, L14HR, provides the sig-nal when the turbine shaft starts or stops rotating.When the shaft speed is below 14HR, or at zero–speed, L14HR picks–up (fail safe) and the permis-sive logic initiates ratchet or slow–roll operationduring the automatic start–up/cooldown sequenceof the turbine.

The minimum speed detector L14HM indicates thatthe turbine has reached the minimum firing speedand initiates the purge cycle prior to the introductionof fuel and ignition. The dropout of the L14HMminimum speed relay provides several permissivefunctions in the restarting of the gas turbine aftershutdown.

The accelerating speed relay L14HA pickup indi-cates when the turbine has reached approximately50 percent speed; this indicates that turbine start–upis progressing and keys certain protective features.

The high–speed sensor L14HS pickup indicateswhen the turbine is at speed and that the acceleratingsequence is almost complete. This signal providesthe logic for various control sequences such as stop-ping auxiliary lube oil pumps and starting turbineshell/exhaust frame blowers.

Should the turbine and generator slow during an un-derfrequency situation, L14HS will drop out at theunder–frequency speed setting. After L14HS dropsout the generator breaker will trip open and the Tur-bine Speed Reference (TNR) will be reset to100.3%. As the turbine accelerates, L14HS willagain pick up; the turbine will then require anotherstart signal before the generator will attempt to auto–synchronize to the system again.

The actual settings of the speed relays are listed inthe Control Specification and are programmed in the<RST> processors as EEPROM control constants.

GE Power Systems


A00023 rev. A 8/16/93

START–UP CONTROL

The start–up control operates as an open loop con-trol using preset levels of the fuel command signalFSR. The levels are: “ZERO”, “FIRE”, “WARM–UP”, “ACCELERATE” and “MAX”. The ControlSpecifications provide proper settings calculated forthe fuel anticipated at the site. The FSR levels are setas Control Constants in the SPEEDTRONIC MarkV start–up control.

Start–up control FSR signals operate through theminimum value gate to ensure that other controlfunctions can limit FSR as required.

The fuel command signals are generated by theSPEEDTRONIC control start–up software. In addi-tion to the three active start–up levels, the softwaresets maximum and minimum FSR and provides formanual control of FSR. Clicking on the targets for“MAN FSR CONTROL” and “FSR GAG RAISEOR LOWER” allows manual adjustment of FSRsetting between FSRMIN and FSRMAX.

While the turbine is at rest, electronic checks aremade of the fuel system stop and control valves, theaccessories, and the voltage supplies. At this time,“SHUTDOWN STATUS” will be displayed on theCRT. Activating the Master Operation Switch (L43)from “OFF” to an operating mode will activate theready circuit. If all protective circuits and trip latchesare reset, the “STARTUP STATUS” and “READYTO START” messages will be displayed, indicatingthat the turbine will accept a start signal. Clicking onthe “START” Master Control Switch (L1S) and“EXECUTE” will introduce the start signal to thelogic sequence.

The start signal energizes the Master Control andProtection circuit (the “L4” circuit) and starts thenecessary auxiliary equipment. The “L4” circuitpermits pressurization of the trip oil system and en-gages the starting clutch if applicable. With the “L4”circuit permissive and the starting clutch engaged,the starting device starts turning. Startup status mes-sage “STARTING” will be displayed on the CRT.See point “A” on the Typical Start–up Curve Figure3.

100

80

60

40

20

0

APPROXIMATE TIME – MINUTES

IGNITION &CROSSFIRE

STARTAUXILIARIES &

DIESEL WARMUP

PURGE COAST

DOWN

WARMUP

1 MIN

ACCELERATE

SPEED – %

IGV – DEGREES

FSR – %

Tx – °F/10

Figure 3 Mark V Start-up Curve

id0093A B

C

D

When the turbine ‘breaks away’ (starts to rotate), theL14HR signal de–energizes starting clutch solenoid20CS and shuts down the hydraulic ratchet. The

clutch then requires torque from the starting deviceto maintain engagement. The turbine speed relayL14HM indicates that the turbine is turning at the

GE Power Systems


A00023 rev.A 8/16/93

speed required for proper purging and ignition in thecombustors. Gas fired units that have exhaust con-figurations which can trap gas leakage (i.e., boilers)have a purge timer, L2TV, which is initiated with theL14HM signal. The purge time is set to allow threeto four changes of air through the unit to ensure thatany combustible mixture has been purged from thesystem. The starting means will hold speed untilL2TV has completed its cycle. Units which do nothave extensive exhaust systems may not have apurge timer, but rely on the starting cycle and naturaldraft to purge the system.

The L14HM signal or completion of the purge cycle(L2TVX) ‘enables’ fuel flow, ignition, sets firinglevel FSR, and initiates the firing timer L2F. Seepoint “B” on Figure 3. When the flame detector out-put signals indicate flame has been established in thecombustors (L28FD), the warm–up timer L2Wstarts and the fuel command signal is reduced to the“WARM–UP” FSR level. The warm–up time is pro-vided to minimize the thermal stresses of the hot gaspath parts during the initial part of the start–up.

If flame is not established by the time the L2F timertimes out, typically 60 seconds, fuel flow is halted.The unit can be given another start signal, but firingwill be delayed by the L2TV timer to avoid fuel ac-cumulation in successive attempts. This sequenceoccurs even on units not requiring initial L2TVpurge.

At the completion of the warm–up period (L2WX),the start–up control ramps FSR at a predeterminedrate to the setting for “ACCELERATE LIMIT”. Thestart–up cycle has been designed to moderate thehighest firing temperature produced during accel-eration. This is done by programming a slow rise inFSR. See point “C” on Figure 3. As fuel is increased,the turbine begins the acceleration phase of start–up.The clutch is held in as long as the starting deviceprovides torque to the gas turbine. When the turbineoverruns the starting device, the clutch will disen-gage, shutting down the starting device. Speed relayL14HA indicates the turbine is accelerating.

The start–up phase ends when the unit attains full–speed–no–load (see point “D” on Figure 3). FSR is

then controlled by the speed loop and the auxiliarysystems are automatically shut down.

The start–up control software establishes the maxi-mum allowable levels of FSR signals during start–up. As stated before, other control circuits are able toreduce and modulate FSR to perform their controlfunctions. In the acceleration phase of the start–up,FSR control usually passes to acceleration control,which monitors the rate of rotor acceleration. It ispossible, but not normal, to reach the temperaturecontrol limit. The CRT display will show which pa-rameter is limiting or controlling FSR.

Fired Shutdown

A normal shutdown is initiated by clicking on the“STOP” target (L1STOP) and “EXECUTE”; thiswill produce the L94X signal. If the generator break-er is closed when the stop signal is initiated, the Tur-bine Speed Reference (TNR) counts down to reduceload at the normal loading rate until the reverse pow-er relay operates to open the generator breaker; TNRthen continues to count down to reduce speed. Whenthe STOP signal is given, shutdown Fuel Stroke Ref-erence FSRSD is set equal to FSR.

When the generator breaker opens, FSRSD rampsfrom existing FSR down to a value equal toFSRMIN, the minimum fuel required to keep theturbine fired. FSRSD latches onto FSRMIN and de-creases with corrected speed. When turbine speeddrops below a defined threshold (Control ConstantK60RB) FSRSD ramps to a blowout of one flamedetector. The sequencing logic remembers whichflame detectors were functional when the breakeropened. When any of the functional flame detectorssenses a loss of flame, FSRMIN/FSRSD decreasesat a higher rate until flame–out occurs, after whichfuel flow is stopped.

During coastdown on units having motor driven at-omizing air booster compressors, the booster isstarted at L14HS drop out to prevent exhaust smokeduring the shut down. Units not having motor drivenboosters may require higher fuel shut off speed toavoid smoke.

Fired shut down is an improvement over the formerfuel shut off at L14HS drop out. By maintaining

GE Power Systems


A00023 rev. A 8/16/93

flame down to a lower speed there is significant re-duction in the strain developed on the hot gas pathparts at the time of fuel shut off.

SPEED CONTROL

The Speed Control System controls the speed andload of the gas turbine generator in response to theactual turbine speed signal and the called–for speedreference. While on speed control the control modemessage “SPEED CTRL”will be displayed.

Speed Signal

Three magnetic sensors are used to measure thespeed of the turbine. These magnetic pickup sensors(77NH–1,–2,–3) are high output devices consistingof a permanent magnet surrounded by a hermeticallysealed case. The pickups are mounted in a ringaround a 60–toothed wheel on the gas turbine com-pressor rotor. With the 60–tooth wheel, the frequen-cy of the voltage output in Hertz is exactly equal tothe speed of the turbine in revolutions per minute.

The voltage output is affected by the clearance be-tween the teeth of the wheel and the tip of the mag-netic pickup. Clearance between the outsidediameter of the toothed wheel and the tip of the mag-netic pickup should be kept within the limits speci-fied in the Control Specifications (approx. 50 mils).If the clearance is not maintained within the speci-fied limits, the pulse signal can be distorted. Turbinespeed control would then operate in response to theincorrect speed feedback signal.

The signal from the magnetic pickups is brought intothe Mark V panel, one mag pickup to each controller<RST>, where it is monitored by the speed controlsoftware.

Speed/Load Reference

The speed control software will change FSR in pro-portion to the difference between the actual turbine–

generator speed (TNH) and the called–for speedreference (TNR).

The called–for–speed, TNR, determines the load ofthe turbine. The range for generator drive turbines isnormally from 95% (min.) to 107% (max.) speed.The start–up speed reference is 100.3% and is presetwhen a “START” signal is given.

FU

LL S

PE

ED

NO

LO

AD

FS

R

MIN

IMU

M F

SR

MA

X F

SR

RA

TE

D F

SR

LOW SPEED STOP

“FSNL”S

PE

ED

RE

FE

RE

NC

E %

(T

NR

)

104

100

95

FUEL STROKE REFERENCE (LOAD)(FSR)

HIGH SPEED STOP

TNR MIN.

TNR MAX.

Figure 4 Droop Control Curve

107

id0044

The turbine follows to 100.3% TNH for synchro-nization. At this point the operator can raise or lowerTNR, in turn raising or lowering TNH, via the70R4CS switch on the generator control panel or byclicking on the targets on the CRT, if required. Referto Figure 4. Once the generator breaker is closedonto the power grid, the speed is held constant by thegrid frequency. Fuel flow in excess of that necessaryto maintain full speed no load will result in increasedpower produced by the generator. Thus the speedcontrol loop becomes a load control loop and thespeed reference is a convenient control of the de-sired amount of load to be applied to the turbine–generator unit.

Droop speed control is a proportional control,changing FSR in proportion to the difference be-

GE Power Systems


A00023 rev.A 8/16/93

tween actual turbine speed and the speed reference.Any change in actual speed (grid frequency) willcause a proportional change in unit load. This pro-portionality is adjustable to the desired regulation or“Droop”. The speed vs. FSR relationship is shownon Figure 4.

If the entire grid system tends to be overloaded, gridfrequency (or speed) will decrease and cause an FSRincrease in proportion to the droop setting. If allunits have the same droop, all will share a load in-crease equally. Load sharing and system stability arethe main advantages of this method of speed control.

Normally 4% droop is selected and the setpoint iscalibrated such that 104% setpoint will generate aspeed reference which will produce an FSR result-ing in base load at design ambient temperature. If theunit has “PEAK” capability, 104% TNR will pro-duce an FSR resulting in peak load.

When operating on droop control, the full–speed–no–load FSR setting calls for a fuel flow which issufficient to maintain full speed with no generatorload. By closing the generator breaker and raisingTNR via raise/lower, the error between speed andreference is increased. This error is multiplied by again constant dependent on the desired droop setting

Figure 5 Speed Control Schematic

FSNL

TNRSPEEDREFERENCE

TNHSPEED

DROOP

ERRORSIGNAL

SPEED CONTROL

<RST>

FSRN+

–

SPEED CHANGER LOAD SET POINT

MEDIANSELECT

TNR

SPEEDREFERENCE

MIN.

MAX. LIMIT

PRESET

OPERATING

<RST>

L83SDRATE

L70RRAISE

L70LLOWER

L83PRESPRESETLOGIC

START-UP

OR SHUTDOWN

L83TNROPMIN. SELECT LOGIC

++

id0040

GE Power Systems


A00023 rev. A 8/16/93

and added to the FSNL FSR setting to produce therequired FSR to take more load and thus assist inholding the system frequency. Refer to Figures 4 and5.

The minimum FSR limit (FSRMIN) in the SPEED-TRONIC Mark V system prevents the speed controlcircuits from driving the FSR below the value whichwould cause flameout during a transient condition.For example, with a sudden rejection of load on theturbine, the speed control system loop would want todrive the FSR signal to zero, but the minimum FSRsetting establishes the minimum fuel level that pre-vents a flameout. Temperature and/or start–up con-

trol can drive FSR to zero and are not influenced byFSRMIN.

Synchronizing

Automatic synchronizing is accomplished usingsynchronizing algorithms programmed into <RST>and software. Bus and generator voltage signalsare input to the core which contains isolationtransformers, and are then paralleled to <RST>.<RST> software drives the synch check and synchpermissive relays, while provides the actualbreaker close command. See Figure 6.

<RST>

<XYZ>

AUTO SYNCH

AND

L25

BREAKERCLOSE

AND

AUTO SYNCHPERMISSIVE

L83ASAUTO SYNCHPERMISSIVE

A

B

A>B

A

B

A>B

REF

REF

GEN VOLTS

LINE VOLTS

Figure 6 Synchronizing Control Schematic

id0048V

CALCULATED PHASE WITHIN LIMITS

CALCULATED SLIP WITHIN LIMITS

CALCULATED ACCELERATION

CALCULATED BREAKER LEAD TIME

There are three basic synchronizing modes. Thesemay be selected from external contacts, i.e., genera-tor panel selector switch, or from the SPEEDTRON-IC Mark V CRT.

1. OFF – Breaker will not be closed by SPEED-TRONIC Mark V control

2. MANUAL – Operator initiated breaker closurewhen permissive synch check relay 25X is satis-fied

3. AUTO – System will automatically match volt-age and speed and then close the breaker at theappropriate time to hit top dead center on thesynchroscope

For synchronizing, the unit is brought to 100.3%speed to keep the generator “faster” than the grid, as-suring load pick–up upon breaker closure. If the sys-

tem frequency has varied enough to cause anunacceptable slip frequency (difference betweengenerator frequency and grid frequency), the speedmatching circuit adjusts TNR to maintain turbinespeed 0.20% to 0.40% faster than the grid to assurethe correct slip frequency and permit synchronizing.

For added protection a synchronizing check relay isprovided in the generator panel. It is used in serieswith both the auto synchronizing relay and themanual breaker close switch to prevent large out–of–phase breaker closures.

ACCELERATION CONTROL

Acceleration control compares the present value ofthe speed signal with the value at the last sampletime. The difference between these two numbers is a

GE Power Systems


A00023 rev.A 8/16/93

measure of the acceleration. If the actual accelera-tion is greater than the acceleration reference,FSRACC is reduced, which will reduce FSR, andconsequently the fuel to the gas turbine. Duringstart–up the acceleration reference is a function ofturbine speed; acceleration control usually takesover from speed control shortly after the warm–upperiod and brings the unit to speed. At “CompleteSequence”, which is normally 14HS pick–up, theacceleration reference is a Control Constant, nor-mally 1% speed/second. After the unit has reached100% TNH, acceleration control usually serves onlyto contain the unit’s speed if the generator breakershould open while under load.

EX

HA

SU

T T

EM

PE

RA

TU

RE

(T

x)

COMPRESSOR DISCHARGE PRESSURE (CPD)

ISOTHERMAL

Figure 7 Exhaust Temperature vs.Compressor Discharge Pressure

id0045

TEMPERATURE CONTROL

The Temperature Control System will limit fuelflow to the gas turbine to maintain internal operatingtemperatures within design limitations of turbinehot gas path parts. The highest temperature in the gasturbine occurs in the flame zone of the combustionchambers. The combustion gas in that zone is di-luted by cooling air and flows into the turbine sec-tion through the first stage nozzle. The temperatureof that gas as it exits the first stage nozzle is known as

the “firing temperature” of the gas turbine; it is thistemperature that must be limited by the control sys-tem. From thermodynamic relationships, gas tur-bine cycle performance calculations, and known siteconditions, firing temperature can be determined asa function of exhaust temperature and the pressureratio across the turbine; the latter is determined fromthe measured compressor discharge pressure (CPD).The temperature control system is designed to mea-sure and control turbine exhaust temperature ratherthan firing temperature because it is impractical tomeasure temperatures directly in the combustionchambers or at the turbine inlet. This indirect controlof turbine firing temperature is made practical byutilizing known gas turbine aero– and thermo–dy-namic characteristics and using those to bias the ex-haust temperature signal, since the exhausttemperature alone is not a true indication of firingtemperature.

Firing temperature can also be approximated as afunction of exhaust temperature and fuel flow (FSR)and as a function of exhaust temperature and genera-tor output (DWATT). Either FSR or megawatt ex-haust temperature control curves are used asback–up to the primary CPD–biased temperaturecontrol curve.

These relationships are shown on Figures 7 and 8.The lines of constant firing temperature are used inthe control system to limit gas turbine operatingtemperatures, while the constant exhaust tempera-ture limit protects the exhaust system during start–up.

Exhaust Temperature Control Hardware

Chromel–Alumel exhaust temperature thermocou-ples are used and, depending on the gas turbine mod-el, there may be 13 to 27. These thermocouples aremounted in the exhaust plenum in an axial directioncircumferentially around the exhaust diffuser. Theyhave individual radiation shields that allow the ra-dial outward diffuser flow to pass over these 1/16”diameter (1.6mm) stainless steel sheathed thermo-couples at high velocity, minimizing the cooling ef-fect of the longer time constant, cooler plenum

GE Power Systems


A00023 rev. A 8/16/93

FUEL STROKE REFERENCE (FSR)

EX

HA

SU

T T

EM

PE

RA

TU

RE

(T

x)

ISOTHERMAL

Figure 8 Exhaust Temperature vs. FuelControl Command Signal

id0046

walls. The signals from these individual, un-grounded detectors are sent to the SPEEDTRONICMark V control panel through shielded thermocou-ple cables and are divided amongst controllers<RST>.

Exhaust Temperature Control Software

The software contains a series of application pro-grams written to perform the exhaust temperaturecontrol and monitoring functions such as digital andanalog input scan. A major function is the exhausttemperature control, which consists of the followingprograms:

1. Temperature control command

2. Temperature control bias calculations

3. Temperature reference selection

The temperature control software determines thecold junction compensated thermocouple readings,selects the temperature control setpoint, calculatesthe control setpoint value, calculates the representa-tive exhaust temperature value, compares this valuewith the setpoint, and then generates a fuel com-

mand signal to the analog control system to limit ex-haust temperature.

Temperature Control Command Program

The temperature control command programcompares the exhaust temperature control setpointwith the measured gas turbine exhaust temperatureas obtained from the thermocouples mounted in theexhaust plenum; these thermocouples are scannedand cold junction corrected by programs describedlater. These signals are accessed by <RST> as wellas <C>. The temperature control command programin <RST> (Figure 9) reads the exhaust thermocou-ple temperature values and sorts them from the high-est to the lowest. This array (TTXD2) is used in thecombustion monitor program as well as in the Tem-perature Control Program. In the Temperature Con-trol Program all exhaust thermocouple inputs aremonitored and if any are reading too low ascompared to a constant, they will be rejected. Thehighest and lowest values are then rejected and theremaining values are averaged, that average beingthe TTXM signal.

If a Controller should fail, this program will ignorethe readings from the failed Controller. The TTXMsignal will be based on the remaining Controllers’thermocouples and an alarm will be generated.

The TTXM value is used as the feedback for the ex-haust temperature comparator because the value isnot affected by extremes that may be the result offaulty instrumentation. The temperature–control–command program in <RST> compares the exhausttemperature control setpoint (calculated in the tem-perature–control–bias program and stored in thecomputer memory) TTRXB to the TTXM value todetermine the temperature error. The software pro-gram converts the temperature error to a fuel strokereference signal, FSRT.

Temperature Control Bias Program

Gas turbine firing temperature is determined by themeasured parameters of exhaust temperature andcompressor discharge pressure (CPD) or exhaust

GE Power Systems


A00023 rev.A 8/16/93

SORTHIGHEST

TOLOWEST

AVERAGEREMAINING

REJECTHIGHANDLOW

REJECTLOWTC’s

TTXDR

TTXDS

TTXDT

TTXD2

TTXM

QUANTITY

<RST>

TOCOMBUSTIONMONITOR

OF TC’s USED

TEMPERATURE CONTROL

MEDIANSELECT

FSRMIN

FSRMAX

TTRXB

TTXM

GAIN

FSR

<RST>

FSRT

Figure 9 Temperature Control Schematic

id0032V

++

.

TEMPERATURECONTROL

REFERENCE

MINSELECT

CORNER

CPD

SLOPE

ISOTHERMAL

FSR

SLOPE

CORNER

<RST>

temperature and fuel consumption (proportional toFSR). In the computer, firing temperature is limitedby a linearized function of exhaust temperature andCPD backed up by a linearized function of exhausttemperature and FSR (See Figure 8). The tempera-ture control bias program (Figure 10) calculates theexhaust temperature control setpoint TTRXB basedon the CPD data stored in computer memory andconstants from the selected temperature–referencetable. The program calculates another setpoint basedon FSR and constants from another temperature–reference table.

Figure 11 is a graphical illustration of the control set-points. The constants TTKn_C (CPD bias corner)and TTKn_S (CPD bias slope) are used with theCPD data to determine the CPD bias exhaust tem-perature setpoint. The constants TTKn_K (FSR bias

DIGITALINPUTDATA

SELECTEDTEMPERATURE

REFERENCETABLE

CONSTANTSTORAGE

COMPUTERMEMORY

TEMPERATURECONTROL

BIASPROGRAM

COMPUTERMEMORY

Figure 10 Temperature Control Bias

id0023

corner) and TTKn_M (FSR bias slope) are used withthe FSR data to determine the FSR bias exhaust tem-perature setpoint. The values for these constants aregiven in the Control Specifications–Control System

GE Power Systems


A00023 rev. A 8/16/93

Settings drawing. The temperature–control–biasprogram also selects the isothermal setpointTTKn_I. The program selects the minimum of thethree setpoints, CPD bias, FSR bias, or isothermalfor the final exhaust temperature control reference.During normal operation with gas or light distillatefuels, this selection results in a CPD bias controlwith an isothermal limit, as shown by the heavy lineson Figure 11. The CPD bias setpoint is comparedwith the FSR bias setpoint by the program and analarm occurs when the CPD setpoint is higher. Forunits operating with heavy fuel, FSR bias controlwill be selected to minimize the effect of turbinenozzle plugging on firing temperature. The FSR biassetpoint will then be compared with the CPD biassetpoint and an alarm will occur when the FSR set-point exceeds the CPD setpoint. A ramp function isprovided in the program to limit the rate at which thesetpoint can change. The maximum and minimumchange in ramp rates (slope) are programmed inconstants TTKRXR1 and TTKRXR2. Consult theControl Sequence Program (CSP) and the ControlSpecifications drawing for the block diagram il-lustration of this function and the value of theconstants. Typical rate change limit is 1.5°F per se-cond. The output of the ramp function is the exhausttemperature control setpoint which is stored in thecomputer memory.

Figure 11 Exhaust Temperature Control Setpoints

EX

HA

US

T T

EM

PE

RA

TU

RE

CPDFSR

TTKn_C

ISOTHERMALTTKn_K

TTKn_I

id0054

Temperature Reference Select Program

The exhaust temperature control function selectscontrol setpoints to allow gas turbine operation atvarious firing temperatures. The temperature–refer-ence–select program (Figure 12) determines the op-erational level for control setpoints based on digitalinput information representing temperature controlrequirements. Three digital input signals are de-coded to select one set of constants which define thecontrol setpoints necessary to meet those require-ments. Typical digital signals are “BASE SE-LECT”, “PEAK SELECT” and “HEAVY FUELSELECT” and are selected by clicking on the ap-propriate target on the operator interface CRT. Forexample, the “PEAK SELECT” signal determinesoperation at PEAK (vs. BASE) firing temperature.When the appropriate set of constants are selected,they are stored in the selected–temperature–refer-ence memory.

FUEL CONTROL SYSTEM

The gas turbine fuel control system will change fuelflow to the combustors in response to the fuel strokereference signal (FSR). FSR actually consists of twoseparate signals added together, FSR1 being thecalled–for liquid fuel flow and FSR2 being thecalled–for gas fuel flow; normally, FSR1 + FSR2 =FSR. Standard fuel systems are designed for opera-tion with liquid fuel and/or gas fuel. This chapterwill describe a dual fuel system. It starts with the ser-vo drive system, where the setpoint is comparedwith the feedback signal and converted to a valve

DIGITALINPUT DATA

CONSTANTSTORAGE

TEMPERATUREREFERENCE

SELECT

SELECTEDTEMPERATURE

Figure 12 Temperature Reference Select Program

id0106

REFERENCETABLE

GE Power Systems


A00023 rev.A 8/16/93

position. It will describe liquid, gas and dual fuel op-eration and how the FSR from the control systemspreviously described is conditioned and sent as a setpoint to the servo system.

Servo Drive System

The heart of the fuel system is a three coil electro–hydraulic servovalve (servo) as shown in Figure 13.The servovalve is the interface between the electri-cal and mechanical systems and controls the direc-tion and rate of motion of a hydraulic actuator basedon the input current to the servo.

Â

3-COIL TORQUE MOTOR

TORQUE

FORCEFEEDBACKSPRING

SPOOL VALVE

1350 PSI

HYDRAULICACTUATOR

TO <RST> LVDT

DRAIN PS

TORQUEMOTOR

JET TUBE

FAILSAFEBIASSPRING

MOTORARMATURE

P

1 2

N N

S S

R P

id0029

FILTER

��

Figure 13 Electrohydraulic Servovalve

The servovalve contains three electrically isolatedcoils on the torque motor. Each coil is connected toone of the three Controllers <RST>. This providesredundancy should one of the Controllers or coilsfail. There is a null–bias spring which positions theservo so that the actuator will go to the fail safe posi-tion should ALL power and/or control signals belost.

If the hydraulic actuator is a double–action piston,the control signal positions the servovalve so that itports high–pressure oil to either side of the hydraulicactuator. If the hydraulic actuator has spring return,hydraulic oil will be ported to one side of the cylin-der and the other to drain. A feedback signal pro-vided by a linear variable differential transformer(LVDT, Figure 13) will tell the control whether ornot it is in the required position. The LVDT outputsan AC voltage which is proportional to the positionof the core of the LVDT. This core in turn is con-nected to the valve whose position is being con-trolled; as the valve moves, the feedback voltagechanges. The LVDT requires an exciter voltagewhich is provided by the TCQC card.

Figure 14 shows the major components of the servopositioning loops. The digital (microprocessor sig-nal) to analog conversion is done on the TCQA card;this represents called–for fuel flow. The called–forfuel flow signal is then compared to a feedback rep-resenting actual fuel flow. The difference is ampli-fied on the TCQC card and sent through the QTBAcard to the servo. This output to the servos is moni-tored and there will be an alarm on loss of any one ofthe three signals from <RST>.

Liquid Fuel Control

The liquid fuel system consists of fuel handlingcomponents and electrical control components.Some of the fuel handling components are: primaryfuel oil filter (low pressure), fuel oil stop valve, fuelpump, fuel bypass valve, fuel pump pressure reliefvalve, secondary fuel oil filter (high pressure), flowdivider, combined selector valve/pressure gauge as-sembly, false start drain valve, fuel lines, and fuelnozzles. The electrical control components are: liq-uid fuel pressure switch (upstream) 63FL–2, fuel oilstop valve limit switch 33FL, fuel pump clutch sole-noid 20CF, liquid fuel pump bypass valve servo-valve 65FP, flow divider magnetic speed pickups77FD–1, –2, –3 and SPEEDTRONIC control cardsTCQC and TCQA. A diagram of the system show-ing major components is shown in Figure 15.

The fuel bypass valve is a hydraulically actuatedvalve with a linear flow characteristic. Located

14

GE Industrial & Power Systems

ÂÂÂ

ÂÂÂ

ÂÂÂ

ÂÂÂ

A/D

Offset

Gain

A/D

Offset

Gain

A/D

Offset

Gain

Maxim

umof tw

oA

ssignedLV

DT

/Rs

D/A

126 Hz

TC

QA

<R>

Type 43 Regulator

DC

C_ <R

>

Control S

equence Program

TB

QC

<R>

PO

S3H

PO

S3L

TC

QC

<R>

QT

BA

<R>

7.0 Vrm

s @ 3.2 K

Hz

GC

VA

ctuatorLV

DT

’S

Gas C

ontrol Valve

Servovalve 65G

C

GC

V – G

as Control V

alve

from S

RV

to manifold

Servovalve com

mand

LVD

T E

xcitation

LVD

T F

eedback

Typical Servovalve C

ontrol Loop

GE Power Systems


A00023 rev. A 8/16/93

between the inlet (low pressure) and discharge (highpressure) sides of the fuel pump, this valve bypassesexcess fuel delivered by the fuel pump back to thefuel pump inlet, delivering to the flow divider the

fuel necessary to meet the control system fuel de-mand. It is positioned by servo valve 65FP, whichreceives its signal from the controllers.

63FL-2

Figure 15 Liquid Fuel Control Schematic

id0031V

DIFFERENTIALPRESSURE GUAGE

COMBUSTIONCHAMBER

FLOWDIVIDER

ACCESSORYGEARDRIVE

MAIN FUEL PUMP

FQROUT

BY-PASS VALVE ASM.

TYPICALFUEL NOZZLES

OFV

FSR1

TNHL4L20FLX

OHHYDRAULIC

SUPPLY

FUELSTOPVALVE VR4

OLT-CONTROL

OIL

FALSE STARTDRAIN VALVE

CHAMBER OFD

TO DRAIN

FQ1 <RST>

<RST>

OF

P R 65FP

33FL

PR/A

<RST>

CONN. FOR PURGEWHEN REQUIRED

ATOMIZINGAIR

40µ

77FD-3

AD

77FD-1

77FD-2

TCQATCQC

TCQA

The flow divider divides the single stream of fuelfrom the pump into several streams, one for eachcombustor. It consists of a number of matched highvolumetric efficiency positive displacement gearpumps, again one per combustor. The flow divider isdriven by the small pressure differential between theinlet and outlet. The gear pumps are mechanicallyconnected so that they all run at the same speed,making the discharge flow from each pump equal.Fuel flow is represented by the output from the flowdivider magnetic pickups (77FD–1, –2 & –3). Theseare non–contacting magnetic pickups, giving apulse signal frequency proportional to flow dividerspeed, which is proportional to the fuel flow deliv-ered to the combustion chambers.

The TCQA card receives the pulse rate signals from77FD–1, –2, and –3 and outputs an analog signalwhich is proportional to the pulse rate input. The

TCQC card modulates servovalve 65FP based on in-puts of turbine speed, FSR1 (called–for liquid fuelflow), and flow divider speed (FQ1).

Fuel Oil Control – Software

When the turbine is run on liquid fuel oil, the controlsystem checks the permissives L4 and L20FLX anddoes not allow FSR1 to close the bypass valve unlessthey are ‘true’ (closing the bypass valve sends fuel tothe combustors). The L4 permissive comes from theMaster Protective System (to be discussed later) andL20FLX becomes ‘true’ after the turbine vent timertimes out. These signals control the opening andclosing of the fuel oil stop valve. The fuel pumpclutch solenoid (20CF) is energized to drive thepump when the stop valve opens.

The FSR signal from the controlling system goesthrough the fuel splitter where the liquid fuel re-

GE Power Systems


A00023 rev. A 8/16/93

quirement becomes FSR1. The FSR1 signal is mul-tiplied by TNH, so fuel flow becomes a function ofspeed – an important feature, particularly while theunit is starting. This enables the system to have bet-ter resolution at the lower, more critical speedswhere air flow is very low. This produces theFQROUT signal, which is the digital liquid fuelflow command. At full speed TNH does not change,therefore FQROUT is directly proportional to FSR.

FQROUT then goes to the TCQA card where it ischanged to an analog signal to be compared to thefeedback signal from the flow divider. As the fuelflows into the turbine, speed sensors 77FD–1, –2,and –3 send a signal to the TCQA card, which in turnoutputs the fuel flow rate signal (FQ1) to the TCQCcard. When the fuel flow rate is equal to the called–for rate (FQ1 = FSR1), the servovalve 65FP ismoved to the null position and the bypass valve re-mains “stationary” until some input to the systemchanges. If the feedback is in error with FQROUT,the operational amplifier on the TCQC card willchange the signal to servovalve 65FP to drive the by-pass valve in a direction to decrease the error.

The flow divider feedback signal is also used forsystem checks. This analog signal is converted todigital counts and is used in the controller’s softwareto compare to certain limits as well as to display fuelflow on the CRT. The checks made are as follows:

1. L60FFLH:Excessive fuel flow on start–up

2. L3LFLT1:Loss of LVDT position feedback(MS7–1 & MS9–1)

3. L3LFBSQ:Bypass valve is not fully open whenthe stop valve is closed.

4. L3LFBSC:Servo current is detected when thestop valve is closed.

5. L3LFT:Loss of flow divider feedback

If L60FFLH is true for a specified time period (nom-inally 2 seconds), the unit will trip; if L3LFLT1through L3LFT are true, these faults will trip the unitduring start–up and require manual reset.

Gas Fuel Control

Fuel gas is controlled by the gas speed ratio/stopvalve (SRV) and gas control valve (GCV) assembly.In all but the F–series machines, two valves are com-bined in this assembly as shown on Figure 16; thetwo valves are physically separate on the F–seriesmachines. Both are servo controlled by signals fromthe SPEEDTRONIC control panel and actuated bysingle–acting hydraulic cylinders moving againstspring–loaded valve plugs.

CONTROL

THREEREDUNDANT

GASPRESSURE

TRANS-DUCERS

STRAINER

PKG LK OFF

96FG–2A, B, C

GASSPEED RATIO/STOP VALVE

RING MANIFOLD

VENT TOATMOSPHERE

TOATMOSPHERE FUEL

NOZZLES

(TYPICAL)

MS3002 2 Manifolds 3 NozzlesMS5001 1 Manifold 10 NozzlesMS5002 1 Manifold 12 NozzlesMS6001 1 Manifold 10 NozzlesMS7001 1 Manifold 10 NozzlesMS9001 1 Manifold 14 NozzlesVALVE

Figure 16 Gas Fuel Systemid0051

PKG LK OFF

20VG–1

It is the gas control valve which controls the desiredgas fuel flow in response to the command signalFSR. To enable it to do this in a predictable manner,the speed ratio valve is designed to maintain a prede-termined pressure (P2) at the inlet of the gas controlvalve as a function of gas turbine speed.

The fuel gas control system consists primarily of thefollowing components: gas strainer, gas supplypressure switch 63FG, speed ratio/stop valve assem-bly, fuel gas pressure transducer(s) 96FG, gas fuelvent solenoid valve 20VG, control valve assembly,LVDT’s 96GC–1, –2 and 96SR–1, –2, electro–hy-draulic servovalves 90SR and 65GC, dump valve(s)VH–5, three pressure gauges, gas manifold with‘pigtails’ to respective fuel nozzles, and SPEED-TRONIC control cards TBQB and TCQC. The com-ponents are shown interconnected schematically inFigure 17. A functional explanation of each subsys-tem is contained in subsequent paragraphs.

GE Power Systems


A00023 rev. A 8/16/93

96FG-2A

96FG-2B

96FG-2C

id0059V

96SR-1,2 96GC-1,2

LVDT’S

GASMANIFOLD

COMBUSTIONCHAMBER

HYDRAULICSUPPLY

GAS

STOP/RATIOVALVE

SPEED RATIOVALVE CONTROL

GAS CONTROLVALVE SERVO

20VG

VENT

GAS CONTROLVALVE POSITION

FEEDBACK

GASCONTROL

VALVE

TRANSDUCERS

POS1

FSR2

FPG

63FG-3

LVDT’S

FPRG

Figure 17 Gas Fuel Control System

P2

VH5-1 DUMPRELAY

TRIP

90SR SERVO65GC SERVO

ElectricalConnection HydraulicPiping

Gas Piping

POS2

TCQCTCQC TCQC

TBQB

GE Power Systems


A00023 rev. A 8/16/93

Gas Control Valve

The position of the gas control valve plug is intendedto be proportional to FSR2 which represents called–for gas fuel flow. Actuation of the spring–loaded gascontrol valve is by a hydraulic cylinder controlled byan electro–hydraulic servovalve.

When the turbine is to run on gas fuel the permis-sives L4, L20FGX and L2TVX (turbine purge com-plete) must be ‘true’, similar to the liquid system.This allows the Gas Control Valve to open. Thestroke of the valve will be proportional to FSR.

FSR goes through the fuel splitter (to be discussed inthe dual fuel section) where the gas fuel requirementbecomes FSR2, which is then conditioned for offsetand gain. This signal, FSROUT, goes to the TCQC

card where it is converted to an analog signal. Thegas control valve stem position is sensed by the out-put of a linear variable differential transformer(LVDT) and fed back to an operational amplifier onthe TCQC card where it is compared to the FSROUTinput signal at a summing junction. There are twoLVDTs providing feedback ; two of the three con-trollers are dedicated to one LVDT each, while thethird selects the highest feedback through a high–se-lect diode gate. If the feedback is in error withFSROUT, the operational amplifier on the TCQCcard will change the signal to the hydraulic servo-valve to drive the gas control valve in a direction todecrease the error. In this way the desired relation-ship between position and FSR2 is maintained andthe control valve correctly meters the gas fuel. SeeFigure 18.

OFFSET

GAIN

<RST>

FSR2

L4

L3GCVFSROUT

ANALOGI/O

GAS CONTROL VALVE

SERVOVALVE

GAS CONTROL VALVEPOSITION LOOPCALIBRATION

PO

SIT

ION

LVD

T

FSR

LVDT’S96GC-1, -2

<RST>

GASP2

++

id0027V

HIGHSELECT

Figure 18 Gas Control Valve Control Schematic

ELECTRICAL CONNECTION

GAS PIPING

HYDRAULIC PIPING

ÎÎÎÎÎÎÎÎÎ

TBQC

GE Power Systems


A00023 rev. A 8/16/93

GAIN

<RST>

ANALOGI/O

TNH

LVDT’S

<RST>

Figure 19 Speed Ratio/Stop Valve Control Schematic

TRIP OIL

OFFSET

ÎÎÎÎÎÎÎÎÎ

++

ELECTRICALCONNECTION

GAS PIPING

HYDRAULICPIPING

DIGITAL

LEGEND

MODULE

OPERATINGCYLINDER

PISTON

SPEED RATIO VALVE

GAS

POS2

FPRG

AD

HIGHSELECT

HYDRAULICOIL

TNH

L4

L3GRV

96SR-1,2

SERVOVALVE

DUMPRELAY

FPG

P2 or PRESSURE

CONTROL VOLTAGE

Speed Ratio Valve Pressure Calibrationid0058V

96FG-2A

96FG-2B

96FG-2C

TBQB

GE Power Systems


A00023 rev. A 8/16/93

The plug in the gas control valve is contoured to pro-vide the proper flow area in relation to valve stroke.The gas control valve uses a skirted valve disc andventuri seat to obtain adequate pressure recovery.High pressure recovery occurs at overall valve pres-sure ratios substantially less than the critical pres-sure ratio. The net result is that flow through thecontrol valve is independent of valve pressure drop.Gas flow then is a function of valve inlet pressure P2and valve area only.

As before, an open or a short circuit in one of the ser-vo coils or in the signal to one coil does not cause atrip. The GCV has two LVDTs and can run correctlyon one.

Speed Ratio/Stop Valve

The speed ratio/stop valve is a dual function valve. Itserves as a pressure regulating valve to hold a de-sired fuel gas pressure ahead of the gas control valveand it also serves as a stop valve. As a stop valve it isan integral part of the protection system. Any emer-gency trip or normal shutdown will move the valveto its closed position shutting off gas fuel flow to theturbine. This is done either by dumping hydraulic oilfrom the Speed Ratio Valve VH–5 hydraulic triprelay or driving the position control closed electri-cally.

The speed ratio/stop valve has two control loops.There is a position loop similar to that for the gascontrol valve and there is a pressure control loop.See Figure 19. Fuel gas pressure P2 at the inlet to thegas control valve is controlled by the pressure loopas a function of turbine speed. This is done by pro-portioning it to turbine speed signal TNH, with anoffset and gain, which then becomes Gas Fuel Pres-sure Reference FPRG. FPRG then goes to the TCQCcard to be converted to an analog signal. P2 pressureis measured by 96FG which outputs a voltage pro-portional to P2 pressure. This P2 signal (FPG) iscompared to the FPRG and the error signal (if any) isin turn compared with the 96SR LVDT feedback toreposition the valve as in the GCV loop.

The speed ratio/stop valve provides a positive stopto fuel gas flow when required by a normal shut–down, emergency trip, or a no–run condition. Hy-draulic trip dump valve VH–5 is located between theelectro–hydraulic servovalve 90SR and the hydrau-lic actuating cylinder. This dump valve is operatedby the low pressure control oil trip system. If permis-sives L4 and L3GRV are ‘true’ the trip oil (OLT) is atnormal pressure and the dump valve is maintained ina position that allows servovalve 90SR to control thecylinder position. When the trip oil pressure is low(as in the case of normal or emergency shutdown),the dump valve spring shifts a spool valve to a posi-tion which dumps the high pressure hydraulic oil(OH) in the speed ratio/stop valve actuating cylinderto the lube oil reservoir. The closing spring atop thevalve plug instantly shuts the valve, thereby shuttingoff fuel flow to the combustors.

In addition to being displayed, the feedback signalsand the control signals of both valves are comparedto normal operating limits, and if they go outside ofthese limits there will be an alarm. The following aretypical alarms:

1. L60FSGH: Excessive fuel flow on start–up

2. L3GRVFB: Loss of LVDT feedback on the SRV

3. L3GRVO: SRV open prior to permissive to open

4. L3GRVSC: Servo current to SRV detected priorto permissive to open

5. L3GCVFB: Loss of LVDT feedback on theGCV

6. L3GCVO: GCV open prior to permissive toopen

7. L3GCVSC: Servo current to GCV detectedprior to permissive to open

8. L3GFIVP: Intervalve (P2) pressure low

The servovalves are furnished with a mechanicalnull offset bias to cause the gas control valve orspeed ratio valve to go to the zero stroke position(fail safe condition) should the servovalve signals orpower be lost. During a trip or no–run condition, apositive voltage bias is placed on the servo coilsholding them in the ‘valve closed’ position.

GE Power Systems


A00023 rev. A 8/16/93

Dual Fuel Control

Turbines that are designed to operate on both liquidand gaseous fuel are equipped with controls to pro-vide the following features:

1. Transfer from one fuel to the other on command.

2. Allow time for filling the lines with the type offuel to which turbine operation is being trans-ferred.

3. Mixed fuel operation.

4. Operation of liquid fuel nozzle purge when op-erating totally on gas fuel.

The software diagram for the fuel splitter is shown inFigure 20.

Figure 20 Fuel Splitter Schematic

RAMP

L84TGTOTAL GASL84TLTOTAL LIQUID

MEDIANSELECT

MAX. LIMIT

L83FZPERMISSIVES

L83FGGAS SELECTL83FLLIQUID SELECT

FSR

FUEL SPLITTER<RST>

A=B

MIN. LIMIT

FSR1LIQUID REF.

FSR2GAS REF.

A=B

RATE

id0034

Fuel Splitter

As stated before FSR is divided into two signals,FSR1 and FSR2, to provide dual fuel operation. SeeFigure 20.

FSR is multiplied by the liquid fuel fraction FX1 toproduce the FSR1 signal. FSR1 is then subtractedfrom the FSR signal resulting in FSR2, the controlsignal for the secondary fuel.

Fuel Transfer – Liquid to Gas

If the unit is running on liquid fuel (FSR1) and the“GAS” membrane switch is pressed to select gasfuel, the following sequence of events will takeplace, providing the transfer and fuel gas permis-sives are true (refer to Figure 21):

FSR1 will remain at its initial value, but FSR2 willstep to a value slightly greater than zero, usually0.5%. This will open the gas control valve slightly tobleed down the intervalve volume. This is done incase a high pressure has been entrained. The pres-ence of a higher pressure than that required by thespeed/ratio controller would cause slow response ininitiating gas flow.

Transfer from Full Gas to Full Distillate

Transfer from Full Distillate to Full Gas

Transfer from Full Distillate to Mixture

UN

ITS

FSR2

FSR1

PURGETIME

SELECT DISTILLATE

SELECT GAS

SELECT GAS SELECT MIX

FSR1

FSR2

PURGE

FSR1

FSR2

PURGE

TIME

TIME

UN

ITS

UN

ITS

id0033

Figure 21 Fuel Transfer

After a typical time delay of thirty seconds to bleeddown the P2 pressure and fill the gas supply line, thesoftware program ramps the fuel commands, FSR2to increase and FSR1 to decrease, at a programmedrate through the median select gate. This is completein thirty seconds.

GE Power Systems


A00023 rev. A 8/16/93

When the transfer is complete logic signal L84TG(Total Gas) will disengage the fuel pump clutch20CF, close the fuel oil stop valve by de–energizingthe liquid fuel dump valve 20FL, and initiate thepurge sequence.

Liquid Fuel Purge

To prevent coking of the liquid fuel nozzles whileoperating on gas fuel, some atomizing air is divertedthrough the liquid fuel nozzles. See Figure 22. Thefollowing sequence of events occurs when transferfrom liquid to gas is complete.

The atomizing air bypass valve VA18 is opened byenergizing 20AA. This results in a purge pressure ra-tio across the fuel nozzles of 1:1, resulting in a smallvolume of liquid fuel flow being purged into thecombustors.

After a 10 second time delay which permits reachingsteady state nozzle pressure ratio, purge valveVA19–1 is actuated by energizing solenoid valve20PL–1. This results in a higher cooling/purging airflow through the liquid fuel nozzles.

20PL-1

FROM ATOMIZINGAIR PRECOOLER

20AA

TO INLET OFATOMIZING

AIR PRECOOLER(RECIRCULATION)

ORIFICE

VA18BLOW-OFFTO ATOMS.

PITCH

AA

PITCH

TELL TALELEAKOFF

TO LIQUIDNOZZLES

PURGE AIR MANIFOLD

FROMATOMIZINGAIR COMPRESSOR

VA19-1

Figure 22 Dual Fuel Liquid Fuel Nozzle Purge System

AV

AV

id0039ORIFICE

PC

The time delay is needed to reduce the load spikewhich occurs when the liquid fuel is purged into thecombustion chamber.

Fuel Transfer – Gas to Liquid

Transfer from gas to liquid is essentially the same se-quence as previously described, except that gas andliquid fuel command signals are interchanged. Forinstance, at the beginning of a transfer, FSR2 re-mains at its initial value, but FSR1 steps to a valueslightly greater than zero. This will command asmall liquid fuel flow. If there has been any fuel leak-age out past the check valves, this will fill the liquid

fuel piping and avoid any delay in delivery at the be-ginning of the FSR1 increase.

The rest of the sequence is the same as liquid–to–gas, except that there is usually no purging se-quence.

Mixed Fuel Operation

Gas turbines may be operated on a mixture of liquidand gas fuel. Operation on a selected mixture is ob-tained by entering the desired mixture at the operatorinterface and then selecting ‘MIX’.

Limits on the fuel mixture are required to ensureproper combustion, gas fuel distribution, and gasnozzle flow velocities. Percentage of gas flow must

GE Power Systems


A00023 rev. A 8/16/93

be increased as load is decreased to maintain theminimum pressure ratio across the fuel nozzle.

MODULATED INLET GUIDE VANESYSTEM

The Inlet Guide Vanes (IGVs) modulate during theacceleration of the gas turbine to rated speed, load-

ing and unloading of the generator, and decelerationof the gas turbine. This IGV modulation maintainsproper flows and pressures, and thus stresses, in thecompressor, maintains a minimum pressure dropacross the fuel nozzles, and, when used in a com-bined cycle application, maintains high exhausttemperatures at low loads.

<RST>

CSRGVD/A

HIGHSELECT

ANALOGI/O

CLOSE

OPENHYD.SUPPLY

IN OUTFH6–1

<RST>

R P

2 1

HM3-1

96TV-1,2

D

OD

ORIFICES (2)

90TV-1

VH3-1

A

OLT-1TRIP OILC1

C2

Figure 23 Modulating Inlet Guide Vane Control Schematic

id0030

CSRGV

CSRGVOUTIGV REF

Guide Vane Actuation

The modulated inlet guide vane actuating system iscomprised of the following components: servovalve90TV, LVDT position sensors 96TV–1 and

96TV–2, and, in some instances, solenoid valve20TV and hydraulic dump valve VH3. Control of90TV will port hydraulic pressure to operate thevariable inlet guide vane actuator. If used, 20TV andVH3 can prevent hydraulic oil pressure from flow-ing to 90TV. See Figure 23.

GE Power Systems


A00023 rev. A 8/16/93

Operation

During start–up, the inlet guide vanes are held fullyclosed, a nominal 34 degree angle, from zero to83.5% corrected speed. Turbine speed is correctedto reflect air conditions at 80° F; this compensatesfor changes in air density as ambient conditionschange. At ambient temperatures greater than 80° F,corrected speed TNHCOR is less than actual speedTNH; at ambients less than 80° F, TNHCOR isgreater than TNH. After attaining a speed of approx-imately 83.5%, the guide vanes will modulate openat about 6.7 degrees per percent increase in correctedspeed. When the guide vanes reach the minimumfull speed angle, nominally 57°, they stop opening;this is usually at approximately 91% TNH. By notallowing the guide vanes to close to an angle lessthan the minimum full speed angle at 100% TNH, aminimum pressure drop is maintained across thefuel nozzles, thereby lessening combustion systemresonance. Solenoid valve 20CB is usually openedwhen the generator breaker is closed; this in turncloses the compressor bleed valves.

As the unit is loaded and exhaust temperature in-creases, the inlet guide vanes will go to the full openposition when the exhaust temperature reaches oneof two points, depending on the operation mode se-lected. For simple cycle operation, the IGVs move tothe full open position at a pre–selected exhaust tem-perature, usually 700° F. For combined cycle opera-tion, the IGVs begin to move to the full openposition as exhaust temperature approaches the tem-perature control reference temperature; normally,the IGVs begin to open when exhaust temperature iswithin 30° F of the temperature control reference.

During a normal shutdown, as the exhaust tempera-ture decreases the IGVs move to the minimum fullspeed angle; as the turbine decelerates from 100%TNH, the inlet guide vanes are modulated to the ful-ly closed position. When the generator breakeropens, the compressor bleed valves will be opened.

In the event of a turbine trip, the compressor bleedvalves are opened and the inlet guide vanes go to the

fully closed position. The inlet guide vanes remainfully closed as the turbine continues to coast down.

For underspeed operation, if TNHCOR decreasesbelow approximately 91%, the inlet guide vanesmodulate closed at 6.7 degrees per percent decreasein corrected speed. In most cases, the MS5001 beingan exception, if the actual speed decreases below95% TNH, the generator breaker will open and theturbine speed setpoint will be reset to 100.3%. TheIGVs will then go to the minimum full speed angle.See Figure 24.

IGV

AN

GLE

– D

EG

RE

ES

(C

SR

GV

)

FULL OPEN (MAX ANGLE)

MINIMUM FULL SPEED ANGLE

REGION OF NEGATIVE5TH STAGE EXTRACTIONPRESSURE

ROTATINGSTALL

REGION

FULL CLOSED(MIN ANGLE)

0CORRECTED SPEED–%

100

0

FSNLEXHAUST TEMPERATURE

BASE LOAD

100LOAD–%

STARTUPPROGRAM

SIMPLE CYCLE(CSKGVSSR)

COMBINEDCYCLE

(TTRX)

Figure 24 Variable Inlet Guide Vane Schedule

id0037

(TNHCOR)

PROTECTION SYSTEMS

The gas turbine protection system is comprised of anumber of sub–systems, several of which operateduring each normal start–up and shutdown. The oth-er systems and components function strictly duringemergency and abnormal operating conditions. Themost common kind of failure on a gas turbine is thefailure of a sensor or sensor wiring; the protectionsystems are set up to detect and alarm such a failure.If the condition is serious enough to disable theprotection completely, the turbine will be tripped.

Protective systems respond to the simple trip signalssuch as pressure switches used for low lube oil pres-sure, high gas compressor discharge pressure, orsimilar indications. They also respond to more com-

GE Power Systems


A00023 rev. A 8/16/93

plex parameters such as overspeed, overtempera-ture, high vibration, combustion monitor, and loss offlame. To do this, some of these protection systemsand their components operate through the mastercontrol and protection circuit in the SPEEDTRON-IC control system, while other totally mechanicalsystems operate directly on the components of the

turbine. In each case there are two essentially inde-pendent paths for stopping fuel flow, making use ofboth the fuel control valve (FCV) and the fuel stopvalve (FSV). Each protective system is designed in-dependent of the control system to avoid the possi-bility of a control system failure disabling theprotective devices. See Figure 25.

VIBRATION

OVERSPEED

OVERTEMP

COMBUSTIONMONITOR

MASTERPROTECTION GAS FUEL

CONTROL VALVE

20FG

CIRCUIT<RST>

MASTERPROTECTION

CIRCUIT<XYZ>

GAS FUELSPEED RATIO/STOP VALVE

FUELPUMP

Figure 25 Protective Systems Schematic

id0036V

LIQUIDFUEL STOPVALVE

RELAY

MODULEVOTING

RELAY

MODULEVOTING 20FL

SRVSERVOVALVE

GCVSERVOVALVE

SERVOVALVE

BYPASSVALVE

PRIMARY

OVERSPEEDSECONDARY

FLAME

LOSSof

Trip Oil

A hydraulic trip system called Trip Oil is the primaryprotection interface between the turbine control andprotection system and the components on the tur-bine which admit, or shut–off, fuel. The system con-tains devices which are electrically operated bySPEEDTRONIC control signals as well as some to-tally mechanical devices.

Besides the tripping functions, trip oil also providesa hydraulic signal to the fuel stop valves for normalstart–up and shutdown sequences. On gas turbinesequipped for dual fuel (gas and oil) operation the

system is used to selectively isolate the fuel systemnot required.

Significant components of the Hydraulic Trip Cir-cuit are described below.

Mechanical Overspeed Trip

This is a totally mechanical device located in the ac-cessory gearbox and is actuated automatically by theoverspeed bolt if the unit’s speed exceeds the bolt’ssetting. The result is a rapid decay of trip oil pressurewhich stops all fuel flow to the unit. See Figure 26and the Overspeed Protection System.

GE Power Systems


A00023 rev. A 8/16/93

Inlet Orifice

An orifice is located in the line running from thebearing header supply to the trip oil system. This ori-fice is sized to limit the flow of oil from the lube oilsystem into the trip oil system. It must ensure ade-quate capacity for all tripping devices, yet preventreduction of lube oil flow to the gas turbine and otherequipment when the trip system is in the trippedstate.

Dump Valve

Each individual fuel branch in the trip oil system hasa solenoid dump valve (20FL for liquid, 20FG forgas). This device is a solenoid–operated spring–re-turn spool valve which will relieve trip oil pressureonly in the branch that it controls. These valves arenormally energized–to–run, deenergized–to–trip.This philosophy protects the turbine during all nor-mal situations as well as that time when loss of dcpower occurs.

PROTECTIVESIGNALS

MASTERPROTECTION

L4CIRCUITS

INLET ORIFICE

OVERSPEEDTRIP

RESET

MANUALTRIP

MANUAL TRIP

LIQUIDFUEL

LIQUID FUELSTOP VALVE

OH

20FG 20FL

GAS FUELSPEED RATIO/GAS

FUEL

GAS FUELDUMP RELAY

VALVE

WIRING

PIPING

ORIFICE ANDCHECK VALVE

NETWORK

(WHEN PROVIDED)

12HA

63HG

63HL

Figure 26 Trip Oil Schematic – Dual Fuel

id0056

STOP VALVE

Check Valve & Orifice Network

At the inlet of each individual fuel branch is a checkvalve and orifice network which limits flow out ofthat branch. This network limits flow into eachbranch, thus allowing individual fuel control with-out total system pressure decay. However, when oneof the trip devices located in the main artery of thesystem, e.g., the overspeed trip, is actuated, thecheck valve will open and result in decay of all trippressures.

Pressure Switches

Each individual fuel branch contains pressureswitches (63HL–1,–2,–3 for liquid, 63HG–1,–2,–3

for gas) which will ensure tripping of the turbine ifthe trip oil pressure becomes too low for reliable op-eration while operating on that fuel.

Operation

The tripping devices which cause unit shutdown orselective fuel system shutdown do so by dumpingthe low pressure trip oil (OLT). See Figure 26. An in-dividual fuel stop valve may be selectively closed bydumping the flow of trip oil going to it. Solenoidvalve 20FL can cause the trip valve on the liquid fuelstop valve to go to the trip state, which permits clo-sure of the liquid fuel stop valve by its spring returnmechanism. Solenoid valve 20FG can cause the tripvalve on the gas fuel speed ratio/stop valve to go to

GE Power Systems


A00023 rev. A 8/16/93

the trip state, permitting its spring–returned closure.The orifice in the check valve and orifice networkpermits independent dumping of each fuel branch ofthe trip oil system without affecting the otherbranch. Tripping all devices other than the individu-al dump valves will result in dumping the total tripoil system, which will shut the unit down.

During start–up or fuel transfer, the SPEEDTRON-IC control system will close the appropriate dumpvalve to activate the desired fuel system(s). Bothdump valves will be closed only during fuel transferor mixed fuel operation.

The dump valves are de–energized on a “2–out–of–3 voted” trip signal from the relay module. Thishelps prevent trips caused by faulty sensors or thefailure of one controller.

The signal to the fuel system servovalves will alsobe a “close” command should a trip occur. This isdone by clamping FSR to zero. Should one control-ler fail, the FSR from that controller will be zero.The output of the other two controllers is sufficientto continue to control the servovalve.

By pushing the Emergency Trip Button, 5E P/B, theP28 vdc power supply is cut off to the relays control-ling solenoid valves 20FL and 20FG, thus de–ener-gizing the dump valves.

Overspeed Protection

The SPEEDTRONIC Mark V overspeed system isdesigned to protect the gas turbine against possibledamage caused by overspeeding the turbine rotor.Under normal operation, the speed of the rotor iscontrolled by speed control. The overspeed systemwould not be called on except after the failure of oth-er systems.

The overspeed protection system consists of a pri-mary and secondary electronic overspeed system.The primary electronic overspeed protection systemresides in the <RST> controllers. The secondaryelectronic overspeed protection system resides inthe <XYZ> controllers. Both systems consist ofmagnetic pickups to sense turbine speed, speed

detection software, and associated logic circuits andare set to trip the unit at 110% rated speed.

There is also a mechanical overspeed protection sys-tem on all units except for F–model heavy–duty andaero–derivatives. This consists of the overspeed boltassembly in an accessory gear shaft and the over-speed trip mechanism. This system should be set totrip the unit at 112.5% rated speed. All systems oper-ate to trip the fuel stop valves and, redundantly, drivethe FSR command to zero.

Electronic Overspeed Protection System

The electronic overspeed protection function is per-formed in both <RST> and <XYZ> as shown in Fig-ure 27. The turbine speed signal (TNH) derived fromthe magnetic pickup sensors (77NH–1,–2, and –3) iscompared to an overspeed setpoint (TNKHOS).When TNH exceeds the setpoint, the overspeed tripsignal (L12H) is transmitted to the master protectivecircuit to trip the turbine and the “ELECTRICALOVERSPEED TRIP” message will be displayed onthe CRT. This trip will latch and must be reset by themaster reset signal L86MR.

TNKHOSSETAND

LATCH

RESET

HIGH PRESSURE OVERSPEED TRIP

HP SPEEDTNHA

A>BB

<RST> <XYZ>

Figure 27 Electronic Overspeed Trip

TNKHOST

LH3HOST

L86MR1

TRIP SETPOINT

TEST

TESTPERMISSIVE

MASTER RESET

SAMPLING RATE = 0.25 SEC

L12H TO MASTERPROTECTIONAND ALARMMESSAGE

id0060

Mechanical Overspeed Protection System

The mechanical overspeed protection system con-sists of the following principal components:

1. Overspeed bolt assembly in the accessory gearshaft

2. Overspeed trip mechanism in the accessory gear

3. Position limit switch 12HA

The mechanical overspeed protection system is thebackup for the electronic overspeed protection sys-

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A00023 rev. A 8/16/93

tem. As the backup system, the trip speed setting ishigher than the primary or electronic overspeedprotection setting. For the most part the mechanicaloverspeed protection system is an integral part of thegas turbine unit and will trip the fuel stop valvesclosed when the turbine speed is at, or exceeds, thetrip setting of the overspeed bolt assembly. This tripaction is totally independent of the electronic con-nections in the turbine control panel. Whenever thistrip is actuated an alarm will occur.

Overspeed Bolt Assembly

An overspeed bolt assembly mounted in an accesso-ry gear shaft is used to sense the overspeed of the gasturbine. It is a spring–loaded, eccentrically locatedbolt assembled in a cartridge and designed so thatthe spring force holds the bolt in the seated positionuntil the trip speed is reached. As the shaft speed in-creases, centrifugal force acting on the bolt is bal-anced by the spring force within the bolt assemblyand the bolt remains seated. Further increase of theshaft speed causes the centrifugal force on the bolt toexceed the spring force and the bolt moves outwardin less than one shaft revolution where it contactsand trips the overspeed trip mechanism. The springforce can be adjusted so that the overspeed bolt willtrip at a specified shaft speed.

Overspeed Trip Mechanism

The overspeed trip mechanism for the turbine shaftis also mounted in the accessory gear, adjacent to theoverspeed bolt assembly. When actuated, the over-speed bolt assembly trips the latching trip finger ofthe overspeed trip mechanism. This action releasesthe trip valve in the mechanism and dumps the tripoil system pressure to drain, which in turn closes thetrip valves controlling the fuel stop valves. This inturn dumps the hydraulic control oil from the stopvalve actuating cylinders to drain, thus closing thevalves. This also prevents hydraulic pressure fromre–opening the valves. See Figure 28.

The overspeed trip mechanism may be trippedmanually and must be reset manually. The trip but-ton and the reset handle are mounted with the over-

OLT

12 HA

OD

OVERSPEED BOLT

MANUALTRIP

MANUALRESET

Figure 28 Mechanical Overspeed Trip

id0047

speed trip mechanism limit switch 12HA on theoutside of the accessory gear.

Overtemperature Protection

The overtemperature system protects the gas turbineagainst possible damage caused by overfiring. It is abackup system, operating only after the failure of thetemperature control system.

Figure 29 Overtemperature Protection

id0053

TTKOT1 TRIP

TRIP MARGINTTKOT2

ALARM MARGINTTKOT3

EX

H T

EM

P

CPD/FSR

TTRX

Under normal operating conditions, the exhausttemperature control system acts to control fuel flowwhen the firing temperature limit is reached. In cer-tain failure modes however, exhaust temperatureand fuel flow can exceed control limits. Under suchcircumstances the overtemperature protection sys-tem provides an overtemperature alarm about 25° Fabove the temperature control reference. To avoidfurther temperature increase, it starts unloading thegas turbine. If the temperature should increase fur-ther to a point about 40° F above the temperaturecontrol reference, the gas turbine is tripped. For theactual alarm and trip overtemperature setpoints referto the Control Specifications. See Figure 29.

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A00023 rev. A 8/16/93

Overtemperature trip and alarm setpoints are deter-mined from the temperature control setpointsderived by the Exhaust Temperature Control soft-ware. See Figure 30.

TTKOT3

TTKOT2

TTKOT1TRIP ISOTHERMAL SET

ANDLATCH

RESET

TO ALARMMESSAGE

AND SPEEDSETPOINT

LOWER

OR

L30TXA

L86TXT

TRIPTO MASTER

PROTECTIONAND ALARMMESSAGE

ALARM

OVERTEMPERATURETRIP AND ALARM

SAMPLING RATE: 0.25 SEC.

TTXM

TTRXB

L86MR1

AA>B

B

AA>B

B

AA>B

B

<RST>

id0055

ALARM

Figure 30 Overtemperature Trip and Alarm

Overtemperature Protection Software

Overtemperature Alarm (L30TXA)

The representative value of the exhaust temperaturethermocouples (TTXM) is compared with alarm andtrip temperature setpoints. The “EXHAUST TEM-PERATURE HIGH” alarm message will be dis-played when the exhaust temperature (TTXM)exceeds the temperature control reference (TTRXB)plus the alarm margin (TTKOT3) programmed as aControl Constant in the software. The alarm will au-tomatically reset if the temperature decreases belowthe setpoint.

Overtemperature Trip (L86TXT)

An overtemperature trip will occur if the exhausttemperature (TTXM) exceeds the temperature con-trol reference (TTRXB) plus the trip margin(TTKOT2), or if it exceeds the isothermal trip set-point (TTKOT1). The overtemperature trip willlatch, the “EXHAUST OVERTEMPERATURETRIP” message will be displayed, and the turbinewill be tripped through the master protection circuit.The trip function will be latched in and the master re-

set signal L86MR1 must be true to reset and unlatchthe trip.

Flame Detection and Protection System

The SPEEDTRONIC Mark V flame detectors per-form two functions, one in the sequencing systemand the other in the protective system. During a nor-mal start–up the flame detectors indicate when aflame has been established in the combustion cham-bers and allow the start–up sequence to continue.Most units have four flame detectors, some havetwo, and a very few have eight. Generally speaking,if half of the flame detectors indicate flame and half(or less) indicate no–flame, there will be an alarmbut the unit will continue to run. If more than half in-dicate loss–of–flame, the unit will trip on “LOSS OFFLAME.” This avoids possible accumulation of anexplosive mixture in the turbine and any exhaustheat recovery equipment which may be installed.The flame detector system used with the SPEED-TRONIC Mark V system detects flame by sensingultraviolet (UV) radiation. Such radiation resultsfrom the combustion of hydrocarbon fuels and ismore reliably detected than visible light, which va-ries in color and intensity.

The flame sensor is a copper cathode detector de-signed to detect the presence of ultraviolet radiation.The SPEEDTRONIC control will furnish up to+350Vdc to drive the ultraviolet detector tube. In thepresence of ultraviolet radiation, the gas in the detec-tor tube ionizes and conducts current. The currentthrough the detector will discharge through circuityin the SPEEDTRONIC control until the drivingvoltage decreases to the point where the gas is nolonger ionized. This cycle continues as long as thereis ultraviolet radiation. The SPEEDTRONIC countsthe number of current pulses per second through theultraviolet sensor. If the number of pulses per se-cond exceeds a set threshold value, the SPEED-TRONIC generates a logic signal to indicate”FLAME DETECTED” by the sensor. Typically,there will be about 300 pulses/second when a strongultraviolet signal is present.

The flame detector system is similar to other protec-tive systems, in that it is self–monitoring. For exam-

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A00023 rev. A 8/16/93

ple, when the gas turbine is below L14HM allchannels must indicate “NO FLAME.” If this condi-tion is not met, the condition is annunciated as a“FLAME DETECTOR TROUBLE” alarm and theturbine cannot be started. After firing speed has beenreached and fuel introduced to the machine, if atleast half the flame detectors see flame the startingsequence is allowed to proceed. A failure of one de-tector will be annunciated as “FLAME DETECTORTROUBLE” when complete sequence is reached

and the turbine will continue to run. More than halfthe flame detectors must indicate “NO FLAME” inorder to trip the turbine.

Note that a short–circuited or open–circuited detec-tor tube will result in a “NO FLAME” signal. Theflame detection circuits are incorporated in the pro-tective module and is triple redundant, utilizingthree channels called <X>, <Y>, and <Z>.

28FDUV Scanner

TurbineProtection

Logic

FlameDetection

Logic

TurbineControlLogic

AnalogI/O

(FlameDetectionChannels)

CRTDisplay

SPEEDTRONIC Mk V Flame Detection

NOTE: Excitation for the sensors and signal processing isperformed by SPEEDTRONIC Mk V circuits

28FDUV Scanner

28FDUV Scanner

28FDUV Scanner

ido115Figure 31 SPEEDTRONIC Mk V Flame Detection

Vibration Protection

The vibration protection system of a gas turbine unitis composed of several independent vibration chan-

nels. Each channel detects excessive vibration bymeans of a seismic pickup mounted on a bearinghousing or similar location of the gas turbine and thedriven load. If a predetermined vibration level is ex-

GE Power Systems


A00023 rev. A 8/16/93

ceeded, the vibration protection system trips the tur-bine and annunciates to indicate the cause of the trip.

Each channel includes one vibration pickup (veloc-ity type) and a SPEEDTRONIC Mark V amplifiercircuit. The vibration detectors generate a relativelylow voltage by the relative motion of a permanentmagnet suspended in a coil and therefore no excita-tion is necessary. A twisted–pair shielded cable isused to connect the detector to the analog input/out-put module.

The pickup signal from the analog I/O module is in-putted to the computer software where it iscompared with the alarm and trip levels pro-grammed as Control Constants. See Figure 32.When the vibration amplitude reaches the pro-grammed trip set point, the channel will trigger a tripsignal, the circuit will latch, and a “HIGH VIBRA-TION TRIP” message will be displayed. Removalof the latched trip condition can be accomplishedonly by depressing the master reset button(L86MR1) when vibration is not excessive.

FAULT

AAB

B

TRIP

AA>B

B

OR

ANDSETAND

LATCH

RESET

VF

VA

VT

TRIP

AUTO OR MANUAL RESETL86AMR

FAULT

<RST>

39V

ALARM

L39VF

L39VA

TRIPL39VT

Figure 32 Vibration Protection

id0057

L39TEST

When the “VIBRATION TRANSDUCER FAULT”message is displayed and machine operation is notinterrupted, either an open or shorted condition maybe the cause. This message indicates that mainte-

nance or replacement action is required. By usingthe display keypad and CRT display, it is possible tomonitor vibration levels of each channel while theturbine is running without interrupting operation.

Combustion Monitoring

The primary function of the combustion monitor isto reduce the likelihood of extensive damage to thegas turbine if the combustion system deteriorates.The monitor does this by examining the exhausttemperature thermocouples and compressor dis-charge temperature thermocouples. From changesthat may occur in the pattern of the thermocouplereadings, warning and protective signals are gener-ated by the combustion monitor software to alarmand/or trip the gas turbine.

This means of detecting abnormalities in the com-bustion system is effective only when there is in-complete mixing as the gases pass through theturbine; an uneven turbine inlet pattern will cause anuneven exhaust pattern. The uneven inlet patterncould be caused by loss of fuel or flame in a combus-tor, a rupture in a transition piece, or some othercombustion malfunction.

The usefulness and reliability of the combustionmonitor depends on the condition of the exhaustthermocouples. It is important that each of the ther-mocouples is in good working condition.

Combustion Monitoring Software

The controllers contain a series of programs writtento perform the monitoring tasks (See CombustionMonitoring Schematic Figure 33). The main moni-tor program is written to analyze the thermocouplereadings and make appropriate decisions. Severaldifferent algorithms have been developed for thisdepending on the turbine model series and the typeof thermocouples used. The significant programconstants used with each algorithm are specified inthe Control Specification for each unit.

GE Power Systems


A00023 rev. A 8/16/93

CALCULATEALLOWABLE

SPREAD

CALCULATEACTUAL

SPREADS

MEDIANSELECT

COMBUSTION MONITOR ALGORITHM

MEDIANSELECT

TTXSPL

L60SP1

L60SP2

L60SP3

L60SP4

CTDA

TTKSPL1MAX

MIN

TTXC

TTKSPL2

TTKSPL5

TTKSPL7

CONSTANTS

MAX

MIN

TTXD2

A

BA>B

<RST>

id0049

A

BA>B

A

BA<B

A

BA<B

Figure 33 Combustion Monitoring Function Algorithm (Schematic)

The most advanced algorithm, which is standard forgas turbines with redundant sensors, makes use ofthe temperature spread and adjacency tests to differ-entiate between actual combustion problems andthermocouple failures. The behavior is summarizedby the Venn diagram (Figure 34) where:

TRIP IF S1 & S2OR S2 & S3

ARE ADJACENT

TC ALARMMONITORALARM

TRIP IF S1 & S2ARE ADJACENT

K3

K1 K2

VENN DIAGRAM

S2Sallow

S1Sallow

� K1

COMMUNICATIONSFAILURE

TYPICAL K 1 = 1.0K2 = 5.0K3 = 0.8

S1Sallow

ALSO TRIP IF:

Figure 34 Exhaust Temperature Spread Limits

id0050

1. Sallow is the “Allowable Spread”, based on aver-age exhaust temperature and compressor dis-charge temperature.

2. S1, S2 and S3 are defined as follows:

a. SPREAD #1 (S1): The difference between thehighest and the lowest thermocouple reading

b. SPREAD #2 (S2): The difference between thehighest and the 2nd lowest thermocouplereading

c. SPREAD #3 (S3): The difference between thehighest and the 3rd lowest thermocouplereading

The allowable spread will be between the limitsTTKSPL7 and TTKSPL6, usually 30° F and 125° F.The values of the combustion monitor programconstants are listed in the Control Specifications.

The various <C> processor outputs to the CRT causealarm message displays as well as appropriate con-trol action. The combustion monitor outputs are:

Exhaust Thermocouple Trouble Alarm(L30SPTA)

If any thermocouple value causes the largest spreadto exceed a constant (usually 5 times the allowablespread), a thermocouple alarm (L30SPTA) is pro-

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A00023 rev. A 8/16/93

duced. If this condition persists for four seconds, thealarm message “EXHAUST THERMOCOUPLETROUBLE” will be displayed and will remain onuntil acknowledged and reset. This usually indicatesa failed thermocouple, i.e., open circuit.

Combustion Trouble Alarm (L30SPA)

A combustion alarm can occur if a thermocouplevalue causes the largest spread to exceed a constant(usually the allowable spread). If this condition per-sists for three seconds, the alarm message “COM-BUSTION TROUBLE” will be displayed and willremain on until it is acknowledged and reset.

High Exhaust Temperature Spread Trip(L30SPT)

A high exhaust temperature spread trip can occur if:

1. “COMBUSTION TROUBLE” alarm exists, thesecond largest spread exceeds a constant (usual-ly 0.8 times the allowable spread), and the low-est and second lowest outputs are from adjacentthermocouples

2. “EXHAUST THERMOCOUPLE TROUBLE”alarm exists, the second largest spread exceeds aconstant (usually 0.8 times the allowablespread), and the second and third lowest outputsare from adjacent thermocouples

3. the third largest spread exceeds a constant (usu-ally the allowable spread) for a period of fiveminutes

If any of the trip conditions exist for 9 seconds, thetrip will latch and “HIGH EXHAUST TEMPERA-TURE SPREAD TRIP” message will be displayed.The turbine will be tripped through the master pro-tective circuit. The alarm and trip signals will be dis-played until they are acknowledged and reset.

Monitor Enable (L83SPM)

The protective function of the monitor is enabledwhen the turbine is above 14HS and a shutdown sig-nal has not been given. The purpose of the “enable”signal (L83SPM) is to prevent false action duringnormal start–up and shutdown transient conditions.When the monitor is not enabled, no new protectiveactions are taken. The combustion monitor will alsobe disabled during a high rate of change of FSR. Thisprevents false alarms and trips during large fuel andload transients.

The two main sources of alarm and trip signals beinggenerated by the combustion monitor are failed ther-mocouples and combustion system problems. Othercauses include poor fuel distribution due to pluggedor worn fuel nozzles and combustor flameout due,for instance, to water injection.

The tests for combustion alarm and trip action havebeen designed to minimize false actions due to failedthermocouples. Should a controller fail, the thermo-couples from the failed controller will be ignored(similar to temperature control) so as not to give afalse trip.

1

GER-3658D

INTRODUCTIONThe SPEEDTRONIC™ Mark V Gas Turbine

Control System is the latest derivative in thehighly successful SPEEDTRONIC™ series.Preceding systems were based on automated tur-bine control, protection and sequencing tech-niques dating back to the late 1940s, and havegrown and developed with the available technol-ogy. Implementation of electronic turbine con-trol, protection and sequencing originated withthe Mark I system in 1968. The Mark V system isa digital implementation of the turbine automa-tion techniques learned and refined in morethan 40 years of successful experience, over 80%of which has been through the use of electroniccontrol technology.

The SPEEDTRONIC™ Mark V Gas TurbineControl System employs current state-of-the-arttechnology, including triple-redundant 16-bitmicroprocessor controllers, two-out-of-three vot-ing redundancy on critical control and protec-tion parameters and Software-ImplementedFault Tolerance (SIFT). Critical control and pro-tection sensors are triple redundant and votedby all three control processors. System outputsignals are voted at the contact level for criticalsolenoids, at the logic level for the remainingcontact outputs and at three coil servo valves foranalog control signals, thus maximizing bothprotective and running reliability. An indepen-dent protective module provides triple redun-dant hardwired detection and shutdown onoverspeed along with detecting flame. This mod-ule also synchronizes the turbine generator tothe power system. Synchronization is backed upby a check function in the three control proces-sors.

The Mark V Control System is designed to ful-fill all gas turbine control requirements. Theseinclude control of liquid, gas or both fuels inaccordance with the requirements of the speed,load control under part-load conditions, tem-perature control under maximum capabilityconditions or during startup conditions. In addi-tion, inlet guide vanes and water or steam injec-tion are controlled to meet emissions and oper-ating requirements. If emissions control uses

Dry Low NOx techniques, fuel staging and com-bustion mode are controlled by the Mark V sys-tem, which also monitors the process.Sequencing of the auxiliaries to allow fully auto-mated startup, shutdown and cooldown are alsohandled by the Mark V Control System. Turbineprotection against adverse operating situationsand annunciation of abnormal conditions areincorporated into the basic system.

The operator interface consists of a colorgraphic monitor and keyboard to provide feed-back regarding current operating conditions.Input commands from the operator are enteredusing a cursor positioning device. An arm/exe-cute sequence is used to prevent inadvertent tur-bine operation. Communication between theoperator interface and the turbine control isthrough the Common Data Processor, or <C>, tothe three control processors called <R>, <S> and<T>. The operator interface also handles com-munication functions with remote and externaldevices. An optional arrangement, using aredundant operator interface, is available forthose applications where integrity of the exter-nal data link is considered essential to contin-ued plant operations. SIFT technology protectsagainst module failure and propagation of dataerrors. A panel mounted back-up operator dis-play, directly connected to the control proces-sors, allows continued gas turbine operation inthe unlikely event of a failure of the primaryoperator interface or the <C> module.

Built-in diagnostics for troubleshooting pur-poses are extensive and include “power-up,”background and manually initiated diagnosticroutines capable of identifying both controlpanel and sensor faults. These faults are identi-fied down to the board level for the panel andto the circuit level for the sensor or actuatorcomponents. The ability for on-line replacementof boards is built into the panel design and isavailable for those turbine sensors where physi-cal access and system isolation are feasible. Setpoints, tuning parameters and control constantsare adjustable during operation using a securitypassword system to prevent unauthorized access.Minor modifications to sequencing and theaddition of relatively simple algorithms can be

SPEEDTRONIC™ MARK V GAS TURBINE CONTROL SYSTEM

T. AshleyGE Power SystemsSchenectady, NY

D. Johnson and R.W. MillerGE Drive Systems

Salem, VA

accomplished when the turbine is not operating.They are also protected by a security password.

A printer is included in the control systemand is connected via the operator interface. Theprinter is capable of copying any alpha-numericdisplay shown on the monitor. One of these dis-plays is an operator configurable demand dis-play that can be automatically printed at aselectable interval. It provides an easy means toobtain periodic and shift logs. The printer auto-matically logs time-tagged alarms, as well as theclearance of alarms. In addition, the printer willprint the historical trip log that is frozen inmemory in the unlikely event of a protectivetrip. The log assists in identifying the cause of atrip for trouble shooting purposes.

The statistical measures of reliability and avail-ability for SPEEDTRONIC™ Mark V systems havequickly established the effectiveness of the newcontrol because it builds on the highly success-ful SPEEDTRONIC™ Mark IV system.Improvements in the new design have beenmade in microprocessors, I/O capacity, SIFTtechnology, diagnostics, standardization andoperator information, along with continuedapplication flexibility and careful design formaintainability. SPEEDTRONIC™ Mark V con-trol is achieving greater reliability, faster mean-time-to repair and improved control systemavailability than the SPEEDTRONIC™ Mark IVapplications.

As of May 1994, almost 264 Mark V systemshad entered commercial service and systemoperation has exceeded 1.4 million hours. Theestablished Mark V level of system reliability,including sensors and actuators, exceeds 99.9percent, and the fleet mean-time-between-forced-outages (MTBFO) stands at 28,000hours. As of May 1994, there were 424 gas tur-bine Mark V systems and 106 steam turbineMark V systems shipped or on order.

CONTROL SYSTEM HISTORYThe gas turbine was introduced as an industri-

al and utility prime mover in the late 1940s withinitial applications in gas pipeline pumping andutility peaking. The early control systems werebased on hydro-mechanical steam turbine gov-erning practice, supplemented by a pneumatictemperature control, preset startup fuel limitingand manual sequencing. Independent devicesprovided protection against overspeed, overtem-perature, fire, loss of flame, loss of lube oil andhigh vibration.

Through the early years of the industry, gasturbine control designs benefited from the

rapid growth in the field of control technology.The hydro-mechanical design culminated in the“fuel regulator” and automatic relay sequencingfor automatic startup, shutdown and cooldownwhere appropriate for unattended installations.The automatic relay sequencing, in combinationwith rudimentary annunciator monitoring, alsoallowed interfacing with SCADA (SupervisoryControl and Data Acquisition) systems for truecontinuous remote control operation.

This was the basis for introduction of the firstelectronic gas turbine control in 1968. This sys-tem, ultimately known as the SPEEDTRONIC™

Mark I Control, replaced the fuel regulator,pneumatic temperature control and electro-mechanical starting fuel control with an elec-tronic equivalent. The automatic relay sequenc-ing was retained and the independent protectivefunctions were upgraded with electronic equiva-lents where appropriate. Because of its electri-cally dependent nature, emphasis was placed onintegrity of the power supply system, leading to aDC-based system with AC- and shaft-poweredback-ups. These early electronic systems provid-ed an order of magnitude increase in runningreliability and maintainability.

Once the changeover to electronics wasachieved, the rapid advances in electronic sys-tem technology resulted in similar advances ingas turbine control technology (Table 1). Notethat more than 40 years of gas turbine controlexperience has involved more than 5,400 units,while the 26 years of electronic control experi-ence has been centered on more than 4,400 tur-bine installations. Throughout this time period,the control philosophy shown in Table 2 hasdeveloped and matured to match the capabili-ties of the existing technology. This philosophyemphasizes safety of operation, reliability, flexi-bility, maintainability and ease of use, in thatorder.

CONTROL SYSTEM FUNCTIONS

The SPEEDTRONIC™ Gas Turbine ControlSystem performs many functions including fuel,air and emissions control; sequencing of turbinefuel and auxiliaries for startup, shutdown andcooldown; synchronization and voltage match-ing of the generator and system; monitoring ofall turbine, control and auxiliary functions; andprotection against unsafe and adverse operatingconditions. All of these functions are performedin an integrated manner that is tailored toachieve the previously described philosophy in

2

GER-3658D

the stated priority.The speed and load control function acts to

control the fuel flow under part-load conditionsto satisfy the needs of the governor.Temperature control limits fuel flow to a maxi-mum consistent with achieving rated firing tem-peratures and controls air flow via the inletguide vanes to optimize part-load heat rates onheat recovery applications. The operating limitsof the fuel control are shown in Figure 1. Ablock diagram of the fuel, air and emissions con-trol systems is shown in Figure 2. The input tothe system is the operator command for speed

(when separated from the grid) or load (whenconnected). The outputs are the commands tothe gas and liquid fuel control systems, the inletguide vane positioning system and the emissionscontrol system. A more detailed discussion ofthe control functionality required by the gas tur-bine may be found in Reference 1.

The fuel command signal is passed to the gasand liquid fuel systems via the fuel signal dividerin accordance with the operator’s fuel selection.Startup can be on either fuel and transfers

3

GER-3658D

Table 2GAS TURBINE CONTROL PHILOSOPHY

• Single control failure alarms when running or duringstartup

• Protection backs up control, thus independent• Two independent means of shutdown will be available• Double failure may cause shutdown, but will always

result in safe shutdown• Generator-drive turbines will tolerate full-load rejection

without overspeeding• Critical sensors are redundant• Control is redundant• Alarm any control system problems• Standardize hardware and software to enhance relia-

bility while maintaining flexibility

Table 1ADVANCES IN ELECTRONIC CONTROL CONCEPTS

GT17610B

Figure 1.Gas turbine generator controls andlimits

under load are accomplished by transitioningfrom one system to the other after an appropri-ate fill time to minimize load excursions. Systemcharacteristics during a transfer from gas to liq-uid fuel are illustrated in Figure 3. Purging ofthe idle fuel system is automatic and continuous-ly monitored to ensure proper operation.Transfer can be automatically initiated on loss ofsupply of the running fuel, which will bealarmed, and will proceed to completion with-out operator intervention. Return to the origi-nal fuel is manually initiated.

The gas fuel control system is shown schemat-ically in Figure 4. It is a two-stage system, incor-porating a pressure control proportional tospeed and a flow control proportional to fuelcommand. Two stages provide a stable turn-down ratio in excess of 100:1, which is morethan adequate for control under starting and

warm-up conditions, as well as maximum flowfor peak output at minimum ambient tempera-ture. The stop/speed ratio valve also acts as anindependent stop valve. It is equipped with aninterposed, hydraulically-actuated trip relay thatcan trip the valve closed independent of controlsignals to the servo valve. Both the stop ratioand control valves are hydraulically actuated,single-acting valves that will fail to the closedposition on loss of either signal or hydraulicpressure. Fuel distribution to the gas fuel noz-zles in the multiple combustors is accomplishedby a ring manifold in conjunction with carefulcontrol of fuel nozzle flow areas.

The liquid fuel control system is shownschematically in Figure 5. Since the fuel pump isa positive displacement pump, the systemachieves flow control by recirculating excess fuel

4

GER-3658D

GT17603B

Figure 2. Gas turbine fuel control

GT20703B

Figure 3. Dual fuel transfer characteristics gas to liquid

GT17599

Figure 4. Gas fuel control system

from the discharge back to the pump suction.The required turndown ratio is achieved by mul-tiplying the fuel command by a signal propor-tional to turbine speed. The resultant signalpositions the pump recirculation, or bypassvalve, as appropriate to make the actual fuelflow, as measured by the speed of the liquid fuelflow divider, equal the product of turbine speedand fuel command. This approach ensures a sys-tem in which both the liquid and gas fuel com-mands are essentially equal. Fuel distribution tothe liquid fuel nozzles in the multiple combus-tors is achieved via the flow divider. This is aproven mechanical device that consists of care-fully matched gear pumps for each combustor,all of which are mechanically connected to runat the same speed.

Control of nitrogen oxide emissions may beaccomplished by the injection of water or steaminto the combustors. The amount of waterrequired is a function of the fuel flow, the fueltype, the ambient humidity and nitrogen oxideemissions levels required by the regulations inforce at the turbine site. Steam flow require-ments are generally about 40% higher than theequivalent water flow, but have a more benefi-cial effect on turbine performance. Accuracy ofthe flow measurement, control system and sys-tem monitoring meets or exceeds both EPA andall local code requirements. An independent,fast-acting shutoff valve is provided to ensureagainst loss of flame from over-watering on sud-den load rejection.

Emissions control using Dry Low NOx com-bustion techniques relies on multiple-combus-tion staging to optimize fuel/air ratios andachieve thorough premixing in various combi-nations, depending on desired operating tem-perature. The emissions fuel control system reg-

ulates the division of fuel among the multiple-combustion stages according to a schedule thatis determined by a calculated value of the com-bustion reference temperature. The control sys-tem also monitors actual combustion systemoperation to ensure compliance with therequired schedule. Special provisions are incor-porated to accommodate off-normal situationssuch as load rejection.

The gas turbine, like any internal combustionengine, is not self-starting and requires an out-side source of cranking power for startup. Thisis usually a diesel engine or electric motor com-bined with a torque converter, but could also bea steam turbine or gas expander if externalsteam or gas supplies are available. Startup viathe generator, using variable frequency powersupplies, is used on some of the larger gas tur-bines. Sufficient cranking power is provided tocrank the unfired gas turbine at 25% to 30%speed, depending on the ambient temperature,even though ignition speed is 10% to 15%. Thisextra cranking power is used for gas path purg-ing prior to ignition, for compressor water wash-ing, and for accelerated cooldown.

A typical automatic starting sequence isshown in Figure 6. After automatic systemchecks have been successfully completed andlube oil pressure established, the crankingdevice is started and, for diesel engines, allowedto warm up. Simple-cycle gas turbines with con-ventional upward exhausts do not require purg-ing prior to ignition and the ignition sequencecan proceed as the rotor speed passes throughfiring speed. If ignition does not occur beforethe 60 second cross-firing timer times out, thecontrols will automatically enter a purgesequence, as described later, and then attemptto refire.

However, if there is heat recovery equipment,or if the exhaust ducting has pockets wherecombustibles can collect, gas path purgingensures a safe light-off. When the turbine reach-es purge speed, this speed is held for the neces-sary purge period, usually sufficient to ensurethree to five volume changes in the gas path.Purge times will vary from one minute to as longas 10 minutes in some heat recovery applica-tions. When purging is completed, the turbinerotor is allowed to decelerate to ignition speed.This speed has been found to be optimum fromthe standpoint of both thermal fatigue duty onthe hot gas path components, as well as offeringreliable ignition and cross firing of the combus-tors.

The ignition sequence consists of turning on

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GT17604

Figure 5. Liquid fuel control system

ignition power to the spark plugs and then set-ting firing fuel flow. When flame is detected bythe flame detectors, which are on the oppositeside of the turbine from the spark plugs, igni-tion and cross-firing are complete. Fuel isreduced to the warm-up value for one minuteand the starting device power is brought to max-imum. If successful ignition and cross firing arenot achieved within an appropriate period oftime, the control system automatically revertsback to the purge sequence, and will attempt asecond firing sequence without operator inter-vention. In the unlikely event of incompletecross firing, it will be detected by the combus-tion monitor as a high exhaust temperaturespread prior to loading the gas turbine.

After completion of the warm-up period, fuelflow is allowed to increase and the gas turbinebegins to accelerate faster. At a speed of about30% to 50%, the gas turbine enters a predeter-mined program of acceleration rates, slower ini-tially, and faster just before reaching runningspeed. The purpose of this is to reduce the ther-mal-fatigue duty associated with startup.

At about 40% to 85% speed, turbine efficien-cy has increased sufficiently so that the gas tur-bine becomes self sustaining and external crank-ing power is no longer required. At about 80%to 90% speed, the compressor inlet guide vanes,which were closed during startup to preventcompressor surge, are opened to the full-speed,no-load position.

As the turbine approaches running speed,synchronizing is initiated. This is a two or three

step process that consists of matching turbinegenerator speed, and sometimes voltage, to thebus, and then closing the breaker at the pointwhere the two are in phase within predeter-mined limits.

Turbine speed is matched to the line frequen-cy with a small positive differential to preventthe generator breaker from tripping on reversepower at breaker closure. In the protective mod-ule, triple-redundant microprocessor-based syn-chronizing methods are used to predict zero-phase angle difference and compensate forbreaker closing time to provide true zero angleclosure. Acceptable synchronizing conditionsare independently verified by the triple-redun-dant control processors as a check function.

At the completion of synchronizing, the tur-bine will be at a spinning reserve load. The finalstep in the starting sequence consists of auto-matic loading of the gas turbine generator, ateither the normal or fast rate, to either a prese-lected intermediate load, base load or peakload. Typical starting times to base load areshown in Table 3. Although the time to full-speed no-load applies to all simple cycle gas tur-bines, the loading rates shown are for standardcombustion and may vary for some Dry LowNOx systems.

Normal shutdown is initiated by the operatorand is reversible until the breaker is opened andthe turbine operating speed falls below 95%.The shutdown sequence begins with automaticunloading of the unit. The main generatorbreaker is opened by the reverse power relay at

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GT17606D

Figure 6. Typical gas turbine starting characteristics

about 5% negative power, which drives the gasturbine fuel flow to a minimum value sufficientto maintain flame, but not turbine speed. Thegas turbine then decelerates to about 40% to25% speed, where fuel is completely shut off. Asbefore, the purpose of this “fired shutdown”sequence is to reduce the thermal fatigue dutyimposed on the hot gas path parts.

After fuel is shut off, the gas turbine coastsdown to a point where the rotor turning systemcan be effective. The rotor should be turnedperiodically to prevent bowing from unevencooldown, which would cause vibration on sub-sequent startups. Turning of the rotor for cool-down or maintenance is accomplished by aratcheting mechanism on the smaller gas tur-bines, or by operation of a conventional turninggear on some larger gas turbines. Normal cool-down periods vary from five hours on the small-er turbines to as much as 48 hours on some ofthe larger units. Cool down sequences may beinterrupted at any point for a restart if desired.

Gas turbines are capable of faster loading inthe event of a system emergency. However, ther-mal fatigue duty for these fast load starts is sub-stantially higher. Therefore, selection of a fastload start is by operator action with the normalstart being the default case.

Gas turbine generators that are equippedwith diesel engine starting devices are optionallycapable of starting in a blacked out conditionwithout outside electrical power. Lubricating oilfor starting is supplied by the DC emergencypump powered from the unit battery. This bat-tery also provides power to the DC fuel forward-ing pump for black starts on distillate. The tur-bine and generator control panels on all unitsare powered from the battery. An inverter sup-

plies the AC power required for ignition and thelocal operator interface. Power for the coolingsystem fans is obtained from the main generatorthrough the power potential transformer afterthe generator field is flashed from the battery atabout 50% speed. The black start option uses aDC battery-powered turning device for rotorcooldown to ensure the integrity of the blackstart capability.

As mentioned, the protective function acts totrip the gas turbine independently from the fuelcontrol in the event of overspeed, overtempera-ture, high rotor vibration, fire, loss of flame orloss of lube oil pressure. With the advent ofmicroprocessors, additional protective featureshave been added with minimum impact on run-ning reliability due to the redundancy of themicroprocessors, sensors and signal processing.The added functions include combustion andthermocouple monitoring, high lube oil headertemperature, low hydraulic supply pressure,multiple control computer faults and compres-sor surge for the aircraft-derivative gas turbines.

Because of their nature or criticality, someprotective functions trip the stop valve throughthe hardwired, triple-redundant protective mod-ule. These functions are the hardwired over-speed detection system, which replaces themechanical overspeed bolt on some units, themanual emergency trip buttons, and “customerprocess” trips. As previously mentioned, the pro-tection model performs the synchronizationfunction to close the breaker at the properinstant. It also receives signals from the flamedetectors and determines if flame is on or off. Ablock diagram of the turbine protective system isshown in Figure 7. It shows how loss of lube oil,hydraulic supply, or manual hydraulic trip will

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Table 3SIMPLE CYCLE PACKAGE POWER PLANT STARTING TIMES

result in direct hydraulic actuation of the stopvalves.

Interfacing to other application-specific tripfunctions is provided through the three controlprocessors, the hardwired protection module orthe hydraulic trip system. These trip functionsinclude turbine shutdown for generator protec-tive purposes and combined-cycle coordinationwith heat recovery steam generators and single-shaft STAG™ steam turbines. The latter ishydraulically integrated as shown in Figure 7.Other protective coordination is provided asrequired to meet the needs of specific applica-tions.

SPEEDTRONIC™ MARK VCONTROL CONFIGURATION

The SPEEDTRONIC™ Mark V control systemmakes increased use of modern microprocessorsand has an enhanced system configuration. Ituses SIFT technology for the control, a newtriple-redundant protective module and a signif-icant increase in hardware diagnostics.Standardized modular construction enhancesquality, speed of installation, reliability and easeof on-line maintenance. The operator interfacehas been improved with color graphic displaysand standardized links to remote operator sta-

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GT20784B

Figure 7. Protective system block diagram; SPEEDTRONIC™ Mark V turbine control

GT20781B

Figure 8. Standard control configuration

tions and distributed control systems (DCS).Figure 8 shows the standard SPEEDTRONIC™

Mark V control system configuration. The topblock in the diagram is the Interface DataProcessor called . It includes a monitor, key-board, and printer. Its main functions are driv-ing operator displays, managing the alarm pro-cess and handling operator commands. alsodoes system configuration and download, off-line diagnostics for maintenance, and imple-ments interfaces to remote operator stationsand plant distributed control systems.

The Common Data Processor, or <C>, collectsdata for display, maintains the alarm buffers,generates and keeps diagnostic data, and imple-ments the common I/O for non-critical signalsand control actions. Turbine supervisory sensorssuch as wheelspace thermocouples come direct-ly to <C>. The processor communicates with<C> using a peer-to-peer communication linkwhich permits one or more processors. <C>gathers data from the control processors by par-ticipating on the voting link.

At the core of SPEEDTRONIC™ Mark V con-trol are the three identical control processorscalled <R> <S> and <T>. All critical control algo-rithms, turbine sequencing and primary protec-tive functions are handled by these processors.They also gather data and generate most of the

alarms.The three control processors accept input

from various arrangements of redundant tur-bine and generator sensors. Table 4 lists typicalredundant sensor arrangements. By extendingthe fault tolerance to include sensors, as withthe Mark IV system, the overall control systemavailability is significantly increased. Some sen-sors are brought in to all three control proces-sors, but many, like exhaust thermocouples, aredivided among the control processors. The indi-vidual exhaust temperature measurements areexchanged on the voter link so that each controlprocessor knows all exhaust thermocouple val-ues. Voted sensor values are computed by eachof the control processors. These voted values areused in control and sequencing algorithms thatproduce the required control actions.

One key output goes to the servo valves usedin position loops as shown in Figure 9. Theseposition loops are closed digitally. RedundantLVDTs (Linear Variable DifferentialTransformers, a position sensor) produce a sig-nal proportional to actuator position. Each con-trol processor measures both LVDT signals andchooses the higher of the two signals. This valueis chosen because the LVDT is designed to havea strong failure preference for low voltage out-put. The signal is compared with the position

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Table 4CRITICAL REDUNDANT SENSORS

Parameter Type Function Usage NumberSpeed Mag. Pickup CTL & PROT Dedicated 3 to 6Exhaust temperature T.C. CTL & PROT Dedicated 13 to 27Generator output Transducer Control Dedicated 3Liquid fuel flow Mag. pickup Control Dedicated 3Gas fuel flow Transducer Control Dedicated 3Water flow Mag. pickup Control Dedicated 3Actuator stroke LVDT Control Shared 2/ActuatorSteam flow Transducer Control Shared 1Vibration Seismic probe Protection Shared 8 to 11Flame Scanner Protection Shared 4 to 8Fire Switch Protection Shared 17 to 21Control oil pressure Switch Protection Shared 3L.O. pressure Switch Protection Shared 3L.O. temperature Switch Protection Shared 3Exh. frame blwr. Switch Protection Shared 2Filter delta p. Switch Protection Shared 3

Notes:1. Dedicated sensors: one-third are connected to each processor2. Shared sensors are shared by processors3. Thee number of exhaust thermocouples is related to the number of combustors4. Vibration and fire detectors are related to the physical arrangement5. Generator output are redundant only for “constant settable droop” systems6. Dry Low NOx has four flame detectors in each of two zones

command and the error signal passed through atransfer function and a D/A converter to a cur-rent amplifier. The current amplifier from eachcontrol processor drives one of the three coils.The servo valve acts on the sum of the ampereturns. If one of the three channels fails, themaximum current that one failed amplifier candeliver is overridden by the combined signalsfrom the remaining two good amplifiers. Theresult is that the turbine continues runningunder control.

The SIFT system ensures that the output fuelcommand signals to the digital servo stay instep. As a result, almost all single failures willnot cause an appreciable bump in the con-trolled turbine parameter. Diagnostics of LVDTexcitation voltage, LVDT outputs that disagree,and current not equalling the commandedvalue make it easy to find a system problem, sothat on-line repair can be initiated quickly.

An independent protective module isinternally triple redundant. It accepts speed sen-sors, flame detectors and potential transformerinputs to perform emergency electronic over-speed, flame detection and synchronizing func-tions. Hardware voting for solenoid outputs

is accomplished on a trip card associated withthe module. The trip card merges trip contactsignals from the emergency overspeed, the maincontrol processors, manual trip push buttonsand other hardwired customer trips.

Overspeed and synchronization functions areindependently performed in both the triple-redundant control and triple-redundant protec-tive hardware, which reduces the probability ofmachine overspeed or out of phase synchroniz-ing to the lowest achievable values.

SPEEDTRONIC™ Mark V control providesinterfaces to DCS systems for plant control fromthe processor. The two interfaces availableare Modbus Slave Station and a standard ether-net link, which complies with the IEEE-802.3specification for the physical and medium accesscontrol (MAC) layers. A GE protocol is availablefor use over the ethernet link. A hardwiredinterface is also available.

Table 5 lists signals and commands availableon the interfacing links. The table includes anoption for hard-wired contacts and 4-20 ma sig-nals intended to interface with older systemssuch as SCADA remote dispatch terminal units.The wires are connected to the I/O module

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GT20782AFigure 9. Digital servo position loops

associated with <C>.The “stage link” that interconnects the <C>

processor with the processor is anextendible Arcnet link that allows daisy chainingmultiple gas turbines with multiple proces-sors. Thus a single gas turbine can be controlledfrom multiple processors, or a single processor can control multiple gas and steamturbines. For multi-unit configurations, the processor can be equipped with plant load con-trol capability that will allow plant level manage-ment of all units for both real and reactivepower. The processor, or OperatorInterface, is shown in Figure 10.

In process plants where maintaining the linkto the DCS is essential to keeping the plant on-line, two processors are used to obtainredundant links to the DCS system. For criticalinstallations, a redundant <C> processor option,referred to as the <D> processor, is available thatensures that no single hardware failure caninterrupt communications between the gas tur-bine and the DCS system.

A specially configured PC is available to act asa “historian,” or <H> processor, for the gas tur-bine installation. All data available in the Mark Vdata base can be captured and stored by the his-torian. Analog data is stored when the valueschange beyond a settable deadband, and eventsand alarms are captured when they occur. Inaddition, data can be requested periodically oron demand in user definable lists. The historianis sized so that about a month’s worth of data fora typical four unit plant can be stored on line,and provisions are included for both archivingand restoring older data. Display optionsinclude a full range of trending, cross-plottingand histogram screens.

Compliance with recognized standards is animportant aspect of SPEEDTRONIC™ Mark Vcontrols. It is designed to comply with severalstandards including:

• ETL — Approval has been obtained forlabeling of the Mark V control panel, withETL labeling of complete control cabs

• CSA/UL — Approval has been obtainedfor the complete SPEEDTRONIC™ Mark Vcontrol panel

• UBC — Seismic Code Section 2312 Zone 4• ANSI — B133.4 Gas Turbine Control and

Protection System• ANSI — C37.90A Surge Withstand

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Table 5INTERFACING OPTIONS

Hardwired• Connects to common “C” processor I/O• Commands to turbine control

– Turbine start/stop– Turbine fast load– Governor set point raise/lower– Base/Peak load selection– Gas/Distillate fuel selection– Generator voltage (VARS) raise/lower– Generator synchronizing inhibit/release

• Feedback from turbine control– Watts, VARS and volts (analog for meters)– Breaker status– Starting sequence status– Flame indication– On temperature control indication

• Alarm management– RS232C data transmission only, from <1>

Modbus link• Turbine control is Modbus slave station• Transmission on request by master, 300 to 19,200

baud• Connects to interface processor (I)• RS232C link layer• Commands available

– All allowable remote commands are available– Alarm management

• Feedback from turbine control– Most turbine data available in the I data base

GT22904

Figure 10. Mark V operator interface

HARDWARE CONFIGURATION

The SPEEDTRONIC™ Mark V gas turbinecontrol system is specifically designed for GE gasand steam turbines, and uses a considerablenumber of CMOS and VLSI chips selected tominimize power dissipation and maximize func-tionality. The new design dissipates less powerthan previous generations for equivalent panels.Ambient air at the panel inlet vents should bebetween 32 F and 72 F (0 C and 40 C) with ahumidity between 5 and 95%, non-condensing.The standard panel is a NEMA 1A panel that is90 inches high, 54 inches wide, 20 inches deep,and weighs approximately 1,200 pounds. Figure11 shows the panel with doors closed.

For gas turbines, the standard panel runs on125 volt DC unit battery power, with AC auxil-iary input at 120 volt, 50/60 Hz, used for theignition transformer and the processor. Thetypical standard panel will require 900 watts ofDC and 300 watts of auxiliar y AC power.Alternatively, the auxiliary power can be 240 voltAC 50 Hz, or it can be supplied from an option-al black start inverter from the battery.

The power distribution module conditionsthe power and distributes it to the individual

power supplies for the redundant processorsthrough replaceable fuses. Each control modulesupplies its own regulated DC busses via AC/DCconverters. These can accept an extremely widerange of incoming DC, which makes the controltolerant of significant battery voltage dips, suchas those caused by starting a diesel crankingmotor. All power sources and regulated bussesare monitored. Individual power supplies can bereplaced while the turbine is running.

The Interface Data Processor, particularly aremote , can be powered by house power.This will normally be the case when the centralcontrol room has an Uninterruptible PowerSupply (UPS) system. AC for the local pro-cessor will normally be supplied via a cable fromthe SPEEDTRONIC™ Mark V panel or alterna-tively from house power.

The panel is constructed in a modular fash-ion and is quite standardized. A picture of thepanel interior is shown in Figure 12, and themodules are identified by location in Figure 13.Each of these modules is also standardized, anda typical processor module is shown in Figure14. They feature card racks that tilt out so cardscan be individually accessed. Cards are connect-ed by front-mounted ribbon cables which can beeasily disconnected for service purposes. Tiltingthe card rack back in place and closing the frontcover locks the cards in place.

Considerable thought has been given to therouting of incoming wires to minimize noiseand crosstalk. The wiring has been made moreaccessible for ease of installation. Each wire iseasily identified and the resulting installation isneat.

The panels are made in a highly standardizedmanufacturing process. Quality control is anintegral part of the manufacturing; only thor-oughly tested panels leave the factory. By having

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RDC26449-2-5

Figure 11. Mark V turbine control panel

RDC26449-2-8

Figure 12. Panel internal arrangement

a highly controlled process, the resulting mod-ules and panels are very consistent and repeat-able.

SOFTWARE CONFIGURATIONImproved methods of implementing the

triple-modular redundant system center on SIFTtechnology and result in a more robust control.SIFT involves exchanging information on thevoter link directly between <R>, <S>, <T> and<C> controllers. Each control processor mea-sures all of its input sensors so that each sensorsignal is represented by a number in the con-troller. The sensor numbers to be voted aregathered in a table of values. The values of allstate outputs, such as integrators, for example,the load setpoint, are added to the table. Eachcontrol processor sends its table out on the voterlink and receives tables from the other proces-sors. Consider the <R> controller: it outputs itstable to and receives the tables from the <S> and<T> controllers. Now all three controller tableswill be in the <R> processor, which selects the

median value for each sensor and integratoroutput, and uses these voted outputs in all sub-sequent calculations. <S> and <T> follow thesame procedure.

The basic SIFT concept brings one sensor ofeach kind into each of <R>, <S> and <T>. If asensor fails, the controller with the failed trans-ducer initially has a bad value. But it exchangesdata with the other processors and when the vot-ing takes place, the bad value is rejected.Therefore, a SIFT-based system can tolerate onefailed transducer of each kind. In previous sys-tems, one failed transducer was likely to causeone processor to vote to trip. A failure of a dif-ferent kind of transducer on another controllercould cause a turbine trip. This does not hap-pen with SIFT because the input data isexchanged and voted.

<C> is also connected to the voter link. Iteavesdrops while all three sets of variables aretransmitted by the control processors and calcu-lates the voted values for itself. If there are anysignificant disagreements, <C> reports them to for operator attention and maintenanceaction. If one of the transducers has failed, itsoutput will not be correct and there will be a dis-agreement with the two correct values. <C> willthen diagnose that the transducer or partsimmediately associated with it have failed andwill post an alarm to .

Voting is also performed on the outputs of allintegrators and other state variables. Byexchanging these variables, fewer bumps in out-put are caused when a failure or a repair takesplace. For instance, if a turbine is set to run onisochronous speed control with an isolated load,an integrator compares the frequency of thegenerator with the nominal frequency reference(50 Hz or 60 Hz). Any error is integrated to pro-duce the fuel command signal. If one computercalculates an erroneously high fuel command,nothing happens because the processors willexchange the fuel command and vote and allwill use the correct value of fuel command.When the processor is repaired and put back inservice, its fuel command will initially be set tozero. But as soon as the first data is exchangedon the voter link, the repaired control processorwill output the voted value that will be from oneof the running processors so no bump in fuelflow will occur. No special hardware or softwareis needed to keep integrated outputs in step.

Since only one turbine is connected to eachpanel, the triple-redundant control informationmust be recombined. This recombination isdone in software or, for more critical signals, in

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GT20783A

Figure 13. Module map of panel interior

GT21533A

Figure14. Typical processor module

dedicated voting hardware. For critical outputs,such as the fuel command, the recombination ofthe signals is done by the servo valve on the tur-bine itself as previously explained.

For example, up to four critical 4 ma to 20 maoutputs are voted in a dedicated electronic cir-cuit. The circuit selects the median signal foroutput. It takes control power for the electronicsand the actual output current from all three sec-tions such that any two control sections will sus-tain the correct output. Non-critical outputs aresoftware voted and output by the I/O associatedwith <C>.

Logic outputs are voted by dedicated hard-ware relay driver circuits that require two orthree “on” signals to pick up the output relay.Control power for the circuit and output relay istaken from all three control sections.

Protective functions are accomplished by thecontrol processors and, for overspeed, indepen-dently by the Protective Module as well.Primary speed pickups are wired to the controlprocessors and used for both speed control andprimary overspeed protection. The trip com-mands, generated by the primary overspeed pro-tective function in the control processors, eachactivate a relay driver. The driver signals are sentto the trip card in the protective model whereindependent relays are actuated. Contacts fromeach of these three primary protective trip relaysare voted to cause the trip solenoid to drop out.Separate overspeed pickups are brought to theindependent protective module. Their relaycontacts are wired in a voting arrangement tothe other side of the trip solenoid and indepen-dently cause the trip solenoid to drop out ondetection of overspeed.

The processor is equipped with a harddisk which keeps the records that define the sitesoftware configuration. It comes from GE withthe site-specific software properly configured.For most upgrades, the basic software configura-tion on the disk is replaced with new softwarefrom the GE factory. The software is quite flexi-ble and most required alterations can be madeon site by qualified personnel. Security codeslimit access to the programs used to change con-stants and sequencing, do logic forcing, manualcontrol and so forth. These codes are under thecontrol of the owner so that if there is a need tochange access codes, new ones can be estab-lished on site. Basic changes in configuration,such as an upgrade to turbine capability,requires that the new software be compiled in and downloaded to the processor modules.The information for <C> is stored in EEPROM

there. The information for the control proces-sors is passed through <C> and stored in EEP-ROM in <R>, <S> and <T>. Once the downloadis complete, the processor can fail and theturbine will continue to run properly, acceptingcommands from the local backup display while is being repaired.

Changes in control constants can be accom-plished on-line in working memory. For exam-ple, a new set of tuning constants can be tried. Ifthey are found to be satisfactory, they can beuploaded for storage in where they will beretained for use in any subsequent softwaredownload. also keeps a complete list of vari-ables that can be displayed and printed.

The most critical algorithms for protection,control and sequencing have evolved over manyyears of GE gas turbine experience. These basicalgorithms are in EPROM. They are tuned andadapted with constants that are field adjustable.By protecting these critical algorithms frominadvertent change, the performance and safetyof the complete fleet of GE gas turbines is mademore secure.

OPERATION ANDMAINTENANCE

The operator interface is comprised of a VGAcolor graphics monitor, keyboard and printer.The functions available on the operator inter-face are shown in Table 6.

Displays for normal operation center aroundthe unit control display. It shows the status ofmajor selections and presents key turbineparameters in a table that includes the variablename, value and engineering units. A list of theoldest three unacknowledged alarms appears onthis screen. The operator interface also supportsan operator-entered list of variables, called auser defined display, where the operator cantype in any turbine-generator variable and it willbe added to the variable list. Commands thatchange the state of the turbine require an armactivate sequence to avoid accidental operation.The exception is setpoint incrementing com-mands, which are processed immediately and donot require an arm-activate sequence.

Alarm management screens list all the alarmsin the chronological order of their time tags.The most recent alarm is added to the top of thedisplay list. The line shows whether the alarmhas been acknowledged or not, and whether thealarm is still active. When the alarm conditionclears, the alarm can be reset. If reset is selectedand the alarm has not cleared, the alarm does

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not clear and the original time tag is retained.The alarm log prints alarms in their arrival

sequence, showing the time tags which are sentfrom the control modules with each alarm.Software is provided to allow printing of otherinformation, such as copying of text screens, or

making a listing of the full text of all alarms orturbine variables. When the printer has beenrequested to make such an output, it will formfeed, print the complete list and form feedagain. Any alarms that happened during thetime of printing were stored and are now print-ed. An optional alternative is to add a secondprinter, dedicating one to the alarm log.

Administrative displays help with various taskssuch as setting processor real time clocks andthe date. These displays will include the selec-tion of engineering units and allow changingbetween English and metric units.

There are a number of diagnostic displaysthat provide information on the turbine and onthe condition of the control system. A partial listof the diagnostics available is presented in Table7. The trip diagnostic screen traps the actual sig-nal condition that caused a turbine trip. Thisdisplay gives detailed information about theactual logic signal path that caused any trip. It isaccomplished by freezing information about thelogic path when the trip occurs. This is particu-larly useful in identifying the original source oftrouble if a spurious signal manages to causeone of the control processors to call for a tripand does not leave a normal diagnostic trail. InSPEEDTRONIC™ Mark V controls, all trips areannunciated and information about the actuallogic path that caused the trip is captured. Inaddition to this information, contact inputs areresolved to one millisecond, which makes thissequence of events information more valuable.

The previously mentioned comparison of vot-ing values is another powerful diagnostic tool.Normally these values will agree and significantdisagreement means that something is wrong.Diagnostic alarms are generated whenever thereis such a disagreement. Examination of theserecords can reveal what has gone wrong with thesystem. Many of these combinations have specif-ic diagnostics associated with them and the soft-ware has many algorithms that infer what hasgone wrong from a pattern of incoming diag-nostic signals. In this way the diagnostic alarmwill identify as nearly as possible what is wrong,such as a failed power supply, blown fuse, failedcard, or open sensor circuit.

Some of the diagnostics are intended toenhance turbine-generator monitoring. Forinstance, reading and saving the actual closingtime of the breaker is an excellent diagnostic onthe health of the synchronizing system. An out-put from the flame detectors which shows theeffective ultraviolet light level is another newdiagnostic routine. It is an indicator of degrada-

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Table 6OPERATOR INTERFACE FUNCTIONS

• Control– Unit control– Generator control (or load control)– Alarm management– Manual control (examples)

• Preselected load setpoint• Inlet guide vane control• Isochronous control• Fuel stroke reference• Auxiliary control• Water wash• Mechanical overspeed test

• Data (examples)– Exhaust temperatures– Lube oil temperatures– Wheelspace temperatures– Generator temperatures– Vibration– Timers and event counters– Emission control data– Logical status

• Contracts in• Relay out• Internal logic

– Demand display• Periodic logging

• Administrative–– Set time/date– Select scale units– Display identification numbers– Change security code• Maintenance/Diagnostics– Control reference– Configuration tools– Tuning tools

• Constant change routines– Actuator auto-calibrate– Trip display– Rung display– Logic forcing– Diagnostic alarms– Diagnostic displays

• Off-line• On-line

– System memory access

tion in the ultraviolet flame detection system.In another example, the contact input circuits

can be forced to either state and then be inter-rogated to ensure that the circuit functions cor-rectly without disturbing their normal opera-tion. The extent of this kind of diagnostics hasbeen greatly increased in SPEEDTRONIC™

Mark V control over previous generations. Thislevel of monitoring and diagnostics makes main-tenance easier and faster so that the control sys-tem stays in better repair. A properly maintainedpanel is highly fault-tolerant and makes systemsstarting and running reliability approach 100%.

Once the diagnostic routines have located afailed part, it may be replaced while the turbinecontinues to run. The most critical function ofthe diagnostics is to identify the proper controlsection where the problem exists. Wrong identi-fication could lead to powering down a goodsection and result in a vote to trip. If the failedsection is also voting to trip, the turbine will trip.A great deal of effort has been put into identify-ing the correct section. To affect the repair, thecorrect section is powered down. The module isopened and tilted out, the offending card locat-ed, cables disconnected, card replaced andcables reconnected. The rack is closed andpower is reapplied to the module. The modulewill then join in with the others to control theturbine and the fault tolerance is restored.

Should the fault be in the or <C> proces-sor, it is likely that the operator display will stopor go blank and commands can no longer besent by the operator to the turbine from .

This upsets the operator much more than it dis-turbs the control processors or turbine. A back-up display is provided to handle this situation. Ithappens very infrequently, and repair of thenormal operator interface will usually be accom-plished in less than three hours. Optionalredundant processors make the use of theback-up display even more unlikely. The gas tur-bine control is completely automatic and needslittle human intervention for starting, running,stopping or tripping once a sequence is initiat-ed.

The back-up display provides for a minimumset of control commands: start, stop, raise loadand lower load. It reports all process alarms bynumber. Since the alarm text can be altered onsite in , a provision is included to print thealarms with their internal alarm numbers. Thislist is used to look up the alarm name from thealarm number. The same is true for data points;however, a preselected list of key data points areprogrammed into the back-up panel that displaythe short symbol name, value and engineeringunits. The control ships from the factory withthis limited list of key parameters established forthe back-up display.

CONTROL SYSTEMEXPERIENCE

The SPEEDTRONIC™ Mark V TurbineControl System was initially put into service inMay 1992 on one of three industrial generatordrive MS9001B gas turbines. The system was sub-sequently put into utility service on two peakinggas turbines to obtain experience in daily start-ing service in order to develop a starting reliabil-ity assessment in addition to the continuousduty running reliability assessment. Generalproduct line shipments of the Mark V System onnew unit production commenced early in 1993,with new installations starting up throughoutthe second half of that year.

Today, virtually all turbine shipments includeMark V Turbine Controls. This includes 424 newgas turbines and 106 new steam turbines eithershipped or on order. In addition, almost 80existing units have been committed toretrofitted SPEEDTRONIC™ Mark V TurbineControl Systems, however, the bulk of these aredesigned as Simplex rather than the triple-redundant systems associated with new units.This is due to the floor space available in retrofitapplications. Reliability of the in service fleet,subsequent to commissioning and after accumu-lating more than 1.4 million powered opera-

16

GER-3658D

Table 7MONITORING AND DIAGNOSTICS

• Power– Incoming power sources– Power distribution– All control voltages– Battery ground, non-interfering with other ground

detectors• Sensors and actuators

– Contact inputs circuits can force and interrogate– Open thermocouple– Open and short on seismic vibration transducers– LVDT excitation voltage– Servovalve current feedback loopback test– 4/20 MA control outputs — loopback testing– Relay driver; voting current monitor– RTD open and short

• Protective– Flame detector; UV light level count output– Synchronizer — phase angle at closure– Trip contact status monitor

• Voted data

tional hours on 264 units, has been as expected.Indicated MTBFO (mean time between forceoutages) is in excess of 28,000 hours for the sys-tem, which includes control panel, sensors, actu-ators and all intervening wiring and connectors.This performance is shown relative to the rest ofthe electronic control history in Figure 15.

Why is the Mark V system so much better thanits predecessors? First, there are fewer compo-nents to fail and fewer types of components inthe control panel. (This also means that thereare fewer spares to stock.) Two-out-of-threeredundancy on critical functions and compo-nents ensures that failures, which are less likelyto begin with, are also less likely to cause a tur-bine trip. Extensive built-in diagnostics and theability to replace almost any component whilerunning further minimize exposure time, whilerunning with a failed component when thepotential to trip resulting from a double failure,is highest. Finally, the high degree of standard-ized, yet still flexible, software and hardwareallowed a much greater degree of automatedmanufacturing and testing, substantially lower-ing the potential for human error, and increas-ing the repeatability of the process.

The Mark V system is a further improvementover the Mark IV system. Although the two-out-of-three voting philosophy is retained, its imple-mentation is improved and made more robustthrough use of SIFT techniques. Componentsand types of components have been furtherreduced in number. Standardization of hard-

ware and software has been carried several stepsfurther, but flexibility has also been increased.Greater degrees of automated manufacturingand testing have been complimented by greateruse of computer-aided engineering to standard-ize the generation and testing of software andsystem configuration. Thus, it is fully expectedthe Mark V system will further advance the con-tinuing growth of gas turbine control systemstarting and running reliability.

SUMMARYThe SPEEDTRONIC™ Mark V Gas Turbine

Control System is based on a long history of suc-cessful gas turbine control experience, with asubstantial portion using electronic and micro-processor techniques. Further advancements inthe goals of starting and running reliability andsystem availability will be achieved by logical evo-lution of the unique architectural features devel-oped and initially put into service with the MarkIV system. Flexibility of application and ease ofoperation will also grow to meet the needs ofgenerator and mechanical drive systems, in pro-cess and utility operating environments, and inboth peaking and base load service.

17

GER-3658D

GT21537B

Figure 15. Control system reliability

REFERENCES1. Rowen, W.I., “Operating Characteristics of

Heavy-Duty Gas Turbines in Utility Service,”ASME Paper No. 88-GT-150, presented at theGas Turbine and Aeroengine Congress,Amsterdam, Netherlands, June 6-9, 1988.

18

GER-3658D

© 1996 GE Company

LIST OF FIGURES

Figure 1. Gas turbine generator controls and limitsFigure 2. Gas turbine fuel controlFigure 3. Dual fuel transfer characteristics gas to liquidFigure 4. Gas fuel control systemFigure 5. Liquid fuel control systemFigure 6. Typical gas turbine starting characteristicsFigure 7. Protective system block diagram; SPEEDTRONIC™ Mark V turbine controlFigure 8. Standard control configurationFigure 9. Digital servo position loopsFigure 10.Mark V operator interfaceFigure 11.Mark V turbine control panelFigure 12.Panel internal arrangementFigure 13.Module map of panel interiorFigure 14.Typical processor moduleFigure 15.Control system reliability

LIST OF TABLES

Table 1. Advances in electronic control conceptsTable 2. Gas turbine control philosophyTable 3. Simple cycle package power plant starting timesTable 4. Critical redundant sensorsTable 5. Interfacing optionsTable 6. Operator interface functionsTable 7. Monitoring and diagnostics

GER-3658D

GEH-5979D

SPEEDTRONIC

Mark VTurbine Control

User’s Manual

SPEEDTRONIC

Mark VTurbine Control

User’s Manual

GEH-5979D

Issue Date: December, 1991Revision A: March, 1993Revision B: June, 1994Revision C: June, 1996

Revision D: February 1998

These instructions do not purport to cover all details or variations in equipment, nor to provide for every possiblecontingency to be met during installation, operation, and maintenance. If further information is desired or if particularproblems arise that are not covered sufficiently for the purchaser’s purpose, the matter should be referred to GEIndustrial Control Systems.

This document contains proprietary information of General Electric Company, USA and is furnished to its cu stomersolely to assist that customer in the installation, testing, operation, and/or maintenance of the equipment described. Thisdocument shall not be reproduced in whole or in part nor shall its contents be disclosed to any third party without thewritten approval of GE Industrial Control Systems.

Copyright© 1994 by General Electric Company, U.S.A.All rights reserved.

Printed in the United States of America.February 18, 1998

ARCNET is a registered trademark of Datapoint Corporation.Ethernet is a trademark of Xerox Corporation.HP is a trademark of Hewlett Packard Company.MODBUS is a trademark of Gould Inc.Proximitor is a registered trademark of Bentley Nevada Corporation.Speedtronic is a trademark of General Electric Company, USA.

SAFETY SYMBOL LEGEND

Indicates a procedure, practice, condition, or statement that, if not strictly observed, could result inpersonal injury or death.

Indicates a procedure, practice, condition, or statement which, if not strictly observed, could result indamage to or destruction of equipment.

NOTE

Indicates an essential operation or important procedure, practice, condition, or statement.

WARNING

CAUTION

This equipment contains a potential hazard of electric shock or burn. Only personnel who areadequately trained and thoroughly familiar with the equipment and the instructions should install,operate, or maintain this equipment.

Isolation of test equipment from the equipment under test presents potential electrical hazards. If thetest equipment cannot be grounded to the equipment under test, the test equipment’s case must beshielded to prevent contact by personnel.

To minimize hazard of electrical shock or burn, approved grounding practices and procedures mustbe strictly followed.

To prevent personal injury or equipment damage caused by equipment malfunction, only adequatelytrained persons should modify any programmable machine.

WARNING

Safety Symbol Legend (cont.)

User’s Manual GEH-5979D

i

TABLE OF CONTENTS

CHAPTER 1 INTRODUCTION1-1. OVERVIEW...............................................................................................................................................................1-11-2. PRIMARY OPERATOR INTERFACE ()............................................................................................................1-11-3. BACKUP OPERATOR INTERFACE (<BOI>) ........................................................................................................1-11-4. CONVENTIONS USED IN THIS MANUAL ...........................................................................................................1-2

1-4.1. Cursor Positioning Conventions .......................................................................................................................1-21-4.2. Keyboard Conventions .....................................................................................................................................1-2

CHAPTER 2 THE PRIMARY OPERATOR INTERFACE2-1. INTRODUCTION.....................................................................................................................................................2-12-2. STARTING THE ................................................................................................................................................2-12-3. MAIN MENU............................................................................................................................................................2-12-4. MAIN DISPLAY.......................................................................................................................................................2-32-5. MAIN MENU DISPLAYS AND FUNCTIONS 2-5

2-5.1. Password Administration 2-52-5.1.1. PASSWORD LEVELS AND THEIR PRIVILEGES. ..........................................................................2-62-5.1.2. ENABLING/DISABLING CURRENT STATUS. ...............................................................................2-72-5.1.3. SETTING OR CHANGING PASSWORDS.........................................................................................2-82-5.1.4. ENABLING/DISABLING THE BOOTUP STATUS. .........................................................................2-82-5.1.5. EXAMPLES AND NOTES. .................................................................................................................2-8

2-5.2. Time Set 2-92-5.3. Synonyms 2-9

2-5.3.1. HOW TO ENABLE/DISABLE SYNONYMS. ..................................................................................2-102-6. COMMON DISPLAY FIELDS 2-10

2-6.1. Display Message Field 2-102-6.2. Alarm Window 2-102-6.3. Display Target Field ......................................................................................................................................2-102-6.4. Unit Command Targets .................................................................................................................................2-11

2-7. USER-DEFINED DISPLAYS.................................................................................................................................2-122-7.1. User-Defined Display Menu...........................................................................................................................2-122-7.2. User-Defined Display Body ...........................................................................................................................2-122-7.3. User-Defined Display Modifications..............................................................................................................2-13

2-7.3.1. ADDING A POINTNAME.................................................................................................................2-132-7.3.2. DELETING A POINTNAME. ............................................................................................................2-142-7.3.3. ADDING A USER-DEFINED DISPLAY TO A MENU. ..................................................................2-142-7.3.4. DELETING A USER-DEFINED DISPLAY FROM THE MENU. ...................................................2-142-7.3.5. MAKING MODIFICATIONS PERMANENT. ..................................................................................2-142-7.3.6. COPYING USER-DEFINED DISPLAYS TO MULTIPLE UNITS. .................................................2-152-7.3.7. COMMAND TARGET ADDITIONS/DELETIONS .........................................................................2-20

2-8. ALARM DISPLAY............................................................................................................ .....................................2-222-8.1. Alarm Information.........................................................................................................................................2-222-8.2. Silencing Annunciated Alarms ......................................................................................................................2-242-8.3. Acknowledging Alarms.................................................................................................................................2-242-8.4. Resetting Alarms ..........................................................................................................................................2-242-8.5. Locking Out Alarms ......................................................................................................................................2-242-8.6. Unlocking Alarms ........................................................................................................................................2-262-8.7. Printing The Alarm Display ..........................................................................................................................2-262-8.8. Diagnostic Alarms ........................................................................................................................................2-26

2-9. TRIP LOG DISPLAY .............................................................................................................................................2-282-9.1. Display Header Information ..........................................................................................................................2-282-9.2. First Displayed Screen (PAGE 2)..................................................................................................................2-282-9.3. Time vs. HIS_AGE CNTS ............................................................................................................................2-28

GEH-5979D User’s Manual

ii

2-9.4. Control Signal Database Pointnames............................................................................................................ 2-292-9.5. Display Targets............................................................................................................................................. 2-30

2-9.5.1. CURRENT LOG/SAVED LOG. ........................................................................................................ 2-302-9.5.2. PRINT REPORT. ............................................................................................................................... 2-312-9.5.3. PRINT IMAGE/SAVE IMAGE. ........................................................................................................ 2-31

2-9.7. Pre-Trip Screens ........................................................................................................................................... 2-312-9.8. Alarms ............................................................................................................... ......................................... 2-322-9.9. Defining Control Signal Database Points ..................................................................................................... 2-32

2-10. EPA DISPLAY............................................................................................................. ........................................ 2-332-10.1. Example ............................................................................................................... ....................................... 2-33

2-11. PRINTING FUNCTIONS .................................................................................................................................... 2-352-11.1. Alarm Logging............................................................................................................................................ 2-352-11.2. Event Logger .......................................................................................................... .................................... 2-36

2-11.2.1. POINTNAME. ................................................................................................................................. 2-362-11.2.2. STATUS. ............................................................................................................. ............................. 2-36

2-11.3. Event Type .......................................................................................................... ...................................... 2-362-11.4. View Image/Save Image............................................................................................................................. 2-37

CHAPTER 3 USING THE BACKUP OPERATOR INTERFACE3-1. INTRODUCTION .................................................................................................................................................... 3-13-2. MENU DISPLAY..................................................................................................................................................... 3-23-3. ALARM DISPLAY .................................................................................................................................................. 3-3

3-3.1. Alarm Management ........................................................................................................................................ 3-43-3.1.1. Silence. ............................................................................................................................................... 3-43-3.1.2. Acknowledge. ....................................................................................................................................... 3-43-3.1.3. Reset. .................................................................................................................................................... 3-4

3-4. ENUMERATED SWITCH DISPLAYS .................................................................................................................. 3-53-5. MAIN/NORMAL DISPLAYS ................................................................................................................................. 3-53-6. NORMAL DISPLAY ............................................................................................................................................... 3-63-7. ALL POINTS DISPLAY.......................................................................................................................................... 3-73-8. OPERATOR DEMAND DISPLAY ......................................................................................................................... 3-83-9. PROCESSOR SELECT DISPLAY (PROC) ............................................................................................................ 3-83-10. DESIGNATED PROCESSOR ............................................................................................................................... 3-9

CHAPTER 4 CONTROL LOCATIONS4-1. Control Lockout........................................................................................................................................................ 4-1

4-1.1. Implementing Control Lockout Using Password Administration ................................................................... 4-14-1.2. Control Lockout for Multi-Panel s ............................................................................................................ 4-1

4-2. CONTROL HIERARCHY ....................................................................................................................................... 4-3

1-1

CHAPTER 1

INTRODUCTION

1-1. OVERVIEW

This manual provides information needed by an operator to use a SPEEDTRONIC Mark V Control Panel’s operatorinterfaces to issue commands to the control panel and monitor the operation of a turbine and driven device. It discussesmethods for selecting operating modes, controlling the turbine and driven device, viewing, acknowledging, and resettingalarms, modification and configuration of displays used primarily by operators, and log printouts associated with turbinesystem operation.

This manual is intended to supplement the Operator’s Manual which is written for the overall turbine system. It does not covermaintenance displays nor specific operating details of each application or installation. Maintenance personnel should refer tothe SPEEDTRONIC Mark V Turbine Control Maintenance Manual (GEH-5980) and the turbine and driven device associateddrawings, specifications, schematics and diagrams.

1-2. PRIMARY OPERATOR INTERFACE ()

The primary operator interface (), consists of a color monitor, keyboard, cursor positioning device (CPD) (that is, amouse, a trackball, or a touch-screen monitor), printer(s), and central processing unit (CPU). These items are collectivelyreferred to as the . These devices are connected to the Mark V Control Panel via an ARCNET cable. The devices can belocated in the installation’s central control room or a gas turbine’s control compartment.

One can be used to control as many as 8 gas and/or steam turbines; also more than one may be used to control aturbine. The operator can thereby select the units he wishes to monitor or issue commands to. All s are capable of issuingcommands to a unit at any time while communicating with Mark V Control Panels. For the purposes of this manual, it isassumed that the is controlling a single turbine and driven device.

Using the , commands may be issued to the turbine and driven device (for example, START, STOP, COOLDOWN ON,AUTO, RAISE SPEED/LOAD, and so on) and displays may be accessed to view the status of the turbine and driven device(for example, ALARMS, WHEELSPACE TEMPERATURES, VIBRATION FEEDBACK, and so on). The associatedprinter(s) enable the operator to manually select and copy any display, to automatically log selected parameters, and to logalarms.

The performs no control or protection functions of the turbine and driven device; it is a means of issuing commands to theMark V Control Panel and monitoring unit operation. Turning the off, turning the computer on, re-booting the computer,or disconnecting or reconnecting the ARCNET cable linking the Mark V Control Panel and the (while the turbine anddriven device are operating) will have no effect on the Mark V Control Panel or unit operation.

1-3. BACKUP OPERATOR INTERFACE (<BOI>)

A second means of issuing commands and monitoring turbine and driven device operation is supported through a BackupOperator Interface or <BOI>. The <BOI> is typically mounted on the door of the Mark V Control Panel enclosure where itmay be implemented in the event of a loss of communication between the and the Mark V Control Panel.

The <BOI> may be used to start, load/unload, and/or stop the turbine and driven device. The <BOI>’s LCD screen iscomposed of two lines of 40 characters each. It can be used to view alarms and monitor turbine and driven device operation.

1-2

Turbine and driven device commands may be issued at any time from the <BOI> regardless of the status of the and/or itscommunication link. This is a "Peer to Peer" control system: All operator interfaces can issue commands equally. The mostrecently issued command - from any interface ( or <BOI>) - will be the current status of the control system.

1-4. CONVENTIONS USED IN THIS MANUAL

The following sections define the conventions used in this manual to help the audience better understand the informationprovided.

1-4.1. Cursor Positioning Conventions

In order to operate and monitor a turbine and driven device using the Mark V’s , the operator will select displays,commands, and functions with the cursor positioning device. The cursor positioning device may be a computer mouse, atrack-ball, or a touch-screen monitor. When using the mouse or trackball to "point" at the desired display, command, orfunction, the operator initiates the action by depressing the left-most button of the mouse or track-ball one time; this action isknown as as "clicking" the device. "Point and click" or "click" means to use the cursor positioning device to move the cursorto point at the display or target on the screen and depress the left button of the device one time. To "point and click" with atouch-screen monitor, the operator would physically touch a point on the screen. The on-screen cursor will move directly tothe point of contact and the "clicking" action will take place when the finger is removed.

1-4.2. Keyboard Conventions

The keyboard keys are printed in a different typeface, for example, the F1 key would be F1. When keys are to bepressed simultaneously, they will be shown with a " + " between them. For example, ALT+F11 means to press and hold downthe ALT key and then (simultaneously) press the F11 key.

Additionally, there are eight display targets, maximum, at the bottom of the screen on any display. Any of the display targetsat the bottom of the screen can be activated by pointing and clicking on that target in the display.

2-1

CHAPTER 2

THE PRIMARY OPERATOR INTERFACE

2-1. INTRODUCTION

The is used to control a turbine and driven device, as well as obtain and log data about the status of equipment. Theoperator can choose from a number of pre-defined and user-configurable displays from the Main Menu (refer to Figure 2-1)and from the user-defined Display Menu (refer to Figure 2-2) by using the cursor positioning device to point and click to thedesired display. The operator can quickly return to the Main Display or the Alarm Display from any display or menu bypointing and clicking on the Main Display or the Alarm Display targets at the bottom of the screen. The Main Menu can alsobe accessed from any display (except the Alarm Display) by pressing the ESC key on the keyboard.

Two types of alarms (Diagnostic Alarms and Process Alarms) and two types of events (Contact Inputs and Events) are loggedto the printer(s) for historical purposes. Additionally, most gas turbine applications will log emissions-related data to theprinter(s).

2-2. STARTING THE 

With the system properly connected to the Mark V Control Panel via the stage link, the operator can issue commands toand receive alarms from the Mark V Control Panel. The order in which the individual devices are energized is notcritical.

When the has completed its initialization routines and internal power-up diagnostics, it is ready to issue commands ormonitor the turbine and driven device through the SPEEDTRONICTM Mark V Control Panel. At this point, the displaydefined as the "Main Display" (see Figure 2-3) will appear on the screen. Any subsequently annunciated alarms or datalogging will be recorded/logged on the printer(s). The operator may then use the cursor positioning device and/or the functionbuttons to change displays, issue commands to and manage any alarms from the Mark V Control Panel.

Re-starting or "rebooting the can be accomplished by pressing and holding down the CTRL+ALT+DEL keys in that orderfor approximately one second. This action causes the computer’s internal microprocessor to re-initialize itself, perform itsinternal diagnostics, and re-establish communications with the Mark V Control Panel using the configurations stored on thecomputer’s hard-disk.

2-3. MAIN MENU

The Main Menu is a list of displays (including the user-defined Display) that an operator and/or a maintenance technician canuse to access information about the unit and/or driven device. To view the Main Menu from any display or sub-menu, pressthe ESC key at least once. To view one of the displays listed, point and click on the desired display. In succession, thefollowing figures show Main Menus for gas turbine various applications. As the Mark V Turbine Control System allows agreat deal of flexibility, these examples should be considered generic in nature and not patterns or prototypes that should becopied or emulated. The Main Menu can be configured by authorized personnel only. See Maintenance Manual GEH-5980.


2-2

Figure 2-2. A Typical Main Menu - Continued

Figure 2-1. A Typical Main Menu


2-3

2-4. MAIN DISPLAY

The Main Display is intended to be the display the operator primarily uses to monitor the operation applications. It can beimmediately accessed from any display by clicking on the "Main Display" target below the alarm window. The Main Displaymay either be a user-defined or animated display, according to the customer’s requirements, see the Application ManualGEH-6195. The Main Display shows key turbine parameters and the main commands necessary to operate the turbine anddriven device. The examples immediately below depict (in succession) Gas (two pages) and Steam (one page) Turbine MainDisplays. As the Mark V Turbine Control System allows a great deal of flexibility, these examples should be consideredgeneric in nature and not patterns or prototypes that should be copied or emulated.

Figure 2-3. A Typical Main Menu - Continued


2-4

Figure 2-5. A Typical Main Display - Continued

Figure 2-4. A Typical Main Display

2-5

2-5. MAIN MENU DISPLAYS AND FUNCTIONS

The following Main Menu displays and functions are used to manage access to or modify features of the .

2-5.1. Password Administration

Operators, technicians, and service personnel can be permitted to access or use certain features of the SPEEDTRONIC MarkV’s through the use of passwords. In order to modify a control constant or force a logic point, for instance, the user mustfirst gain access to the program/feature by enabling the current status of an appropriate Password Level. This is done byentering the proper password in the Password Administration Display of the Main Menu. Up to five levels of access, orprivileges, to various functions can be protected by password(s). Password levels and the corresponding features they controlare defined below:

OPERATOR Allows the use of the Logic Forcing feature.

MAINTENANCE Allows the use of all Customer-level features (see Table 2-1), plus operator privileges.

SUPERVISOR Allows the setting of the Customer-level passwords by Customer’s Supervisor(s).

SERVICE Allows use of all Customer-level features (see Table 2-1); intended for use by GEDS, GE, and/orGE Business Associates Field Service personnel.

Figure 2-6. A Typical Main Display - Continued


2-6

SUPPLIER Allows the use of all Customer-level features (see Table 2-1); intended for use by GEDS, GE,and/or GE Business Associates Factory personnel.

All of the Password levels’ Current and "BOOTUP" Statuses should be disabled if the users are not to have access to LogicForcing, Control Constant adjustment, the Control Sequence Editor, and other such features. For example, to enable a newpassword level the user should access the Password Administration display from the Main Menu, click on the ENABLE targetof the desired level, type in the correct password and press ENTER. If the proper password is entered, the ENABLE target’sbackground will change to white and privileges will be enabled. As a suggested procedure, the user should remove thePassword privileges after completing the assigned task(s).

2-5.1.1. PASSWORD LEVELS AND THEIR PRIVILEGES. Table 2-1 explains the view/modify privileges of the variouspassword levels. Privileged view and/or modification of the various features is permitted when the current status of theappropriate password level is enabled. For more information on each feature, refer to the appropriate Mark V documentation.

Figure 2-7. Password. Administration with Operator Level Current & "BOOTUP" Status Enabled

2-7

Access/Use Privilege OPERATOR MAINTENANCE SUPERVISOR SERVICE SUPPLIER

Control ConstantAdjustment

v v, m v v, m v, m

Logic Forcing v, m v, m v v, m v, m

EEPROM Upload/Download v, m v, m v, m

Control SequenceProgram Editor

v, m v, m v, m

Control SequenceProgram Compiler

v, m v, m v, m

Control Sequence ProgramDocumenter

v, m v, m v ,m

I/O Configurator v, m v, m v, m

Table Compiler v, m v, m v, m

I/O Modification Utility v, m v, m v, m

Spare Signal PointnameEditor

v, m v, m v, m

Control Lockout v, m v, m v, m v, m v, m

Exit to DOS Command Line v, m v, m v, m

Table 2-1. Privileges of the Five Password Levelsv = view, m = modify

2-5.1.2. ENABLING/DISABLING CURRENT STATUS. Figure 2-7 shows two Status columns (CURRENT and "BOOTUP")for each password level. Current Status refers to the present status of a password level and "BOOTUP" status refers to thestatus of the password level on startup or "re-boot" of the . The targets with white backgrounds indicate the levels arecurrently enabled/disabled. Click on the desired ENABLE target to enable the current status of a password level. When awhite rectangle appears under the password level’s name, type in the password for that level and press ENTER. (Asteriskswill be displayed as the password is typed in for security purposes). If the correct password was entered, the ENABLEtarget’s background will become white and the white background of the password level’s name will disappear. If the wrongpassword was entered, the white background of the password level’s name will disappear and the DISABLE target’sbackground will turn white.

To return to the Main Menu and save the present status of the password levels, click on the EXIT target at the bottom of thePassword Administration Display. Click on the DISABLE target to disable that level. (It is not necessary to know a level’spassword in order to disable it.)

2-8

2-5.1.3. SETTING OR CHANGING PASSWORDS. The following table should be helpful in understanding which passwordscan be set by each of the three password-setting levels.

Password Changing Privileges SUPERVISOR SERVICE SUPPLIER

Change Operator Password X X X

Change Maintenance Password X X X

Change Supervisor Password X X X

Change Service Password X X

Change Supplier Password X

Table 2-2. Password-Changing Privileges of Three Password-setting Levels (Supervisor, Service, and Supplier)

Table 2-2 shows that passwords for the Operator, Maintenance, and Supervisor levels can be set by anyone with knowledge ofthe Supervisor, Service, and/or the Supplier passwords. Setting or changing a particular level’s password requires the Currentstatus of an appropriate password level be enabled. For example, changing the Supervisor level password requires that theCurrent status of either the Supervisor, Service, or Supplier levels be enabled. If one of these password levels is enabled,pressing CTRL+S and clicking on the SET NEW PASSWORD target of the Supervisor level will cause a white rectangle toappear under the password level name. Typing in the new password will cause the text to appear in the white rectangle. When the new password is confirmed, press ENTER. The white rectangle beneath the password level name will disappear toindicate the new password has been accepted. All future attempts to enable the Supervisor Password level require entering thenew password. Clicking on the EXIT display target at the bottom of the display will save the present statuses and passwordsand return the user to the Main Menu.

2-5.1.4. ENABLING/DISABLING THE BOOTUP STATUS. If the background of the ENABLE target of a password level’s"BOOTUP" status is white, access to the programs/features of the for that password level will be permitted (at any time)after a startup or "re-boot" of the . For example, when the Current and "BOOTUP" statuses of the Operator password levelare disabled and enabled respectively, the next startup or re-booting of the enables both the "BOOTUP" and currentstatus.

The "BOOTUP" status of any password level may be enabled/disabled as long as the concurrent or higher level current statusfunction is enabled (the user must know the appropriate password for the desired level, or a level higher than is required). Forexample, enabling the Supervisor "BOOTUP" status requires that either the Supervisor, Service, or Supplier current statusfunction be enabled. If the correct current status level has been enabled, the "BOOTUP" status may be turned on or off byclicking on the function’s ENABLE/DISABLE targets respectively.

Clicking on the EXIT display target at the bottom of the display will save the present statuses of the various password levelsto the ’s hard-disk and return the user to the Main Menu.

2-5.1.5. EXAMPLES AND NOTES. To maintain the operational integrity of the , set and maintain unique Operator,Maintenance, and Supervisor password levels.

NOTE

The Supervisor, Service, or Supplier password levels should not be left enabled in either Current or"BOOTUP" status at any time as this would permit changing of the Operator, Maintenance, and/orSupervisor passwords by anyone.

If the Current status of a particular password level is enabled and its "BOOTUP" status is disabled, startup or "re-booting" the will disable the Current status of that password level.

2-9

NOTE

Access to the DOS command line is allowed when the Current status of the Maintenance password level (orabove) is enabled.

When the Maintenance password level is enabled a grey target will appear at the lower left-hand corner of the Main Menuscreen. When this target is visible, pressing ALT + X will exit the user to the DOS command line.(Clicking on the dark grey rectangle will not permit access to the DOS command line.)

Access to the DOS command line of the should be permitted only for maintenance, troubleshooting, or configurationpurposes as required. Novice users executing certain DOS commands from the DOS command line can erase files indirectories or the entire hard-disk. Also, software can only be loaded onto the by typing in commands from the DOScommand line. Disks containing computer viruses used to load software onto the computer and/or programs containingviruses loaded onto the can impair the computer’s ability to: 1. monitor turbine and driven device operation, 2. issuecommands to a unit, and 3. annunciate unit alarms.

2-5.2. Time Set

The Mark V panel clock may be reset to reflect the time kept by the processor. This update is accomplished by clickingon the TimeSet Menu target.

Time can be configured to send the ’s time to all Mark V Control Panels or just selected ones. It can also be set toautomatically send a TimeSet command at preset intervals.

2-5.3. Synonyms

Control Data Base (CDB) signal pointnames used in the Mark V are intended to be descriptive acronyms. Examples of thesepointnames are L52GX, a logic signal associated with the status of the generator breaker (52G); TNH, the percent of high-pressure turbine shaft speed; and CPD, the axial compressor discharge pressure. To the experienced individual these signalpointnames are meaningful and easily recognizable. The Synonym function of the aids the operator and/or technician byallowing the individual to substitute a more recognizable mnemonic or acronym for the Mark V signal pointname. Forexample, the value associated with TNH (HP turbine shaft speed) could be displayed as "HP_SPEED". When the synonymfunction is enabled, the CDB signal pointname or the synonym can be used when adding points to a display (either user-defined Displays or animated displays). Synonyms can be defined and edited by authorized personnel only. (SeeMaintenance Manual GEH-5986.)

2-5.3.1. HOW TO ENABLE/DISABLE SYNONYMS. When the is powered-up or "re-booted", the Data DictionaryLoader program searches the unit-specific directory for a SYNONYM.DAT file. If the file is found, its contents are loadedinto the computer’s Random Access Memory (RAM) and the synonyms are displayed in various screens by default. Anysignal pointname which has a synonym defined file will be replaced by the its synonym on any display which it appears. Theoperator may enter either the signal pointname or the synonym when adding points to a display (either user-defined displaysor animated displays). If a synonym exists in the RAM, the synonym will replace the CDB signal pointname on thedisplay when it is entered.

The display of synonyms can be temporarily disabled by accessing the Synonym Administration Display from the Main Menuand clicking on the DISABLE target. The display of synonyms will be disabled until the is "re-booted" or the ENABLEtarget of the Synonym Administration Display is clicked on.


2-10

2-6. COMMON DISPLAY FIELDS

Common elements of each display include the display message field, the alarm window, and the display targets (refer toFigure 2-9). These non-configurable elements are described below.

2-6.1. Display Message Field

The area at the top of the screen is used to give the operator information about the display being viewed.

• SITE NAME/DESIGNATION. The site name/designation defined at the time of shipment is shown in theupper left-hand area of the screen.

• DISPLAY GROUP/MENU NAME. The name of the display group or menu currently being viewed on themonitor is shown in the upper center area of the screen.

• DATE AND TIME. The system date and time is shown on the monitor in the upper right area of the screen.

• CURRENT DISPLAY DEFINITION. The name of the current or most recently viewed display is shown onthe monitor in the area just below the Site Name/Designation.

2-6.2. Alarm Window

The blue "bar" near the bottom of each display is the Alarm Window. Displayed in this area are the first threeunacknowledged alarms, their dates, times, unit numbers, alarm statuses, acknowledgement statuses, drop numbers, and alarmmessages. If more than three unacknowledged alarms have been annunciated, only the oldest three unacknowledged alarmswill appear in the Alarm Window.

2-6.3. Display Target Field

Below the Alarm Window may be as many as eight "display" targets whose functions can be selected using the CPD device.Two display targets common to all displays are EXIT and MAIN DISPLAY. Pointing and clicking on the MAIN DISPLAYdisplay target will return the Main Display to the monitor’s screen. Additionally, an ALARM DISPLAY display target isavailable on every menu or display except the Alarm Display itself. Pointing and clicking on the ALARM DISPLAY displaytarget will immediately dump to the Alarm Display. Clicking on the MORE OPTIONS display target (when present) willprovide the operator with more display targets/choices.

2-6.4. Unit Command Targets

Displays available through the user-defined Display Menu have Unit Command Target Fields on the right-hand side of thescreen (refer to Figure 2-9). Examples of unit commands could include:

• START• STOP• CRANK• RAISE SPD SET


2-11

There are three types of unit command targets:

1. ARM/EXECUTE TARGETS. Displayed with a green background with black text, these command targetsrequire an arm/execute action to send the command to the Mark V Control Panel. For example, to initiate aturbine start from the Main Display, position the cursor on the START command target and click. The targetbackground turns cyan (light blue) to indicate that the target is armed. Next, move the cursor to the EXECUTECOMMAND target at the bottom of the display (in the Display Target Field) and click. The two targetbackgrounds, START and EXECUTE COMMAND, then turn magenta (light purple) to indicate the commandwas sent to the Mark V Control Panel. When the START command is acknowledged by the Mark V ControlPanel, the command target background reverts to green and the text in the target changes to yellow. These colorchanges indicate the command was accepted and is being implemented.

2. IMMEDIATE ACTION TARGETS. Displayed on red background with black text, immediate action targetssend commands to the Mark V Control Panel immediately. That is, they do not require an arm/execute action.This type of target is used for commands where an arm/execute action is not required. For example, the RAISESPD SET (increase the speed setpoint) is enabled by pointing and clicking on the RAISE SPD SET commandtarget. Once selected, the text of the target changes to yellow to indicate that the command is beingacknowledged by the Mark V Control Panel. This text reverts to black when the command sequence iscompleted.

3. SETPOINT TARGETS. Displayed with a grey background and black text, setpoint command targets requirean arm/execute action to send a setpoint change command to the control panel. Arming a setpoint target entailsclicking on it with the CPD device. When selected, the background of the target turns cyan. At this point, theuser types in the new value for the setpoint, which appears on the second line of the target. After the desiredvalue is inserted, clicking on the EXECUTE COMMAND target on the bottom of the display will cause the

Figure 2-9. Example of a User-Defined Display Showing Alarm Window

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backgrounds of the two targets to change to magenta. This color change indicates the command was sent to thecontrol panel and was acknowledged. The setpoint or reference increases or decreases to the new value at a pre-programmed rate.

2-7. USER-DEFINED DISPLAYS

User-Defined Displays are displays that can be altered to conform to the user’s needs. The sections that follow define,describe, and instruct the user in the use of User-Defined Displays.

2-7.1. User-Defined Display Menu

The User-Defined Display Menu is a list of alterable displays that does not include Animated Displays. These displays aretypically known as "Demand" displays. Any Demand display may be selected from the User-Defined Display Menu bypointing and clicking on the desired display with the CPD. Figure 2-9 shows an example of a User-Defined Display Menu.

2-7.2. User-Defined Display Body

The main body of each User-Defined Display (other than the Main Menu or the User-Defined Display Menu) is actually a listof up to 40 pointnames and (if applicable) their associated values and units. This information is arranged in two columns of20 pointnames each. Pointnames can be added or deleted from the display body by the user. Pointnames can be logic (forexample L1START_CPB, L4QAZ, L63TK1L, and so on) or variable (TTXSP1, FSR, CPD, and so on) data points, messagepoints (for example SS43, STATUS_FLD, FLAME, and so on), or annotations (for example TURBINE #1, SRV VALVE,REHEAT VALVE, and so on).

NOTE

Changes to the display body of any display are not saved in the ’s memory unless the user performs aDISPLAY UPDATE from the User-Defined Display Menu immediately after modifying the display. Changesto the display body of any display saved to the ’s memory are not saved permanently to the hard disk filesuntil the operator performs a SAVE FILE operation; this must be done before leaving the User-DefinedDisplay program. See section 2-7.3.5 for details for permanently changing the display body.

2-7.3. User-Defined Display Modifications

User-Defined Displays may be modified by adding or deleting pointnames. User-Defined Displays may also be added to ordeleted from the User-Defined Display Menu. Procedures for the User-Defined Display modifications are described in theparagraphs below. Refer to the flowcharts in the accompanying figures for a quick step-by-step procedure for modifyingUser-Defined Displays.

2-7.3.1. ADDING A POINTNAME. To insert a pointname or notation in the body of a User-Defined Display, point and clickon the display’s INSERT POINT target. The background of the target will change to yellow to indicate the target is enabled. Using the CPD, point to the location in the body of the display where the new pointname or notation is to be inserted andclick. The background of the INSERT POINT display target reverts to white and a white rectangle will appear on the displayin the location chosen. Using the keyboard, enter the desired pointname or notation and press ENTER. The notation or thepointname and its value and units will appear on the display. Refer to Figure 2-10 for a flowchart of the steps involved inadding a pointname to a User-Defined Display.

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Multi-unit functionality permits points from more than one unit to be inserted into a single Demand Display. To enter apoint from a unit that is currently not selected, repeat the steps above but be sure to add a unit specifier before the pointname.This added parameter should include the unit designation, which should be in turn followed by a colon and the pointname (forexample T1:TTXMV4). When the point is displayed, the unit designation will also be shown.

Each time a new pointname is inserted, the pointnames below it scroll down one position. When the forty-first pointname isadded to the display (counting any blank spaces inserted between pointnames) the pointname (or space) at the lower right ofthe body of the display scrolls off the screen and is deleted from the display.

To save pointname or notational additions to the display body, point and click on the MENU display target (this returns theUser-Defined Display Menu to the screen). Check to see that the display named in the Current Display Definition field at thetop of the screen is the name of the display just modified. If the display name is correct, point and click on the UPDATEDISPLAY display target (this action updates the Display/Menu files in the ’s memory).

NOTE

Modifications to the body of a user defined display will be lost if any display (including the Main Display) isviewed prior to performing an UPDATE DISPLAY action from the User-Defined Display Menu.Modifications to a display or displays will be lost if the Main Display is viewed prior to performing a SAVEFILE action (refer to Section 2-9.4.).

2-7.3.2. DELETING A POINTNAME. To delete a pointname or notation from a display, point and click on the DELETEPOINT display target. The background of the target will change to yellow to indicate the target is enabled. Using the CPD,point to the pointname or notation in the display body to be deleted and click. The selected notation or pointname will bedeleted from the display. This method applies to multi-unit pointnames as well. Refer to Figure 2-11. for a flowchart of thesteps involved in deleting a pointname to a User-Defined Display.

To save pointname or notational deletions from the display body, point and click on the MENU display target (this returns theUser-Defined Display Menu to the screen). Check to see that the display named in the Current Display Definition field at thetop of the screen is the name of the display just modified. If the display name is correct, point and click on the UPDATEDISPLAY display target (this action updates the Display/Menu files in the ’s memory).

2-7.3.3. ADDING A USER-DEFINED DISPLAY TO A MENU. To add a new display to a User-Defined Display Menu, switchto the desired unit by clicking on the unit specifier at the top right hand corner of the screen until the required unit isdisplayed. Click on any display in the User-Defined Menu. Repeat the steps outlined above in sections2-7.3.1. and 2-7.3.2. to complete the necessary changes. Once the alterations to the display body have been made, click on theINSERT POINT display target and then click on the display title in the Current Display Definition Field at the top of thescreen. The display title will change to reverse type. Enter in the new title using the keyboard (the BACKSPACE key erasesthe last character in the line; pressing CTRL+U causes the entire title to be erased from the field) and strike the keyboardENTER key when finished (the title will be shown in normal fashion). Click on the MENU display target to return to theUser-Defined Display Menu. From this display click on the UPDATE DISPLAY target. The new display will be added to thebottom of the current User-Defined Display Menu. To make the display addition permanent, click on the SAVE FILE displaytarget. This will store the display addition on the ’s hard disk files. Refer to Figure 2-12 for a flowchart of the stepsinvolved in adding a new display to a User-Defined Display Menu.

A User-Defined Display may be copied to multiple units within a multi-unit .

2-7.3.4. DELETING A USER-DEFINED DISPLAY FROM THE MENU. To delete a display from the User-Defined DisplayMenu, click on the display to be deleted. A display cannot be deleted without first being viewed. Return to the User-DefinedDisplay Menu by clicking on the MENU display target. The title of the display previously viewed will appear in the CurrentDisplay Definition Field. Click on the REMOVE DISPLAY display target. The name of the display just deleted will beremoved from the User-Defined Display Menu even though it will still appear in the Current Display Definition Field. To

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make the display deletion permanent, click on the SAVE FILE display target. This will store the deletion on the ’s harddisk files. Refer to Figure 2-13. for a flowchart of the steps involved in deleting a display from the User-Defined DisplayMenu.

2-7.3.5. MAKING MODIFICATIONS PERMANENT. To make changes to User-Defined Displays or the User-Defined DisplayMenu permanent after performing an Update Display action, click on the SAVE FILE display target before viewing the MainDisplay, the Alarm Display, or the Main Menu. This action saves the current User-Defined Displays and Menus from the’s memory to the hard disk files.

2-7.3.6. COPYING USER-DEFINED DISPLAYS TO MULTIPLE UNITS. A screen that has been created or amended for asingle unit (for example, T1) within a multi-unit , can be copied to other units (for example T2, T3, and so on). This canbe done by viewing the selected screen (this loads the screen in the screen buffer), exiting the screen to the User-DefinedDisplay Menu, changing to the desired unit by clicking on the display’s unit specifier in the screen’s upper right-hand corner,and then in succession executing the UPDATE DISPLAY and SAVE FILE commands. Copying the screen loaded in thescreen buffer to subsequent units can now be accomplished by changing units and again executing the UPDATE DISPLAYand SAVE FILE commands.

NOTE

Performing a SAVE FILE action before executing an Update Display operation does not sav e any changesmade to a display or the User-Defined Display Menu.

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NO

Pointnameaddition

COMPLETE

Pointnameaddition

saved to hard disk

Pointnameaddition

saved to memory only

User DefinedMenu

appears onCRT

YES

Pointname appearson Display; white

rectangle disappears

White rectangleappears wherepointname is to

be added

TargetBackgroundchanges to

yellow

Displayappears on

CRT

Pointname additionTERMINATED

View any otherdisplay

(except AlarmDisplay) and addition

will be lost

Click onSAVE FILE

Display Target

Click onUPDATE DISPLAY

Display Target

Click on MENUDisplay Target

Savepointname addition

to display?

Type in pointnameand press <ENTER>

Click to location indisplay where

pointname is to beadded

Click onINSERT POINTDisplay Target

From the user DefinedDisplay Menu, click on

the display to whichthe pointname is to be

added

Adding apointname

Figure 2-10. Steps Required for Adding a Pointname to a User-Defined Display

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Pointnamedisappears

from display

Pointnamedeletion

saved to hard disk file

Pointnamedeletion

saved to memory only

User DefinedMenu

appears onCRT

YES

NO

Targetbackgroundchanges to

yellow

Displayappears on

CRT

Pointnamedeletion

TERMINATED


(except AlarmDisplay) and deletion

will be lost

Click onSAVE FILE

Display Target


Display Target


Pointnamedeletion

COMPLETE

Do you wish tomake deletion to display

permanent?

From User Defined DisplayMenu, click on display

from which pointname is tobe deleted

Click on pointnameto be deleted from

display

Click onDELETE POINTDisplay Target

Deleting apointname

Figure 2-11. Steps for Deleting a Pointname from a User-Defined Display

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New UserDefined

Display savedto harddisk files

New DisplayTitle appears

on UserDefined

Display Menu;Displayaddition

saved to 

User DefinedMenu

appears onCRT

Display backgroundchanges to white

Targetbackgroundchanges to

yellow

YES

NO

Displayappears on

CRT

Display additionterminated


(except AlarmDisplay) and all

Display additionCOMPLETE

Click onSAVE FILE

Display Target


Display Target


Edit display title using<BACKSPACE> to deletecharacters one at a time

or press <CTRL>+ toerase entire display title;type in new display title

and press <ENTER>

Click on Display Title incurrent Display Definition

Field at top of screen

Click onINSERT POINTDisplay Target

Click on any displayfrom the

User Defined DisplayMenu

Do you wish tocontinue and save

changes to create a newdisplay?

Make addition/deletionsto the display usingINSERT POINT and

DELETE POINT actions

Adding a UserDefined Display

Figure 2-12. Adding a User-Defined Display to User-Defined Display Menu

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Display Titledisappears from

Menu(but still appears

in CurrentDisplay

Definition field)

Displayappears on

CRT

User DefinedDisplay Menuappears with

selected displayin Current

DisplayDefinition Field

Displaydeletion

saved to hard disk files

Deleted Display titlereturns to MENU

(at bottom) YES

NO

Display deletionTERMINATED


Display Target

Display deletionCOMPLETE

Click on SAVEFILE Display

Target

Continue andmake display deletion

permanent?

Click onREMOVE

DISPLAY DisplayTarget


From the User DefinedDisplay Menu, click on

the display to be deleted

Deletion of a userDefined Display

Figure 2-13 Deleting User-Defined Display from the User-Defined Display Menu


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2-7.3.7. COMMAND TARGET ADDITIONS/DELETIONS. Command targets may be added or deleted from a User-definedscreen by implementing the Edit Form function. To access the Edit Form screen, click on the MORE OPTIONS and EDITFORM display targets in succession. The Edit Form screen for the current User-Defined Display (complete with the AlarmWindow) lists the five groups of target definition fields for the 12 available target positions. The cyan fields are used to enterinformation for each command target. To enter information in a particular field, select it by clicking on it; the fieldbackground will change to white to indicate information may be typed in from the keyboard. Pressing ENTER or clicking onanother field completes the action of typing information in a field. To correct, change, or delete information in a selectedfield, use the BACKSPACE key to erase one character at a time beginning with the last character on the line (pressingCTRL+U erases the field completely). The DATA DISPLAY and CHECK FORM targets are both unique to the Edit Formscreen. Clicking on the DATA DISPLAY target returns the user to the current User-Defined Display. Clicking on the CHECKFORM target allows the user to check changes to the edited form for accuracy as the display highlights errors to modificationsin yellow.

Figure 2-14. Edit Form Screen

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The five groups of fields for each command target are:1. Command Pointname2. Value3. Feedback Signal (optional)4. Target Type5. Target Name

1. Command Pointname Fields - The two fields in this group indicate the unit name (in a multi-unit application) andthe pointname of the logic signal which receives the command in the unit control panel. If the unit name field is leftblank (it should be left blank when one or more s are acting on a single unit control panel), the command will besent to the current unit. The unit name field should only be filled in if there are commands which need to be sent to adifferent unit/location than the currently selected unit in a multi-unit installation.

Valid signal pointames which can be acted on by command targets can be found in the UNITDATA.DAT file. Aftercompleting a command pointname entry, the user can verify the validity of the signal pointname which receives thecommand by clicking on the CHECK FORM display target. If the command pointname is valid, one of the fourfollowing messages will appear directly beneath the field: Pushbutton, Logic state, Analog setpoint, or Enumeratedstate.

If the entered signal pointname is invalid, executing the CHECK FORM function will cause it to be displayed with ayellow background or the error message "Not a command" to appear.

A pointname that is displayed with a yellow background indicates the could not find a match in the DataDictionary. A pointname that is found in the Data Dictionary but is not a valid signal pointname which can be actedon by a command target will cause the above error message to be displayed.

2. Value Fields - The Value and Value Type fields are used respectively to specify the actual value and value type thatwill be sent to the current unit control panel (this is for command targets which do not require the operator to enter ina setpoint or value when selected or executed).

The following represent the three valid value types:

= For logic state, analog setpoint, and enumerated state command pointnames, this value type instructs the toread the current value of the command pointname from the unit control panel into its memory, replace it with avalue from the value field to the right, and send the new value to the unit control panel to be acted upon. If thecommand pointname is a pushbutton value, this value type tells the to set and hold the command pointnameequal to a logic "1" for the number of scans in the value field to the right. By default, when the commandpointname is a pushbutton, the value type is set to " = " and the value field is set to " 4 " (meaning thepushbutton command pointname will be set for four scans of the unit control panel).

+ This value type can only be used with analog setpoint commands. Its function is to instruct the to read thecurrent value of the command pointname from the unit control panel into its memory, add the value from thevalue field to the right, and send the new value to the unit control panel to be acted upon.

- This value type is used in conjunction with analog setpoint commands; its function is to instruct the to readthe current value of the command pointname from the unit control panel into its memory, subtract the value fromthe value field to the right, and send the new value to the unit control panel to be acted upon.

Values entered and shown in the value field itself are hexidecimal values. When a value is entered into this field, theline directly below the field will contain the engineering units conversion of the hexidecimal value. This conversionwill only be done if a valid command pointname has been entered into the command pointname field. (It is notpossible to enter a value in the value field in engineering units .)

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3. Feedback Signal Fields - When used, this option changes the color of the text of the command target to yellowbased on the logic state of the command pointname. For example, the text of ARM/EXECUTE targets used to selector change the operating state of a turbine changes to yellow as an extra indication to the viewer of the currentoperating state (this is the most common usage of this option). The three fields in this option are feedback sense ofthe signal pointname (that is, either "0" or "1"), unit number/designation (the two character designator for the desiredunit), and the signal pointname (whose feedback sense will be used to set the color of the text of the commandtarget). If logic "1" is selected as the feedback sense, the text of the target will be displayed in yellow when thefeedback signal pointname is a logic is "1".

4. Target Type Field - This field is used to specify the type of target, and consequently, its background color.ARM/EXECUTE targets have a green background, SETPOINT targets have a dark grey background, andIMMEDIATE ACTION targets have a red background. The following values are used in this single-character fieldto specify the type of target:

? This symbol is used to specify an ARM/EXECUTE target.# This symbol is used to specify a SETPOINT target.! This symbol is used to specify an IMMEDIATE ACTION target.

5. Target Name - This is the text which will appear in the target on the display. A maximum of two lines of eightcharacters per line may be typed in. (To allow space for the outline around the target, the first character in each lineshould be a blank space). Remember, setpoint command targets which prompt the operator for a value use the lowerline of the target for the entry; therefore, the main function of the target, or the most descriptive term, should beplaced on the upper line of the target.

2-8. ALARM DISPLAY

The Alarm Display is a list of turbine and driven device alarms (refer to Figure 2-15). Alarms are listed on the display withthe latest, that is, the very last alarm condition to have occurred, at the top of the list. This is the "Track Latest" mode. Whenan alarm condition is annunciated, it also appears in the blue Alarm Window of any display. The display message field of theAlarm Display includes an additional line of information about the number of acknowledged and unacknowledged alarms.Alarm management is required to correct, resolve, and remove annunciated alarms from the display (alarm management tasksare explained further in this section). Annunciated and changed state alarms are automatically logged by the printer.


2-22

2-8.1. Alarm Information

Each annunciated alarm on the display includes the following information:

• DATE/TIME. This value defines the date and time (from the Mark V Control Panel’s system clock) that thealarm condition first occurred and was annunciated (prior to being reset).

• UNIT NUMBER/DESIGNATION. Found under the "U" column of the Alarm Display, this value defines theunit number or designation of the turbine control panel which annunciated the alarm condition.

• ALARM STATUS FLAG. Found under the "S" column of the Alarm Display, this value defines the currentstatus of the alarm condition. A logic "1" in this column indicates an alarm condition currently exists andrequires corrective action to be reset (or cleared from the screen). A logic "0" in this column indicates the alarmcondition no longer exists and the message can be cleared from the screen by performing an alarm reset.

• ALARM ACKNOWLEDGEMENT. Found under the "A" status column of the Alarm Display, an asterisk(*) in this column indicates the alarm condition has not been acknowledged. The absence of an asterisk in thiscolumn indicates the alarm condition has been acknowledged. Acknowledgement of an alarm is necessarybefore an alarm can be reset, even if the status flag for an alarm is a logic "0".

• PROCESSOR. The characters in this column ("P") indicate which processor(s) annunciated the listed alarms.• ALARM DROP NUMBER. The value in the "Drop" column for an alarm is the drop number for the alarm

being annunciated. (Drop numbers are useful when troubleshooting alarms with the unit elementaries.)• ALARM MESSAGE. This is a short written description of the alarm condition being annunciated.

Figure 2-15. A Typical Alarm Display

2-23

2-8.2. Silencing Annunciated Alarms

The first step in resolving an alarm condition is to silence the alarm horn. To this end, there are two methods. The first (andsimplest) is simply to click anywhere in the Alarm Window. The second method involves changing to the Alarm Display byclicking on the ALARM DISPLAY display target, and clicking on the SILENCE target.

2-8.3. Acknowledging Alarms

Alarm conditions annunciated on the require an acknowledgement indicating that the operator is aware of the alarm. Theoperator can acknowledge any or all unacknowledged alarms by clicking on the ACK ALL target of the Alarm Display. Whenalarms are acknowledged, the asterisks (*) denoting their unacknowledged )ondition are deleted from the Alarm Display’sAcknowled)ment Status column; also, the associated alarm messages are removed from the Alarm Window. Alarms may beacknowledged individually from the Alarm Display by clicking on the desired alarm message ("selecting" the alarm). Thealarm message is highlighted in a grey rectangle and the text of the alarm message changes to green. The display targets at thebottom of the screen change to allow individual acknowledgement (and resetting) of the selected alarm; clicking on the ACKALARM display target will acknowledge only the selected alarm. Another method of acknowledging an alarm is to click onone character/space on either side of the Acknowledgement Status asterisk in the Alarm Window. This will send a commandto the Control Panel to acknowledge the alarm, delete the Acknowledgement Status asterisk from the alarm message on thescreen, and delete the associated message from the Alarm Window.

2-8.4. Resetting Alarms

When an alarm condition has been corrected or satisfied, the Status Flag of the alarm message changes from a logic "1" to alogic "0". To remove acknowledged, invalid alarm messages from the Alarm Display once the conditions have been correctedor satisfied, the operator performs an alarm reset action by clicking on the RESET ALL display target.

NOTE

Before alarms can be reset, they must be acknowledged (no asterisk in the Acknowledgement Status column)and the alarm conditions must no longer exist (a logic "0" in the Status Flag column).

Resetting an alarm causes future occurrences of the alarm condition to be annunciated with an audible signal. Failure to resetan alarm condition which has been corrected or satisfied will prevent future occurrences of the alarm from being annunciatedby an audible signal. They will however be logged to the printer and in the Historical Log Alarm Queue. Individualacknowledged alarms may be reset from the Alarm Display by clicking on the desired alarm message ("selecting" the alarm),then clicking on the RESET ALARM display target. The highlighted alarm will be erased from the Alarm Display.

2-8.5. Locking Out Alarms

An alarm whose condition is changing repeatedly (dithering) and whose Status Flag is toggling between logic "1" and logic"0" can be a nuisance. Alarms such as these are logged to the printer and to the Historical Log Alarm History queue wherethey take up valuable alarm history queue space. An operator may prevent such an alarm from being continually logged byselecting the alarm, clicking on the MORE OPTIONS display target, and clicking on the LOCK ALARM display target. TheStatus Flag of the selected alarm message will change to an " L " to indicate that the alarm is locked-out (refer to Figure 2-16). The locked-out alarm is logged to the printer with an appropriate message, date, and time. Subsequent changes in thestatus of the alarm will not be logged to the printer or the Historical Log Alarm History queue.


2-24

CAUTION

Full understanding of the consequences of an alarm condition to the unit operating system should be known prior tolocking the alarm out.

Failure to unlock and reset an alarm after the dithering condition has been corrected or satisfied prevents futureoccurrences of the alarm from being annunciated and logged. Immediately after resolving a dithering alarmcondition, unlock and reset the alarm to allow annunciation and logging of the alarm.

2-8.6. Unlocking Alarms

Once a dithering alarm condition has been corrected, it is necessary to unlock the alarm in order to reset the alarm (clear itfrom the alarm display). Alarms are unlocked from the Alarm Display by selecting the alarm which is to be unlocked byclicking on it, clicking on the MORE OPTIONS display target, and clicking on the UNLOCK ALARM display target. TheStatus Flag of the selected alarm will revert to the actual state of the alarm condition (if the alarm condition has beencorrected or satisfied, the Status Flag will be a logic "0"). An unlocked, acknowledged alarm whose Status Flag is a logic "0"can then be reset from the Alarm Display.

2-8.7. Printing The Alarm Display

Figure 2-16. Alarm Display with an Alarm Selected and Locked Out

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A color print of the Alarm Display may be made at any time by clicking on the display’s MORE OPTIONS display targettwice, and then clicking on the COLOR PRINT display target.

2-8.8. Diagnostic Alarms

Internal diagnostic self-checks and tests are performed in the Mark V Control Panel by the processors and other components(that is, individual printed wiring assemblies). Whenever a component or process fails one of these internal tests, the result isreported to the operator as a Diagnostic Alarm on the Alarm Display and consequently the Alarm Display window. DiagnosticAlarms are annunciated by an audible alarm horn. This horn can in turn be silenced in a manner identical to that for processalarms (See section 2-8.2.). Annunciated Diagnostic Alarms that appear in the Alarm Display are logged to the printer in theformat shown below:

Date/Time U SA P Drop Description

13-MAY-1994 16:15:13.015 S1 1* Q 0000 TRUE DALARM DIAGNOSTIC ALARM <C><Q>

Figure 2-17. Diagnostic Alarm Format

Note that the alarm message details the processor in which the alarm occurred (Q) while the alarm description is definedsimply as "DIAGNOSTIC ALARM." The viewing of a silenced Diagnostic Alarm and its complete description can be donevia the Diagnostic Alarm Display (See Figure 2-18). To access the display, exit to the Main Menu and click on the DiagnosticAlarm Display selection. For a printout of the Diagnostic Alarm Display click on MORE OPTIONS and COLOR PRINTdisplay targets in succession. These targets are located at the bottom of the screen.

NOTE

Diagnostic Alarms should be reported to the proper personnel for investigation and resolution. Theyserve as an indication of the internal operation of the Mark V Control Panel and as such, should bedealt with promptly to ensure continued availability and reliability of the control system and turbine.

From the Diagnostic Alarm Display, diagnostic alarms may be manipulated (selected, locked out, unlocked) just like processalarms on the normal Alarm Display. Diagnostic Alarms must be acknowledged, resolved and reset from the DiagnosticAlarm Display, just like process alarms are from the normal Alarm Display. Once a Diagnostic Alarm condition has beenresolved, the Diagnostic Alarm Status Flag on the Diagnostic Alarm Display will change to a logic"0". This will allow the alarm to be reset (by clicking on the RESET ALL display target) and cleared from the DiagnosticAlarm Display. When all Diagnostic Alarms have been cleared from the Diagnostic Alarm Display, the Alarm Status Flag onthe normal Alarm Display will change to a logic "0". This will permit the diagnostic alarm to be reset/cleared from the normalAlarm Display.

NOTE

The Diagnostic Alarm annunciation on the normal Alarm Display can only be reset, or cleared, fromthe display when all Diagnostic Alarms have been acknowledged, resolved, and reset from theDiagnostic Alarm Display.

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2-9. TRIP LOG DISPLAY

The function of the Trip Log Display is to assist in the evaluation of circumstances that lead to turbine trip events. The displayaccomplishes this by providing a chronological record of relevant data gathered by the Mark V Control Panel. Whenaccessed, the Trip Log Display allows the user to view, save, and print turbine trip data. Screens and the signal pointinformation they depict are organized within the display according to post-trip, pre-trip, and alarm categories. Control SignalDatabase information logged in the alarm section of the display is not user-definable. However, Control Signal DatabasePoints (CDBs) can be defined for both pre-trip and post-trip screens. These definitions (64 max.) are made within a single file(HIST_B.SRC) and are identical for the two screen types. All data in the display is chronologically indexed according toMark V Control Panel time and a separate panel counter (HIS_AGE CNTS).

2-9.1. Display Header Information

The Trip Log Display can be accessed from the Main Menu system.

In the top left-hand corner of the display, four separate fields define the site name (GEDS), unit number (6A), page number ofthe display (PAGE #), and sampling rate at which the exhibited data was collected (1 second). To the right of this informationare two fields that define the display’s title (TRIP LOG DISPLAY) and status (CURRENT LOG). This latter designationspecifies whether the display is presenting the latest data received from the panel (CURRENT LOG) or data that has beenpreviously viewed and saved to a file on the ’s hard drive (SAVED LOG). The date and time specifiers in the display’s topright corner represent Mark V Control Panel time for the panel being interrogated (6A).

Figure 2-18. Example of the Diagnostic Alarm Display


2-27

2-9.2. First Displayed Screen (PAGE 2)

The screen shown in Figure 2-19 is the first to appear when the Trip Log Display is called. However, it is not the first page ofthe display. The first screen displayed is actually the second page (PAGE 2) of information. The first displayed page (PAGE1) is a register (updated once-per-second) of the first three seconds of data gathered after a trip has occurred (LIST POST).The rationale for this arrangement is twofold: 1. it prevents the user from being presented a blank screen if the display isaccessed and no trip has occurred 2. should a turbine trip occur, data recorded up until the time of the trip will be displayedimmediately when the Trip Log menu is selected.

2-9.3. Time vs. HIS_AGE CNTS

For pre-trip and post-trip screens, time (TIME) tag definitions are listed for the displayed Control Data Point information.These designations provide a chronological index that ties the exhibited signal information to Mark V Control Panel time.This register can provide valuable information in terms of determining the sequence of events that lead to a turbine trip. If thepanel time is reset during an event however, this index will be lost. To prevent such an occurrence, the Trip Log Display isequipped with a second counter that, though internal to the Mark V Control Panel, runs independently of the panel clock.Updated once-per-second, this counter (HIS_AGE), advances until a maximum value is reached (65535). At that point, thecounter returns to zero and restarts.

Figure 2-19. Trip Log Display

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NOTE

In the post-trip example (Figure 2-22.), there is a discrepancy between the panel time designationsand the HIS_AGE counter. The panel time continues for all three seconds while HIS_AGE stopsincrementing. This is due to the fact that the counter (HIS_AGE) is enabled/disabled by the L4permissive, which is in turn disabled (set to 0) by a turbine trip event.

2-9.4. Control Signal Database Pointnames

Each Mark V Control Signal Database point defined for the Trip Log Display is incorporated into pre-trip and post-tripscreens as a column header (for example DWATT, TNH, FSR, L52GX, L14HR). Underneath these point definitions arefields that display their respective scale types (MW, %, LOGIC, and so on). Although only five data points are viewable inthe illustration above, pre-trip and post-trip screen types can display the data of up to 64 points. Points that are notimmediately viewable can be examined by wrapping the screen using the <6 POINTS and >6 POINTS targets at the bottom ofthe display below the alarm window. Note that each wrapped screen will show six data points, five new points plus theHIS_AGE counter.

2-9.5. Display Targets

In addition to the <6 POINTS and >6 POINTS targets described above, there are display targets defined for the Trip LogDisplay that allow the user to save, print, and switch screens (in both CURRENT and SAVED logs) as well as exit theprogram altogether. All of these targets can be viewed by clicking on the MORE OPTIONS selection.

Exiting the display to the Main Menu can be accomplished using the CPD to click on the EXIT target. Similarly, the Alarm orMain Displays can be directly accessed by executing the ALARM DISPLAY or MAIN DISPLAY commands. Clicking onthe MORE OPTIONS target results in the following targets being displayed:

Supplementary targets in this new set include CURRENT LOG, SAVED LOG, UPDATE CUR LOG , and UPDATE SAVLOG.

2-9.5.1. CURRENT LOG/SAVED LOG. The (Current) Trip Log Display is essentially a fixed "snapshot" of binary dataretrieved from a Mark V Control Panel buffer. This Current Log exists in the Mark V Control Panel. As such, the user maywish to update the display log information by copying new information from the buffer. This can be done using the UPDATECUR LOG display target.

NOTE

Updating the Trip Log will cause data previously stored to be overwritten and lost unles s the old log is savedfirst.

Figure 2-20. Display Targets (2nd Set)

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Recorded Trip log information may be copied from the Mark V Control Panel to a unit-specific file(F:\RUNTIME\HISTORYF.B#) in the by executing the UPDATE SAV LOG command.

NOTE

Updating the unit-specific file stored in the RUNTIME directory will cause previously saved data to beoverwritten and lost. This can be avoided by copying the data file to another location before an update isexecuted. Current and Saved Logs can be examined by executing the CURRENT LOG and SAVED LOGcommands respectively.

2-9.5.2. PRINT REPORT. If executed, the PRINT REPORT command will cause the sum of the information in the logcurrently being viewed (Current Log, Saved Log) to be sent to the printer. The CURRENT LOG or SAVED LOG reports canbe printed individually using this function.

2-9.5.3. PRINT IMAGE/SAVE IMAGE. If, from the initial target set, the MORE OPTIONS target is clicked on twice, thefollowing display target options will appear:

Figure 2-21. Display Targets (3rd Set)

Again, as in all Trip Log Display target sets, the EXIT, ALARM DISPLAY, and MAIN DISPLAY targets are shown. Thisuniformity permits direct access to either Alarm or Main Displays or the Main Menu from anywhere in the Trip Log Display.Supplemental commands in this series are found in the PRINT REPORT, SAVE IMAGE and PRINT IMAGE targets. ThePRINT REPORT target was discussed in the previous section. The SAVE IMAGE command saves the currently viewedimage to a file. When the SAVE IMAGE command is executed, the SAVE IMAGE target will momentarily indicate thenumber of the image file into which the screen is being saved. Image files are created and stored in the F:\USER directory.The PRINT IMAGE target sends to the printer the image currently being viewed.

2-9.7. Pre-Trip Screens

In terms of formatting, the pre-trip display screen is identical to the post-trip screen. Screen header information and signalpoint data is shown in an identical fashion. However, whereas there is only one post-trip screen, there are five (5) pre-tripscreens. These screens record information at varying time intervals. The first pre-trip screen is updated once-per-second whilesubsequent screens are updated at ten second, one minute, ten minute, and one hour intervals. For pre-trip screens with updateintervals of more than one second, the HIS_AGE counter can not only act as a backup timing device but also help to enhanceresolution of the intervals between screen updates.

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2-9.8. Alarms

The alarm screens in the Trip Log Display form an itemized list of the last sixty alarm events that occurred before the turbinetrip event. Individual alarms are chronologically labelled according to panel time.

NOTE

Although they can be displayed, the <6 POINTS and >6 POINTS targets have no effect on alarm screens.All other display targets remain functional for the alarm section.

2-9.9. Defining Control Signal Database Points

A single set of Control Signal Database Points may be defined for both pre-trip and post-trip sections ofthe Trip Log Display. For details, see the Maintenaqnce Manual GEH-5980.

2-10. EPA DISPLAY

Located in the Main Menu, the Environmental Protection Agency (EPA) display allows the user to view, save, and printenvironmental data for gas turbine applications. This data is displayed in terms of both hourly and minute-to-minute rollingaverages. Hourly rolling averages are computed according to data received once a minute while minute-to-minute rollingaverages are computed on the basis of 60 second intervals.

Figure 2-22. Post-Trip Display

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2-10.1. Example

The screen shown in Figure 2-25 is an example of the EPA display. In the top left-hand corner there are three fields thatdefine site and unit information. Also shown is the specific page number of the display. Moving to the top right, the displayshows the name of the display (EPA DATA DISPLAY) and the current Mark V Control Panel date and time.

Below the display information, to the left side of the display, there are headers that label the HOUR AVERAGE andMINUTE AVERAGES. The Time (definition field) for the hourly average is static in the sense that it is not replicated everytime an update occurs. When an update takes place, the time exhibited in the field changes to denote the time the new hourlyaverage was calculated. Conversely, the MINUTE AVERAGES fields are reproduced in vertical succession each minute. Thismeans that eventually the screen will scroll down until all 60 minute averages have been displayed. At that point, the hourlyaverage will be updated and the minute averages will start over. Each Mark V data point defined for the EPA display isincorporated into the screen as a column header (DWATT, CTIM, TTXM, WXJ, WXC, CMHUM).

Underneath these point definitions are fields that display their respective scale types. Although there are only six data pointsdefined in the example, the EPA screen can display the rolling averages of up to sixteen Control Data Points. Data points andtheir rolling averages that are not immediately viewable can be examined by wrapping the screen using the < POINTS and >

Figure 2-23. Post-Trip Display - Continued


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POINTS targets at the bottom of the display. In addition to these targets, the PREV PAGE and NEXT PAGE targets permitviewing of more than one screen. This function can be useful for inspecting Minute averages that have scrolled off the initialdisplay. Other targets shown below the alarm window include the EXIT, MORE OPTIONS, ALARM DISPLAY , andMAIN DISPLAY targets. The EPA screen can be exited to the Menu system by clicking on the EXIT target. Clicking on theALARM DISPLAY or MAIN DISPLAY targets effects an exit to these respective displays. The MORE OPTIONS targetcan be used to bring up the following additional targets: SAVE IMAGE and PRINT IMAGE. These items can be used tosave the screen currently displayed to the F:\USER directory or print the screen currently displayed. If the PRINT IMAGEcommand is executed, the screen image will be sent to the print queue.

2-11. PRINTING FUNCTIONS

Various functions of the Mark V Control Panel are logged to the printer(s) automatically while others make use of the printeron command.

Fig. 2-24. Alarm Screen


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Figure 2-25. EPA Screen

2-11.1. Alarm Logging

Mark V Control Panel diagnostic and process alarms are logged on the printer(s) when they are annunciated and when theyare resolved. When an alarm is annunciated, the printed alarm status will read "True". When the alarm condition is corrected,resolved, or satisfied, the event is logged to the alarm status and will read "False". The format of logged alarms is shown inFigure 2-26.

Figure. 2-26. A Sample of an Alarm Printout

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When an alarm is logged to the printer with a FALSE status, the date and time the alarm condition was resolved is noted.

2-11.2. Event Logger

The event logger consists of two fields that use the printer(s) as described below.

2-11.2.1. POINTNAME. This field identifies the pointname which has been selected/designated to be logged to a printerwhen a change of state occurs.

2-11.2.2. STATUS. There are two status conditions for events which are logged.

• TRUE If the event logged with a TRUE status is a logic pointname, the pointname's logic value just changed to a logic "1".

• FALSE If the event logged with a FALSE status is a logic pointname, the pointname's logic value just changedto a logic "0".

2-11.3. Event Type

Two types of events can be logged to the printer(s) in the Mark V system. The first includes digital contact inputs which havebeen selected/designated to print out on a change of state. The second entails selected logic state changes (update at framerate). The date and time, unit number, and processor fields of logged events are identical to those of the alarm logger. Thefields unique to the event logger are described below.

• CONT_IN If an event logged to the printer is a CONT_IN (contact input) type, the logic valueof the pointname which is printed as part of the event is "attached" directly to (or"driven by") an external contact input device such as a limit switch, temperatureswitch, pressure switch, and so on For example, if the following event were loggedto the printer, it would be an indication that the limit switch 26QT2A had justchanged state.

10-DEC-1991 17:03:22.679 T1 Q L26QT2AH TRUE CONT_IN L.O. TEMP TRIP SWITCH

• EVENT If an event logged to the printer is an EVENT type, the logic value of the pointnamehas just changed state. For example, if the following event was logged to the printer,it would be an indication that the primary overspeed test mode had been deselected.

10-DEC-1991 11:15:10.150 T1 C L83POST_ONL FALSE EVENT ON-LINE OVERSPEED TEST

2-11.4. View Image/Save Image

The functions of the Image Viewer are to view, print, and delete image files saved with the SAVE IMAGE target. This targetcan be found on most of the displays. An image is, in effect, a 'snapshot' of a Mark V screen. Images may be useful forlogging current operating data, or for referencing screens when creating new ones.

The Image Viewer may be accessed from the Main Menu System. Clicking on the View Image option will display the screenshown in Figure 2-27.

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Figure 2-27. Sample of Image Viewer Screen Display

The display includes the following information and options:

• DISPLAY HEADER INFORMATION. The field at the top center of the display defines the display titleIMAGE VIEWER. The top left-hand field displays the site name NRV562, and top right-hand field displays the time. Under the title is the instruction to "CLICK ON THE DESIRED DISPLAY."

• DISPLAY TARGETS. The Image Viewer has three targets located at the bottom of the display. Return to theMain Menu by using the CPD to click on the EXIT target. Similarly, access the Alarm or Main displays byexecuting the ALARM DISPLAY or MAIN DISPLAY commands.

• SAVED IMAGES. The body of the Save Image Display is a menu of images saved from other displays. Themenu lists the saved images numerically. When the SAVE IMAGE target is selected from the other displays,the system saves the image and names the file with a sequential number (01, 02, 03, and so on) and an ".IMG"extension. Successive numeric values are assigned to files according to availability. For example, if the file02.IMG is deleted and the files 01.IMG and 03.IMG exist, the next execution of SAVE IMAGE from a displaywill save the image as 02.IMG. The SAVE IMAGE target will supply the user with the image name when thefile is saved.


2-36

• VIEWING AN IMAGE. To view an image, select it with the CPD device. Note that the EXIT, ALARMDISPLAY, and MAIN DISPLAY targets flash between white and cyan. This is to show that this is a frozenimage, not a real time display, and that these three targets are active while viewing an image. Any keyboardaction or a CPD click will return to the menu of saved images. Selecting an image highlights the image name inyellow.

• PRINTING AN IMAGE. On the right-hand side of the display, display targets listing the printers defined forthe system are presented. Clicking on a printer target will send the highlighted image to the selected printer. Besure not to delete an image until it has completed printing as it will not print. Also, it is recommended that notmore than ten images be sent to the printer spooler at one time. If more than ten files are sent, only the first tenwill be printed. When the printer completes the printing of a file, the spooler will accept another file insuccession.

• DELETING AN IMAGE. The DELETE IMAGE target at the bottom will delete the image from the disk. Usethis feature to make room on the hard drive for more images or for deleting unwanted image files.

3-1

CHAPTER 3

USING THE BACKUP OPERATOR INTERFACE

3-1. INTRODUCTION

The backup operator interface <BOI>, or backup display, is a second means of monitoring turbine and driven deviceoperation and/or issuing commands to the Mark V Control Panel (refer to Figure 3-1). Typically mounted on the Mark VControl Panel enclosure, it is comprised of an integrated keypad and LCD display. The backup display is capable ofannunciating alarms, acknowledging alarms, resetting alarms, initiating turbine startups and normal shutdowns, loading andunloading the turbine and driven device, displaying operating data in both pre-defined and user-defined displays, andperforming manual operations on the turbine and driven device. Help screens are available on the backup operator interfaceto assist the operator in the use of the backup operator interface displays.

Intended for use as an alternate means of turbine/process control and monitoring in the event of loss of communicationsbetween the and the Mark V Control Panel, or a failure of the , the <BOI> can be used to monitor turbine and drivendevice operation and issue commands at any time. The <BOI> Control and Display functions are fully configurable. Fordetails see the Maintenance Manual GEH-5980.

Figure 3-1. Backup Operator Interface <BOI>

3-2

CAUTION

Turbine and driven device commands may be issued at any time from the <BOI> regardless of the status ofthe and/or its communication link with the Mark V Control Panel. Therefore, care should be taken not toinitiate unit commands from the <BOI> when control is being executed from the as the Mark V ControlPanel will execute these commands.

In a Mark V TMR Control Panel, the <BOI> is connected to <R>, <S>, and <T> ; commands are therefore issued from the<BOI> to all three processors. Conversely, data shown on the <BOI> display is received from a single "designatedprocessor." The processor typically selected for this function is <R>, however, the <BOI> allows the user to choose whichprocessor (<R>, <S>, <T>) will be used to update the display (See section 3-9, Processor Select Display). In a Simplex MarkV Control Panel, the <BOI> is connected to the <R> processor; as such, data transmission only occurs between the <BOI>and this device.

Several of the <BOI> displays are multi-page (that is, there is more than one screen of information or commands available).To advance to the next page or return to the previous page of a display, use the SCROLL UP and SCROLL DOWN keys onthe <BOI> keypad.

3-2. MENU DISPLAY

The Menu Display is a multi-page listing of Enumerated Switch and Main/Normal displays (max. 32). It can be accessed bypressing and holding the SHIFT key while the MENU key is depressed. Four Enumerated Switch or Main/Normal displays,including their corresponding function keys (F1 - F20), can be viewed at one time. Any Menu Display screen can beexamined by using the SCROLL UP and SCROLL DOWN keys; also, an individual Menu display may be directly accessedby pressing the appropriate function key. The first twenty Menu displays can be accessed using the function keys (F1-F20); inaddition, these and any other Menu Display (1-32) can be accessed by pressing the DSP and the numbered value keys (0 - 9).

While viewing the Menu Display, pressing the HELP key presents the operator with the following multi-page message:

The Menu Display can also be accessed from any display by pressing DSP, pressing the "0" key, and pressing ENTER.

MENU SHOWS THE KEY WHICH SELECTS ADISPLAY. DISPLAYS CAN ALSO BE SELECTEDBY PRESSING DSP, ENTERING A DISPLAYNUMBER, AND PRESSING ENTER. SCROLL KEYSMOVES THE DISPLAY THROUGH THE MENU LIST

Figure 3-2. Multi-Page Instruction Message

3-3

3-3. ALARM DISPLAY

The Alarm Display can be accessed at any time by pressing the ALARMS key. The display lists alarms in the <RST> alarmqueue in order of occurrence. The last annunciated alarm is shown in the upper left-hand field of page 1 (see figure 3-3). TheAlarm Display pages are divided into four fields; the upper right-hand field shows the number of unacknowledged andacknowledged alarms and the page number of the Alarm Display. The Display’s three remaining fields display annunciatedalarms. If more than three alarms are annunciated, subsequent pages of the Alarm Display can be accessed by pressing theSCROLL DOWN key. Each annunciated alarm is displayed with an alarm drop number, the status flag/acknowledgecondition, and the date and time the alarm occurred. (Note that these signifiers are identical in function to those displayed inthe Alarm Display of the . See section 2-8.1., Alarm Information.) An asterisk "*" in the status flag column indicates thealarm has not been acknowledged.

While viewing the Alarm Display, pressing the HELP key presents the operator with the following multi-page message:

229 * 18DEC13:08:51 UNACK 15 ACK 00 P02149 * 18DEC13:09:58 191 * 18DEC13:09:29

Figure 3-3. <BOI> Display Showing Portion of Alarm Display

THE DISPLAY COMES UP SHOWING THE NEWESTUNACKNOWLEDGED ALARMS. AN * IN THE STATEFIELD INDICATES AN UNACKNOWLEDGED ALARM.PRESSING THE ALARM ACK ACKNOWLEDGES THEALARMS SHOWN. PRESSING THE ALARM RESETREMOVES ALL THE ALARMS WHICH AREACKNOWLEDGED AND HAVE A ZERO STATE.SCROLL KEYS MOVES DISPLAY THROUGH THEALARM LIST.

Figure 3-4. Alarm Display Multi-Page Message

3-4

Alarm management using the <BOI> requires silencing of the audible alarm horn, acknowledgement of the annunciatedalarm, and resetting the alarm (removing it from the display) once the alarm condition has been corrected or satisfied. Theseactions are described in the following sections.

3-3.1. Alarm Management

The following sections provide information concerning the management of alarms.

3-3.1.1. Silence. To silence the audible alarm horn in the Mark V Control Panel, press the ALARM SIL key on the <BOI>keypad..

3-3.1.2. Acknowledge. To acknowledge an alarm using the <BOI> Alarm Display, press the ALARM ACK key on thedevice keypad. This action acknowledges the alarm(s) exhibited in the Display’s current page and increments theacknowledged alarms counter in the upper right-hand field of the backup display. The asterisk in the status flag column of thealarm(s) will change to either "1" or "0", depending on the current condition of the alarm. To acknowledge other annunciatedalarms (if present), use the SCROLL DOWN key to move to the next page of the Alarm Display and press ALARM ACKuntil all alarms have been annunciated. The unacknowledged alarm counter in the upper right-hand field will show "00".Alarms must be acknowledged in order to be reset (removed from the display) once the alarm condition has been corrected.

3-3.1.3. Reset. An acknowledged (annunciated) alarm condition that has been corrected or satisfied may be reset (removedfrom the display) by pressing the ALARM RESET key. (Only an acknowledged alarm with a status field value of logic "0"can be reset.) Resetting an alarm causes future occurrences of the alarm condition to be annunciated with an audible signal inorder to alert the operator. Failure to reset an alarm condition which has been corrected or satisfied will prevent futureoccurrences of the alarm from being annunciated by an audible signal; they will, however, be logged to the printer and in theHistorical Log Alarm Queue.

3-4. ENUMERATED SWITCH DISPLAYS

Enumerated Switch Displays are operator selectable modes of operation (for example, OFF, AUTO, MANUAL, BASELOAD, and so on ) that can be executed from the <BOI>. To select a different function on an Enumerated Switch Display,use the cursor left, < , and cursor right, > , keys to move the locator (or cursor) symbol to the desired function and press theENTER. The newly selected function will now be preceded by an asterisk (see Figure 3-5). If an Enumerated Switch Displayhas more functions than can be shown on a single page, the SCROLL DOWN and SCROLL UP keys can be used to view theadditional functions.

*......... PRESEL BASE PEAK PEAK_R

Figure 3-5. <BOI> Display Showing Preselect Load Selection Display

3-5

While viewing the Enumerated Switch Displays, pressing the HELP key presents the operator with the following multi-pagemessage:

3-5. MAIN/NORMAL DISPLAYS

Main or Normal Displays are used to implement such functions as Lead/Lag Pump or Fan Selection, Speed or Load SetpointCommand and Selection, and so on (see Figure 3-7). Typically broken into four fields, the points which can be selected areprefixed by the symbol " ^ ". The cursor symbol ">" on a Main/Normal Display can be moved by using the left arrow "<"and right arrow">" keys. Selected points are prefixed with an asterisk, "*". With the locator in front of a desired point,pressing ENTER will select the point; this is indicated by the appearance of an asterisk in front of the point. Points can bedeselected by pressing the ESC key. Only one point can be selected at a time. If the selected point is a command"pushbutton", pressing the RAISE or LOWER key will send the command to the Mark V Control Panel. If the selected pointis a logic representation of a two-position switch (either "0" or "1"), pressing RAISE will change the state from a logic "0" toa logic "1" while pressing LOWER will change the state from a logic "1" to a logic "0".

If the selected point is an analog type, two methods are available for changing its value. The first involves implementing theRAISE and LOWER keys which can be used to increase or decrease the point’s value. The second entails direct entry of avalue via the Set mode screen. Access to this screen can be had by pressing the SET key. Within the screen, the selected valueand a field into which the new value may be entered directly will be shown. After entering the new value into the field, thenew value will be transmitted directly to the processor(s) by pressing ENTER. Pressing the ESC key will transfer the operatorback to the Main Display from which the Set Mode was entered.

THE FUNCTION PREFIXED BY AN * IS THESELECTED FUNCTION. THE < AND > KEYS AREUSED TO MOVE TO A NEW FUNCTION. THE NEWFUNCTION WILL BE PREFIXED BY AN >. THEENTER KEY WILL SELECT THE NEW FUNCTIONPREFIXING IT WITH AN *) AND DESELECTTHE OLD FUNCTION. IF THERE ARE MORE THAN1 WINDOW OF FUNCTIONS, THE SCROLL KEYSWILL MOVE THE DISPLAY TO THE NEXT WINDOWOF FUNCTIONS.

Figure 3-6. Enumerated Switch Display Multi-Page Message

LOAD_S ......... >PS_CMD 15.0 MW DW 15.2 MW

Figure 3-7. <BOI> Display Showing Load Selection Display

3-6

While viewing Main/Normal Displays, pressing the HELP key presents the operator with the following multi-page message:

THE POINTS PREFIXED BY AN ^ ARE THEPOINTS WHICH CAN BE RAISED, LOWERED ANDSET. THE POINT PREFIXED BY > IS THECURRENT POINT. THE < AND > KEYS ARE USEDTO MOVE TO A NEW POINT. THE ENTER KEYWILL SELECT THE NEW POINT (PREFIXING ITWITH AN *) AND DESELECT AN OLD POINT. THESELECTED POINT CAN THEN BE RAISED ANDLOWERED. PRESSING ESC WILL DESELECT THEPOINT. PRESSING SET DISPLAYS THE SELECTEDPOINT IN THE SET MODE. TO SET THE POINTTO A NEW VALUE IN THE SET MODE, KEY INTHE VALUE AND PRESS ENTER. ESC WILL EXITTHE SET MODE.

3-6. NORMAL DISPLAY

The Normal Display (see Figure 3-8), also known as the Monitor Display, is a single user-configurable display that can beimmediately accessed by pressing the NORMAL key.Showing up to four data points or one Enumerated Switch, it isessentially a display (0-32) configured from the DEMAND SECTION of the BOI_Q.SRC source file. Multiple screenEnumerated Switch displays can be viewed by pressing the SCROLL UP and SCROLL DOWN keys.

While viewing the Normal Display, pressing the HELP key presents the operator with the following message:

SCROLL KEYS MOVE THE DISPLAY THROUGHTHE FUNCTIONS

3-7. ALL POINTS DISPLAY

The All Points Display depicts all of the points that can be accessed by the <BOI>. It is a copy of the POINTNAME columnof the BOI_Q.SRC source file’s DISPLAY SECTION. Downloading the BOI_Q.SRC file will cause an updating of thedisplay. The function of this display is not only to depict accessible <BOI> points, but to permit Operator Demand Displaysto be created from the <BOI>. The latter operation can be accomplished using the All Points Display’s Build Demand Mode.For more information, see Maintenance Manual, GEH-5980.

To place a point into the Operator Demand Display, scroll through the points until the desired point is shown. Use the < and >keys to locate the point (the located point will be prefixed by a " > "). Pressing the ENTER key will select the located pointand prefix it with an asterisk (*). The Build Demand Mode is then accessed by pressing the SET key. In this mode, theselected point is shown in the left-half of the top line of the display. The right-half of the top line shows the current point inthe Demand Display at the location shown on the bottom line (see Figure 3-9).

MODE_S AUTO DW 89.1 MWCONTRL LOOP FSR 64.51 %

Figure 3-8. <BOI> Display Showing Normal Display (Monitor Display)

3-7

To put the point into the Demand Display, select the desired location with the raise and lower keys and press ENTER. Thepoint will then be put into the Demand Display in the selected location. Pressing the ESC key will exit the build mode.

NOTE

Only Main/Normal Display types can be inserted in an Operator Demand Display using the <BOI>.

3-8. OPERATOR DEMAND DISPLAY

The Operator Demand Display is a user-configurable list of Main/Normal and/or Enumerated Switch Display types that canbe immediately accessed by pressing the SHIFT + HELP keys. Two (2) Demand Displays can be created with each holdingup to four Main/Normal data points (POINT_TAGs) or one Enumerated Switch Display which must include SIGNAL_TAG,MASK_TAG, ENUM_TAG, and COMMAND_TAG parameters. Four data points or Enumerated Switch mode options canbe viewed at one time.

Operator Demand Displays that incorporate Main/Normal Display types may be constructed from the <BOI> or the processor (see the ALL POINTS DISPLAY section of this chapter and the BOI_Q.SRC section in the Maintenance ManualGEH-5980). Enumerated Switch Display types may be inserted into the Operator Demand Display only through the use of theBOI_Q.SRC file located in the UNIT(n) directory of the processor (also see BOI_Q.SRC File in the Maintenance ManualGEH-5980).

The Operator Demand Display can be accessed by pressing the SHIFT + HELP keys. Any screen in the display can beviewed by using the SCROLL keys. Individual points in the display can be raised, lowered, forced, and set. The < and > keysare used to locate a specific point. A located point is prefixed by a >. Pressing the ENTER key will select the located point,prefixing it with an "*". Selected points can then be increased and decreased by the RAISE and LOWER keys. Pressing theESC key deselects the point. The force key selects a located logic point, prefixing it with an "!". The RAISE key forces thepoint to a one while the LOWER key forces the point to a zero. Pressing CLEAR will unforce the selected point. A selectedanalog point which is prefixed by an "*" can be displayed in the SET Mode by pressing the SET key. The SET Mode shows

AP -327.4 . . . 0 cnt 15 ENTER: 01

Figure 3-9. <BOI> Build Demand Mode

IP 53.3 psi HPXP -586 psi AP -327 psi EV -2.5 in Hg

Figure 3-10. Operator Demand Display with Four Data Points.

3-8

the current value of the point and allows it to be set to a value. To set a value, key in the desired number and press ENTER.The ESC key can be used to exit the SET Mode.

3-9. PROCESSOR SELECT DISPLAY (PROC)

The <BOI> can be configured to receive data from any one of the three cores <R>, <S>, or <T> in TMR configurations. Simplex <BOI> panels are limited to receiving data from the default processor <R>. Processor selection can be performed viathe (shifted) R, S, or T keys or the Processor Select Display. To access the Processor Select Display, press the SHIFT +NORMAL keys. When the display is pictured, select the desired processor by pressing the < and > keys; pressing ENTER willexecute the selection.

3-10. DESIGNATED PROCESSOR

For TMR applications, the <BOI> is equipped with a designated processor function that allows communication to bereestablished when the selected processor fails. If a communication failure occurs, press the SHIFT + PROC keys. This willestablish a communication link between the <BOI> and the designated processor and restore the <BOI> display.

NOTE

The control hierarchy of TMR panels automatically compensates for the loss of the designated p rocessor,<R>, by reassigning this role to <S>, and finally <T> if successive processors are lost. This allowscommunication between the panel and the <BOI> to be regained if only one processor remains operable.

*DZ R S T

Figure 3-11. <BOI> Processor Display (TMR Configuration)

4-1

CHAPTER 4

CONTROL LOCATIONS

4-1. Control Lockout

Working in conjunction with Password Level Administration, Control Lockout is a means by which an Operator or Supervisorcan disable an from issuing commands to the Mark V Control Panel. This option is an exclusive function of the processor and does not require changes to the configuration of a panel.

NOTE

Initiating Control Lockout does not affect MODBUS or ETHERNET links. However, it can limit the tobecoming a view-only device for Mark V data.

Rebooting the will not affect the state of Control Lockout Commands. However, the status is not saved until the ControlLockout Administration is exited normally by clicking on the EXIT target at the bottom of the display..

The enable/disable Commands function can itself be disabled or enabled according to two levels of authorization(OPERATOR, SUPERVISOR). Authorization is carried out through the ’s Password Administration scheme.

4-1.1. Implementing Control Lockout Using Password Administration

Control Lockout is a function that is subject to Password Administration enabling. Without the proper level of authorization,the Control Lockout feature cannot be utilized. There are two levels of Password Administration required to implementControl Lockout, SUPERVISOR and OPERATOR.

4-1.2. Control Lockout for Multi-Panel s

In circumstances where a single processor is controlling multiple panels, Control Lockout may be implemented in such away that the is prohibited only from sending (COMMANDS or ALARMS Commands) signals to specific panels.

Multi-panel s will necessarily have their configuration files setup to facilitate multi-panel control. Specifically, this entailsconfiguring the CONFIG.DAT file. Divided into two sections (UNIT_DATA & NETWORK_DATA), this data file isresponsible for defining which of the panels the should communicate with, and consequently, the Stage Link address ofeach. It is here (specifically the UNIT_DATA section) that the Control Lockout program looks to see if the is multi-panelfunctional. The following is a conventional example of a UNIT_DATA segment that defines multi-panel (3 panels) capability:

; UNIT# UNIT NAME PATH TO CONFIG DATA; ----- --------- -------------------

UNIT_DATA 1 T1 F:\UNIT1 2 T2 F:\UNIT2 3 T3 F:\UNIT3 4 T4 F:\UNIT4 5 T5 F:\UNIT5

If the file specifies multi-panel operation, the Control Lockout program will automatically compensate to allow separate panellockout capability. From the example above, the Control Lockout Display shown in Figure 4-2 would be constructed.

4-2

Operation of multi-panel Control Lockout is essentially identical to that for single panel s except for the fact that morethan one panel can be locked out at a time. With this configuration, the Password Administration program will enable/disableall OPERATOR and/or SUPERVISOR levels at the same time.

4-2. CONTROL HIERARCHY

Control Hierarchy is an optional scheme to define different control locations and pass control between these locations. Control locations are defined, and then different elements in the system are configured to only send commands if the currentcontrol location allows them to send commands.

To implement the Control Hierarchy option, please contact the local GE Power Generation Field Service Office.

Figure 4-1. Control Lockout Screen with Multi-Unit Configuration

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�GE IndustrialControl Systems

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April 2000Replaces ATCMKV_VI

GEK 107359


Annunciator Troubleshooting Chart

GEK 107359 Annunciator Troubleshooting Chart

2

/HMI Alarm Message, Logic & No. Cause ActionÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L63ADL_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Atomizing Air Diff. Pressure Low

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Atomizing air compressornot providing adequatepressure.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check atomizing air system.


L26AAH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Atomizing Air Temp.High

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure of atomizingprecooler louvers to openand close.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check water supply to theatomizing air precooler,isolating valve position flowrestrictions.


L86S ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Auto Synchronizing Lockout


Auto synchronizingself-checking system hasdetected a synchronizingequipment abnormality.


Investigate synchronizationsystem to determine exactcause of problem.


L52HQ_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Auxiliary Hydraulic OilPump Motor Running


Accessory gear-drivenhydraulic pump has notsupplied sufficientpressure because of leaksor failure of pump.


Check hydraulic system.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L52QA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Auxiliary Lube Oil PumpMotor Running

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

The main accessory geardriven lube oil pump issupplying insufficientlube oil pressure due topump failure or leaks

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Examine main lube pump.Check pump output and mainlube filters for leaks orplugging.


L49X_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Auxiliary MotorOverload


One of the auxiliarymotors is overloaded.


Check auxiliary motors todetermine which motor isoverloaded and the cause ofthe overloading.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L52QS_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Auxiliary Seal Oil PumpRunning


Insufficient pressure frommain seal oil supplypump.


Check seal oil supply systemcomponents.



Battery 125 VDC GroundÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Insulation failure hasresulted in a ground onthe 125 VDC system.


Isolate and remove groundfrom the system.


L27BLN_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Battery Charger ACUndervoltage


Battery charger ACundervoltage.


Check battery charger ACbreaker. Check voltagemagnitude.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Battery DC UndervoltageÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Battery system voltage islow. Battery charger isnot functioning properly,excessive drain on thebatteries, or bad cells inbattery.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check battery charger forproper operation, correctexcessive drain on battery,check for bad cells. The gasturbine should not beoperated unless DC power isavailable to the emergencyDC lube oil pump.

Annunciator Troubleshooting Chart GEK 107359

3

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L30LOAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Bearing DrainTemperature High

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High bearing draintemperature.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check lube oil feed and drainpiping.



Bearing MetalTemperature High


Bearing or lube oilproblem.


Check bearings and lube oilsystem.


L27VVN_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Black Start InverterTrouble


The black start inverteroutput voltage has gonelow, ignition power hasbeen transferred to theMCC 12 VAC.


Troubleshoot black startinverter.


L27BN_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Bus Undervoltage – No Auto Synch


Bus synchronizingpotential not available.


Check bus PT fuses andwiring. Do not use autosynchronizing or manualsynchronizing until problemis resolved.


L28FD_SD ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Chamber Flamed OutDuring Shutdown


Flame loss during firedshutdown period.


Investigate cause and remedybefore restarting turbine.Monitor vibration on the wayup.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L30SPA ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Combustion Trouble ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Faulty thermocouples, gaspath hardware or unevendistribution of fuel to thefuel nozzles.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Analyze data for trends. Atearliest shutdown checkthermocouples. Performborescope or combustioninspection. Check flowdivider fuel pressures. Checkfor plugged nozzles.


LCOM_B_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Common IOCommunication Loss(MKV Control Only)


<C> processor is nolonger communicating.


Check <C> power supplycard and cabling.


L86TCI ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Compressor InletThermocouples Disagree


Bad thermocouple signal.Thermocouples in theinlet have failed, shortedor open.


Check thermocouples andwiring and replace faultythermocouple(s).


L86CB1 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Compressor Bleed ValvePosition Trouble


Compressor bleed valveshave not operatedproperly. They are in thewrong position orrequired an excessiveamount of time to movefrom one position to theother.


Investigate problem. Theproblem should be correctedbefore restarting. The MasterReset switch must be pressedbefore restarting.

4

/HMI Alarm Message, Logic & No. ActionCause

L30 COMM_IO_R VCMI I/O StateExchange for <R> failed(MKVI Only)

<R> Processor is nolonger communicating.

Check <R> power supply,cards, and cabling.

L30 COMM_IO_S VCMI I/O StateExchange for <S> failed(MKVI Only)

<S> Processor is nolonger communicating.

Check <S> power supply,cards, and cabling.

L30 COMM_IO_T VCMI I/O StateExchange for <T> failed(MKVI Only)

<T> Processor is nolonger communicating.

Check <T> power supply,cards, and cabling.


L26CTH_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Control Panel Temp HighÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Air conditions notmaintaining propertemperature.


Check air conditioners.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L12HF ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Control Speed Signal Loss - HP


Machine tripped due toloss of speed signal.


Check wiring to speedpickups.


L12HFD_C ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Control Speed SignalTrouble - HP


HP speed pickup votingmismatch in <Q>.


Check and recalibrate HPspeed pickups.


L12HFD_P ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Protective Speed SignalTrouble - HP


HP speed pickup votingmismatch in .


Check and recalibrate HPspeed pickups.


L12LFÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Control Speed SignalTrouble - LP


LP speed pickup votingmismatch.


Check and recalibrate LPspeed pickups.


L30CDÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Cooldown TroubleÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Unit failed to go oncooldown, or thecooldown cycle wasaborted prior to cooldowntimer timeout.


Check ratchet system.Monitor vibration whencooldown cycle is reinitiated.


L52FC_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Cooling Fan MotorBreaker Open


Cooling fan motor did notstart.


Check cooling fan motormodule in PECC.


L71WL_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Cooling Water Level LowÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Cooling water tank levellow.


Check cooling water systemfor leaks.


L63QQ3H_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Coupling Oil Filter DiffPressure High


Clogged filter.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Replace filter.


L3CP_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Customer Start InhibitÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Customer contact inputnot enabled.


Check customer’s permissive.


L4CT_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Customer Trip ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Customer trips input tothe L4CT logic havecaused an automatic tripof the unit.


Determine which of thecustomer trip devices causedthe trip and correct.

5

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L27QEL_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

DC Motor Undervoltage(Lube Oil)

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

DC power not supplied toemergency DC lubepump.


Check power to DC lubepump (MCC breaker on). Thegas turbine should not beoperated unless DC power isavailable to the emergencyDC lube pump.


L30DIAG_C ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diagnostic Alarm <C>(Mark V Control Only)


The microprocessor self-checking program hasuncovered a control panelproblem.


Call up diagnostic display.


L30DIAG_QÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diagnostic Alarm <Q>(Mark V Control Only)


The microprocessorself-checking programhas uncovered a controlpanel problem.


Call up diagnostic display.


L26DWH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Engine CoolingWater Temp High


Diesel cooling watertemperature is high.


Check diesel cooling watersystem.


L2DWZ2ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Failure to BreakTurbine Away


Diesel was unable toaccelerate to maximumrpm.


Check diesel. Check dieselmaximum torque solenoid.


L48DSXÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Failure to StartÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁDiesel has failure to start.


Check diesel fuel tank.


L4DEY_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Failure to Stop ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel should stopautomatically after a 5minute cooldown period.


Check diesel stop solenoid20DV.


L63QDN_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Lube Oil Pressure Low


Diesel lube oil pressure islow.


Check diesel lube oil system.


L83DT1ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Diesel Test Mode Selected


Indication that diesel testpushbutton permissivehas been activated.


Test mode should bedeselected once the test iscomplete.


L63LF2H_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Distillate Fuel FilterDifferential Pressure High



Replace filter.


L26FD1H_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Distillate FuelTemperature High


Possible cooling systemproblem.


Check temperature sensorand cooling system.


L12HÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Electrical Overspeed Trip - HP


The speed control systemhas not limited HPturbine speed within thetrip limits.


Isolate problem and correct.


L12LÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Electrical Overspeed Trip - LP


The speed control systemhas not limited LP turbinespeed within the triplimits.


6


L72QEZ_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Emergency Lube OilPump Motor Running


Loss of AC power tomain lube oil pumps.


Determine cause of ACpower loss.


L72ES_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Emergency Seal Oil Pump Running


Generator seal oilpressure is low.


Check main and auxiliaryseal oil supply systemcomponents.


L59E_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exciter OvervoltageÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Excessive field volts havebeen detected.


Check exciter.


L94EK ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exciter Rect CoolingTrouble - Trip 52G


Breaker has tripped andmachine is at FSNLbecause of problem withexciter rectifier cooling.


Investigate exciter rectifiercooling system.


L26SFH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exciter Rectifier BridgeTemp High


Possible cooling systemproblem.


Check exciter rectifiercooling system.


L86TXT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust OvertemperatureTrip


Turbine has tripped due tohigh median exhausttemperature.


Investigate.


L86TXT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust OvertemperatureTrip


The temperature controlsystem has not limitedexhaust temperaturewithin the trip limits.




L63TK_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust Frame CoolingAir Pressure Low


Exhaust frame blowermotor not operating. Airpassages blocked.


Check motor operation.Inspect cooling air flowpassages.


L90TKLÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust Frame CoolingSystem Trouble - Unload


Exhaust frame coolingfans 88TK-1,2 problem orsystem problem.


Investigate exhaust framecooling system.


L63EAH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust Pressure HighAlarm


Exhaust pressure hasrisen above recommendedlevels.


Inspect exhaust filter andducting for blockage.


L63ETHÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust Pressure HighTrip


Exhaust pressure hasrisen above the trip level.


Inspect exhaust filter andducting for blockage.


L63ETHX_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust Pressure SwitchTrouble


Bad signal from exhaustpressure switch.


Check switches and switchwiring.


L30TXA ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust TemperatureHigh


The exhaust gastemperature is excessive.


Check all thermocouples.Replace any badthermocouples. If problem isnot thermocouples, isolateportion of Control Systemcausing the problem.


L30TXAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust TemperatureHigh


High median exhausttemperature calculated in.


Lower load to reduce exhausttemperature. Investigate.


7


L30SPTAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust ThermocoupleTrouble


Faulty thermocouple.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check thermocouples.


L86TFBÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Exhaust ThermocouplesOpen Trip


Excessive number ofthermocouples notconnected.


Check and reconnectthermocouples.


L63FLZ_FLTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure to Establish Liquid Fuel Press.


Liquid fuel forwardingsystem problem.


Check that power is beingsupplied to liquid fuelforwarding pump/motor.Troubleshoot per systemcomponents per instructions.


L30FD_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure to Ignite ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure to fire within theone minute period.


Check that ac power issupplied to the ignitionsystem.


L62TT2_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure to Start ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

The master protectivelogic signal “L4” has notbeen set within 30seconds of the startsignal, has tripped theunit twice or, if the unit isoperating in remote,flame was not establishedafter two tries.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check all signals making upthe L4 logic signal todetermine which caused theproblem, or determine causeof lack of flameestablishment.


L3Z ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure to Synchronize ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Unit did not synchronizeand close generatorbreaker within the normalexpected time (15seconds).


Check all signals goingmaking up the L4 logic signalto determine which causedthe problem or determine thecause of lack of flameestablishment.


L45FTX2_ALML45FTX1_ALM


Fire in Zone #1 or Zone #2 Trip


Fire in the turbine oraccessory compartment.


Restarting after an operationof the CO2 system requiresthat the CO2 system be reset,including all doors anddampers, and the CO2 releasemechanism.


L45FAX_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Fire Protection SystemInoperative


CO2 pressure or controlproblem.


Check fire protection system.


L28FD_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Flame Detector Trouble ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

One of the detectorsoperating when no flameis present.


Check for proper operation ofthe flame detection system.Check that the flame detectorquartz window are clean.

8

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L60FSRGÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

FSR Gag Not at MaxLimit


Manual FSR control hasnot been reset to aposition where it will notinterfere with automaticFSR control.


Raise the manual FSR controlto maximum.


L3GCVFLT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Control Valve ServoTrouble


The gas control valvefeedback signal isabnormal.


Check LVDT.


L63HGL_SENSR ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel HydraulicPressure Switch Trouble


Bad signal from hydraulicpressure switch.


Check switch and switchwiring.


L63HGL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Hydraulic TripPressure Low


Low oil pressure in gasfuel hydraulic oil tripcircuit.


Check the control oil filterand control oil piping. Thisalarm will actuate if theturbine is tripped with themanual emergency trip valveon the turbine or a large leakwere to occur in the hydraulictrip circuit piping.


L3GFIVP ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel IntervalvePressure Trouble


Pressure sensed betweenthe gas control valve andthe speed ratio valve isabnormal.


Check GRV control system,intervalve vent, and pressuretransducer.


L63PGFT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Nozzle PurgeSystem Pressure High


Problem with valves. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Determine cause of incorrectvalve positioning.


L94PGT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Nozzle PurgeSystem Trouble Trip


Either VA13-1 or -2 or20VG-2 are stuck openand machine has tripped.Gas may be backingthrough the system.


Check valves for cause.Correct positioning prior torefire.


L33PGFT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Nozzle PurgeValve Fail to Close


VA13-1 or -2 areobstructed.


Check valves to removeobstruction to resume purge.


L33PGO_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Nozzle PurgeValve Fail to Open


No atomizing air flow;VPR44-1 stuck.


Check valve.


L63FGL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Fuel Pressure LowÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas fuel pressure toturbine has been sensed aslow.


Check cause of low supplypressure.


L3GRVFLT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gas Ratio Valve PositionServo Trouble


The gas ratio valvefeedback signal isabnormal.


Check LVDT.


L63CA3L_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gen Air Filter CleanerPressure Low


Generator air inlet filtercleaning systemproblems.


Check air inlet filter cleaningcomponents.


9


L43HPA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gen Purge System onManual Control


Operator has selectedmanual control.


Change to automatic control.


L52GA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Gen. Inlet Air DirtSeparator Not Running


Generator inlet air dirtseparator malfunction.


Check separator motor forproper operation. Checksupply system wiring.


L63GFH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator Air Filter HighPressure Drop


High pressure differentialacross generator air inletfilters.


Inspect and clean/changefilter elements, as required.


L63BQL_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator BearingVacuum Low


Generator bearings aresealed by vacuum. Thisalarm indicates a potentialproblem with the sealingsystem.


Investigate generator bearingsealing system.


L52G_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator BreakerTripped


Generator breaker hasbeen tripped by anautomatic protectivedevice or manually.


Determine device that trippedthe breaker.


L63GKL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator CasingHydrogen Press. Low


Low hydrogen pressure ingenerator.


Check hydrogen supplysystem.


L71WGH_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator Casing LiquidLevel High


Liquids have accumulatedin bottom of generator.


Remove liquids, check forleaks and take action toprevent recurrence ofproblem.


L33GCC_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator CO2 DoorTrouble


Generator CO2 door isclosed.


Door must be opened and thelatch reset.


L86TGT_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator DifferentialTrip


A generator panelprotective device hastripped the 86G lockoutrelay.


Determine which protectivedevice tripped the 86G andcorrect the abnormality thatprecipitated the trip.


L64F_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator Field GroundÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

A ground on thegenerator field has beendetected.


Operation of the generatorwith the field grounded is notrecommended as a secondground could result inexcessive damage to thegenerator field.

10

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L94H_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator HydrogenPurge Shutdown

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Shutdown initiated due toone or more hydrogensystem problems, e.g.,hydrogen purity has fallento shutdown level.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check hydrogen cabinet forundervoltage. Checkhydrogen control switch inmaintenance/auto. Check andrestore hydrogen purity.Check seal unit. If puritycontinues to deteriorate, apossible hazard conditionmay develop.


L49GH_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator Stator TempHigh


Generator statortemperature is excessivecaused by lack of coolingor overload.


The generator should not beoperated when the statortemperature is excessive.Check cooling system, reduceoverload on generator.


L94GEN ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Generator VentilationTrouble Shutdown


Temperature in generatorcompartment exceedslimits. Vent fansinoperable or insufficientto handle ventilationrequirements.


Check generator ventilationsystem for proper fan/motoroperation. Check ventilationdampers for properoperation/position.


L63FU2LAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Heavy Fuel Pressure Low,Auto Xfer to Dist


Problem with heavy fuelsystem.


Investigate heavy fuelsystem.


L26FU2LAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Heavy Fuel Temp Low,Auto Xfer to Dist


Problem with heavy fuelsystem.


Investigate heavy fuelsystem.


L3FUZÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Heavy Fuel TransferPermissive Trouble


Turbine unable to transferto heavy fuel.


Check heavy fuel system. Besure fuel is warm andfree-flowing.


L30SPTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High Exhaust Temp.Spread Trip


Faulty thermocouples, gaspath parts or unevendistribution of fuel to thefuel nozzles.


Analyze data for trends.Perform borescope orcombustion inspection.Check flow divider, fuelpressures. Check for pluggednozzles.


L39VA ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High Vibration Alarm ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High vibration at one ormore bearings.


Monitor vibration readings.


L39VTX_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High Vibration Trip orShutdown


High vibration due tobowed rotor, mechanicalimbalance, bearingfailure, etc.


Check that the hydraulicratchet is operating properly.Check for mechanicalfailures, observe vibrationlevel on the next startup.

11

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L30TNH_DIFFÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

HP Speed SignalDifferential Alarm


One of the HP speedsensors is showing adifferent speed than theother two.


Check HP speed pickups.


L63HF1H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydraulic FilterDifferential Pressure High


Clogged filter. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Loss of fluid pressure anddeterioration of fluid puritymay result. Change filter.


L86HD ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydraulic ProtectiveTrouble


One second after thehydraulic oil trip isinitiated either the liquidfuel stop valve is notclosed or the hydraulictrip pressure (63HG,63HL) has not decreasedsufficiently.


Check operation of 20FL and20HD servos.


L63HQ1L_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydraulic Supply Pressure Low


Hydraulic supply pressureis low.


Check hydraulic supplypressure filter and differentialpressure gauge, regulatingvalve or pump.


L27GHN_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydrogen Control PanelUndervoltage


Ac power supply voltagelow.


Check power supply forproper operations. Checkwiring.


L63GL_GH_AL ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydrogen Pressure Highor Low (Gen)


High machine gaspressure or low manifoldgas pressure.


Check generator hydrogensystem.


L63HHL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydrogen Pressure Low(Skid)


Hydrogen supply skidpressure low.


Check skid components forproper operation.


L30HP ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Hydrogen Purity TroubleÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Bad generator hydrogenpurity or purity pressure.


Check generator hydrogensystem.


LWLX4MINÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Injection to Fuel RatioLow-Four MinuteAverage


Steam (water) injectionflow four minute averagelow.


Check steam (water) injectionsystem.

LWLXHR Injection to Fuel RatioLow-Hourly Average

Steam (water) injectionflow one hour averagelow.



L86GVAÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Inlet Guide Vane ControlTrouble Alarm


IGV control systemproblem.


Check IGV control system.


L4IGVTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Inlet Guide Vane ControlTrouble Trip


IGV control systemproblem.


Check IGV control system.


L3IGVFLT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Inlet Guide Vane PositionServo Trouble


Incorrect servo operation.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check servos.


12


L30TNI_DIFFÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

IP Speed SignalDifferential Alarm


One of the IP speedsensors is showing adifferent speed than theothers.


Check IP speed pickups.


L71WG_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Detected inGenerator


Excessive liquid inbottom of generator.


Remove liquid and takecorrective action to preventrecurrence of problem.


L3LFLT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel Control FaultÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid fuel checkingsystem has detected anabnormal servo or LVDTposition or signal.


Determine abnormalcondition by reading signals(L3LFLT1 to L3LFLT5).


L63LF1H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel FilterDifferential Pressure High





L30FQL_DIFF ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel FlowDifferential Alarm


Speed pickups on flowdivider disagree.


Check and recalibrate speedpickups.


L63HL_SENSR ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel HydraulicPressure Switch Trouble


Bad signal from hydraulicpressure switch.


Check switch and switchwiring.


L63HLL_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel HydraulicTrip Pressure Low


Low oil pressure in liquidfuel hydraulic oil tripcircuit.


Check the control oil filterand control oil piping. Thisalarm will actuate if theturbine is tripped with themanual emergency trip valveon the turbine or a large leakwere to occur in the hydraulictrip circuit piping.


L63FLZ_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel Pressure LowÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid fuel forwardingsystem problem.


Check fuel forwardingsystem components forproper operation. Checkliquid fuel forwarding pipingfor leaks.


L3LFP_FLT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel PumpControl Trouble


Problem with one or morecontrol devices.


Troubleshoot liquid fuelpump control components todetermine problem andcorrect.


L33FL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel Stop ValveFailure to Open


Valve or control failure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check operation of VSI andcontrols.


L26FL2LA ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Liquid Fuel Temp Low,Auto Xfer to Dist


Heavy fuel temperature islow. Unit has beenautomatically transferredto distillate fueloperation.


Check heavy fuel supplyheating equipment.

13

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L3TFLTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Loss of CompressorDischarge Pressure Bias


Bad signal fromcompressor dischargepressure transmitter.


Check transmitter andassociated connections forproper bias signal.


L3DWRFÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Loss of External SetpointLoad Signal


ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


L28FDTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Loss of Flame TripÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Failure of one of thedetectors to detect flame.


Check for following: fuelbeing supplied to thecombustors, flame in allchambers, damaged crossfiretubes, or combustors. Checkfor proper control valveposition and fuel pressure.


L63QTX ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Low Lube Oil PressureTrip


Lube oil pressure hasfallen below the trip level.


Determine cause and correctbefore restarting unit.


L30TNL_DIFF ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

LP Speed SignalDifferential Alarm


One of the LP speedsensors is showing adifferent speed than theother two.


Check HP speed pickups.


L26QA_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Header TempHigh


Lube header temperatureabove recommendedlimits.


Check for proper operation ofthe lube oil heat exchangers,cooling water fans (properrotation) and temperatureregulating valve.


L26QT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Header TempHigh Trip


Lube header temperatureabove recommendedlimits.


Check for proper operation ofthe lube oil heat exchangers,cooling water fans (properrotation) and temperatureregulating valve.


L71QH_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Level High ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube oil tank level high.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Investigate cause of highlevel alarm and restorenormal level.


L71QL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Level Low ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube oil tank level low. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check for leaks, restorenormal level.


L63QA1L_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Pressure Low ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube system leaks orpump trouble.


Repair leaks or pump.


L63QT_SENSRÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil Pressure SwitchTrouble


Bad signal from lube oilpressure switch.




L26QN_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil TankTemperature Low


Lube tank temperaturebelow recommendedlimits (see pipingschematic).


Check for proper operation ofthe lube oil tank heaters.Starting is inhibited if thetank temperature is low.


14


L26QT_SENSRÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Lube Oil TemperatureSwitch Trouble


Bad signal from lube oiltemperature switch.




L63QQ1H_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Main LO Filter DiffPressure High





L43MAINTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Maintenance - ForcingMode Enable


Auto calibrate, memorychanging or logic forcingmode of operation hasbeen selected.


When done with theoperation, deselect theoperation.


L86MAN_SYNCÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Manual SynchronizingLockout


Manual synch lockout hasbeen selected on OperatorInterface. Breaker willnot close.


Determine why manual synchhas been locked out. Resetusing Master Resetpushbutton on OperatorInterface.


L5E_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Manual Trip ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

The emergency stoppushbutton has beenpressed.


Correct abnormality thatcaused the operator to pushthe emergency stoppushbutton.


L86MP ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Master Protective StartupLockout


Within the turbine controlpanel the threemicroprocessorcontrollers R, S and T arein disagreement for theproper condition of theMaster Protective logic“4X”.


Determine which controller isin disagreement with theother two.


L27MC1N_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

MCC Undervoltage ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Motor control centerundervoltage.


Check that power is suppliedto the motor control center.


L30LTA ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

No. 3 BearingTemperature High


High number 3 bearingtemperature.


Check lube oil feed and drainpiping.


L33BS_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

No. 3 Drain ValvePosition Trouble


Valve incorrectlypositioned.


Check drain valve operations.


L3NZFLTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Nozzle Control ServoTrouble


Problem with secondstage nozzle servo.


Check servo wiring andhydraulic oil system.


L43DIAG_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Off-Line DiagnosticsRunning


Off-line diagnosticoperation has beenselected.


Do not start unit untildiagnostics are complete.


L3WCTIM_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

On Line Water WashInhibited


Ambient temperature isbelow 50 deg F.


Wait to water wash untilambient temperature ishigher.

15


L12HBLT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Overspeed Bolt Trip - HPÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

The speed control systemhas not limited turbinespeed within the triplimits.




L83HOST ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Overspeed Test ModeSelected - HP


HP overspeed trip beingtested.


See “Overspeed Trip Checks”section of text.


L83LOSTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Overspeed Test ModeSelected - LP


LP overspeed trip beingchecked.


See “Overspeed Trip Checks”section of text.


L30EKÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Prim Exciter RectCooling Fan Trouble


Problem with primaryexciter rectifier coolingfan.


Determine and correctproblem with primary exciterrectifier cooling fan.


L4ETR_FLTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Protective Module ETRRelay Trouble


Trip due to masterprotective relay (4’s)circuit has a problem.


Isolate ProtectiveModule and correct theproblem.


L12H_P_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Protective ModuleOverspeed Trip - HP


 module HPoverspeed trip.


Investigate cause ofoverspeed.


L12L_P_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Protective ModuleOverspeed Trip - LP


 module LPoverspeed trip.


Investigate cause ofoverspeed.


L12LF_OS ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Protective Speed SignalTrouble - LP


LP speed pickup votingmismatch in .


Check and recalibrate LPspeed pickups.


L30HRX2 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet Did Not Start ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet did not initiate aratchet stroke in theprescribed time.


Check ratchet permissives.


L49HR1A_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet Motor OverloadÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet motor overload.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check ratchet motor overload(MCC). Check for properoperation of ratchetmechanism.


L30HRX1 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet Trouble ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Ratchet did not completea prescribed motion innormal time.


Check for proper operation ofratchet mechanism.


L30RHFLTX ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Relative Humidity SensorFault


Humidity sensor failure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check sensor and wiring.


R5E_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Remote Emergency TripÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Unit was tripped with theremote emergency trippushbutton.


Investigate and correct causeof trip. Manually resetpushbutton.


L63SAL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Seal Oil Diff. PressureLow


Low seal oil pressureacross bearings.


Check seal oil system.


L63STÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Seal Oil Diff. PressureLow Shutdown


Seal oil pressure acrossbearings has reachedshutdown setpoint.


Correct seal oil systemproblem before restarting.


16


L71SDH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Seal Oil Drain LiquidLevel High


Seal oil drain systemproblem.


Check generator seal oil drainsystem.


L63STX_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Seal Oil Press. ShutdownSwitch Trouble


Bad signal from seal oilpressure switch.




L30WC_LAG ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Standby Cooling WaterPump Running


Either low cooling waterpressure, or a problemwith the main coolingwater pump.


Investigate problem withcooling water system or maincooling water pump.


L30FD_LAGÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Standby Dist Fuel FwdPump Running


Low distillate fuelpressure or problem withmain dist fuel fwd pump.


Investigate fuel forwardingsystem and main pump.


L4DTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting Device LockoutÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ


L3SMT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting Device Trip ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

The turbine has beentripped because thestarting device has failedto start the turbine.


Note where in the startsequence the turbine trippedto aid in determining cause oftrip. Check the suspectsystem.


L4CRTÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting Motor BreakerDid Not Pick Up


Starting motor did notstart.


Checking starting motormodule in PEECC.


L49CR_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting Motor OverloadÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting motor is showingan overload.


Investigate starting motorcircuits.


L86CRTX ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Starting Motor ProtectiveLockout


Cranking motor circuitelectrical fault.


Clear fault and reset 88CR.


L2SFT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Startup Fuel FlowExcessive Trip


Excessive fuel for startuphas been detected. For gasfuel the gas control valveis open too far.


Check the servo and feedbacksignals for proper operation.


L30EKR ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Stby Exciter Rect CoolingFan Running


Problem with primaryexciter rectifier coolingfan.


Determine and correctproblem with primary exciterrectifier cooling fan.


L60APHA_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -High Pressure


High steam pressure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Reduce steam pressure.


L60APHT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -High Pressure Trip


Steam augmentationsystem tripped due tohigh pressure.


Correct problem beforerestarting steamaugmentation.


L60ATHT ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -High Temp. Trip


Steam augmentationsystem tripped due tohigh temperature.




L60ATHA_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -High Temperature


High steam temperature.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Reduce steam temperature.


17


L60APLA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -Low Pressure


Low steam pressure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Increase steam pressure.


L60ALPT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -Low Pressure Trip


Steam augmentationsystem tripped due to lowpressure.




L60ATLT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -Low Temp. Trip


Steam augmentationsystem tripped due to lowtemperature.




L60ATLA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Augmentation -Low Temperature


Low steam temperature.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Increase steam temperature.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L60WL1_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Flow High ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁExcessive steam flow. ÁÁÁÁÁÁÁÁÁÁ

ÁÁÁÁÁÁÁÁÁÁCheck steam system.


L60WQPL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Flow HighLockout


Excessive steam flow. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Correct problem beforerestarting.


L30SJÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Injection NotSelected


NOx control steaminjection systeminoperative.


Select Steam Injection onOperator Interface.


L60SPHA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Pressure HighÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

High steam pressure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Reduce steam pressure.


L60SPHT_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Pressure HighLockout


High steam pressure. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Correct steam pressure beforerestarting.

ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L60SPLA_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Pressure Low ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁLow steam pressure. ÁÁÁÁÁÁÁÁÁÁ

ÁÁÁÁÁÁÁÁÁÁIncrease steam pressure.


L60SPLT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Pressure LowLockout


Low steam pressure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Correct steam pressure beforerestarting.


L60STHA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Temperature HighÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁHigh steam temperature.


Reduce steam temperature.


L60STHT_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Temperature HighLockout


High steam temperature.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Correct steam temperaturebefore restarting.


L60STLA_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Temperature LowÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Low steam temperature.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Increase steam temperature.


L60STLT_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam Temperature LowLockout


Low steam temperature.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Correct steam temperaturebefore restarting.


LWLXHR ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Steam to Fuel Ratio Low– Hourly Average


Steam (water) injectionflow one hour averagelow.




L63QQ2H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Trip Oil Filter DiffPressure High


Clogged filter. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Replace filter.


L63TF1H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine Air InletDifferential PressureAlarm



Replace filter.

18

/HMI Alarm Message, Logic & No. ActionCauseÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

L63TFH_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine Air InletDifferential PressureShut-Down


Clogged or iced filter.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Determine cause of blockage.


L63TFH_SENSRÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine Air InletDifferential PressureSwitch Trouble


Bad signal fromdifferential pressureswitch.


Check switch calibration andswitch wiring.


L30TFXÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine Air Inlet TroubleÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Inlet filter excessivepressure drop or inletfilter motor overloaded orinlet compartment bypassdoor is not in properposition.


Check the following:

Inlet filter for blockage.

Inlet filter motor for properoperation.

Inlet house bypass door.


L26BT1H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine CompartmentTemp High


Compartment temperatureexcessive.


Check cooling air fan forproper operation.


L83KU_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine CompressorAbrasive CleaningSelected


Compressor beingcleaned.


Turn function off whencleaning is complete.


L48 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine IncompleteSequence


Failure of unit to reachcomplete sequence.


Check equipment which iscausing the problem in thenormal sequence.


L3A ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine Underspeed ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Turbine has boggeddown.


Reduce the load that will beapplied to the generatorbefore reclosing the generatorbreaker.


L39VD3_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Vibration – Start InhibitÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Vibration protectionsystem problem.


Check vibration protectionsystem.


L39VDIFF ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Vibration DifferentialTrouble


Vibration protectionsystem problem.


Check vibration protectionsystem.


L39VD1 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Vibration Sensor DisabledÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Signal from vibrationsensor is faulty.


Check vibration sensors andwiring.


L39VFÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Vibration TransducerFault


Vibration detectorimpedance is not withinnormal bounds.


Check impedance of eachvibration detector.


L3WFD_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Flow FeedbackTrouble


A disagreement betweenthe water flow sensors hasbeen detected.


Determine failed sensor andreplace.


L86WN3ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Flow High LockoutÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water injection systemlocked out due toexcessive water flow.This is dangerous becauseit could extinguish flame.


Investigate water injectionsystem.


19


L3WFLT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Flow SensorTrouble


Water flow sensorsdisagree.


Recalibrate or replace faultyflow sensor.


L86WN1ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Inj SuctionPressure High Lockout


High supply pressure.ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check water supply system.


L86WN2 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Injection DischargePressure Low Lockout


Low supply pressure. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check water supply system.


L30WN ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Injection NotSelected


NOx control waterinjection systeminoperative.


Select Water Injection onOperator Interface.


L26JS2H_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Skid EnclosureTemperature High


Failure of exhaust fan. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check exhaust fan/motorcomponents for properoperation.


L26ALL_ALM ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Skid EnclosureTemperature Low


Failure of heaters. ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Check heater and blower forproper operation.


L86WN4 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water System TroubleLockout


Water injection systemnot ready for use.


Check water injection systemcomponents.


L3WSFLT_ALMÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Valve LVDTTrouble


Water valve LVDTsdisagree.


Recalibrate or replace faultyLVDT.


L30TWWÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Water Wash InhibitWheelspace Temp High


Turbine not sufficientlycooled before attemptingwater wash.


Allow turbine to cool tospecification prior toselection.


L30WSA1ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Wheelspace TempDifferential High


Excessive differentialbetween wheelspacethermocouples.


Check thermocouples forshorts, grounds or opens.Replace failures. If conditionpersists investigate for sealfailure.


L30WSA2 ÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁÁ

Wheelspace TemperatureHigh


High wheelspace temperature. Check thermocouples,investigate for seal failure.


GE Power Systems

GE Power Systems

GE Gas TurbinePerformanceCharacteristics

Frank J. BrooksGE Power SystemsSchenectady, NY

GER-3567H

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Thermodynamic Principles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2The Brayton Cycle. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Thermodynamic Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Combined Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Factors Affecting Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Air Temperature and Site Elevation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Humidity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Inlet and Exhaust Losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Fuel Heating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Diluent Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Air Extraction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Performance Enhancements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Inlet Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Steam and Water Injection for Power Augmentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Peak Rating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Performance Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Verifying Gas Turbine Performance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

List of Figures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

GE Gas Turbine Performance Characteristics

GE Power Systems ■ GER-3567H ■ (10/00) i


GE Power Systems ■ GER-3567H ■ (10/00) ii

IntroductionGE offers both heavy-duty and aircraft-derivativegas turbines for power generation and industri-al applications. The heavy-duty product line con-sists of five different model series: MS3002,MS5000, MS6001, MS7001 and MS9001.

The MS5000 is designed in both single- andtwo-shaft configurations for both generatorand mechanical-drive applications. TheMS5000 and MS6001 are gear-driven units thatcan be applied in 50 Hz and 60 Hz markets.

All units larger than the Frame 6 are direct-drive units. The MS7000 series units that areused for 60 Hz applications have rotationalspeeds of 3600 rpm. The MS9000 series unitsused for 50 Hz applications have a rotationalspeed of 3000 rpm. In generator-drive applica-

tions the product line covers a range fromapproximately 35,800 hp to 345,600 hp (26,000kW to 255,600 kW).

Table 1 provides a complete listing of the avail-able outputs and heat rates of the GE heavy-dutygas turbines. Table 2 lists the ratings of mechani-cal-drive units, which range from 14,520 hp to108,990 hp (10,828 kW to 80,685 kW).

The complete model number designation foreach heavy-duty product line machine is pro-vided in both Tables 1 and 2. An explanation of

the model number is given in Figure 1.

This paper reviews some of the basic thermo-dynamic principles of gas turbine operationand explains some of the factors that affect itsperformance.


GE Power Systems ■ GER-3567H ■ (10/00) 1

Table 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings

GE Generator Drive Product LineModel Fuel ISO Base Heat Heat Exhaust Exhaust Exhaust Exhaust Pressure

Rating Rate Rate Flow Flow Temp Temp Ratio(kW) (Btu/kWh) (kJ/kWh) (lb/hr) (kg/hr) (degrees F) (degrees C)

x10-3 x10-3

PG5371 (PA) Gas 26,070. 12,060. 12,721 985. 446 905. 485 10.6Dist. 25,570. 12,180. 12,847 998. 448 906. 486 10.6

PG6581 (B) Gas 42,100. 10,640. 11,223 1158. 525 1010. 543 12.2Dist. 41,160. 10,730. 11,318 1161. 526 1011. 544 12.1

PG6101 (FA) Gas 69,430. 10,040. 10,526 1638. 742 1101. 594 14.6Dist. 74,090. 10,680. 10,527 1704. 772 1079. 582 15.0

PG7121 (EA) Gas 84,360. 10,480. 11,054 2361. 1070 998. 536 12.7Dist. 87,220. 10,950. 11,550 2413. 1093 993. 537 12.9

PG7241 (FA) Gas 171,700. 9,360. 9,873 3543. 1605 1119. 604 15.7Dist. 183,800. 9,965. 10,511 3691. 1672 1095. 591 16.2

PG7251 (FB) Gas 184,400. 9,245. 9,752 3561. 1613 1154. 623 18.4Dist. 177,700. 9,975. 10,522 3703. 1677 1057. 569 18.7

PG9171 (E) Gas 122,500. 10,140. 10,696 3275. 1484 1009. 543 12.6Dist. 127,300. 10,620. 11,202 3355. 1520 1003. 539 12.9

PG9231 (EC) Gas 169,200. 9,770. 10,305 4131. 1871 1034. 557 14.4Dist. 179,800. 10,360. 10,928 4291. 1944 1017. 547 14.8

PG9351 (FA) Gas 255,600. 9,250. 9,757 5118. 2318 1127. 608 15.3Dist. 268,000. 9,920. 10,464 5337. 2418 1106. 597 15.8

GT22043E

Thermodynamic PrinciplesA schematic diagram for a simple-cycle, single-shaft gas turbine is shown in Figure 2. Air entersthe axial flow compressor at point 1 at ambientconditions. Since these conditions vary fromday to day and from location to location, it isconvenient to consider some standard condi-tions for comparative purposes. The standardconditions used by the gas turbine industry are59 F/15 C, 14.7 psia/1.013 bar and 60% relativehumidity, which are established by theInternational Standards Organization (ISO)and frequently referred to as ISO conditions.

Air entering the compressor at point 1 is com-pressed to some higher pressure. No heat isadded; however, compression raises the airtemperature so that the air at the discharge ofthe compressor is at a higher temperature andpressure.

Upon leaving the compressor, air enters thecombustion system at point 2, where fuel isinjected and combustion occurs. The combus-tion process occurs at essentially constant pres-sure. Although high local temperatures arereached within the primary combustion zone(approaching stoichiometric conditions), the



Mechanical Drive Gas Turbine Ratings

Model Year ISO Rating ISO Rating Heat Heat Mass Mass Exhaust Exhaust

Continuous Continuous Rate Rate Flow Flow Temp Temp

(kW) (hp) (Btu/shp-hr) (kJ/kWh) (lb/sec) (kg/sec) (degrees F) (degrees C)

M3142 (J) 1952 11,290 15,140 9,500 13,440 117 53 1,008 542

M3142R (J) 1952 10,830 14,520 7,390 10,450 117 53 698 370

M5261 (RA) 1958 19,690 26,400 9,380 13,270 205 92 988 531

M5322R (B) 1972 23,870 32,000 7,070 10,000 253 114 666 352

M5352 (B) 1972 26,110 35,000 8,830 12,490 273 123 915 491

M5352R (C) 1987 26,550 35,600 6,990 9,890 267 121 693 367

M5382 (C) 1987 28,340 38,000 8,700 12,310 278 126 960 515

M6581 (B) 1978 38,290 51,340 7,820 11,060 295 134 1,013 545

Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings

MS7000

(EA)12PG

ModelNumberof

Shafts

PowerSeriesApplication

ApproxOutputPower inHundreds,Thousands, or10 Thousandsof Horsepower

R - RegenBlank - SC

1 or 2Frame3,5,76,9

MechDrivePkgdGen

M -

PG -

17

Figure 1. Heavy-duty gas turbine model designation

GT25385A

GT23054A

combustion system is designed to provide mix-ing, burning, dilution and cooling. Thus, by thetime the combustion mixture leaves the com-bustion system and enters the turbine at point3, it is at a mixed average temperature.

In the turbine section of the gas turbine, theenergy of the hot gases is converted into work.This conversion actually takes place in twosteps. In the nozzle section of the turbine, thehot gases are expanded and a portion of thethermal energy is converted into kinetic energy.In the subsequent bucket section of the turbine,a portion of the kinetic energy is transferred tothe rotating buckets and converted to work.

Some of the work developed by the turbine isused to drive the compressor, and the remain-der is available for useful work at the outputflange of the gas turbine. Typically, more than50% of the work developed by the turbine sec-tions is used to power the axial flow compressor.

As shown in Figure 2, single-shaft gas turbinesare configured in one continuous shaft and,therefore, all stages operate at the same speed.These units are typically used for generator-drive applications where significant speed varia-tion is not required.

A schematic diagram for a simple-cycle, two-shaft gas turbine is shown in Figure 3. The low-pressure or power turbine rotor is mechani-cally separate from the high-pressure turbineand compressor rotor. The low pressure rotoris said to be aerodynamically coupled. Thisunique feature allows the power turbine to beoperated at a range of speeds and makes two-shaft gas turbines ideally suited for variable-speed applications.

All of the work developed by the power turbineis available to drive the load equipment sincethe work developed by the high-pressure tur-bine supplies all the necessary energy to drivethe compressor. On two-shaft machines thestarting requirements for the gas turbine loadtrain are reduced because the load equipmentis mechanically separate from the high-pressureturbine.

The Brayton CycleThe thermodynamic cycle upon which all gasturbines operate is called the Brayton cycle.Figure 4 shows the classical pressure-volume(PV) and temperature-entropy (TS) diagramsfor this cycle. The numbers on this diagram cor-



Compressor

Inlet Air

1

CombustorFuel

2

4

Exhaust

3

Turbine

Generator

Figure 2. Simple-cycle, single-shaft gas turbine

GT08922A

respond to the numbers also used in Figure 2.Path 1 to 2 represents the compression occur-ring in the compressor, path 2 to 3 representsthe constant-pressure addition of heat in thecombustion systems, and path 3 to 4 representsthe expansion occurring in the turbine.

The path from 4 back to 1 on the Brayton cyclediagrams indicates a constant-pressure coolingprocess. In the gas turbine, this cooling is doneby the atmosphere, which provides fresh, cool

air at point 1 on a continuous basis in exchangefor the hot gases exhausted to the atmosphereat point 4. The actual cycle is an “open” ratherthan “closed” cycle, as indicated.

Every Brayton cycle can be characterized by twosignificant parameters: pressure ratio and firingtemperature. The pressure ratio of the cycle isthe pressure at point 2 (compressor dischargepressure) divided by the pressure at point 1(compressor inlet pressure). In an ideal cycle,



Exhaust

LoadLP

Compressor

Inlet Air

CombustorFuel

HP

Turbine

Figure 3. Simple-cycle, two-shaft gas turbine

1

2

1

2

1

2

3

4

4

4

3

3

FuelP

T

S

V

Figure 4. Brayton cycle

GT08923C

GT23055A

this pressure ratio is also equal to the pressureat point 3 divided by the pressure at point 4.However, in an actual cycle there is some slightpressure loss in the combustion system and,hence, the pressure at point 3 is slightly lessthan at point 2.

The other significant parameter, firing temper-ature, is thought to be the highest temperaturereached in the cycle. GE defines firing temper-ature as the mass-flow mean total temperature

at the stage 1 nozzle trailing edge plane.Currently all first stage nozzles are cooled tokeep the temperatures within the operating lim-its of the materials being used. The two types ofcooling currently employed by GE are air andsteam.

Air cooling has been used for more than 30years and has been extensively developed in air-craft engine technology, as well as the latest fam-ily of large power generation machines. Airused for cooling the first stage nozzle enters thehot gas stream after cooling down the nozzleand reduces the total temperature immediatelydownstream. GE uses this temperature since it ismore indicative of the cycle temperature repre-

sented as firing temperature by point 3 in Figure4.

Steam-cooled first stage nozzles do not reducethe temperature of the gas directly throughmixing because the steam is in a closed loop.As shown in Figure 5, the firing temperature ona turbine with steam-cooled nozzles (GE’s cur-rent “H” design) has an increase of 200degrees without increasing the combustionexit temperature.

An alternate method of determining firing tem-perature is defined in ISO document 2314, “GasTurbines – Acceptance Tests.” The firing tem-perature here is a reference turbine inlet tem-perature and is not generally a temperature thatexists in a gas turbine cycle; it is calculated froma heat balance on the combustion system, usingparameters obtained in a field test. This ISOreference temperature will always be less thanthe true firing temperature as defined by GE, inmany cases by 100 F/38 C or more for machinesusing air extracted from the compressor forinternal cooling, which bypasses the combustor.Figure 6 shows how these various temperaturesare defined.



Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle

OPEN LOOPAIR-COOLED NOZZLE

ADVANCED CLOSED LOOPSTEAM-COOLED NOZZLE

200F More Firing Temp. at Same NOx Production Possible GT25134

Thermodynamic Analysis

Classical thermodynamics permit evaluation ofthe Brayton cycle using such parameters as pres-sure, temperature, specific heat, efficiency fac-tors and the adiabatic compression exponent. Ifsuch an analysis is applied to the Brayton cycle,the results can be displayed as a plot of cycleefficiency vs. specific output of the cycle.

Figure 7 shows such a plot of output and

efficiency for different firing temperatures andvarious pressure ratios. Output per pound of airflow is important since the higher this value,the smaller the gas turbine required for the sameoutput power. Thermal efficiency is importantbecause it directly affects the operating fuel costs.

Figure 7 illustrates a number of significantpoints. In simple-cycle applications (the topcurve), pressure ratio increases translate intoefficiency gains at a given firing temperature.



Turbine Inlet Temperature - Average Gas Temp in Plane A. (TA)

ISO Firing Temperature - Calculated Temp in Plane C. TC = f(Ma , Mf)

GE Uses Firing Temperature TB

• Highest Temperature at Which Work Is Extracted

Firing Temperature - Average Gas Temp in Plane B. (TB)

CL

Figure 6. Definition of firing temperature

Figure 7. Gas turbine thermodynamics

GT23056

GT17983A

The pressure ratio resulting in maximum out-put and maximum efficiency change with firingtemperature, and the higher the pressure ratio,the greater the benefits from increased firingtemperature. Increases in firing temperatureprovide power increases at a given pressureratio, although there is a sacrifice of efficiencydue to the increase in cooling air lossesrequired to maintain parts lives.

In combined-cycle applications (as shown in thebottom graph in Figure 7), pressure ratioincreases have a less pronounced effect on effi-ciency. Note also that as pressure ratio increas-es, specific power decreases. Increases in firingtemperature result in increased thermal effi-ciency. The significant differences in the slopeof the two curves indicate that the optimumcycle parameters are not the same for simpleand combined cycles.

Simple-cycle efficiency is achieved with highpressure ratios. Combined-cycle efficiency isobtained with more modest pressure ratios andgreater firing temperatures. For example, theMS7001FA design parameters are 2420 F/1316 Cfiring temperature and 15.7:1 pressure ratio;

while simple-cycle efficiency is not maximized,combined-cycle efficiency is at its peak.Combined cycle is the expected application forthe MS7001FA.

Combined CycleA typical simple-cycle gas turbine will convert30% to 40% of the fuel input into shaft output.All but 1% to 2% of the remainder is in theform of exhaust heat. The combined cycle isgenerally defined as one or more gas turbineswith heat-recovery steam generators in theexhaust, producing steam for a steam turbinegenerator, heat-to-process, or a combinationthereof.

Figure 8 shows a combined cycle in its simplestform. High utilization of the fuel input to thegas turbine can be achieved with some of themore complex heat-recovery cycles, involvingmultiple-pressure boilers, extraction or toppingsteam turbines, and avoidance of steam flow toa condenser to preserve the latent heat content.Attaining more than 80% utilization of the fuelinput by a combination of electrical power gen-eration and process heat is not unusual.



Exhaust

Fuel

Gas TurbineAir

Comp Turb Gen

Gen

Comb

HRSGST

Turb

Figure 8. Combined cycle

GT05363C

Gen

Combined cycles producing only electricalpower are in the 50% to 60% thermal efficien-cy range using the more advanced gas turbines.

Papers dealing with combined-cycle applica-tions in the GE Reference Library include:GER-3574F, “GE Combined-Cycle Product Lineand Performance”; GER-3767, “Single-ShaftCombined-Cycle Power Generation Systems”;and GER-3430F, “Cogeneration ApplicationConsiderations.”

Factors Affecting Gas TurbinePerformance

Air Temperature and Site ElevationSince the gas turbine is an air-breathing engine,its performance is changed by anything thataffects the density and/or mass flow of the airintake to the compressor. Ambient weatherconditions are the most obvious changes fromthe reference conditions of 59 F/15 C and 14.7psia/1.013 bar. Figure 9 shows how ambient tem-perature affects the output, heat rate, heat con-sumption, and exhaust flow of a single-shaftMS7001. Each turbine model has its own tem-perature-effect curve, as it depends on the cycle

parameters and component efficiencies as wellas air mass flow.

Correction for altitude or barometric pressureis more straightforward. The air density reducesas the site elevation increases. While the result-ing airflow and output decrease proportionate-ly, the heat rate and other cycle parameters arenot affected. A standard altitude correctioncurve is presented in Figure 10.

HumiditySimilarly, humid air, which is less dense thandry air, also affects output and heat rate, asshown in Figure 11. In the past, this effect wasthought to be too small to be considered.However, with the increasing size of gas turbinesand the utilization of humidity to bias water andsteam injection for NOx control, this effect hasgreater significance.

It should be noted that this humidity effect is aresult of the control system approximation offiring temperature used on GE heavy-duty gasturbines. Single-shaft turbines that use turbineexhaust temperature biased by the compressorpressure ratio to the approximate firing tem-perature will reduce power as a result of



-7

0

130

Output

CompressorInlet

Temperature

PercentDesign

Heat Rate

Exhaust FlowHeat Cons.

120

49

100

38

80

27

60

16

40

4

20

-18

°F

°C

70

80

90

100

110

120

Figure 9. Effect of ambient temperature

GT22045D

increased ambient humidity. This occursbecause the density loss to the air from humidi-ty is less than the density loss due to tempera-ture. The control system is set to follow the inletair temperature function.

By contrast, the control system on aeroderiva-tives uses unbiased gas generator discharge tem-perature to approximate firing temperature.The gas generator can operate at differentspeeds from the power turbine, and the powerwill actually increase as fuel is added to raise the

moist air (due to humidity) to the allowabletemperature. This fuel increase will increase thegas generator speed and compensate for theloss in air density.

Inlet and Exhaust LossesInserting air filtration, silencing, evaporativecoolers or chillers into the inlet or heat recov-ery devices in the exhaust causes pressure lossesin the system. The effects of these pressure loss-es are unique to each design. Figure 12 shows



Figure 10. Altitude correction curve

Figure 11. Humidity effect curve

GT18848B

GT22046B

the effects on the MS7001EA, which are typicalfor the E technology family of scaled machines(MS6001B, 7001EA, 9001E).

FuelsWork from a gas turbine can be defined as theproduct of mass flow, heat energy in the com-busted gas (Cp), and temperature differentialacross the turbine. The mass flow in thisequation is the sum of compressor airflowand fuel flow. The heat energy is a functionof the elements in the fuel and the productsof combustion.

Tables 1 and 2 show that natural gas (methane)produces nearly 2% more output than does dis-tillate oil. This is due to the higher specific heatin the combustion products of natural gas,resulting from the higher water vapor contentproduced by the higher hydrogen/carbon ratioof methane. This effect is noted even thoughthe mass flow (lb/h) of methane is lower thanthe mass flow of distillate fuel. Here the effectsof specific heat were greater than and in oppo-sition to the effects of mass flow.

Figure 13 shows the total effect of various fuelson turbine output. This curve uses methane asthe base fuel.

Although there is no clear relationship betweenfuel lower heating value (LHV) and output, it is

possible to make some general assumptions. Ifthe fuel consists only of hydrocarbons with noinert gases and no oxygen atoms, outputincreases as LHV increases. Here the effects ofCp are greater than the effects of mass flow.Also, as the amount of inert gases is increased,the decrease in LHV will provide an increase inoutput. This is the major impact of IGCC typefuels that have large amounts of inert gas in thefuel. This mass flow addition, which is not com-pressed by the gas turbine’s compressor,increases the turbine output. Compressorpower is essentially unchanged. Several sideeffects must be considered when burning thiskind of lower heating value fuels:

■ Increased turbine mass flow drives upcompressor pressure ratio, whicheventually encroaches on thecompressor surge limit

■ The higher turbine power may exceedfault torque limits. In many cases, alarger generator and other accessoryequipment may be needed

■ High fuel volumes increase fuel pipingand valve sizes (and costs). Low- ormedium-Btu coal gases are frequentlysupplied at high temperatures, whichfurther increases their volume flow



Figure 12. Pressure drop effects (MS7001EA)

4 Inches (10 mbar) H2O Inlet Drop Produces:

1.42% Power Output Loss

0.45% Heat Rate Increase

1.9 F (1.1 C) Exhaust Temperature Increase

4 Inches (10 mbar) H2O Exhaust Drop Produces:

0.42% Power Output Loss

0.42% Heat Rate Increase

1.9 F (1.1 C) Exhaust Temperature IncreaseGT18238C

■ Lower-Btu gases are frequentlysaturated with water prior to deliveryto the turbine. This increases thecombustion products heat transfercoefficients and raises the metaltemperatures in the turbine sectionwhich may require lower operatingfiring temperature to preserve partslives

■ As the Btu value drops, more air isrequired to burn the fuel. Machineswith high firing temperatures may notbe able to burn low Btu gases

■ Most air-blown gasifiers use airsupplied from the gas turbinecompressor discharge

■ The ability to extract air must beevaluated and factored into the overallheat and material balances

As a result of these influences, each turbinemodel will have some application guidelines onflows, temperatures and shaft output to preserve

its design life. In most cases of operation withlower heating value fuels, it can be assumed thatoutput and efficiency will be equal to or higherthan that obtained on natural gas. In the case ofhigher heating value fuels, such as refinerygases, output and efficiency may be equal to orlower than that obtained on natural gas.

Fuel HeatingMost of the combined cycle turbine installationsare designed for maximum efficiency. Theseplants often utilize integrated fuel gas heaters.Heated fuel results in higher turbine efficiencydue to the reduced fuel flow required to raisethe total gas temperature to firing temperature.Fuel heating will result in slightly lower gas tur-bine output because of the incremental volumeflow decrease. The source of heat for the fueltypically is the IP feedwater. Since use of thisenergy in the gas turbine fuel heating system isthermodynamically advantageous, the com-bined cycle efficiency is improved by approxi-mately 0.6%.



100%H2

4020

100%CH4

Output - Percent

Kca

l/kg

(Tho

usan

ds)

LHV

-Btu

/lb (

Tho

usan

ds)

105

100% CO75% N2 - 25% CH4

75% CO2 - 25% CH4

100%CH4H10

60

50

30

20

10

10

30

0100 110 115 120 125 130

Figure 13. Effect of fuel heating value on output

GT25842

Diluent InjectionSince the early 1970s, GE has used water orsteam injection for NOx control to meet appli-cable state and federal regulations. This isaccomplished by admitting water or steam inthe cap area or “head-end” of the combustionliner. Each machine and combustor configura-tion has limits on water or steam injection levelsto protect the combustion system and turbinesection. Depending on the amount of water orsteam injection needed to achieve the desiredNOx level, output will increase because of the

additional mass flow. Figure 14 shows the effectof steam injection on output and heat rate foran MS7001EA. These curves assume that steamis free to the gas turbine cycle, therefore heatrate improves. Since it takes more fuel to raisewater to combustor conditions than steam,water injection does not provide an improve-ment in heat rate.

Air ExtractionIn some gas turbine applications, it may bedesirable to extract air from the compressor.

Generally, up to 5% of the compressor airflowcan be extracted from the compressor dis-charge casing without modification to casingsor on-base piping. Pressure and air temperaturewill depend on the type of machine and siteconditions. Air extraction between 6% and 20%may be possible, depending on the machineand combustor configuration, with some modi-fications to the casings, piping and controls.Such applications need to be reviewed on acase-by-case basis. Air extractions above 20%will require extensive modification to the tur-bine casing and unit configuration. Figure 15

shows the effect of air extraction on output andheat rate. As a “rule of thumb,” every 1% in airextraction results in a 2% loss in power.

Performance EnhancementsGenerally, controlling some of the factors thataffect gas turbine performance is not possible.The planned site location and the plant config-uration (such as simple- or combined-cycle)determine most of these factors. In the eventadditional output is needed, several possibilitiesto enhance performance may be considered.



130

120

110

100

90

80

70

Output%

Compressor Inlet Temperature

40 60 80 100 120ºF

4 16 27 38 49ºC

1%

3%

No SteamInjection

With 5%Steam

Injection

Figure 14. Effect of steam injection on output andheat rate

Figure 15. Effect of air extraction on output and heatrate

GT18851A GT22048-1C

Inlet CoolingThe ambient effect curve (see Figure 9) clearlyshows that turbine output and heat rate areimproved as compressor inlet temperaturedecreases. Lowering the compressor inlet tem-perature can be accomplished by installing anevaporative cooler or inlet chiller in the inletducting downstream of the inlet filters. Carefulapplication of these systems is necessary, as con-densation or carryover of water can exacerbatecompressor fouling and degrade performance.These systems generally are followed by mois-ture separators or coalescing pads to reduce thepossibility of moisture carryover.

As Figure 16 shows, the biggest gains from evap-orative cooling are realized in hot, low-humid-ity climates. It should be noted that evapora-tive cooling is limited to ambient temperaturesof 59 F/15 C and above (compressor inlet tem-perature >45 F/7.2 C) because of the potentialfor icing the compressor. Information con-tained in Figure 16 is based on an 85% effectiveevaporative cooler. Effectiveness is a measureof how close the cooler exit temperatureapproaches the ambient wet bulb tempera-

ture. For most applications, coolers having aneffectiveness of 85% or 90% provide the mosteconomic benefit.

Chillers, unlike evaporative coolers, are not lim-ited by the ambient wet bulb temperature. Theachievable temperature is limited only by thecapacity of the chilling device to producecoolant and the ability of the coils to transferheat. Cooling initially follows a line of constant



Figure 16. Effect of evaporative cooling on outputand heat rate

49

120°F

°C

Dry BulbTemperature

20

25

30

35

40100% RH

15.005

.020

SpecificHumidity

EvaporativeCooling Process

Btu Per Poundof Dry Air

(Simplified)

PsychrometricChart

.000

.010

.015

40 60 80 100

4 16 27 38

10% RH

Inlet ChillingProcess

20% RH

40% RH

60% RH

Figure 17. Inlet chilling process

GT22419-1D

GT21141D

specific humidity, as shown in Figure 17. As satu-ration is approached, water begins to condensefrom the air, and mist eliminators are used.Further heat transfer cools the condensate andair, and causes more condensation. Because ofthe relatively high heat of vaporization of water,most of the cooling energy in this regime goesto condensation and little to temperaturereduction.

Steam and Water Injection for PowerAugmentationInjecting steam or water into the head end ofthe combustor for NOx abatement increasesmass flow and, therefore, output. Generally, theamount of water is limited to the amountrequired to meet the NOx requirement in orderto minimize operating cost and impact oninspection intervals.

Steam injection for power augmentation hasbeen an available option on GE gas turbines forover 30 years. When steam is injected for poweraugmentation, it can be introduced into thecompressor discharge casing of the gas turbineas well as the combustor. The effect on outputand heat rate is the same as that shown in Figure14. GE gas turbines are designed to allow up to5% of the compressor airflow for steam injec-tion to the combustor and compressor dis-charge. Steam must contain 50 F/28 C super-heat and be at pressures comparable to fuel gaspressures.

When either steam or water is used for poweraugmentation, the control system is normallydesigned to allow only the amount needed forNOx abatement until the machine reaches base(full) load. At that point, additional steam orwater can be admitted via the governor control.

Peak RatingThe performance values listed in Table 1 arebase load ratings. ANSI B133.6 Ratings and

Performance defines base load as operation at8,000 hours per year with 800 hours per start. Italso defines peak load as operation at 1250hours per year with five hours per start.

In recognition of shorter operating hours, it ispossible to increase firing temperature to gen-erate more output. The penalty for this type ofoperation is shorter inspection intervals.Despite this, running an MS5001, MS6001 orMS7001 at peak may be a cost-effective way toobtain more kilowatts without the need foradditional peripheral equipment.

Generators used with gas turbines likewise havepeak ratings that are obtained by operating athigher power factors or temperature rises. Peakcycle ratings are ratings that are customized tothe mission of the turbine considering bothstarts and hours of operation. Firing tempera-tures between base and peak can be selected tomaximize the power capabilities of the turbinewhile staying within the starts limit envelope ofthe turbine hot section repair interval. Forinstance, the 7EA can operate for 24,000 hourson gas fuel at base load, as defined. The startslimit to hot section repair interval is 800 starts.

For peaking cycle of five hours per start, the hotsection repair interval would occur at 4,000hours, which corresponds to operation at peakfiring temperatures. Turbine missions betweenfive hours per start and 800 hours per start mayallow firing temperatures to increase above basebut below peak without sacrificing hours to hotsection repair. Water injection for power aug-mentation may be factored into the peak cyclerating to further maximize output.

Performance DegradationAll turbomachinery experiences losses in per-formance with time. Gas turbine performancedegradation can be classified as recoverable ornon-recoverable loss. Recoverable loss is usually



associated with compressor fouling and can bepartially rectified by water washing or, morethoroughly, by mechanically cleaning the com-pressor blades and vanes after opening the unit.Non-recoverable loss is due primarily toincreased turbine and compressor clearancesand changes in surface finish and airfoil con-tour. Because this loss is caused by reduction incomponent efficiencies, it cannot be recoveredby operational procedures, external mainte-nance or compressor cleaning, but onlythrough replacement of affected parts at rec-ommended inspection intervals.

Quantifying performance degradation is diffi-cult because consistent, valid field data is hardto obtain. Correlation between various sites isimpacted by variables such as mode of opera-tion, contaminants in the air, humidity, fuel anddilutent injection levels for NOx. Another prob-lem is that test instruments and procedures varywidely, often with large tolerances.

Typically, performance degradation during thefirst 24,000 hours of operation (the normallyrecommended interval for a hot gas pathinspection) is 2% to 6% from the performancetest measurements when corrected to guaran-teed conditions. This assumes degraded partsare not replaced. If replaced, the expected per-formance degradation is 1% to 1.5%. Recentfield experience indicates that frequent off-linewater washing is not only effective in reducingrecoverable loss, but also reduces the rate ofnon-recoverable loss.

One generalization that can be made from thedata is that machines located in dry, hot cli-mates typically degrade less than those inhumid climates.

Verifying Gas Turbine PerformanceOnce the gas turbine is installed, a perform-ance test is usually conducted to determine

power plant performance. Power, fuel, heatconsumption and sufficient supporting datashould be recorded to enable as-tested per-formance to be corrected to the condition ofthe guarantee. Preferably, this test should bedone as soon as practical, with the unit in newand clean condition. In general, a machine isconsidered to be in new and clean condition ifit has less than 200 fired hours of operation.

Testing procedures and calculation methods arepatterned after those described in the ASMEPerformance Test Code PTC-22-1997, “GasTurbine Power Plants.” Prior to testing, all sta-tion instruments used for primary data collec-tion must be inspected and calibrated. The testshould consist of sufficient test points to ensurevalidity of the test set-up. Each test point shouldconsist of a minimum of four complete sets ofreadings taken over a 30-minute time periodwhen operating at base load. Per ASME PTC-22-1997, the methodology of correcting test resultsto guarantee conditions and measurementuncertainties (approximately 1% on output andheat rate when testing on gas fuel) shall beagreed upon by the parties prior to the test.

SummaryThis paper reviewed the thermodynamic princi-ples of both one- and two-shaft gas turbines anddiscussed cycle characteristics of the severalmodels of gas turbines offered by GE. Ratings ofthe product line were presented, and factorsaffecting performance were discussed alongwith methods to enhance gas turbine output.

GE heavy-duty gas turbines serving industrial,utility and cogeneration users have a provenhistory of sustained performance and reliabili-ty. GE is committed to providing its customerswith the latest in equipment designs andadvancements to meet power needs at highthermal efficiency.



List of FiguresFigure 1. Heavy-duty gas turbine model designation

Figure 2. Simple-cycle, single-shaft gas turbine

Figure 3. Simple-cycle, two-shaft gas turbine

Figure 4. Brayton cycle

Figure 5. Comparison of air-cooled vs. steam-cooled first stage nozzle

Figure 6. Definition of firing temperature

Figure 7. Gas turbine thermodynamics

Figure 8. Combined cycle

Figure 9. Effect of ambient temperature

Figure 10. Altitude correction curve

Figure 11. Humidity effect curve

Figure 12. Pressure drop effects (MS7001EA)

Figure 13. Effect of fuel heating value on output

Figure 14. Effect of steam injection on output and heat rate

Figure 15. Effect of air extraction on output and heat rate

Figure 16. Effect of evaporative cooling on output and heat rate

Figure 17. Inlet chilling process

List of TablesTable 1. GE gas turbine performance characteristics - Generator drive gas turbine ratings

Table 2. GE gas turbine performance characteristics - Mechanical drive gas turbine ratings




UOGTDLN1Revision B, July 1995


Unit Operation/Turbine (Gas)

(Applicability MS5001P, 6001B, 7001EA, 9001E)

I. REFERENCE DATA AND PRECAUTIONS

A. Operator Responsibility

It is essential that the turbine operators be familiar with the information contained in the following opera-tion text, the Control Specification drawings (consult the Control System Settings drawing for the indexof Control Specification drawings), the Piping Schematic drawings including the Device Summary (con-sult the Control System Settings Drawing for the index by model list and drawing number of applicableschematics), the SPEEDTRONIC control sequence program and the SPEEDTRONIC Mark V Users’Manual (GEH 5979). The operator must also be aware of the power plant devices which are tied into thegas turbine mechanically and electrically and could affect normal operation. No starts should be attemptedwhether on a new turbine or a newly overhauled turbine until the following conditions have been met:

1. Requirements listed under CHECKS PRIOR TO OPERATION have been met.

2. Control systems have been functionally checked for proper operation before restarting.

3. All GENERAL OPERATING PRECAUTIONS have been noted.

It is extremely important that gas turbine operators establish proper operating practices. We emphasizeadherence to the following:

1. Respond to Annunciator Indicators — Investigate and correct the cause of the abnormal condition.This is particularly true for the protection systems, such as low oil pressure, overtemperature, vibra-tion, overspeed etc.

2. Check of Control Systems — After any type of control maintenance is completed, whether repair orreplacement of parts, functionally check control systems for proper operation. This should be doneprior to restart of the turbine. It should not be assumed that reassembly, “as taken apart” is adequatewithout the functional test.

3. Monitor Exhaust Temperature During All Phases of Startup — The operator is alerted to the follow-ing:


UOGTDLN1–2

CAUTION

Overtemperature can damage the turbine hot gas pathparts.

Monitor exhaust temperature for proper control upon first startup and after any turbine maintenance isperformed. Trip the turbine if the exhaust temperature exceeds the normal trip level, or increases at anunusual rate. A particularly critical period for overtemperature damage to occur is during the startup phasebefore the turbine reaches governing speed. At this time air flow is low and the turbine is unable to acceler-ate away from excess fuel.

B. General Operating Precautions

1. Temperature Limits

Refer to the Control Specifications for actual exhaust temperature control settings. It is important todefine a “baseline value” of exhaust temperature spread with which to compare future data. This base-line data is established during steady state operation after each of the following conditions:

a. Initial startup of unit

b. Before and after a planned shut-down

c. Before and after planned maintenance

An important point regarding the evaluation of exhaust temperature spreads is not necessarily themagnitude of the spread, but the change in spread over a period of time. The accurate recording andplotting of exhaust temperatures daily can indicate a developing problem. Consult Control Specifica-tion-Settings Drawings for maximum allowable temperature spreads and wheelspace temperature op-erating limits.

The wheelspace thermocouples, identified together with their nomenclature, are on the Device Sum-mary. A bad thermocouple will cause a “High Wheelspace Differential Temperature” alarm. Thefaulty thermocouple should be replaced at the earliest convenience.

When the average temperature in any wheelspace is higher then the temperature limit set forth in thetable, it is an indication of trouble. High wheelspace temperature may be caused by any of the follow-ing faults:

1. Restriction in cooling air lines

2. Wear of turbine seals

3. Excessive distortion of the turbine stator

4. Improper positioning of thermocouple

5. Malfunctioning combustion system

6. Leakage in external piping

UOGTDLN1–3

7. Excessive distortion of exhaust inner diffuser

Check wheelspace temperatures very closely on initial startup. If consistently high, and a check ofthe external cooling air circuits reveals nothing, it is permissible to increase the size of the coolingair orifices slightly. Consult with a GE Company field representative to obtain recommendations asto the size that an orifice should be increased. After a turbine overhaul, all orifices should be changedback to their original size, assuming that all turbine clearances are returned to normal and all leakagepaths are corrected.

CAUTION

Wheelspace temperatures are read on the CRT. Tem-peratures in excess of the maximum are potentially harm-ful to turbine hot-gas-path parts over a prolonged periodof time. Excessive temperatures are annunciated but willnot cause the turbine to trip. High wheelspace tempera-ture readings must be reported to the GE technical repre-sentative as soon as possible.

2. Pressure Limits

Refer to the Device Summary for actual pressure switch settings. Lube oil pressure in the bearing feedheader is a nominal value of 25 psig kPa. The turbine will trip at 8 psig kPa. Pressure variations be-tween these values will result from entrapped particulate matter within the lube oil filtering system.

3. Vibration Limits

The maximum overall vibration velocity of the gas turbine should never exceed 1.0 inch (2.54 cm)per second in either the vertical or horizontal direction. Corrective action should be initiated whenthe vibration levels exceed 0.5 inch (1.27 cm) per second as indicated on the SPEEDTRONIC CRT.

If doubt exists regarding the accuracy of the reading or if more accurate and specific vibration read-ings are desired a vibration check is recommended using vibration test equipment.

4. Load Limit

The maximum load capability of the gas turbine is given in the control specification. For the upperlimits of generator capability, refer to the Reactive Capability Curve.

5. Overloading of Gas Turbine, Facts Involved and Policy

It is GE practice to design gas turbines with margins of safety to meet the contract commitments andto secure long life and trouble-free operation.

So that maximum trouble-free operation can be secured, GE designs these machines with more thanample margins on turbine bucket thermal and dynamic stresses, compressor and turbine wheelstresses, generator ventilation, coolers, etc. As a result, these machines are designed somewhat better


UOGTDLN1–4

than is strictly necessary, because of the importance of reliability of these turbines to our customersand to the electrical industry.

It cannot be said, therefore, that these machines cannot be safely operated beyond the load limits. Suchoperation, however, always encroaches upon the design margins of the machines with a consequentreduction in reliability and increased maintenance. Accordingly, any malfunction that occurs as a re-sult of operation beyond contract limits cannot be the responsibility of the GE Company.

The fact that a generator operates at temperature rises below the 185F (85C) for the rotor and 140F(60C) for the stator permitted by the AIEE Standards does not mean that it can be properly run withfull safety up to these values by overloading beyond the nameplate rating. These standards were pri-marily set up for the protection of insulation from thermal deterioration on small machines. The im-bedded temperature detectors of the stator register a lower temperature than the copper because ofthe temperature drop through the insulation from the copper to the outside of the insulation, wherethe temperature detectors are located. There are also conditions of conductor expansion, insulationstress, etc., which impose limitations. These factors have been anticipated in the “Vee” curves andreactive capability curves which indicate recommended values consistent with good operating prac-tice. The “Vee” curves and reactive capability curves form part of the operating instructions for thegenerator and it is considered unwise to exceed the values given.

The gas turbine-generator sets may require gearing between the gas turbine and the generator. Wherea reduction (or speed-increasing) gear is required between the gas turbine and generator, the gear israted at the maximum capability of the gas turbine, or the maximum kva capability of the generator,whichever is less. If the gas turbine-generator set is operated beyond the maximum rating of the gear,the gear will also be overloaded with corresponding increased maintenance and reduced length of life.

The gas turbines are mechanically designed so that (within prescribed limits), advantage can be takenof the increased capability over nameplate rating, which is available at lower ambient temperatures(because of increased air density), without exceeding the maximum allowable turbine inlet tempera-ture.

The load limit of the gas turbine-generator must not be exceeded, even when the ambient temperatureis lower than that at which the load limit of the gas turbine is reached. Under these conditions, the gasturbine will operate at this load with a lower turbine inlet temperature and the design stresses on theload coupling and turbine shaft will not be exceeded.

If the turbine is overloaded so that the turbine exhaust temperature schedule is not followed for rea-sons of malfunctioning or improper setting of the exhaust temperature control system, the maximumallowable turbine inlet temperature or the maximum allowable exhaust temperature, or both, will beexceeded and will result in a corresponding increase in maintenance and, in extreme cases, might re-sult in failure of the turbine parts.

The exhaust temperature control system senses the turbine exhaust temperature and introduces properbias to limit the fuel flow so that neither the maximum allowable turbine inlet temperature nor themaximum allowable turbine exhaust temperature is exceeded.

6. Fire Protection System Operating Precautions

The fire protection system, when actuated, will cause several functions to occur in addition to actuat-ing the media discharge system. The turbine will trip, an audible alarm will sound, and the alarm mes-

UOGTDLN1–5

sage will be displayed on the CRT. The ventilation openings in the compartments will be closedby a pressure-operated latch and the damper in the turbine shell cooling discharge will be actuated.

The annunciator audible alarm may be silenced by clicking on the alarm SILENCE target. The alarmmessage can be cleared from the ALARM list on the CRT after the ACKNOWLEDGE target andthe ALARM RESET target are actuated, but only after the situation causing the alarm has been cor-rected.

The fire protection system must be replenished and reset before it can automatically react to anotherfire. Reset must be made after each activation of the fire protection system which includes an initialdischarge followed by an extended discharge period of the fire protection media.

Fire protection system reset is accomplished by resetting the pressure switch located on the fireprotection system.

Ventilation dampers, automatically closed by a signal received from the fire protection system, mustbe reopened manually in all compartments before restarting the turbine.

CAUTION

Failure to reopen compartment ventilation dampers willseverely shorten the service life of major accessoryequipment. Failure to reopen the load coupling compart-ment dampers will materially reduce the performance ofthe generator.

7. Combustion System Operating Precautions

WARNING

Sudden emission of black smoke may indicate a possi-bility of outer casing failure or other serious combus-tion problems. In such an event:

a. Immediately shut down the turbine.

b. Allow no personnel inside the turbine compartment until turbine is shut down.

c. Caution all personnel against standing in front of access door openings into pressurized compart-ments.

d. Perform a complete combustion system inspection.

To reduce the possibility of combustion outer casing failure, the operator should adhere to the follow-ing:


UOGTDLN1–6

a. During operation, exhaust temperatures are monitored by the SPEEDTRONIC control system.The temperature spread is compared to allowable spreads with alarms and/or protective trips re-sulting if the allowable spread limits are exceeded.

b. After a trip from 75% load or above, observe the exhaust on startup for black or abnormal smokeand scan the exhaust thermocouples for unusually high spreads. Record temperature spread dur-ing a normal startup to obtain base line signature for comparison. Excessive tripping should beinvestigated and eliminated.

c. Adhere to recommended inspection intervals on combustion liners, transition pieces and fuelnozzles.

Operating a turbine with non-operational exhaust thermocouples increases the risk of turbine overfiring andprevents diagnosis of combustion problems by use of temperature differential readings.

To prevent the above described malfunctions the operator should keep the number of non-operational exhaustthermocouples to a maximum of two but no more than one of any three adjacent thermocouples.

CAUTION

Operation of the gas turbine with a single faulty thermo-couple should not be neglected, as even one faulty ther-mocouple will increase the risk of an invalid “combus-tion alarm” and/or “Trip”. The unit should not be shutdown just for replacement of a single faulty thermocou-ple. However, every effort should be made to replace thefaulty thermocouples when the machine is down for anyreason.

Adherence to the above criteria and early preventive maintenance should reduce distortions of thecontrol and protection functions and the number of unnecessary turbine trips.

8. Cooldown/Shutdown Precautions

CAUTION

In the event of an emergency shutdown in which internaldamage of any rotating equipment is suspected, do notturn the rotor after shutdown. Maintain lube oil pump op-eration, since lack of circulating lube oil following a hotshutdown will result in rising bearing temperatureswhich can result in damaged bearing surfaces. If the mal-function that caused the shutdown can be quickly re-paired, or if a check reveals no internal damage affectingthe rotating parts, reinstate the cooldown cycle.


UOGTDLN1–7

If there is an emergency shutdown and the turbine is not turned with the rotor turning device, the fol-lowing factors should be noted:

a. Within 20 minutes, maximum, following turbine shutdown, the gas turbine may be started with-out cooldown rotation. Use the normal starting procedure.

b. Between 20 minutes and 48 hours after shutdown a restart should not be attempted unless the gasturbine rotor has been turned from one to two hours.

c. If the unit has been shut down and not turned at all, it must be shut down for approximately 48hours before it can be restarted without danger of shaft bow.

CAUTION

Where the gas turbine has not been on rotor turning op-eration after shutdown and a restart is attempted, as underconditions (a) and (b) above, the operator should main-tain a constant check on vibration velocity as the unit isbrought up to its rated speed. If the vibration velocity ex-ceeds one inch per second at any speed, the unit shouldbe shut down and the shaft rotated for at least one hourbefore a second starting attempt is made. If seizure oc-curs during the turning operation of the gas turbine, theturbine should be shut down and remain idle for at least30 hours, or until the rotor is free. The turbine may be ro-tated at any time during the 30-hour period if it is free;however, audible checks should be made for rubs.

Note: The vibration velocity must be measured at points near the gas turbinebearing caps.

II. PREPARATIONS FOR NORMAL LOAD OPERATION

A. Standby Power Requirements

Standby AC power insures the immediate startup capability of particular turbine equipment and relatedcontrol systems when the start signal is given. Functions identified by asterisk are also necessary for unitenvironmental protection and should not be turned off except for maintenance work on that particularfunction. Standby AC power is required for:

1. Lube oil heaters, which when used in conjunction with the lube oil pumps, heat and circulate turbinelube oil at low ambient temperatures to maintain proper oil viscosity.

2. *Control panel heating.

3. *Generator heating.

4. Lube oil pumps. Auxiliary pump should be run at periodic intervals to prevent rust formation in thelube oil system.

UOGTDLN1–8

5. Fuel oil heaters, where used. These heaters used in conjunction with the fuel oil pumps, heat and circu-late fuel oil at low ambient temperatures to maintain proper fuel oil viscosity.

6. Compartment heating.

7. *Operation of control compartment air conditioner during periods of high ambient temperature tomaintain electrical equipment insulation within design temperature limits.

8. *Battery charging (where applicable).

9. Heating diesel engine cooling water to assure quick starting capability. (Applicable to diesel enginestarting only.)

If a black start is required, it is recommended that the turbine be started and loaded within one hour oflosing AC power.

B. Checks Prior to Operation

The following checks are to be made before attempting to operate a new turbine or an overhauled turbine.It is assumed that the turbine has been assembled correctly, is in alignment and that calibration of theSPEEDTRONIC system has been performed per the Control Specifications. A standby inspection ofthe turbine should be performed with the lube oil pump operating and emphasis on the following areas:

1. Check that all piping and turbine connections are securely fastened and that all blinds have been re-moved. Most tube fittings incorporate a stop collar which insures proper torquing of the fittings atinitial fitting make up and at reassembly. These collars fit between the body of the fitting and the nutand contact in tightening of the fitting. The stop collar is similar to a washer and can be rotated freelyon unassembled fittings. During initial assembly of a fitting with a stop collar, tighten the nut untilit bottoms on the collar. The fitting has to be sufficiently tightened until the collar cannot be rotatedby hand. This is the inspection for a proper fitting assembly. For each remake of the fitting, the nutshould again be tightened until the collar cannot be rotated.

2. Inlet and exhaust plenums and associated ducting are clean and rid of all foreign objects. All accessdoors are secure.

3. Where fuel, air or lube oil filters have been replaced check that all covers are intact and tight.

4. Verify that the lube oil tank is within the operating level and if the tank has been drained that it hasbeen refilled with the recommended quality and quantity of lube oil. If lube oil flushing has been con-ducted verify that all filters have been replaced and any blinds if used, removed.

5. Check operation of auxiliary and emergency equipment, such as lube oil pumps, water pumps, fuelforwarding pumps, etc. Check for obvious leakage, abnormal vibration (maximum 3 mils), noise oroverheating.

6. Check lube oil piping for obvious leakage. Also using provided oil flow sights, check visually thatoil is flowing from the bearing drains. The turbine should not be started unless flow is visible at eachflow sight.

7. Check condition of all thermocouples and/or resistance temperature detectors (RTDs) on the CRT. Reading should be approximately ambient temperature.


UOGTDLN1–9

8. Check spark plugs for proper arcing.

WARNING

Do not test spark plugs where explosive atmosphereis present.

If the arc occurs anywhere other than directly across the gap at the tips of the electrodes, or if by blow-ing on the arc it can be moved from this point, the plug should be cleaned and the tip clearance ad-justed. If necessary, the plug should be replaced. Verify the retracting piston for free operation.

9. Devices requiring manual lubrication are to be properly serviced.

10. Determine that the cooling water system has been properly flushed and filled with the recommendedcoolant. Any fine powdery rust, which might form in the piping during short time exposure to atmo-sphere, can be tolerated. If there is evidence of a scaly rust, the cooling system should be powerflushed until all scale is removed. If it is necessary to use a chemical cleaner, most automobile coolingsystem cleaners are acceptable and will not damage the carbon and rubber parts of the pump mechani-cal seals or rubber parts in the piping.

Refer to “Cooling Water Recommendations for Combustion Gas Turbine Closed Cooling Systems” in-cluded under tab titled Fluid Specifications. Note the following regarding antifreeze.

CAUTION

Do not change from one type antifreeze to another with-out first flushing the cooling system very thoroughly. In-hibitors used may not be compatible and can causeformation of gums, in addition to destroying effective-ness as an inhibitor. Consult the antifreeze vendor forspecific recommendations.

Following the water system refill ensure that water system piping, primarily pumps and flexible cou-plings, do not leak. It is wise not to add any corrosion inhibitors until after the water system is found tobe leak free.

11. Turbines having a diesel engine starting means should have the engine tested using the diesel testpushbutton in the accessory compartment.

12. The use of radio transmitting equipment in the vicinity of open control panels is not recommended.Prohibiting such use will assure that no extraneous signals are introduced into the control system thatmight influence the normal operation of the equipment.

13. Check the Cooling and Sealing Air Piping against the assembly drawing and piping schematic, to en-sure that all orifice plates are of designated size and in designated positions.


UOGTDLN1–10

14. At this time all annunciated ground faults should be cleared. It is recommended that units not be oper-ated when a ground fault is indicated. Immediate action should be taken to locate all grounds and cor-rect the problems.

C. Checks During Start Up and Initial Operation

The following is a list of important checks to be made on a new or newly overhauled turbine with the OP-ERATION SELECTOR switch in various modes. The Control Specifications — Control Systems Adjust-ments should be reviewed prior to operating the turbine.

CAUTION

Where an electric motor is used as the starting means re-fer to the Control Specifications for maximum operatingtime.

When a unit has been overhauled those parts or components that have been removed and taken apart forinspection/repair should be critically monitored during unit startup and operation. This inspection shouldinclude: leakage check, vibration, unusual noise, overheating, lubrication.

1. Crank

a. Listen for rubbing noises in the turbine compartment and in the reduction gear compartment espe-cially in the load tunnel area. A soundscope or some other listening type device is suggested.Shutdown and investigate if unusual noise occurs.

b. Check for unusual vibration.

c. Inspect for water system leakage.


UOGTDLN1–11

2. Fire

* * * WARNING * * *

Due to the complexity of gas turbine fuel systems, it is imperative for ev-eryone to exercise extreme caution in and near any turbine compartment,fuel handling system, or any other enclosures or areas containing fuel pip-ing or fuel system components.

Do not enter the turbine compartment unless absolutely necessary. Whenit is necessary, exercise caution when opening and entering the compart-ment. Be aware of the possibility of fuel leaks, and be prepared to shutdown the turbine and take action if a leak is discovered.

At any time, if/when entering the turbine compartment or when in the vi-cinity of the fuel handling system or other locations with fuel piping, fuelsystem components, or fuel system connections, while the turbine is oper-ating, implement the following:

Conduct an environmental evaluation of the turbine compartment,fuel handling system, or specific area. Pay particular attention to alllocations where fuel piping/components/connections exist.

Follow applicable procedures for leak testing. If fuel leaks are discov-ered, exit the area quickly, shut the turbine down, and take appropri-ate actions to eliminate the leak(s).

Require personnel entering the turbine comparrtment to be fittedwith the appropriate personal protective equipment, i.e., hard hat,safety glasses, hearing protection, harness/manline (optional depend-ing on space constraints), heat resistant/flame retardant coveralls andgloves.

Establish an attendant to maintain visual contact with personnel in-side the turbine compartment and radio communications with thecontrol room operator.

During the first start-up after a disassembly, visually check all connectionsfor fuel leaks. Preferably check the fittings during the warm-up periodwhen pressures are low. Visually inspect the fittings again at full speed, noload, and at full load. Do not attempt to correct leakage problems by tight-ening fittings and/or bolting while lines are fully pressurized. Note area inquestion and, depending on severity of leak, repair at next shutdown, orif required shut unit down immediately. Attempts to correct leakage prob-lem on pressurized lines could lead to sudden and complete failure of com-ponent and resulting damage to equipment and personnel injury.

a. Bleed fuel oil filters, if appropriate. Then check entire fuel system and the area immediatelyaround the fuel nozzle for leaks. In particular check for leaks at the following points:

UOGTDLN1–12

Turbine Compartment

(1) Fuel piping/tubing to fuel nozzle

(2) Fuel check valves

(3) Atomizing air manifold and associated piping (when used)

(4) Gas manifold and associated piping (when used)

Accessory Compartment or Fuel Module

(1) Flow divider (when used)

(2) Fuel and water pumps

(3) Filter covers and drains

CAUTION

Elimination of fuel leakage in the turbine compartmentis of extreme importance as a fire preventive measure.

WARNING

Do not attempt to correct leakage problems by tight-ening fittings and/or bolting while lines are pressur-ized. Note area in question and, depending on severityof leak, repair at next shutdown, or if required shutunit down immediately. Attempts to correct leakageproblem on pressurized lines could lead to sudden andcomplete failure of component and resulting damageto equipment and personnel injury.

b. Monitor FLAME status on the processor to verify all flame detectors are correctly indicatingflame. Two sight glasses are included as part of the unit startup kit. Use of sight glasses to be lim-ited to initial startup and special requirements, as opposed to normal operation. Following initialstartup remove sight glasses and plug opening.

c. Monitor the turbine control system readings on the processor for unusual exhaust thermocou-ple temperature, wheelspace temperature, lube oil drain temperature, highest to lowest exhausttemperature spreads and “hot spots” i.e. combustion chamber(s) burning hotter than all the others.

d. Listen for unusual noises and rubbing.

e. Monitor for excessive vibration.

UOGTDLN1–13

3. Automatic, Remote

On initial startup, permit the gas turbine to operate for a 30 to 60 minute period in a full speed, no loadcondition. This time period allows for uniform and stabilized heating of the parts and fluids. Tests andchecks listed below are to supplement those recorded in Control Specification — Control System Ad-justments. Record all data for future comparison and investigation.

a. Continue monitoring for unusual rubbing noises and shutdown immediately if noise persists.

b. Monitor lube oil tank, header and bearing drain temperatures continually during the heating peri-od. Refer to the Schematic Piping Diagram — Summary Sheets for temperature guidelines. Ad-just VTRs if required.

c. At this time a thorough vibration check is recommended, using vibration test equipment such asIRD equipment (IRD Mechanalysis, Inc.) or equivalent with filtered or unfiltered readings. It issuggested that horizontal, vertical and axial data be recorded for the:

(1) accessory gear (when used) forward and aft sides

(2) all accessible bearing covers on the turbine

(3) turbine forward compressor casing

(4) turbine support legs

(5) reduction gear (when used) forward and aft sides, gear and pinion

(6) bearing covers on the load equipment

d. Check wheelspace, exhaust and control thermocouples for proper indication on the CRT. Re-cord these values for future reference.

e. Flame detector operation should be tested per the Control Specification — Control System Ad-justments.

f. Utilize all planned shutdowns in testing the Overspeed Trip System per the Control Specifica-tions — Control System Adjustments. Refer to Special Operations section of this text.

g. Monitor CRT display data for proper operation.

III. OPERATING PROCEDURES

A. General

The following instructions pertain to the operation of a model series 5001, 6001, 7001EA or 9001E gasturbine unit designed for generator drive application. These instructions are based on use of Mark VSPEEDTRONIC turbine control panels.

Functional description of the CRT Main Display follows; however, panel installation, calibration, andmaintenance are not included.

UOGTDLN1–14

Operational information includes startup and shutdown sequencing in the AUTO mode of operation. Themost common causes of alarm messages can be found in the concluding section.

It is not intended to cover initial turbine operation herein; rather, it will be assumed that initial startup,calibration and checkouts have been completed. The turbine is in the cooldown or standby mode readyfor normal operation with AC and DC power available for all pumps, motors, heaters, and controls andall annunciator drops are cleared.

Refer to the Control Specifications in this volume, and the previously furnished Control Sequence Pro-gram (CSP) for additional operating sequence information and related diagrams.

B. Start-Up

1. General

Operation of a single turbine/generator unit may be accomplished either locally or remotely.

The following description lists operator, control system and machine actions or events in starting thegas turbine.

Reference the section “Description of Panels and Terms — Turbine Control Panel” for descriptionof turbine panel devices. The following assumes that the unit is off of cooldown, and in a ready to startcondition.

2. Starting Procedure

a. Using the cursor positioning device, select “MAIN” display from the DEMAND DISPLAYmenu.

(1) The display will indicate speed, temperature, various conditions etc. Three lines displayedon the CRT will read:

SHUTDOWN STATUS OFF COOLDOWN OFF

b. Select “AUTO” and “EXECUTE”

(1) The CRT display will change to:

STARTUP STATUS READY TO START AUTO

c. Select “START” and “EXECUTE”

(1) Unit auxiliaries will be started including a motor driven lube oil pump used to establish lubeoil pressure. The CRT message SEQ IN PROGRESS will appear.

UOGTDLN1–15

(2) If the starting clutch is not engaged, the rotor turning device will operate until the clutch en-gages. With the clutch engaged, the lube oil pressure and all other permissives satisfied, themaster protective logic (L4) will be satisfied. The CRT display will change to:

STARTUP STATUS STARTINGAUTO; START

(3) Where a diesel engine is utilized as starting equipment, the starting diesel will start and runat idle for two minutes to warm up. At the end of the diesel warmup period, the rotor turningdevice will operate continuously and the diesel will accelerate. Where an electric motor isutilized as starting equipment, the motor will start immediately.

(4) The turbine shaft will begin to rotate and accelerate. When the unit reaches approximately10 rpm, the turning device will be turned off. The CRT display will change to START-UPSTATUS/CRANKING. The zero speed signal “14HR” will be displayed.

(5) When the unit reaches approximately 20% speed, the minimum speed signal “14HM” willbe displayed on the CRT. (For machines with cooling water fan motors receiving powerfrom the generator terminals via the UCAT transformer, field flashing will be initiated to buildup generator voltage to power the fans; otherwise, field flashing to build up generator voltagewill occur at operating speed.)

(6) If the unit configuration requires purging of the gas path prior to ignition, the starting devicewill crank the gas turbine at purge speed for a period of time determined by the setting of thepurge timer. See Control Specifications-Settings Drawing for purge timer settings.

(7) FSR will be set to firing value. (FSR, Fuel Stroke Reference, is the electrical signal that deter-mines the amount of fuel delivered to the turbine combustion system.) Ignition sequence isinitiated. The CRT display will change to START UP STATUS/FIRING.

(8) When flame is established, the CRT display will indicate flame in those combustorsequipped with flame detectors.

(9) FSR is set back to warm-up value, and the CRT display will indicate STARTUP STATUS/WARMING UP. If the flame goes out during the 60 second firing period, FSR will be resetto firing value. (At the end of the ignition period, if flame has not been established, the unitwill remain at firing speed.) At this time the operator may shut the unit down or attempt tofire again. To fire again select CRANK on the Main Display. The purge timer and firing timerare reinitialized. The purge timer will begin to time. Reselecting AUTO will cause the igni-tion sequence to repeat itself after the purge timer has timed out. If the unit is being operatedremotely (REMOTE having previously been selected on the Main Display), and no fire hasbeen established at the end of the ignition period, the unit will be purged of unburned fuel.At the end of the purge period (normally 1 to 2 minutes) ignition will be attempted again. Ifflame is not established at this time, the starting sequence will be terminated and the unit willshutdown.

At the end of the warmup period, with flame established, FSR will begin increasing. The CRT will indicate STARTUP STATUS/ACCELERATING and the turbine will increase in

UOGTDLN1–16

speed. At approximately 50% speed, the accelerating speed signal “14HA” will be displayedon the CRT.

(10) The turbine will continue to accelerate. When it reaches about 60% speed, the starting devicewill disengage and shutdown (if the starting device is a diesel engine, it will cooldown at idlespeed before shutting down). The CRT will indicate the change in status from STARTUPCONTROL to SPEED CONTROL at approximately 60% speed.

(11) When the turbine reaches operating speed, the operating speed signal “14HS” will be dis-played on the CRT. The motor-driven lube oil pump will shutdown, since lube oil is beingsupplied by the shaft driven pump. Field flashing is terminated. If the synchronizing selectorswitch (43S) on the generator control panel is in the OFF position and REMOTE is not se-lected on the CRT, as the turbine reaches operating speed, CRT will now read:

RUN STATUSFULL SPEED NO LOAD AUTO; START

If the synchronizing selector switch on the generator panel is in the AUTO position or REMOTEis selected on the CRT automatic synchronizing is initiated. The CRT will readSYNCHRONIZING.

The turbine speed is matched to the system (to less than 1/3 Hz difference) and when the properphase relationship is achieved the generator breaker will close. The machine will load to SpinningReserve unless a load control point BASE, PEAK or PRESELECTED LOAD has been selected.

The CRT will display SPINNING RESERVE, once the unit has reached this load point.

C. Synchronizing

When a gas turbine-driven synchronous generator is connected into a power transmission system, thephase angle of the generator going on-line must correspond to the phase angle of the existing line voltageat the moment of its introduction into the system. This is called synchronizing.

CAUTION

Before initiating synchronization procedures, be surethat all synchronization equipment is functioning proper-ly, and that the phase sequence of the incoming unit cor-responds to the existing line phase sequence and the po-tential transformers are connected correctly to properphases. Initial synchronization and checkout after per-forming maintenance to synchronizing equipmentshould be performed with the breaker racked out.

Note: Synchronizing cannot take place unless AUTO or REMOTE has beenselected on the CRT Main Display and the turbine has reached fullspeed.

UOGTDLN1–17

Generator synchronization can be accomplished either automatically or manually. Manual synchroniza-tion is accomplished by the following procedure:

1. Place the synchronizing selector switch on the generator panel (43S) in the MANUAL position.

2. Select AUTO on the CRT Main Display.

3. Select START and EXECUTE on the CRT Main Display. This will start the turbine and accelerateit to full speed as previously described. At this point the CRT will indicate RUN STATUS, FULLSPEED NO LOAD.

4. Compare the generator voltage with the line voltage. (These voltmeters are located on the generatorcontrol panel.)

5. Make any necessary voltage adjustment by operating the RAISE- LOWER (90R4) switch on the gen-erator panel until the generator voltage equals the line voltage.

6. Compare the generator and line frequency on the synchroscope (located on the generator control pan-el). If the pointer is rotating counterclockwise, the generator frequency is lower than the line frequen-cy and should be raised by increasing the turbine-generator speed. The brightness of the synchroniz-ing lights will change with the rotation of the synchroscope. When the lights are their dullest thesynchroscope will be at the 12 o’clock position. The lights should not be used to synchronize but onlyto verify proper operation of the synchroscope.

7. Adjust the speed until the synchroscope rotates clockwise at approximately five seconds per revolu-tion or slower.

8. The generator circuit breaker “close” signal should be given when it reaches a point approximatelyone minute before the 12 o’clock position. This allows for a time lag for the breaker contacts to closeafter receiving the close signal.

Automatic synchronization is accomplished by the following steps:

1. Place the synchronizing selector switch (43S) in the AUTO position.

2. Select AUTO on the CRT Main Display.

3. Select START on the CRT Main Display.

This procedure will start the turbine, and upon attainment of “complete sequence”, match generator volt-age to line voltage (if equipped with optional voltage matching), synchronize the generator to the line fre-quency, and load the generator to the preselected value. A “breaker closed” indicator will actuate whenthe generator circuit breaker has closed placing the synchronized unit on-line.

Once the generator has been connected to the power system, the turbine fuel flow may be increased to pickup load, and the generator excitation may be adjusted to obtain the desired KVAR value.

UOGTDLN1–18

WARNING

Failure to synchronize properly may result in equip-ment damage and/or failure, or the creation of cir-cumstances which could result in the automatic re-moval of generating capacity from the power system.

In those cases where out-of-phase breaker closures are not so serious as to cause immediate equipmentfailure or system disruption, cumulative damage may result to the on-coming generator. Repeated occur-rences of out-of-phase breaker closures can eventually result in generator failure because of the stressescreated at the time of closure. Gear damage may result on load packages with a reduction gear in the gasturbine-generator train. Such damage may occur separately or in conjunction with generator damage fromout-of-phase breaker closure. Damage may be to the gear teeth or to the quill shaft (if there is a quill shaft).

Out-of-phase breaker closure of a magnitude sufficient to cause either immediate or cumulative equip-ment damage mentioned above will usually result in annunciator drops to notify the operator of the prob-lem. The following alarms have been displayed at various occurrences of known generator breaker mal-closures:

1. High vibration trip

2. Loss of excitation

3. Various AC undervoltage drops

Out-of-phase breaker closure will result in abnormal generator noise and vibration at the time of closure.If there is reason to suspect such breaker malclosure, the equipment should be immediately inspected todetermine the cause of the malclosure and for any damage to the generator and/or reduction gear.

Refer to the “Control and Protection” section of this volume for additional information on the synchroniz-ing system.

D. Normal Load Operation

1. Manual Loading

Manual loading is accomplished by clicking on the SPEED SP RAISE/SPEED SP LOWER targetson the CRT Main Display.

Manual loading can also be accomplished by means of the governor control switch (70R4/CS) on thegenerator control panel. Holding the switch to the right will increase the load; holding it to the leftwill decrease the load.

Manual loading beyond the selected temperature control point BASE or PEAK is not possible. Themanual loading rate is shown in the Control Specification-Settings Drawing.

Note: When manually loading with the governor control switch (70R4/CS)for load changes greater than 25% of full load, the operator should notchange more than 25% of full load in one minute.

UOGTDLN1–19

2. Automatic Loading

On startup if no load point is selected, the unit will load to the SPINNING RESERVE load point. TheSPINNING RESERVE load point is slightly greater than no load, typically 8% of base rating.

An intermediate load point, PRE-SELECTED load, and temperature control load points BASE andPEAK can be selected anytime after a start signal has been given. The selection will be displayed onthe CRT. The unit will load to the selected load point. PRESELECTED LOAD is a load pointgreater than SPINNING RESERVE and less than BASE, typically 50%. The auto loading rate isshown in Control Specification-Settings Drawing.

E. Remote Operation

To transfer turbine control from the control compartment to remotely located equipment, select REMOTEon the CRT Main Display. The turbine may then be started, automatically synchronized, and loadedby the remote equipment.

If manual synchronization is to be performed at the remote location, the synchronizing selector switch(43S) mounted on the generator control panel must be placed in the OFF/REMOTE position.

F. Shutdown and Cooldown

1. Normal Shutdown

Normal shutdown is initiated by selecting STOP on the CRT Main Display. The shutdown proce-dure will follow automatically through generator unloading, turbine speed reduction, fuel shutoff atpart speed and initiation of the cooldown sequence as the unit comes to rest.

2. Emergency Shutdown

Emergency shutdown is initiated by depressing the EMERGENCY STOP pushbutton. An emergencyshutdown can also be mechanically initiated by pushing the manual emergency trip valve on the gaugecabinet assembly, or the manual trip button on the overspeed trip mechanism mounted on the side ofthe accessory gear. Cooldown operation after emergency shutdown is also automatic provided thepermissives for this operation are met.

3. Cooldown

Immediately following a shutdown, after the turbine has been in the fired mode, the rotor is turnedto provide uniform cooling. Uniform cooling of the turbine rotor prevents rotor bowing, resultant rub-bing and imbalance, and related damage that might otherwise occur when subsequent starts are at-tempted without cooldown. The turbine can be started and loaded at any time during the cooldowncycle.

The cooldown cycle may be accelerated using the starting device; in which case it will be operatedat cranking speed. On units having an electric motor as the starting device, the operator must heedinstructions regarding the length of time the motor can be operated without overheating. Refer to thecontrol specifications.

UOGTDLN1–20

The device furnished for cooldown rotation on MS 5000 and MS 6001 units is the hydraulic ratchetwhich is mounted as part of the torque converter. The ratchet cycles once every 3.0 minutes to turnthe rotor 47°. A continuous rotor turning device is provided on MS 7001 and MS 9001 units. A de-scription of rotor turning operation and servicing can be found in the Starting System tab.

The minimum time required for turbine cooldown depends mainly on the turbine ambient tempera-ture. Other factors, such as wind direction and velocity in outdoor installations and air drafts in indoorinstallations, can have an affect on the time required for cooldown. The cooldown times recom-mended in the following paragraphs are the result of GE Company operating experience in both facto-ry and field testing of GE gas turbines. The purchaser may find that these times can be modified asexperience is gained in operation of the gas turbine under his particular site conditions.

Cooldown times should not be accelerated by opening up the turbine compartment doors or the lag-ging panels since uneven cooling of the outer casings may result in excessive stress.

The unit must be on rotor turning operation immediately following a shutdown for at least 24 hoursto ensure minimum protection against rubs and unbalance on a subsequent starting attempt. The GECompany, however, recommends that the rotor turning operation continue for 48 hours after shut-down to ensure uniform rotor cooling.

To terminate the cooldown sequence, prior to timer timeout select the Auxiliary Control Display onthe CRT. Select “RATCHET OFF”. This will cause the cooldown auxiliaries to be turned off. Sim-ilarly, by selecting the “RATCHET ON” target, the cooldown auxiliaries can be reinstated.

G. Special Operations

1. Black Start Operation(Optional with Gas Turbines equipped with a diesel engine starting device)

a. General

Gas turbine operation under “black start” conditions is defined as a requirement to start and runthe turbine when an external AC power source is not available. Diesel engines are normally uti-lized as starting equipment with other compatible steam or gas starting means optional.

The prime DC controlling power for the turbine control system is derived from the unit battery.

Ignition and internal AC control power is obtained through DC conversion circuitry within theSPEEDTRONIC power supply system.

b. Operation

When the turbine is started, the DC emergency lube pump will supply adequate lubrication untilthe accessory gear-driven main lube oil pump pressure is established. The emergency pump con-tinues to run until the accelerating speed signal (14HA) indicates that the unit has accelerated to50% speed. The emergency pump then shuts down if lube oil pressure switch (63QL) indicatesadequate pressure.

Black start operation also requires the addition of the 88HR DC hydraulic ratchet pump assembly.This unit furnishes the required hydraulic control oil pressure for operation of the starting clutchand ratchet assembly.

UOGTDLN1–21

For liquid fuel machines, fuel pressure delivered to the input of the turbine gear driven fuel pumpis provided by a dc/ac powered fuel forwarding pump. The DC motor drives the pump until ACpower is available to drive the AC motor. The turbine high pressure fuel oil requirements are satis-fied by the normal accessory gear driven fuel pump.

Gas turbine AC powered cooling system fan drive motors are operated from partial to full powerby driven load generator output, as the gas turbine is brought up to operational speed level.

During turbine shutdown and cooldown periods, the operational lube supply is again furnishedby the emergency DC lube pump and the 88HR DC hydraulic ratchet supply pump assembly men-tioned previously operates to turn the rotor.

Refer to the Lube Oil and Hydraulic Oil Supply Schematic Piping Diagrams; and the SPEED-TRONIC Control instructions of this service manual for further related information.

2. Fuel Transfer (Gas-Distillate Option)

Fuel transfer is initiated using the Fuel Mixture Display on the CRT. When transferring from onefuel to the other, there is a thirty second delay before the transfer begins. For the gas-to-distillate trans-fer, the delay allows for filling the liquid fuel lines. For the distillate-to-gas transfer, the delay allowstime for the speed ratio valve (and gas control valve) to modulate the inter volume gas pressure beforethe transfer begins. Once started, fuel transfer takes approximately thirty seconds. The transfer canbe stopped at any fuel mixture proportion within limits as specified in the Control Specification-Set-tings Drawing by setting the FUEL MIX SETPOINT and then selecting MIX. Fuel transfer shouldbe initiated prior to ignition or after the unit reaches operating speed.

3. Automatic Fuel Transfer On Low Gas Pressure (Gas-Distillate Option)

In the event of low fuel gas pressure the turbine will transfer to liquid fuel. The transfer will occurwith no delay for line filling. To return to gas fuel operation after an automatic transfer, manually rese-lect gas fuel.

4. Diesel Testing (Optional on MS 5001 and MS 6001 Units)

The starting diesel may be tested either with the turbine operating or while shutdown. To test the die-sel, first select the Auxiliary Control Display on the CRT. Select the “DIESEL TEST ON” target.The diesel can now be tested by operating the diesel test pushbutton located on the accessory base.The diesel will run at idle speed as long as the pushbutton is held in. (Do not exceed two (2) minutes.)

5. Jogging Turbine Rotor (MS 5001 and MS 6001 Units)

A pushbutton (43HR) located on the accessory base is provided for manual jogging of the turbineshaft by means of the hydraulic ratchet.

6. Testing the Emergency DC Lube Pump

The DC emergency pump may be tested using the test pushbutton on the motor starter.

UOGTDLN1–22

7. Overspeed Trip Checks

Overspeed trip system testing should be performed on an annual basis on peaking and intermittentlyused gas turbines. On continuously operated units, the test should be performed at each scheduledshutdown and after each major overhaul. All units should be tested after an extended shutdown periodof two or more months unless otherwise specified in the Control Specifications-Adjustments Draw-ings.

Note: The turbine should be operated for at least 30 minutes at rated speedbefore checking the overspeed settings. This will allow determinationof the actual trip speed, which might be higher or lower than the “cold”trip speed depending upon several contributing factors, such as oil tem-perature and vibration.

a. Electrical Overspeed

Turbine speed is controlled by the turbine speed reference signal TNR. The maximum speedcalled for by TNR is limited by the high speed stop control constant. This value is nominally setat 107% of rated speed. It will be necessary to enter a new constant value for the high speed stopconstant that will allow the speed to increase above the electrical overspeed trip setting. Newconstants can be entered with the Control Constant Adjust display activated and via the key-pad. Reference the control specification and the SPEEDTRONIC Mark V Maintenance Manu-al (GEH 5980) for details. For security, an identification code must be entered via the keypad inorder to make any changes to the control system constants. With the high speed stop constant ad-justed to be higher than the electrical overspeed trip speed, raise unit speed gradually by usingthe SPEED SP RAISE target on the Main Display and observe speed at which the unit tripsagainst the value tabulated in the Control Specifications — Setting drawing.

CAUTION

1. Do not exceed the maximum search speed as definedin the Control Specifications.

2. Return all constants to their normal value after coast-down of unit.

b. Mechanical Overspeed (if applicable)

In order to test the mechanical overspeed bolt it is necessary to change the electrical overspeedtrip setting constant to be greater than the mechanical overspeed bolt overspeed setting. Afterchanging the required constants raise unit speed gradually by using the SPEED SP RAISE targeton the Main Display and observe speed at which the unit trips against the value tabulated inthe Control Specifications — Settings drawing.


UOGTDLN1–23

CAUTION


2. Return all constants to their normal values followingtests.

3. Reset mechanical overspeed trip mechanism on unitaccessory gear.

Record all trip speeds. Mechanical testing should also include the emergency trip button on theturbine control panel and the manual overspeed mechanical trip located on the right side of theaccessory gear. Successful completion of the above tests will assure that all shutdown devices areoperating correctly.

To reduce the possibility of overspeed bolt trip system degradation where the trip speed becomesexcessively high, especially after long periods of inactivity, it is recommended that the mechani-cal bolt be tested periodically by carefully overspeeding the turbine and noting the speed at whichthe trip occurs. If the trip does not occur within the limits, as defined in the Control Specifications,the bolt should be sparingly oiled in place with a lightweight machine oil, stroked by manuallydepressing the plunger several times through its stroke limits, and retested. The overspeed boltshould then be tripped three successive times within 1% of nominal trip speed and within 1% re-peatability unless defined otherwise in the Control Specifications.

CAUTION


2. The turbine should not be operated unless the over-speed bolt, the overspeed trip mechanisms, the fuelstop valves and other shutdown devices are in reliablecondition.

If a trip does not occur within reliable limits, refer to the adjustment instructions in the ServiceManual, Protection System, Overspeed Bolt Assembly. If three successive trips do not occurwithin acceptable repeatability limits, see instructions for Maintenance and Replacement or con-tact your Field Service Representative for assistance.

8. Steam Injection Operation (Optional)

Before operating the steam injection system for the first time following an overhaul or periods of ex-tended shutdown, it is important that the following checks be made:

a. Steam supply is within design parameters

b. Instrument air supply is at required pressure

c. Steam line orifice size is correct

UOGTDLN1–24

a. Pre-Operation Checks

Prior to operation, check for the following conditions:

a. CRT controls are in non-select positions (Steam Injection OFF)

b. Manual stop valve is open

c. All hand valves in line of flow are open

d. All valves to temperature or pressure gauges are open

e. Steam supply pressure and temperature are in operating range

b. Startup

The automatic control system, in conjunction with logic circuits of the microcomputer of theSPEEDTRONIC control system, operates the steam injection system control valving and as-sures that the proper amount of steam injection is provided to the turbine combustion system dur-ing operation.

To initiate steam injection the operator must first select the Steam Injection Overview Displayon the CRT. Selecting the STM INJ ON target initiates the steam injection control. At thispoint the automatic steam control circuits will take over, initiate the drain and stop valve se-quences and control the system. When steam conditions are correct, the steam control valve re-leases steam into the combustion system at the proper steam-to-fuel flow ratio.

The startup and operating sequence of the steam injection system is described and explained inthe Steam Injection control system text of the Control and Protection Tab.

c. Trouble Shooting

The purpose of the system is to provide steam to the turbine combustion system at the desiredpressure, temperature and flow. If this does not happen, the following problems may be the cause:

(1) Steam supply exhausted

(2) Insufficient supply pressure

(3) Control valve closed

(4) Stop valve closed

The following should be checked:

(1) Adequate steam supply

(2) Check steam supply system

(3) Check control valve actuator and drain valve operation

UOGTDLN1–25

(4) Check that instrument air supply pressure is sufficient and/or check solenoid control valveoperation.

Alarm and shutdown conditions of the steam injection system are detected by a protection pro-gram built into Control Sequence Program. Alarm and trip indications are displayed on the CRT. An alarm condition is initiated by high or low pressure levels and by high or low tempera-tures. See Control Specifications for alarm and trip point values.

The computer program is designed to trip the steam stop valve and prevent steam flow if steamtemperature becomes too high or too low. It can trip the system on temperature or pressure to pro-tect against loss of superheat and carry over of condensate. Steam at too high a pressure can causedamage to valve stem packing and system seals. A steam injection trip only shuts down the steaminjection system. It does not trip the turbine.

9. DLNx I System Operation

a. General

The Dry Low NOx system has been designed to function normally without operator input. It doesnot effect the normal running of the unit, but does require an understanding of the system for prop-er operation.

The Dry Low NOx I (DLNx I) control system regulates the distribution of fuel delivered tostaged, multi-nozzle combustors located around the gas turbine.

The fuel flow distribution to the combustion chamber fuel nozzles is determined as a functionof a calculated turbine firing temperature signal (TTRF) in the SPEEDTRONIC controller. Thelocation of the combustor flame is controlled by changing the fuel flow distribution.

b. Gas Fuel Operation

There are four basic modes of distributing gas fuel to the DLNx combustor which are describedbelow:

(1) Primary

Fuel and combustion are only in the primary zone. The typical firing temperature TTRF rangefor this mode is from startup ignition through full speed no load to approximately 1500°F.

(2) Lean-Lean

Fuel and combustion are in both the primary and secondary zones. Typical firing tempera-tures for the Lean-Lean mode are between 1500°F and 1950°F.

(3) Secondary

All fuel and combustion occur in the secondary zone of the combustor. A typical firing tem-perature for this mode is 1900°F.


UOGTDLN1–26

(4) Premix

In this mode, fuel is in both the primary and secondary zones, with combustion only occurringin the secondary zone. Basically, air and a majority of the fuel are mixed in the primary zoneand flow into the secondary zone to be burned in an effort to reduce NOx exhaust emissions.The typical firing temperature range for this mode of operation is above 1900°F.

The gas turbine will startup in Primary mode and accelerate to full speed. After synchronizationto the electrical power grid, the turbine will continue to load up in the Primary combustion modeuntil about TTRF = 1550°F. At this point, the control system will initiate fuel flow into the Sec-ondary combustion zone and the Lean-Lean mode of operation will be established.

Lean-Lean operation continues through the load range until approximately TTRF = 1900°F. Atthis point, the control system will transition the combustor through the Secondary mode, in orderto extinguish the flame in the primary zone, and will readmit fuel into the Primary zone withoutburning which is the Premix mode of operation.

Using the “Lean-Lean Base” select, the combustor can be operated in the Lean-Lean mode aboveTTRF = 1900°F. This mode is called Extended Lean-Lean. Choosing this mode bypasses the tran-sition into the Premix mode of operation. The consequence of operating in Extended Lean-Leanis that the turbine exhaust emissions will contain higher levels of NOx and unburned hydrocar-bons.

Unloading of the gas turbine with the DLNx I system from Base Load progresses from the Premixmode through the Lean-Lean mode to Primary mode. Primary mode is held through generatorbreaker opening until turbine shutdown.

During Premix operation, an upset or disturbance in the combustion system may cause flame topropagate from the secondary burning zone back into the fuel/air flow stream in the primary zone.This phenomena, called “flashback,” will light off the primary zone and force the combustor intoan Extended Lean-Lean mode. The control system is designed to react to such disturbances andsound off an alarm “Extended Lean-Lean — High Emission Levels.” Note that this alarm doesnot annunciate when “Lean-Lean Base” is selected.

If the combustor is operating in the Extended Lean-Lean mode and Premix operation is desired,the turbine must first be lowered in load until the firing temperature TTRF is below approximate-ly 1820°F. This measure is required to reset certain permissives in the DLNx I control for Premixtransfer. These permissives are required because the transfer from Lean-Lean to Premix can onlybe performed through a designated window in the turbine operating region. The Control Specifi-cations should be consulted to determine the firing temperature TTRF required for Premix Trans-fer for a particular unit.

c. DLNx I Inlet Guide Vane Operation

The DLNx I combustor emission performance is sensitive to changes in fuel to air ratio. TheDLNx combustor was designed according to the airflow regulation scheme used with Inlet GuideVane (IGV) Temperature Control. The IGVs remain at a fixed minimum value (typically 57 Deg)from full speed no load until the turbine exhaust temperature reaches the exhaust temperaturecontrol curve. The IGVs open from their minimum value as the turbine increases load while onthe exhaust temperature control curve until they reach a maximum (typically 84 Deg) at BaseLoad.


UOGTDLN1–27

The DLNx I system must be operated with IGV Temperature Control selected “on.” Logic in thecontrol panel software has been developed to default IGV Temperature Control in the “on” state,but the operator should check this during startup.

d. Liquid Fuel Operation (If applicable)

DLNx I liquid fuel operation is limited to the Primary and Lean-Lean modes of combustion. Theunit will startup and load up from full speed no load in Primary mode. A transition to the Lean-Lean mode will be made at an approximate firing temperature of 1600°F by diverting a portionof the liquid fuel to the Secondary combustion zone. Liquid fuel operation will occur in the Lean-Lean mode with approximately a 50/50 primary to secondary fuel split distribution above TTRF= 1600°F until Base Load.

e. Gas Fuel Transfer Manifold Purge System

The design of the diffusion style gas fuel transfer nozzle in the DLNx I combustor requires thatthe nozzle be purged with a steady flow of compressor discharge air whenever gas fuel is not di-verted through the transfer nozzle manifold. A lack of transfer nozzle purge flow can seriouslydamage the fuel nozzle tip.

WARNING

A complete and routine checkout of the gas fuel trans-fer purge system operation should be performed bythe operator.

The transfer purge system is designed with redundant measures to avoid the hazardous conditionof gas fuel mixing with compressor discharge air. The transfer purge system is a normally open(purge air flowing) system that uses two shutoff valves to turn off the purge flow. Each of thesevalves has two redundant limit switches to indicate valve position. In between the transfer purgeshutoff valves is a solenoid operated valve connected to a vent line which is used to port any leak-age past the shutoff valves to a safe atmospheric vent. An interstage pressure switch located be-tween the shutoff valves is also provided to indicate excessive line pressure when the vent lineshould be open.

Control logic is designed into the SPEEDTRONIC software to detect potential failures in thetransfer purge system. Alarms and protective actions are also built into the software to ensure thesafe operation of this system. The operator should pay particular attention to any annunciatedalarms concerning the gas fuel transfer purge given the serious ramifications of a failure to thissystem.

f. DLNx Inlet Heating (if applicable)

Operation of the gas turbine with reduced minimum IGV settings (typically less than 57 Deg) canbe used to extend the Premix operating region to lower loads. Reducing the minimum IGV angleallows the combustor to operate at near a constant firing temperature high enough to support Pre-mix operation while maintaining a sufficient fuel to air ratio.


UOGTDLN1–28

Inlet heating through the use of recirculated compressor discharge airflow is necessary when op-erating with reduced IGV angles in order to protect the turbine compressor. Inlet heating protectsthe turbine compressor from stall by relieving the discharge pressure and by increasing the inletair stream temperature. Also, inlet heating prevents ice formation due to increased drop acrossthe reduced angle IGVs.

The DLNx Inlet heating system regulates compressor discharge bleed flow through a controlvalve and into a manifold located in the compressor inlet air stream. The control valve varies theinlet heating air flow as a function of the IGV angle. At minimum IGV angles the inlet bleed flowis controlled to a maximum of 5% of the total compressor discharge flow. As the IGVs are openedat higher loads, the inlet bleed flow is turned down linearly until shutoff.

The inlet bleed heat control valve is monitored for its ability to track the command setpoint. Ifthe valve command setpoint differs from the actual valve position by a prescribed amount for aperiod of time, an alarm will annunciate to warn the operator. If the condition persists for an ex-tended amount of time, the inlet bleed heat system will be tripped and the IGVs will be reset totheir normal schedule.

The inlet bleed heat system also looks to detect a temperature rise in the compressor inlet airflowas an indication of flow when the control valve is opened. Failure to detect a sufficient tempera-ture rise in a set amount of time will cause the inlet bleed heat system to be tripped and an alarmannunciated to alert the operator.

g. DLNx I Display Messages

The following display messages will appear on the SPEEDTRONIC control panel CRT in orderto inform the operator of the current combustion mode of operation:

Primary Mode

Lean-Lean Mode Pos

Lean-Lean Mode Neg

Lean-Lean Ext. Mode

Secondary Transfer

Secondary Load Recovery

Premix Transfer

Premix Steady State

h. DLNx I System Annunciator Troubleshooting Chart

The following is a list of typical alarms and corrective action procedures for a gas turbine suppliedwith DLNx I and related systems. This list is intended to supplement the annunciator trouble-shooting chart contained in the standard gas turbine operating procedures instruction book ar-ticles.


UOGTDLN1–29

Alarm Message Cause Action

Gas Splitter ValveControl Trouble

GSV command setpoint dif-ferent from actual position.

Examine GSV for sticky op-eration, jamming and LVDTtrouble

Gas Splitter ValvePosition Trouble

GSV position servo looptrouble.

Examine GSV servovalveand LVDTs for proper operation.

Gas Spitter ValveTrouble — Trip

GSV command setpoint dif-ferent from actual positionfor extended period.

Examine GSV for sticky op-eration, jamming and LVDTtrouble.

Gas Transfer ValveControl Trouble

GTV command setpoint dif-ferent from actual position.

Examine GTV for sticky op-eration, jamming and LVDTtrouble.

Gas Transfer ValvePosition Trouble

GTV position servo looptrouble.

Examine GTV servovalveand LVDTs for proper operation.

Gas Transfer ValveTrouble — Trip

GTV command setpoint dif-ferent from actual positionfor extended period.

Examine GTV for sticky op-eration, jamming, and LVDTtrouble.

Failure to Flame OutPrimary Zone — Alarm

Unable to extinguish the Primary Zone flame duringthe transfer from Lean-Leanto Premix.

Investigate the GSV forproper seating and shut off ofthe Primary valve cage.

Failure to Leave SecondaryTransfer — Trip

System bogged down in Secondary mode while trans-ferring from Lean-Lean toPremix.

Investigate the GSV forproper seating and shut off ofthe Primary valve cage.

Extended Lean-Lean Mode High Emissions

Unexpected Lean-Lean modeoperation at high loads possi-bly due to flashback.

Excessive flashbacks couldindicate combustion systemtrouble — Investigate ex-haust temp. spreads and otherindications of potential com-bustion hardware damage.

Failure to Reignite Primary Zone — Alarm

Possible failure of ignitionsystem or flame detectionsystem during Primary zonereignition.

Check ignition exciters,spark plugs and flame detectors.

Failure to ReignitePrimary Zone — Trip

Failure of ignition system orflame detect. system duringPrimary zone reignition.

Check ignition exciters,spark plugs and flame detectors.

Failure to Reignite Primaryin Sec Load Recovery —Alarm

Possible failure of ignitionsystem or flame detectionsystem during SecondaryLoad Recovery mode.

Check ignition exciters,spark plugs, and flame detectors.


UOGTDLN1–30

Alarm Message ActionCause

Failure to Reignite Primaryin Sec Load Recovery —Trip

Failure of ignition system orflame detect. system duringSecondary Load Recoverymode.

Check ignition exciters,spark plugs, and flame detectors.

Gas Transfer Purge ValveFailure to Close

Transfer purge valve stuck orfaulty limit switch indication.

Inspect transfer purge valvesand limit switches.

Gas Transfer Purge ValveFailure to Open

Transfer purge valve stuck orfaulty limit switch indication.

Inspect transfer purge valvesand limit switches.

Gas Transfer Purge SystemPressure High

Transfer purge valve leak,blocked vent line, or faultypressure switch indication.

Examine transfer purgevalves, interstage pressureswitch setting, purge vent solenoid valve and vent lineconnection.

Loss of CPD Transducers —Trip

Failure of two or more com-pressor discharge pressuretransducers (96CD-1, 1B,1C).

Check compressor disch.pressure transducers andsensing lines.

i. DLNx I Liquid Fuel Additional Alarms (if applicable):


Liquid Fuel Splitter ValveFailure to Open

Liquid fuel splitter valvestuck or faulty limit switch.

Examine liquid fuel splittervalve and limit switch operation.

Liquid Fuel Splitter ValveFailure to Close

Liquid fuel splitter valvestuck or faulty limit switch.

Examine liquid fuel splittervalve and limit switch operation.

j. Inlet Bleed Heating Additional Alarms (if applicable):


Bleed Heat Valve Not Tracking — Alarm

Inlet bleed heat control valvestuck or faulty position feed-back transmitter.

Inspect the control and theposition transmitter for proper operation.

Bleed Heat System Not Operational — Trip

Control valve stuck closed orfaulty inlet thermocouplereadings.

Observe the control valvestoke and check the inletthermocouples.

No Inlet Heating Airflow —Trip

Control valve stuck closed orfaulty inlet thermocouplereadings. Manual stop valveclosed.

Observe the control valvestoke and check the inletthermocouples. Open manualstop valve.

UOGTDLN1–31

10. Water Washing System Operation (Optional)

a. General

Water washing should be scheduled during a normal shutdown, if possible. This will allowenough time for the internal machine temperature to drop to the required levels for the washing.The time required to cool the machine can be shortened by maintaining the unit at crank speed.During this cooling of the turbine, the wash water is to be heated to the proper level.

b. Mandatory Precautions

Before water washing of the compressor begins, the turbine blading temperature must be lowenough so that the water does not cause thermal shock.

CAUTION

The differential temperature between the wash water andthe interstage wheelspace temperature must not be great-er than 120°F (48.9°C) to prevent thermal shock to thehot gas parts. For wash water of 180°F (82.2°C), the max-imum wheelspace temperature must be no greater than300°F (148.9°C) as measured by the digital thermocou-ple readout system on the turbine control panel.

To reduce this difference, the wash water may be heated and the turbine kept on crank until thewheelspace temperatures drop to an acceptable level. The wheelspace temperatures are read inthe control room on the CRT.

CAUTION

If, during operation, there has been an increase in exhausttemperature spread above the normal 15°F to 30°F (8.3°Cto 16.6°C), the thermocouples in the exhaust plenumshould be examined. If they are coated with ash, the ashshould be removed.

Radiation shields should also be checked. If they are notradially oriented relative to the turbine, they should be re-positioned per the appropriate drawing. If the thermo-couples are coated with ash, or if the radiation shields arenot properly oriented, a correct temperature reading willnot be obtained.

If neither of the above conditions exists and there is no other explanation for the temperaturespread, consult the GE Installation and Service Engineering representative.

UOGTDLN1–32

WARNING

The water wash operation involves water under highpressure. Caution must be exercised to ensure theproper positioning of all valves during this operation.Since the water may also be hot, necessary precau-tions should be taken in handling valves, pipes, andpotentially hot surfaces.

Note: Before water washing the compressor, inspect the inlet plenum and gasturbine bellmouth for large accumulations of atmospheric contami-nants which could be washed into the compressor. These deposits canbe removed by washing with a garden hose.

c. Water Wash Procedures

Refer to cleaning publication included in this section for details on procedure.

11. Standby Gas Turbines on Extended Shutdown

The GE Company recommends the following procedures for gas turbines subject to extended shut-downs.

a. The turbine rotor should be operated on turning gear or ratchet for one hour each day to preventthe buildup of corrosive deposits in the turbine wheel dovetails, OR

b. The gas turbine should be operated at full speed, no load for one hour per week to dry the turbineout and thereby preventing moisture condensation in the turbine wheel dovetail crevices.

IV. DESCRIPTION OF PANELS AND TERMS

A. Turbine Control Panel (TCP)

The turbine control panel contains the hardware and software required to operate the turbine.

EMERGENCY STOP (5E) — This red pushbutton is located on the front of the TCP. Operation of thispushbutton immediately shuts off turbine fuel.

BACKUP OPERATOR INTERFACE (BOI) — This interactive display is mounted on the front of theTCP. All operator commands can be issued from this module. In addition, alarm management can be per-formed and turbine parameters can be monitored from the <BOI>.

B. CRT

The CRT is a personal computer that directly interfaces to the turbine control panel. This is the primaryoperator station. All operator commands can be issued from the CRT. Alarm management can be per-formed and turbine parameters can be monitored. With the proper password, editing can also be accom-plished.


UOGTDLN1–33

1. Main Display

Operator selector targets and master control selector targets can be actuated from the main displayby using the cursor positioning device (CPD). Operator selector targets include:

OFF — Inhibits a start signal.

CRANK — With crank selected, a start signal will bring the machine to cranking speed (14HM).

FIRE — With FIRE selected, a START signal will bring the machine to minimum speed and establishflame in the combustors. Selecting FIRE while the machine is on CRANK will initiate the firing se-quence and establish flame in the combustors.

AUTO — With AUTO selected, a START signal will bring the machine to operating speed. Changingselections from FIRE to AUTO will allow the machine to accelerate to operating speed.

REMOTE — With REMOTE selected, control for the unit is transferred to the remote control equip-ment.

Master control selector targets include:

START — A START selection will cause the unit to start. With AUTO selected, the unit will load tothe SPINNING RESERVE load point.

FAST START - A FAST START selection will cause the unit to start. With AUTO selected, the unitwill load to the PRESELECTED load point. The machine will load at the manual loading rate.

STOP - A STOP selection will cause the unit to initiate a normal shutdown.

All operator selector switches and master control selector targets are green and are located on the rightside of the display. All green targets are the AUTO/EXECUTE type, which means that the target mustbe selected with the CPD and then, within three seconds, the EXECUTE target at the bottom of thedisplay must also be selected in order to actuate that command.

2. Load Control Display

Load selector targets can be actuated from the load control display by using the cursor positioningdevice (CPD). Load selector targets include:

PRESEL - Select the preselected load point.

BASE - Select base temperature control load point.

*PEAK - Select peak temperature control load point.

3. *Fuel Mixture Display

Fuel selector targets are used to select the desired fuel by using the cursor positioning device (CPD).Fuel selector targets include:

*Optional equipment


UOGTDLN1–34

GAS SELECT - 100% gas fuel operation.

DIST SELECT - 100% distillate fuel operation.

MIX SELECT - Selecting MIX while on 100% single fuel will cause the machine to transfer to mixedfuel operation at a preset mixture.

4. *Isochronous Setpoint Display

Governor selector targets are used to select the desired type of speed control by using the cursor posi-tioning device (CPD). Governor selector targets include:

DROOP SELECT - Used to select droop speed control.

ISOCH SELECT - Used to select isochronous speed control.

5. *Inlet Guide Vane Control Display

The inlet guide vane (IGV) temperature control targets are IGV TEMP CNTL ON and IGV TEMPCNTL OFF. The IGV AUTO target selects normal operation of the IGVs. The IGV MANUAL targetallows the maximum IGV angle to be manually set by the operator (not normally used while on-line).

6. Alarm Display

This screen displays the current un-reset alarms, the time when each alarm occurred, the alarm dropnumber and a word description of the alarm. An “*” indicates that the alarm has not been acknowl-edged. The “*” disappears after the alarm has been acknowledged. For more information, see theMark V Users’ Manual (GEH 5979).

7. Auxiliary Display

COOLDOWN ON and COOLDOWN OFF can be selected from this display. The DIESEL TEST ONand DIESEL TEST OFF targets (if diesel starting means is used) can also be selected from this display.Selecting the DIESEL TEST ON target enables the permissive which allows the Diesel Test Pushbut-ton to be manually operated.

8. *Mechanical Overspeed Test Display

After selecting the ENABLE SOFTSW’s target, the OVERSPEED TEST HP target can be selected.This will adjust the electrical overspeed setpoint to allow testing of the mechanical overspeed equip-ment.

9. Manual Reset Target

Selecting the manual reset target resets the Master Reset Lockout function. This target must be se-lected so that the unit can be restarted following a trip.

*Optional equipment

UOGTDLN1–35

C. Definition of Terms

SPINNING RESERVE - The minimum load control point based on generator output. The spinning reservemagnitude in MWs can be found in the control specifications (5–10% of rating is a typical value).

PRESELECTED LOAD - A load control point based on generator output. The preselected load point isadjustable within a range designated in the Control Specification. The preseelected load point is normallyset below the base load point (50–60% of rating is a typical value).

BASE LOAD - This is the normal maximum loading for continuous turbine operation as determined byturbine exhaust temperature levels.

PEAK LOAD (Optional) - This is the maximum allowable output permitted for relatively long-duration,emergency power requirement situations consistent with acceptable turbine parts life. Peak loading dura-tion is based on turbine exhaust temperature levels.

D. Generator Control Panel (Typical)

SYNCHRONIZING LAMPS — Rough indication of the speed and phase relationship between the gen-erator and the bus.

FREQUENCY METER — Indicates generator frequency.

INCOMING VOLTMETER — Indicates generator voltage.

RUN VOLTMETER — Indicates bus voltage.

SYNCHROSCOPE — Indicates the phase relationship between the generator and bus voltage.

GENERATOR AMMETER — Indicates generator phase current. The phase current to be read is se-lected on the three position ammeter selector switch.

GENERATOR WATTMETER — Indicates the generator output in megawatts.

GENERATOR VARMETER — Indicates the generator reactive output in megavars.

GENERATOR TEMPERATURE METER — (Traditionally included on the Generator Control Panel,but actually displayed in Mark V SPEEDTRONIC systems on the CRT.) Reads the generator Resis-tance Temperature Detector (RTD) selected by the temperature meter selector switch.

EXCITER VOLTMETER — Indicates generator field voltage (if used).

GENERATOR FIELD AMMETER — Indicates generator field amperes (if used).

AMMETER SELECTOR SWITCH — See Generator Ammeter (above).

SYNCHRONIZING SELECTOR SWITCH (43S/CS) — Three position switch used to select the syn-chronizing mode.

Manual — Selects manual synchronizing mode. In this position the generator frequency and voltage, busvoltage, and phase relationship will be displayed to facilitate manual synchronizing.

UOGTDLN1–36

Off/Remote — Used when the unit is being controlled from the remote control equipment.

Auto — Used for local automatic synchronizing.

VOLTMETER SWITCH (VS) — Used to select the phase of the bus voltage to be displayed on the runvoltmeter.

TEMPERATURE METER SELECTOR SWITCH — Traditionally included on the Generator Con-trol Panel, but actually displayed in Mark V SPEEDTRONIC systems on the CRT.

VOLTAGE/VAR CONTROL SWITCH (90R4/CS) — Controls generator voltage when the unit is offthe line, and controls voltage/vars when the machine is on the line. (Increase — Right; Decrease — Left;spring return to normal.)

GENERATOR BREAKER CONTROL SWITCH (52G/CS) — Used to open or close the generatorbreaker. The indicator lights above the switch indicate Open (Green) and Closed (Red).

Note: Using this switch, the generator breaker should be closed only whenproper synchronizing techniques are used or when the system ontowhich the generator is being brought is not energized.

GENERATOR DIFFERENTIAL LOCK-OUT SWITCH (86G) — Manual reset lockout switchwhich operates in the event of a generator fault.

GOVERNOR RAISE/LOWER CONTROL SWITCH (70R4/CS) — Used to control turbine speedwhen the generator is off the line (i.e. for manual synchronizing); generator load when the generator ison the line; and frequency when the generator is running isolated and on DROOP speed control.

TRANSFORMER DIFFERENTIAL LOCK-OUT SWITCH (86T) — Manual reset lockout switchwhich operates in the event of a transformer fault.

WATTHOUR METER — Measures the watthour output of the generator.

E. Motor Control Center

The turbine is provided with a motor control center for the control of the electrical auxiliaries. The motorcontrol center includes AC and DC distribution systems.

Motor controllers are used for auxiliaries such as motors and heaters. Each motor controller normally con-sists of a breaker, control power transformer, control circuit, power contactor, selector switch and indica-tor lights. The selector switch is normally left in AUTO. Each motor control center is also provided withAC and DC distribution panel boards with circuit breakers.

F. Supervisory Remote Equipment

Supervisory equipment is normally functionally the same as the equipment described in the cable con-nected master panel. However, it may differ somewhat in metering and indications. Refer to the superviso-ry manufacturer’s instruction manual for details.

UOGTDLN1–37

G. Annunciator System

Alarms are displayed on the CRT when the ALARM Display mode is selected. Before clearing analarm, action should be taken to determine the cause and perform the necessary corrective action. The fol-lowing is a list of annunciator messages along with suggested operator action.

Note: The alarm messages can be categorized as either “trip” or “alarm”.The “trip” messages contain the word TRIP in the message. The“alarm” messages do not indicate TRIP. For those alarms associatedwith permissive to start and trip logics latched up through the MAS-TER RESET function, it will be necessary to call up the CRT Dis-play with the Master Reset target in order to unlatch and clear thesealarms.

UNLESS OTHERWISE SPECIFIED NAMES DATE GENERAL ELECTRIC COMPANY DIMENSIONS ARE IN MM [INCHES] TOLERANCES ON:

DRAWN

THIRION F. 03 OCT 01 g GE Energy Products – Europe

1 [2] PL DECIMALS + CHECKED

JOST JM. 03 OCT 01

2 [3] PL DECIMALS + APPROVED

ANCEL T. 03 OCT 01 NOMEMCLATURE DES APPAREILS DE CONTROLE ANGLES + DIAGRAM. SCHEMA. P.P. – DEVICE SUMMARY FRACTIONS + FIRST MADE FOR : 9E : ITEM 0414 WEIGHT : 0000 kg SIZE CAGE CODE DWG NO

A 372A8094 INDEX SIM TO: SCALE SHEET 1

SIZE DWG NO SH REV A 372A8094 1 C

REVISIONS REV DESCRIPTION DATE SIGNATURES

A First Issue THIRION F. 03 OCT 01 JOST JM. 03 OCT 01 ANCEL T. 03 OCT 01

B IM-2002003364 TCA DW-NG 03 JUI 02 THIRION F. 03 JUI 02 JEZEQUEL

M 03 JUI 02

C IM-2002003561 ROUSSEL A. 15 JUI 02 THIRION F. 15 JUI 02 JEZEQUEL

M 15 JUI 02

SECTION NO. OF SHEETS

REV

INDEX 3 C 01F 7 C 01E 7 C

ITEM DESCRIPTION DWG. NO. LIST OF COMPLEMENTARY DOCUMENTS

First made for : MS9001E ITEM : 0414

ISO PROJECTION

EACH SECTION SHALL BE REVISED IN ITS ENTIRETY. ALL SHEETS OF EACH SECTION ARE THE SAME REVISION LEVEL AS INDICATED IN THE REVISION BLOCK.

This document, exclusive property of GE Energy Products France SNC

is strictly confidential. It must not be communicated, copied or reproduced without our prior written consent.

Ce document, propriété exclusive de GE Energy Products France SNC

est strictement confidentiel. Il ne peut être communiqué,copié ou reproduit sans notre autorisation

écrite préalable.

GENERAL ELECTRIC COMPANY SIZE CAGE CODE DWG NO

g GE Energy Products - Europe A 372A8094

DRAWN THIRION F. SECTION INDX SCALE SHEET 2


NOMENCLATURE DES SCHEMAS ET DES TUYAUTERIES

DEVICE SUMMARY - PIPING SYSTEMS SCHEMATIC

DESIGNATION (FRANCAIS) ITEMS SYS. NUMEROS DESCRIPTION (ENGLISH)

SYMBOLES NOMENCLATURE APPAREILLAGE 0414 372A8094 SYMBOLS - DEVICE SUMMARY

SCHEMA APPAREILS DE PROTECTION T.G. 0415 CD 356B2601 DIAGRAM, CONT DEVICES - TURBINES

SCHEMA TUY. HUILE DE GRAISSAGE 0416 LO 202D8427 DIAGRAM, SCHEM P.P. LUBE OIL

SCHEMA TUY. AIR REFROIDT ET ETANCHETTE 0417 CSA 239C7408 DIAGRAM, SCHEM P.P. CLG - SLG AIR

SCHEMA TUY. HUILE DE CONTROLE 0418 TO 91-316352 DIAGRAM, SCHEM P.P. TRIP OIL

SCHEMA TUY. EAU DE REFROIDISSEMENT 0420 CW 360B1319 DIAGRAM, SCHEM P.P. COOLING WATER

SCHEMA MOTEUR DE LANCEMENT 0421 SM 356B2630 DIAGRAM, SCHEM P.P. STARTING MEANS

SCHEMA TUY. COMBUSTIBLE GAZ 0422 GF 356B2265 DIAGRAM, SCHEM P.P. FUEL GAS

SCHEMA TUY COMBUSTIBLE LIQUIDE 0424 LF DIAGRAM, SCHEM P.P. LIQ. FUEL

SCHEMA TUY. AIR ATOMISATION 0425 AA DIAGRAM, SCHEM P.P. ATOMIZING AIR

SCHEMA PROTECTION INCENDIE 0426 FP 356B2647 DIAGRAM, SCHEM P.P. FIRE PROTECT

SCHEMA TUY. RECHAUFF. AIR ASPIRATION 0432 IAR 239C7268 DIAGRAM, SCHEM P.P INLET AIR REHEATING

SCHEMA TUY. ALIMENTATION HUILE HP 0434 HS 356B2725 DIAGRAM, SCHEM P.P. HYDR. SUPPLY

SCHEMA CHAUFF. ET VENTIL. COMPT. TG AUX 0436 HV 91-313088 DIAGRAM, FLOW-HEATING - VENT

SCHEMA NETTOYAGE COMPRESSEUR ET TURBINE 0441 TCC DIAGRAM, SCHEM P.P. TURB & CPRSR CLN

SCHEMA LAVAGE COMPRESSEUR TURBINE 0442 TCW 356B2267 DIAGRAM, SCHEM P.P. TURB - CPRSR WSHG

SCHEMA NETTOYAGE COMPRESSEUR 0443 CC DIAGRAM, SCHEM P.P. - CPRSR CLN

SCHEMA TUY. INJECTION D'EAU TG 0461 WI DIAGRAM, SCHEM P.P. WATER INJ. GT

SCHEMA TUY. INJECTION D'EAU TG 0462 WI DIAGRAM, SCHEM P.P. WATER INJ. GT

SCHEMA COMMANDE AUBES VARIABLES 0469 IGV 91-242B9854 DIAGRAM, SCHEM P.P. I.G.V.

SCHEMA DETECTION GAZ 0474 HGD 91-317644 DIAGRAM, SCHEM GAZ DETECTOR

SCHEMA PURGE TUY. COMBUSTIBLE 0477 FPU 91-315296 DIAGRAM, SCHEM P.P. FUEL PURGE

SCHEMA PURGE TUY. COMBUSTIBLE 0495 FPU DIAGRAM, SCHEM P.P. FUEL PURGE

-SYMBOLES UTILISES DANS LES SCHEMAS ET TABLEAUX -LEGEND FOR DESCRIPTION OF MISCELLANEOUS ABBREVIATIONS AND SYMBOLS APPEARING ON LISTED DRAWINGS DESIGNATION ABBR DESCRIPTION DESIGNATION ABBR DESCRIPTION

DRAWN THIRION F. SECTION INDX SCALE SHEET 3


CONTACT ADDITIONNEL NC AVEC POINT COMMUN ELECTRIQUE

CEC ADDITIONAL CONTACT NC ELECTRICALLY COMMON

AIR D'ATOMISATION AA ATOMIZING AIR

CONTACT ADDITIONNEL NC AVEC CONTACT ELECTRIQUEMENT SEPARE

CES ADDITIONAL CONTACT NC ELECTRICALLY SEPARATE

AIR SORTIE COMPRESSEUR AD COMPRESSOR DISCHARGE AIR

CONTACT ADDITIONNEL NO AVEC POINT COMMUN ELECTRIQUE

OEC ADDITIONAL CONTACT NO ELECTRICALLY COMMON

AIR D'EXTRACTION AE EXTRACTION AIR

CONTACT ADDITIONNEL NO AVEC CONTACT ELECTRIQUEMENT SEPARE

OES ADDITIONAL CONTACT NO ELECTRICALLY SEPARATE

MANOMETRE- PRESSION DIFFERENTIELLE

DPG DIFFERENTIAL PRESSURE GAUGES.

CROISSANT INC INCREASING COMBUSTIBLE GAZEUX GF GAS FUEL NORMALEMENT FERME NC NORMALLY CLOSED EVENT DE GAZ GFV GAS FUEL VENT NORMALEMENT OUVERT NO NORMALLY OPEN FUITE AUX GARNITURES

VANNE COMBINEE GAZ GPL GAS VALVE STEM

PACKAGING LEAKOFF NORMALEMENT DESENGAGE

ND NORMALLY DISENGAGED HUILE DE REGULATION HP OH CONTROL OIL HIGH PRESSURE

NORMALEMENT RETRACTE NR NORMALLY RETRACTED HUILE DE SECURITE HP OHT TRIP OIL HIGH PRESSURE SIMPLE CONTACT SIMPLE POLE

SPST SIMPLE POLE SIMPLE THROW

HUILE DE GRAISSAGE OL LUBE OIL

TRANSFORMATEUR DIFFERENTIEL ROTATIF DE POSITION

RVDT ROTARY VARIABLE DIFFERENTIAL TRANSFORMER-POSITION TRANSMIT

EVENT D' HUILE DE GRAISSAGE

OLV LUBE OIL EVENT

TRANSMETTEUR POSITION TRANSF.DIF.LINEAIRE

LVDT LINEAR VARIABLE DIFFERENTIAL TRANSFORMER (POSITIONTRANSMIT)

HUILE DE GRAISSAGE MODULEE

OR REGULATED LUBE OIL

DIFFERENTIEL NON REGLABLE

D DIFFERENTIAL NOT ADJUSTABLE

RACCORDEMENT CLIENT PC PURCHASER CONN.

VANNE 2 VOIES (2) 2 WAY (VALVE) EGOUTTURES D'EAU WD WATER DRAIN VANNE 3 VOIES (3) 3 WAY (VALVE) ALIMENTATION D'EAU WR WATER FEED DECROISSANT DEC DECREASING RETOUR D'EAU WR WATER RETURN PLUS GRAND QUE > GREATER THAN RETOUR D' HUILE OD OIL DRAIN PLUS PETIT QUE < LESS THAN DOUBLE CONTACT

DOUBLE POLE DPDT DOUBLE POLE DOUBLE

THROW VALEUR DE MOINDRE IMPORTANCE

( ) NUMBER IS OF SECONDARY IMPORTANCE

BOUCHON X--- PLUGGED TAP

PRESSION AVAL FILTRE PRINCIPAL HUILE

AMF LUBE OIL FILTER DOWNSTREAM PRESSURE

PRESSION AMONT FILTRE PRINCIPAL HUILE

BMF LUBE OIL FILTER UPSTREAM PRESSURE

PRESSION AVAL FILTRE HUILE CONTROLE

ACF CONTROL FILTER DOWNSTREAM PRESSURE

PRESSION AMONT FILTRE HUILE CONTROLE

BCF CONTROL FILTER UPSTREAM PRESSURE

PRESSION AVAL FILTRE HUILE HYDRAULIQUE

AHF1-2

HYDRAULIC FILTER DOWNSTREAM PRESSURE

PRESSION AMONT FILTRE HYDRAULIQUE HUILE

BHF1-2

HYDRAULIC FILTER UPSTREAM PRESSURE

RETOUR HUILE AU-DESSUS DU NIVEAU CUVE A HUILE

OD

OIL DRAIN ABOVE LEVEL IN OIL TANK

RETOUR HUILE AU-DESSOUS DU NIVEAU CUVE A HUILE

OD

OIL DRAIN BELOW LEVEL IN OIL TANK



DRAWN THIRION F. SECTION 01F SCALE SHEET 1


SYSTEME SYMBOLE DESIGNATION 20CB-1 1071

0417 CSA

ELECTROVANNE 3 VOIES POUR COMMANDE VANNE ANTI POMPAGE COMPRESSEUR NORMAL= B VERS C OUVERT ; A FERME

20FG-1 0991

0418 TO

ELECTROVANNE D'ARRET COMBUSTIBLE GAZEUX NORMAL = OUVERT

20PG-3,4 0991

0477 FPU

ELECTROVANNE PURGE SYSTEME COMBUSTIBLE GAZ NORMAL = 1 VERS 3:OUVERT -2:FERME

20TH-1 A037

0432 IAR

ELECTROVANNE COMMANDE VANNE VA20-1 POUR SOUTIRAGE AIR COMPRESSEUR ACTIVE POUR FERMETURE DE VA20-1

20TU-1 0605

0421 SM

ELECTROVANNE DE DECHARGE CONVERTISSEUR DE COUPLE NORMAL = OUVERT

20TV-1 1019

0418 TO

ELECTROVANNE DE COMMANDE DES AUBES A OUVERTURES VARIABLES NORMAL = OUVERT

20TW-1 0953

0442 TCW

ELECTROVANNE LAVAGE COMPRESSEUR OFF LINE

20TW-3 0953

0442 TCW

ELECTROVANNE LAVAGE COMPRESSEUR ON LINE

20VG-1 0991

0422 GF

ELECTROVANNE EVENT COMBUSTIBLE GAZEUX NORMAL = OUVERT

20VG-3 0991

0477 FPU

ELECTROVANNE EVENT(PURGE)COMBUSTIBLE GAZ NORMAL = FERME

23CR-1to3 0603

0421 SM

RESISTANCES CHAUFFANTES DANS MOTEUR DE LANCEMENT 240 V – 150 W

23HQ-1 0628

0434 HS

RESISTANCE ANTI-CONDENSATION MOTEUR 88 HQ-1

23QA-1 1006

0416 LO

RESISTANCE ANTI-CONDENSATION MOTEUR 88 QA-1

23QT-1,2 0938

0416 LO

RESISTANCES DE CHAUFFAGE CUVE A HUILE 10,2 KW – 400 V - 3 PH - 50 Hz

23TG-1 0538

0421 SM

RESISTANCE ANTI-CONDENSATION MOTEUR 88 TG-1

23TK-1,2 1233

0417 CSA

RESISTANCE ANTI-CONDENSATION MOTEUR 88 TK

26CR-1to3 0603

0421 SM

SONDE A RESISTANCE(C.T.P.) DANS MOTEUR DE LANCEMENT

28FD-14P,14S 1121

0415 CD

DETECTEUR FLAMMES-CHAMBRE DE COMBUSTION N°14 ETAT LOGIQUE:1=PAS DE FLAMME,0=FLAMME SORTIE LOGIQUE DIRECTEMENT DANS ARMOIRE SPEEDTRONIC

28FD-1P,1S 1121

0415 CD

DETECTEUR FLAMMES-CHAMBRES DE COMBUSTION N°1 ETAT LOGIQUE:1=PAS DE FLAMME;0=FLAMME SORTIE LOGIQUE DIRECTEMENT DANS ARMOIRE SPEEDTRONIC

28FD-2P,2S 1121

0415 CD

DETECTEUR FLAMMES-CHAMBRES DE COMBUSTION N°2 ETAT LOGIQUE:1=PAS DE FLAMME;0=FLAMME SORTIE LOGIQUE DIRECTEMENT DANS ARMOIRE SPEEDTRONIC

28FD-3P,3S 1121

0415 CD

DETECTEUR FLAMMES-CHAMBRE DE COMBUSTION N°3 ETAT LOGIQUE:1=PAS DE FLAMME,0=FLAMME SORTIE LOGIQUE DIRECTEMENT DANS ARMOIRE SPEEDTRONIC

33BQ-1 1044

0417 CSA

FIN DE COURSE SOUTIRAGE AIR ETANCHEITE PALIER LE FIN DE COURSE EST TOUJOURS FERME AVEC LA VA14 DANS LA POSITION SOUTIRAGE 5e ETAGE

33CB-1to4 1022

0417 CSA

FIN DE COURSE VANNE ANTI-POMPAGE 11eme ETAGE COMPRESSEUR VANNE OUVERTE : FIN DE COURSE ACTIONNE , CONTACT FERME

33PG-5,7 0991

0477 FPU

FIN DE COURSE VANNE PURGE SYSTEME COMBUSTIBLE GAZ NORMAL =(2) NC-OES FERME QUAND VANNE OUVERTE

33PG-6,8 0991

0477 FPU

FIN DE COURSE VANNE PURGE SYSTEME COMBUSTIBLE GAZ NORMAL =(2) NO-CES OUVERT QUAND VANNE OUVERTE

33TC-1 0605

0421 SM

FIN DE COURSE POSITION VANNE DE GAVAGE CONVERTISSEUR DE COUPLE AU REPOS,20TU = 0,FIN DE COURSE ACTIONNE, CONTACT FERME

33TH-3 A037

0432 IAR

FIN DE COURSE SUR VANNE ISOLATION SOUTIRAGE AIR COMPRESSEUR VM15-1 CONTACT FERME QUAND VANNE VM15-1 PLEINE OUVERTURE

33TH-4 A037

0432 IAR

FIN DE COURSE SUR VANNE ISOLATION SOUTIRAGE AIR COMPRESSEUR VA30-1 CONTACT FERME QUAND VANNE VA30-1 TOTALEMENT FERMEE

33TM-5 0605

0421 SM

FIN DE COURSE:POSITION AUBES CONVERTISSEUR DE COUPLE - LIMITEUR COUPLE MAXI CONTACT S'OUVRE SUR DEPASSEMENT COUPLE MAXI EN COURSE MINI NORMAL = NC-OEC

33TM-6 0605

0421 SM

FIN DE COURSE:POSITION AUBES CONVERTISSEUR DE COUPLE - LIMITEUR COUPLE MAXI. CONTACT S'OUVRE SUR DEPASSEMENT COUPLE MAXI EN COURSE MINI NORMAL = NC-OEC





SYSTEME SYMBOLE DESIGNATION 33VG-1 0991

0422 GF

FIN DE COURSE SUR ELECTROVANNNE 20VG-1 FIN DE COURSE ACTIONNE CONTACT FERME NORMAL = NO CES

39V-1A,1B 1218

0415 CD

CAPTEUR DE VIBRATION PALIER 1 TEMP. 375°C MAX. VOLTAGE DE SORTIE A 25,4 mm/s = 150 mv CRETE

39V-2A 1218

0415 CD

CAPTEUR DE VIBRATION PALIER 2 TEMP. 375°C MAX. VOLTAGE DE SORTIE A 25,4 mm/s =150 mv CRETE

39V-3A,3B 1218

0415 CD

CAPTEUR DE VIBRATION PALIER 3 TEMP. 375°C MAX. VOLTAGE DE SORTIE A 25,4 mm/s = 150 mv CRETE

39VS-11,12 0235

0415 CD

CAPTEURS SANS CONTACT X,Y -PALIER 1

39VS-31,32 1160

0415 CD

CAPTEURS SANS CONTACT X,Y -PALIER 3

43TW-1/PB 1105

0442 TWC

BOUTON POUSSOIR:COMMANDE VANNE MOTORISEE (20TW-1) LAVAGE COMPRESSEUR

45FA-1A,1B 1104

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT AUXILIAIRE INC FERME = 316±5°C - NORMAL = NO SPST

45FA-2A,2B 1104

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT AUXILIAIRE. INC FERME = 316±5°C - NORMAL = NO SPST

45FA-6A,6B 0991

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT GAZ INC FERME = 316±5°C - NORMAL = NO SPST

45FT-1A,1B 1103

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT TURBINE INC FERME = 316±5°C - NORMAL = NO SPST

45FT-2A,2B 1154

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT TURBINE. INC FERME = 316±5°C - NORMAL = NO SPST

45FT-3A,3B 1154

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT TURBINE INC FERME = 316±5°C - NORMAL = NO SPST

45FT-8A,8B 1160

0426 FP

DETECTEUR D'INCENDIE TUNNEL PALIER DIFFERENT DE 3 INC FERME = 510±5°C - NORMAL = NO SPST

45FT-9A,9B 1160

0426 FP

DETECTEUR D'INCENDIE COMPARTIMENT DE PUISSANCE INC FERME = 316±5°C - NORMAL = NO SPST

45HA-4to6 0991

0474 HGD

DETECTEUR GAZ COMPARTIMENT GAZ ALARME : 5% DE LA L.I.E DECLENCHEMENT : 8% DE LA L.I.E

45HT-1to3 1154

0474 HGD

DETECTEUR GAZ COMPARTIMENT TURBINE ALARME : 5% DE LA L.I.E DECLENCHEMENT : 8% DE LA L.I.E

5E-1,2 1104

0426 FP

BOUTON D'ARRET D'URGENCE

63GQ-1 0991

0422 GF

PRESSION DIFFERENTIELLE FILTRE ENTREE GAZ INC OPEN :1,51±0,07

63HF-1 0926

0434 HS

PRESSION DIFFERENTIELLE FILTRE HYDRAULIQUE H.P.(ALARME) DEC FERME = 2,75±1,03 BARS INC OUVERT = 4,13±0,20 BARS NORMAL =NC-OEC

63HG-1to3 0991

0418 TO

MANOSTAT DE PRESSION D' HUILE DE DECLENCHEMENT POUR VANNE D'ARRET COMBUSTIBLE GAZEUX INC FERME = 1,65± 0,14 BARS DEC OUVERT = 1,4±0,07 BARS NORMAL = NO CEC

63HQ-1 0926

0434 HS

PRESION BASSE ALIMENTATION CIRCUIT HUILE HP (DEMARRAGE POMPE AUX. HP.) INC FERME = 100±3,10 BARS DEC OUVERT = 93,11±1,72 BARS NORMAL =NO-CEC

63PG-2 0991

0477 FPU

PRESSION SYSTEME VANNE DE PURGE DEC OUVERT = 2,75±0,13 BARS INC FERME = 3,10±0,13 BARS NORMAL =(2) NO-CEC

63QA-2 0926

0416 LO

PRESSION BASSE HUILE DE GRAISSAGE (DEMARRAGE POMPES AUX.) INC FERME = 3,10±0,14 BARS DEC OUVERT = 2.8±0,07 BARS NORMAL =NO-CEC

63QQ-1 0926

0416 LO

PRESSION DIFFERENTIELLE FILTRE PRINCIPAL HUILE DE GRAISSAGE DEC FERME = 0,9±0,2 BARS INC OUVERT = 1,03± 0,068 BARS NORMAL =NC-OEC

63QQ-8 0916

0416 LO

PRESSION DIFFERENTIELLE FILTRE CONVERTISSEUR DE COUPLE INC OUVERT = 1.5 BARS

63QT-2A ALTERNATEUR

0416 LO

MANOSTAT DE BASSE PRESSION D'HUILE DE LUBRIFICATION COTE ALTERNATEUR INC FERME = 0,62±0,035 BARS DEC OUVERT = 0,55± 0,021 BARS NORMAL = NO CEC

63QV-1 A098

0416 LO

MANOSTAT DIFFERENTIEL ENCRASSEMENT FILTRE COALESOEUR NORMAL NO FERMETURE 80MBAR ALARME POUR FERMETURE A DEFINIR

63TK-1,2 A053

0417 CSA

MANOSTAT DE PRESSION AIR REFFROIDISSEMENT CORPS TURBINE ET CADRE ECHAPPEMENT FERME : AU-DESSUS DE 381±76 mm H20 NORMAL = NO CEC

65EP-3 A037

0432 IAR

TRANSDUCTEUR ELECTRO-PNEUMATIQUE ETAT DENTREE 4mA POUR VANNE VA20-1 PLEINE OUVERTURE

65GC-1 0541

0422 GF

SERVO VALVE POUR VANNE CONTROLE GAZ DEBIT:0,0315 L/SEC A 69 BARS ALIMENTATION HUILE DE CONTROLE:103,4 BARS

65GD-1 0568

0422 GF

SERVOVANNE VANNE TRANSFERT GAZ (3 ENROULEMENTS) DEBIT:0,063 L/SEC A 69 BARS FLUIDE:HUILE HP A 83 BARS





SYSTEME SYMBOLE DESIGNATION 65GS-1 0565

0422 GF

SERVOVANNE SPLITTER VANNE GAZ(3 ENROULEMENTS) DEBIT:0,063 L/SEC A 69 BARS FLUIDE:HUILE HP A 83 BARS

71QH-1 1038

0416 LO

NIVEAU HAUT HUILE DE GRAISSAGE ALARME VOIR SCHEMA HUILE DE GRAISSAGE(ML ITEM 0416) NORMAL =NC-OEC

71QL-1 1038

0416 LO

NIVEAU BAS HUILE DE GRAISSAGE ALARME VOIR SCHEMA HUILE DE GRAISSAGE(ML ITEM 0416) NORMAL =NO-OEC

77HT-1to3 0546

0415 CD

CAPTEUR DE VITESSE. SITUE SUR PALIER N°1 JEUX:1,27±0,12 mm

77NH-1to3 0546

0415 CD

CAPTEUR DE VITESSE SITUE SUR PALIER N°1 JEUX:1,27±0,12 mm

77RP-11 0235

0415 CD

REPERE DE PHASE

88CR-1 0603

0421 SM

MOTEUR DE LANCEMENT TG 1000KW –2975 TR/MN -11500 V -50 Hz

88HQ-1 0628

0434 HS

MOTO-POMPE AUXILIAIRE HUILE HP 15 KW –1450 TR/MN -400 V -3 PH -50 Hz

88QA-1 1006

0416 LO

MOTO-POMPE AUXILIAIRE HUILE DE GRAISSAGE 90 KW –2960 TR/MN -400 V -3 PH -50 Hz

88QE-1 1007

0416 LO

MOTO-POMPE DE SECOURS HUILE DE GRAISSAGE 7,5 KW –1750 TR/MN -125 V -DC

88QV-1 A098

0416 LO

MOTO VENTILATEUR (MIST ELIMINATOR) 18.5 KW - MULTI TENSION 3 PHASES -MULTI FREQUENCE ETURE 80MBAR

88TG-1 0538

0421 SM

MOTEUR DE VIRAGE TG 30 KW –725 TR/MN -400 V -3 PH -50 Hz

88TK-1,2 1233

0417 CSA

MOTEUR-VENTILATEUR REFROIDISSEMENT CORPS T.G. ET CADRE ECHAPPEMENT 45 KW –2900 TR/MN -400 V -3 PH -50 Hz

88TM-1 0605

0421 SM

MOTEUR CONVERTISSEUR DE COUPLE 1,5 KW –3000 TR/MN -400 V -50 Hz

90SR-1 0541

0422 GF

SERVO-VALVE VANNE D'ARRET DETENTE GAZ DEBIT:0,315 L/SEC A 69 BARS ALIMENTATION HUILE DE CONTROLE:103,4 BARS

90TH-4 A037

0432 IAR

MOTEUR COMMANDE VANNE DE PURGE SUR ENTREE SOUTIRAGE AIR COMPRESSEUR 120V AC 50/60 HZ ALIMENTATION VA20-1 PLEINE A FOURNIR

90TV-1 0540

0469 IGV

SERVO VALVE COMMANDE DES AUBES VARIABLES ENTREE AIR DEBIT:0,315 L/SEC A 69 BARS ALIMENTATION HUILE DE CONTROLE:103,4 BARS

95SG-11 1213

0415 CD

TRANSFORMATEUR POUR BOUGIE D'ALLUMAGE 95SP-11

95SG-12 1213

0415 CD

TRANSFORMATEUR POUR BOUGIE D'ALLUMAGE 95SP-12

95SP-11 1214

0415 CD

BOUGIE D'ALLUMAGE CHAMBRE N°11

95SP-12 1214

0415 CD

BOUGIE D'ALLUMAGE CHAMBRE N°12

96AP-1 0557

0415 CD

TRANSMETTEUR PRESSION ATMOSPHERIQUE 0,8 - 1,2 BARS

96BD-1 0557

0415 CD

TRANSMETTEUR PRESSION DIFFERENTIELLE AIR CORPS ADMISSION 0 - 0,311 BARS

96BH-1 A037

0432 IAR

TRANMETTEUR DE PRESSION AMONT VANNE CONTROLE VA20-1 CAPACITE 0-20,69 BARG AJUSTEMENT SUR CONDITION SORTIE TRANSMETTEUR. ZERO 0 BARG 4 +/- 0,2 mA "ZERO" MAXI 20,69 BARG 20 +/- 0,2 mA "GAIN"

96BH-2 A037

0432 IAR

TRANMETTEUR DE PRESSION AVAL VANNE CONTROLE VA20-1 CAPACITE 0-10,35 BARG AJUSTEMENT SUR CONDITION SORTIE TRANSMETTEUR. ZERO 0 BARG 4 +/- 0,2 mA "ZERO" MAXI 10,35 BARG 20 +/- 0,2 mA "GAIN"

96CD-1A 0557

0417 CSA

TRANSMETTEUR PRESSION ECHAPPEMENT COMPRESSEUR ECHELLE 0-20,7 BARS ZERO 0 BAR - 4mA MAXI 20,7 BARS - 20mA

96CD-1B 0557

0417 CSA


96CD-1C 0557

0417 CSA


96CS-1 0557

0415 CD

TRANSMETTEUR PRESSION ENTREE D'AIR 0 – 12,45 m BARS

96FG-2A 0991

0422 GF

TRANSMETTEUR PRESSION COMBUSTIBLE GAZ ECHELLE 0-34.5 ±0 BARS ZERO 0 BAR - 0±0,01V MAXI 34.5 BARS - 5±0,01V

96FG-2B 0991

0422 GF

TRANSMETTEUR PRESSION COMBUSTIBLE GAZ ECHELLE 0-34.5 ±0 BARS ZERO 0 BAR - 0±0,01V MAXI 34.5 BARS -5±0,01V





SYSTEME SYMBOLE DESIGNATION 96FG-2C 0991

0422 GF

TRANSMETTEUR PRESSION COMBUSTIBLE GAZ ECHELLE 0-34.5 ±0 BARS ZERO 0 BAR - 0±0,01V MAXI 34.5 BARS - 5±0,01V

96FG-3 0991

0422 GF

TRANSMETTEUR PRESSION ENTREE COMBUSTIBLE GAZ ECHELLE 0-25 BARS ZERO 0 BAR 4 mA "ZERO" MAXI 25 BARS 20 mA "GAIN"

96GC-1,2 0509

0422 GF

L.V.D.T. VANNE DE REGLAGE GAZ COURSE 44-45mm

96GD-1,2 0567

0422 GF

LVDT VANNE TRANSFERT GAZ COURSE:50,8 mm

96GS-1,2 0564

0422 GF

LVDT SPLITTER VANNE GAZ-COURSE:57,15 mm

96QA-2 0926

0416 LO

TRANSMETTEUR DE PRESSION HUILE DE LUBRIFICATION SORTIE VPR2 ECHELLE 0-7 BARS ZERO 0 BAR 4 mA "ZERO" MAXI 7 BARS 20 mA "GAIN"

96QT-2A ALTERNATEUR

0416 LO

TRANSMETTEUR DE PRESSION HUILE DE LUBRIFICATION COTE ALTERNATEUR ECHELLE 0-5 BARS ZERO 0 BAR - 4mA "ZERO" MAXI 5 BARS - 20mA "GAIN"

96SR-1,2 0507

0422 GF

L.V.D.T. VANNE D'ARRET ET DETENTE GAZ COURSE 88,67mm (+1;-0)

96TH-1 A037

0432 IAR

TRANMETTEUR POSITION VANNE DE COMMANDE SOUTIRAGE AIR COMPRESSEUR 4 +/- 0.2 mA = 0.0% 20 +/- 0,2 mA = 100%

96TM-1 0605

0421 SM

TRANSMETTEUR DE POSITION DES AUBES CONVERTISSEUR DE COUPLE ZERO : COUPLE MINIMUM : 0% - 4mA MAXI : COUPLE MAXIMUM : 100% - 20mA

96TV-1,2 0548

0469 IGV

L.V.D.T.COMMANDE DES AUBES VARIABLES ENTREE AIR

96VC-11,12 0235

0415 CD

CAPTEURS SANS CONTACT BUTEE

AH1-1,2 0502

0434 HS

ACCUMULATEUR SUR HUILE DE CONTROLE CAPACITE :9,5 L PRECHARGE:51,7 BARS

AH1-3,4 0991

0422 GF

ACCUMULATEUR SUR HUILE DE CONTROLE CAPACITE UNITAIRE:10 L PRECHARGE:42 BARS FONCTION:FOURNIR UNE CAPACITE D'APPOINT

AT_LC-1 0637

0436 HV

TEMPERATURE COMPARTIMENT PUISSANCE RESISTANCE THERMOMETRIQUE

AT_TC-1 0637

0436 HV

TEMPERATURE COMPARTIMENT TURBINE RESISTANCE THERMOMETRIQUE

BT_J1-1A,1B 0235

0415 CD

THERMOCOUPLE COUSSINET PALIER 1 TURBINE

BT_J1-2A,2B 0235

0415 CD

THERMOCOUPLE COUSSINET PALIER 1 TURBINE.

BT_J2-1A,1B 0235

0415 CD


BT_J2-2A,2B 0235

0415 CD


BT_J3-1A,1B 0235

0415 CD


BT_J3-2A,2B 0235

0415 CD


BT_TA1-2A,2B 0235

0415 CD

T.C.MATIERE BUTEE PALIER 1 TURBINE

BT_TA1-5A,5B 0235

0415 CD


BT_TA1-8A,8B 0235

0415 CD


BT_TI1-2A,2B 0235

0415 CD

T.C.MATIERE CONTRE-BUTEE PALIER 1 TURBINE

BT_TI1-5A,5B 0235

0415 CD

T.C.MATIERE CONTRE-BUTEE PALIER 1 TURBINE.

BT_TI1-9A,9B 0235

0415 CD

T.C.MATIERE CONTRE-BUTEE PALIER 1 TURBINE.

CT_BD-1 A037

0432 IAR

THERMOCOUPLE TEMPERATURE SOUTIRAGE AIR COMPRESS. TYPE K - THERMOCOUPLE CHROMEL/ALUMEL

CT_DA-1,2 0637

0415 CD

TEMPERATURE SORTIE COMPRESSEUR THERMOCOUPLE TYPE K

CT_IF-1,2 0637

0415 CD

TEMPERATURE ENTREE COMPRESSEUR THERMOCOUPLE TYPE K

CT_IF-3/R 0637

0415 CD

RESISTANCE THERMOMETRIQUE TEMPERATURE ENTREE COMPRESSEUR





SYSTEME SYMBOLE DESIGNATION FA2-1 0991

0477 FPU

FILTRE AIR COMMANDE BALAYAGE GAZ

FG-1 0929

0422 GF

FITRE ALIMENTATION GAZ FILTRATION NOMINAL 1,5 MICRONS

FH14-1 0564

0422 GF

FILTRE ALIMENTATION HYD.SPLITTER VANNE FILTRATION:15 MICRONS

FH15-1 0567

0422 GF

FILTRE ALIMENTATION HYD.VANNE TRANSFERT FILTRATION:15 MICRONS

FH2-1,2 0908

0434 HS

FILTRE SUR HUILE H.P. FILTRATION:0,5 MICRONS

FH6-1 0905

0469 IGV

FILTRE SUR ALIMENTATION EN HUILE H.P. DES IGV FILTRATION:40 MICRONS (ELEMENT FILTRANT EN METAL FRITTE)

FH7-1 0991

0422 GF

FILTRE SUR ALIMENTATION EN HUILE H.P. DES VANNES GAZ FILTRATION:40 MICRONS (ELEMENT FILTRANT EN METAL FRITTE)

HM3-1 0548

0469 IGV

SYSTEME COMMANDE AUBES VARIABLES - VERIN DOUBLE ACTION REGLAGE VERIN POUR 34°-2° A 84+2° SUR LES VIGV

LT_B1D-1A,1B 0637

0416 LO

TEMPERATURE RETOUR D'HUILE PALIER 1 THERMOCOUPLE TYPE K

LT_B2D-1A,1B 0637

0416 LO


LT_B3D-1A,1B 0637

0416 LO


LT_BT1D-1A,1B 0637

0416 LO

TEMPERATURE RETOUR D'HUILE BUTEE PALIER 1 THERMOCOUPLE TYPE K

LT_G1D ALTERNATEUR

0416 LO

TEMPERATURE RETOUR D'HUILE PALIER 4 THERMOCOUPLE TYPE K ALTERNATEUR

LT_G2D ALTERNATEUR

0416 LO

TEMPERATURE RETOUR D'HUILE PALIER 5 THERMOCOUPLE TYPE K ALTERNATEUR

LT_OT-1A 0938

0416 LO

TEMPERATURE BASSE CUVE A HUILE RESISTANCE THERMOMETRIQUE

LT_OT-2A 0938

0416 LO

TEMPERATURE NORMALE CUVE A HUILE RESISTANCE THERMOMETRIQUE

LT_TH-1A,1B 0637

0416 LO

TEMPERATURE COLLECTEUR HUILE DE LUBRIFICATION THERMOCOUPLE TYPE K .

LT_TH-2A,2B 0637

0416 LO

TEMPERATURE COLLECTEUR HUILE DE LUBRIFICATION. THERMOCOUPLE TYPE K.

LT_TH-3A,3B 0637

0416 LO

TEMPERATURE COLLECTEUR HUILE DE LUBRIFICATION. THERMOCOUPLE TYPE K

MG1-1 0513

0422 GF

INJECTEUR COMBUSTIBLE GAZ PRIMAIRE

MG1-2 0513

0422 GF

INJECTEUR COMBUSTIBLE GAZ-SECONDAIRE

MG1-3 0513

0422 GF

INJECTEUR COMBUSTIBLE GAZ-TRANSFERT

PH1 0627

0434 HS

POMPE HYDRAULIQUE PRICIPALE ATTELEE AU REDUCTEUR DES AUXILLIAIRES DEBIT :65 L/MN A 105 BARS-1422 TR/MN

PH2 0627

0434 HS

POMPE AUXILIAIRE HUILE HP DEBIT :45,4 L/MN A 105 BARS -1450 TR/MN ENTRAINEE PAR MOTEUR ELECTRIQUE 88 HQ

SLI-1,2 1104

0426 FP

AVERTISSEUR LUMINEUX

TT_IB-1 0637

0415 CD

TEMPERATURE TUNNEL PALIER 3 THERMOCOUPLE TYPE K

TT_WS1AO-1,2 0637

0415 CD

TEMPERATURE APRES 1ere ROUE TURBINE (EXTERIEUR) THERMOCOUPLE TYPE K

TT_WS1FI-1,2 0637

0415 CD

THERMOCOUPLES AVANT 1ere ROUE TURBINE (INTERIEUR) THERMOCOUPLE TYPE K

TT_WS2AO-1,2 0637

0415 CD

TEMPERATURE APRES 2eme ROUE TURBINE (EXTERIEUR) THERMOCOUPLE TYPE K

TT_WS2FO-1,2 0637

0415 CD

TEMPERATURE AVANT 2eme ROUE TURBINE (EXTERIEUR) THERMOCOUPLE TYPE K

TT_WS3AO-1,2 0637

0415 CD

TEMPERATURE APRES 3eme ROUE TURBINE (EXTERIEUR) THERMOCOUPLE TYPE K

TT_WS3FO-1,2 0637

0415 CD

TEMPERATURE AVANT 3eme ROUE TURBINE (EXTERIEUR) THERMOCOUPLE TYPE K





SYSTEME SYMBOLE DESIGNATION TT_XD-1to24 0623

0415 CD

TEMPERATURE ECHAPPEMENT TURBINE THERMOCOUPLE TYPE K

VA13-3,4 0991

0477 FPU

VANNE SYSTEME PURGE COMBUSTIBLE GAZ ACTIONNE PAR AIR VENANT DE 20PG

VA14 1044

0417 CSA

VANNE ETANCHEITE AIR PALIER NORMAL: .OUVERT DU 11e ETAGE VERS PALIERS .5e ETAGE FERME

VA17-1 1026

0442 TCW

VANNE FAUX DEPART VIDANGE CARTER DES CHAMBRES NORMAL = OUVERT

VA17-2 1026

0442 TCW

VANNE DE FAUX DEPART VIDANGE CADRE ECHAPPEMENT NORMAL = OUVERT

VA20-1 A037

0432 IAR

VANNE DE CONTROLE SOUTIRAGE AIR CONNEXION BRIDE 8" ANSI

VA2-1to4 1022

0417 CSA

VANNES ANTI-POMPAGE COMPRESSEUR 11eme ETAGE NORMAL = OUVERT

VA30-1 A037

0432 IAR

VANNE DE PURGE SOUTIRAGE AIR COMPRESSEUR CONNEXION BRIDE 2" ANSI

VA40-1 A037

0432 IAR

VANNE DE VOLUME DE CHARGE SOUTIRAGE AIR COMPRESSEUR

VAB1 0947

0434 HS

PURGEUR D'AIR SUR TUYAUTERIE HUILE H.P. PRINCIPALE

VAB2 0947

0434 HS

PURGEUR D'AIR SUR TUYAUTERIE HUILE H.P. AUXILIAIRE

VCK3-1 0947

0434 HS

CLAPET ANTI-RETOUR SUR CIRCUIT HYDRAULIQUE HUILE HP POUR POMPE PRINCIPALE

VCK3-2 0947

0434 HS

CLAPET ANTI-RETOUR SUR CIRCUIT HYDRAULIQUE HUILE HP POUR POMPE AUXILIAIRE

VCK7-1,2 A053

0417 CSA

CLAPET ANTI-RETOUR SUR CIRCUIT AIR REFROIDISSEMENT CORPS TURBINE

VGC-1 0509

0422 GF

VANNE CONTROLE GAZ - SERVO VALVE 65GC, LVDT 96GC-1,2 CORPS 152,4mm - CONTROLE 300LB-ASA - COURSE 44+1/-0 mm

VGD-1 0567

0422 GF

VANNE TRANSFERT GAZ CONTROLE 300 LB-ASA;COURSE 50.8 mm +1/0 CORPS 63,5 mm

VGS-3 0564

0422 GF

SPLITTER VANNE COMBUSTIBLE GAZ CONTROLE 300 LB-ASA;COURSE 57.1 mm +1/0 CORPS 63,5 mm

VH12-1 0509

0422 GF

DUMP VALVE COMBUSTIBLE GAZ - VANNE GAZ CONTROLE -COMMANDEE HYDRAULIQUEMENT

VH3-1 0548

0469 IGV

VANNE DE DECHARGE DE SECURITE IGV

VH5 0507

0422 GF

VANNE DE DECHARGE DE SECURITE DE LA VSR

VM15-1 A037

0432 IAR

VANNE ISOLATION ENTREE RECHAUFFAGE

VM4 1052

0434 HS

VANNE TRANSFERT POUR FILTRE HUILE H.P. (FH2-1,2)

VPR2-1 1023

0416 LO

VANNE DE REGULATION DE PRESSION COLLECTEUR HUILE PALIERS TARAGE:1,72 +0,13/-0 BARS

VPR3-1 1005

0434 HS

COMPENSATEUR DE PRESSION POMPE HYDRAULIQUE PRINCIPALE PH1 TARAGE:103,4±1,37 BARS

VPR41-1 A037

0432 IAR

VANNE DE CONTROLE REGULATION PRESSIONSEUR SOUTIRAGE AIR TURBINE REGLAGE 3,104 +/- 0,1379 BARG

VPR44-3,4 0991

0477 FPU

REGULATEUR PRESSION D'AIR-VANNE PURGE COMBUSTIBLE GAZ TARAGE 2,3 +0/-0.2 BARS

VR1 1016

0416 LO

VANNE DE DECHARGE POMPE PRINCIPALE HUILE DE LUBRIFICATION TARAGE:6,89 BARS +0,13/-0 BARS

VR21 0947

0434 HS

VANNE DE DECHARGE POMPE PRINCIPALE HUILE HP TARAGE:113,7±1,37 BARS

VR22 0947

0434 HS

VANNE DE DECHARGE POMPE AUXILIAIRE HP TARAGE:113,7±1,37 BARS

VSR-1 0507

0422 GF

VANNE D_ARRET COMBUSTIBLE GAZ SERVO-VALVE 90SR - LVDT 96SR-1,2 CORPS 152,4 mm - CONTROLE 300 LB-ASA - COURSE 88,67+1/-0 mm

VTR1 1035

0420 CW

VANNE THERMOSTATIQUE REFRIGERANT HUILE DE GRAISSAGE AVANT PALIER NORMAL = B VERS E OUVERT ; C FERME DEBUT DE FERMETURE B VERS E : A 54±1,6°C

WT_TL-1,2 0637

0420 CW

RESISTANCE THERMOMETRIQUE TEMPERATURE PATTES TURBINE



DRAWN THIRION F. SECTION 01E SCALE SHEET 1


SYSTEM SYMBOLE DESCRIPTION 20CB-1 1071

0417 CSA

COMPRESSOR BLEED VALVE SOLENOID 3 WAY VALVE NORMAL= B TO C OPEN ; A CLOSED

20FG-1 0991

0418 TO

GAS FUEL STOP VALVE SOLENOID NORMAL = OPEN

20PG-3,4 0991

0477 FPU

GAS FUEL SYSTEM PURGE SOLENOID VALVE NORMAL =1 TO 3:OPEN-2:CLOSED

20TH-1 A037

0432 IAR

INLET HEATING CONTROL VALVE TRIP SOLENOID VALVE DE-ENERGISED TO TRIP VA20-1

20TU-1 0605

0421 SM

TORQ. CONVERTER UNLOADING(DRAIN) SOLENOID VALVE NORMAL = OPEN

20TV-1 1019

0418 TO

TURB COMPRESSOR IGV SOLENOID VALVE NORMAL = OPEN

20TW-1 0953

0442 TCW

OFF LINE COMPRESSOR WATER WASH SOLENOID VALVE

20TW-3 0953

0442 TCW

ON LINE COMPRESSOR WATER WASH SOLENOID VALVE

20VG-1 0991

0422 GF

GAS FUEL VENT SOLENOID VALVE VALVE NORMAL = OPEN

20VG-3 0991

0477 FPU

GAS FUEL(PURGE)VENT SOLENOID VALVE NORMAL = CLOSED

23CR-1to3 0603

0421 SM

CRANKING MOTOR SPACE HEATER 240 V - 150 W

23HQ-1 0628

0434 HS

MOTOR SPACE HEATER FOR 88 HQ-1

23QA-1 1006

0416 LO

MOTOR SPACE HEATER FOR 88 QA-1

23QT-1,2 0938

0416 LO

IMMERSION HEATER LUBE OIL TANK EACH:10,2 KW - 400 VAC - 3 PH - 50 Hz

23TG-1 0538

0421 SM

MOTOR SPACE HEATER FOR 88 TG-1

23TK-1,2 1233

0417 CSA

TURB. SHELL AND EXHAUST FRAME BLOWER MOTOR HEATER

26CR-1to3 0603

0421 SM

(R.T.D.) IN CRANKING MOTOR RESISTANCE THERMOMETER DETECTOR

28FD-14P,14S 1121

0415 CD

FLAME DETECTORS-COMBUSTION CHAMBERS Nr14 DIGITAL LOGIC:1=NO FLAME;0=FLAME DIGITAL OUTPUT DIRECTLY INTO SPEEDTRONIC PANEL

28FD-1P,1S 1121

0415 CD

FLAME DETECTORS-COMBUSTION CHAMBERS Nr 1 DIGITAL LOGIC:1=NO FLAME;0=FLAME DIGITAL OUTPUT DIRECTLY INTO SPEEDTRONIC PANEL

28FD-2P,2S 1121

0415 CD

FLAME DETECTORS-COMBUSTION CHAMBERS Nr 2 DIGITAL LOGIC:1=NO FLAME;0=FLAME DIGITAL OUTPUT DIRECTLY INTO SPEEDTRONIC PANEL

28FD-3P,3S 1121

0415 CD

FLAME DETECTORS-COMBUSTION CHAMBERS Nr3 DIGITAL LOGIC:1=NO FLAME;0=FLAME DIGITAL OUTPUT DIRECTLY INTO SPEEDTRONIC PANEL

33BQ-1 1044

0417 CSA

BEARING SEALING AIR VALVE-LIMIT SWITCH SWITCH CONT CLOSED WITH VA14 IN 5 TH STG POSITION - NORMAL=NO-SPST

33CB-1to4 1022

0417 CSA

11 TH STAGE COMPRESSOR BLEED VALVE LIMIT SWITCH VALVE OPEN : SWITCH ACTUATED AND CONTACT CLOSED

33PG-5,7 0991

0477 FPU

GAS FUEL SYSTEM PURGE VALVE LIMIT SWITCH NORMAL =(2) NC-OES CLOSED WITH VALVE OPEN

33PG-6,8 0991

0477 FPU

GAS FUEL SYSTEM PURGE VALVE LIMIT SWITCH NORMAL =(2) NO-CES OPEN WITH VALVE OPEN

33TC-1 0605

0421 SM

LIMIT SWITCH TORQ. CONVERTER FILLING VALVE 20TU DESENERGIRED,SWITCH ACTUATED, CONTACT CLOSED

33TH-3 A037

0432 IAR

INLET HEATING ISOLATION VALVE LIMIT SWITCH CONTACT CLOSED WHEN VM15-1 FULL OPEN

33TH-4 A037

0432 IAR

INLET HEATING ISOLATION VALVE LIMIT SWITCH CONTACT CLOSED WHEN VA30-1 FULL CLOSED

33TM-5 0605

0421 SM

TORQUE ADJUSTOR-LIMIT SWITCH HIGH TORQUE LIMIT CONTACT OPEN IF HIGH TORQUE DURING RUN DOWN. NORMAL = NC-OEC

33TM-6 0605

0421 SM

TORQUE ADJUSTOR-LIMIT SWITCH HIGH TORQUE LIMIT CONTACT OPEN IF HIGH TORQUE DURING RUN DOWN. NORMAL = NC-OEC

33VG-1 0991

0422 GF

LIMIT SWITCH ON SOLENOID VALVE 20VG-1 LIMIT SWITCH ACTUATED AND CONTACT CLOSED NORMAL = NO CES





SYSTEM SYMBOLE DESCRIPTION 39V-1A,1B 1218

0415 CD

VIBRATION SENSOR TURBINE BEARING 1 TEMP. 707°F MAX. OUTPUT VOLTAGE AT 1"/s = 150 mv PEAK

39V-2A 1218

0415 CD


39V-3A,3B 1218

0415 CD


39VS-11,12 0235

0415 CD

NON CONTACTING PROBES X,Y -BRG 1

39VS-31,32 1160

0415 CD

NON CONTACTING PROBES X,Y -BRG 3

43TW-1/PB 1105

0442 TWC

COMPRESSOR WATER WASH PUSH BUTTON STATION

45FA-1A,1B 1104

0426 FP

FIRE DETECTOR ACCESSORY COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45FA-2A,2B 1104

0426 FP

FIRE DETECTOR ACCESSORY COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45FA-6A,6B 0991

0426 FP

FIRE DETECTOR GAS COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45FT-1A,1B 1103

0426 FP

FIRE DETECTOR TURBINE COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45FT-2A,2B 1154

0426 FP

FIRE DETECTOR TURBINE COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45FT-3A,3B 1154

0426 FP

FIRE DETECTOR TURBINE COMPARTMENT. INC CLOSE = 600±9°C - NORMAL = NO SPST

45FT-8A,8B 1160

0426 FP

FIRE DETECTOR NOT EQUAL TO 3 BEARING TUNNEL INC CLOSE = 950±9°C - NORMAL = NO SPST

45FT-9A,9B 1160

0426 FP

FIRE DETECTOR LOAD COMPARTMENT INC CLOSE = 600±9°C - NORMAL = NO SPST

45HA-4to6 0991

0474 HGD

GAS DETECTOR GAS COMPARTMENT ALARM : 5% OF L.E.L TRIP : 8% of L.E.L

45HT-1to3 1154

0474 HGD

GAS DETECTOR TURBINE COMPARTMENT ALARM : 5% OF L.E.L TRIP : 8% of L.E.L

5E-1,2 1104

0426 FP

BUTTON OF STOP OF EMERGENCY

63GQ-1 0991

0422 GF

GAS INLET FILTER DIFFERENTIAL INC OPEN : 22,05±1,03 NORMAL : NC-OEC

63HF-1 0926

0434 HS

HYD.FILTER DIFF. PRESS. ALARM DEC CLOSE = 40±15 PSIG INC OPEN = 60±3 PSIG NORMAL =NC-OEC

63HG-1to3 0991

0418 TO

HYDRAULIC OIL TRIP CIRCUIT PRESSURE GAS FUEL STOP VALVE INC CLOSE = 24±2 PSIG DEC OPEN = 20±1 PSIG NORMAL = NO CEC

63HQ-1 0926

0434 HS

LOW HYDRAULIC SUPPLY PRESS. AUX HYDL. PUMP START INC CLOSE = 1450±45 PSIG DEC OPEN = 1350±25 PSIG NORMAL =NO-CEC

63PG-2 0991

0477 FPU

GAS FUEL SYS. PURGE PRESSURE SWITCH DEC OPEN 40±2 PSIG INC CLOSE 45±2 PSIG NORMAL =(2) NO-CEC

63QA-2 0926

0416 LO

LOW LUBE OIL PRESSURE AUXILIARY PUMP START INC CLOSE = 45±2 PSIG DEC OPEN = 40.6±1 PSIG NORMAL =NO-CEC

63QQ-1 0926

0416 LO

MAIN LUBE OIL FILTER DIFFERENTIAL PRESS. ALRM DEC CLOSE = 12,7±3 PSIG INC OPEN = 15±1 PSIG NORMAL =NC-OEC

63QQ-8 0916

0416 LO

TORQUE ADJUSTER FILTER DIFFERENCIAL PRESSURE INC OPEN = 21.75 PSIG

63QT-2A ALTERNATEUR

0416 LO

LOW LUBE OIL PRESSURE GENERATOR SIDE INC CLOSE =9±0,5 PSIG DEC OPEN = 8±0,3 PSIG NORMAL = NO CEC

63QV-1 A098

0416 LO

FOULING COALESOEUR FILTER DIFFERENTIAL PRESSURE NORMAL NO CLOSE 80 MBAR ALARM TO DEFINE

63TK-1,2 A053

0417 CSA

TURB SHELL AND EXHAUST FRAME BLOWER DISCHARGE PRESSURE SWITCH CLOSE : ABOVE 15±3 inch H20 NORMAL = NO CEC

65EP-3 A037

0432 IAR

ELECTRO-PNEUMATIC TRANSDUCER POSITIONER INPUT 4mA FOR VA20-1 FULL OPEN

65GC-1 0541

0422 GF

GAS CONTROL VALVE SERVO VALVE RATED FLOW:5 GPM AT 1000 PSIG FLUID:HYD.SUPPLY OIL AT 1500 PSIG

65GD-1 0568

0422 GF

GAS FUEL TRANSFER VALVE SERVO VALVE (3 COILS) RATED FLOW:1 GPM AT 1000 PSIG FLUID:HYD. SUPPLY OIL AT 1200 PSIG

65GS-1 0565

0422 GF

GAS FUEL SPLITTER VALVE SERVO VALVE (3 COILS) RATED FLOW:1 GPM AT 1000 PSIG FLUID:HYD. SUPPLY OIL AT 1200 PSIG





SYSTEM SYMBOLE DESCRIPTION 71QH-1 1038

0416 LO

HIGH LUBE OIL LEVEL ALARM SEE LUBE OIL SCHEMATIC (ML ITEM 0416) NORMAL =NC-OEC

71QL-1 1038

0416 LO

LOW LUBE OIL LEVEL ALARM SEE LUBE OIL SCHEMATIC (ML ITEM 0416) NORMAL =NO-OEC

77HT-1to3 0546

0415 CD

HIGH PRESSURE SET MAGNETIC PICKUP LOCATION:N°1 BEARING GAP = 0,050±0,005 INCH

77NH-1to3 0546

0415 CD

HIGH PRESSURE SET MAGNETIC PICKUP LOCATION:N°1 BEARING GAP = 0,050±0,005 INCH

77RP-11 0235

0415 CD

KEY PHASOR

88CR-1 0603

0421 SM

CRANKING MOTOR 1000KW -2975 RPM -11500 V -50 Hz

88HQ-1 0628

0434 HS

(AUXILIARY) HYDRAULIC SUPPLY PUMP MOTOR 15 KW -1450 RPM -400 V -3 PH -50 Hz

88QA-1 1006

0416 LO

AUXILIARY LUBE OIL PUMP MOTOR 90 KW -2960 RPM -400 V -3 PH -50 Hz

88QE-1 1007

0416 LO

EMERGENCY LUBE OIL PUMP MOTOR 7,5 KW -1750 RPM -125 V -DC

88QV-1 A098

0416 LO

FAN MOTOR (MIST ELIMINATOR) 18.5 KW - MULTI TENSION 3 PHASES - MULTI FREQUENCE

88TG-1 0538

0421 SM

TURBINE GEAR MOTOR 30 KW -725 RPM -400 V -3 PH -50 Hz

88TK-1,2 1233

0417 CSA

TURBINE EXHAUST FRAME COOLING FAN MOTOR 45 KW -2900 RPM -400 V -3 PH -50 Hz

88TM-1 0605

0421 SM

TORQUE ADJUSTER DRIVE MOTOR 1,5 KW -3000 RPM -400 V -50 Hz

90SR-1 0541

0422 GF

SPEED RATIO/STOP VALVE SERVO VALVE RATED FLOW:5 GPM AT 1000 PSIG FLUID:HYD. SUPPLY OIL AT 1500 PSIG

90TH-4 A037

0432 IAR

INLET BLEED HEAT DRAIN VALVE MOTOR OPERATOR 120V AC 50/60 HZ POWER SUPPLY0-1 FULL OPEN REQUIRED

90TV-1 0540

0469 IGV

TURBINE INLET GUIDE VANE SERVO VALVE RATED FLOW:5 GPM AT 1000 PSIG FLUID:HYD. SUPPLY OIL AT 1500 PSIG

95SG-11 1213

0415 CD

IGNITION TRANFORMER FOR 95SP-11

95SG-12 1213

0415 CD

IGNITION TRANFORMER FOR 95SP-12

95SP-11 1214

0415 CD

SPARK PLUG-COMBUSTION CHAMBER N°11

95SP-12 1214

0415 CD

SPARK PLUG-COMBUSTION CHAMBER N°12

96AP-1 0557

0415 CD

BAROMETRIC PRESSURE TRANSMITTER 11,6, - 17,4 PSIG

96BD-1 0557

0415 CD

COMPRESSOR BELLMOUTH DIFFERENTIAL PRESSURE TRANSMITTER 4,5 PSIG

96BH-1 A037

0432 IAR

INLET HTG CV UPSTREAM PRESSURE TRANSMITTER RANGE 0-300,0 PSIG ADJUSTEMENT ON CONDITION PRESSURE OUTPUT TRANSMITTER. ZERO 0 PSIG 4 +/- 0,2 mA "ZERO" MAXI 300,0 PSIG 20 +/- 0,2 mA "GAIN"

96BH-2 A037

0432 IAR

INLET HTG CV DOWNSTREAM PRESSURE TRANSMITTER RANGE 0-150,0 PSIG ADJUSTEMENT ON CONDITION PRESSURE OUTPUT TRANSMITTER. ZERO 0 PSIG 4 +/- 0,2 mA "ZERO" MAXI 150,0 PSIG 20 +/- 0,2 mA "GAIN"

96CD-1A 0557

0417 CSA

COMPRES. DISCHARGE PRESSURE TRANSMITTER RANGE 0-300 PSIG ZERO 0 PSIG -4mA MAXI 300 PSIG - 20mA

96CD-1B 0557

0417 CSA

COMPRES. DISCHARGE PRESSURE TRANSMITTER RANGE 0-300 PSIG ZERO 0 PSIG - 4mA MAXI 300 PSIG - 20mA

96CD-1C 0557

0417 CSA

COMPRES. DISCHARGE PRESSURE TRANSMITTER RANGE 0-300 PSIG ZERO 0 PSIG -4mA MAXI 300 PSIG - 20mA

96CS-1 0557

0415 CD

INLET AIR TOTAL PRESSURE TRANSMITTER 0 – 0.18 PSIG

96FG-2A 0991

0422 GF

FUEL GAS PRESSURE TRANSMITTER RANGE 0-500 PSIG ZERO 0 PSIG - 0±0,01V MAXI 500 PSIG - 5±0,01V

96FG-2B 0991

0422 GF


96FG-2C 0557

0422 GF






SYSTEM SYMBOLE DESCRIPTION 96FG-3 0557

0422 GF

FUEL GAZ INLET PRESSURE TRANSMITTER RANGE 0-362 PSIG ZERO 0 PSIG 4 mA "ZERO" MAXI 362 PSIG 20 mA "GAIN"

96GC-1,2 0509

0422 GF

GAS CONTROL VALVE LVDT STROCKE 1,73-1,77inch

96GD-1,2 0567

0422 GF

GAS FUEL TRANSFER VALVE LVDT STROKE: 2 INCH

96GS-1,2 0564

0422 GF

GAS FUEL SPLITTER VALVE LVDT STROKE:2.25 INCH

96QA-2 0926

0416 LO

LUBE OIL PRESSURE TRANSMITTER VPR2 OUTLET RANGE 0-101.5 PSIG ZERO 0 PSIG 4 mA "ZERO" MAXI 101.5 PSIG 20 mA "GAIN"

96QT-2A ALTERNATEUR

0416 LO

LOW LUBE OIL PRESSURE TRANSMITTER GENERATOR SIDE RANGE 0-72 PSIG ZERO 0 PSIG - 4mA "ZERO" MAXI 72 PSIG - 20mA "GAIN"

96SR-1,2 0507

0422 GF

STOP/SPEED RATIO VALVE LVDT STROCKE 3,49inch (+0,04;-0)

96TH-1 A037

0432 IAR

INLET HEATING CONTROL VALVE POSITION TRANSMITTER 4 +/- 0,2 mA = 0,0% 20 +/- 0,2 mA = 100%

96TM-1 0605

0421 SM

TORQUE ADJUSTER VANE POSITION TRANSMITTER ZERO : LOW TORQUE : 0% - 4mA MAXI : HIGH TORQUE : 100% - 20mA

96TV-1,2 0548

0469 IGV

TURBINE INLET GUIDE VANE LVDT

96VC-11,12 0235

0415 CD

NON CONTACTING PROBES THRUST POSITION

AH1-1,2 0991

0434 HS

CONTROL OIL HYDRAULIC ACCUMULATOR CAPACITY:2,5 GAL PRECHARGE:750 PSIG

AH1-3,4 0991

0422 GF

CONTROL OIL HYDRAULIC ACCUMULATOR-HALE CAPACITY:2.6 GAL PRECHARGE:596 PSIG FUNCTION:PROVIDE ADDITIONAL CAPACITY DURING SHORT FLOW TRANSIENTS

AT_LC-1 0637

0436 HV

LOAD COMPARTMENT TEMPERATURE RESISTANCE THERMOMETER DETECTOR

AT_TC-1 0637

0436 HV

TURBINE COMPARTMENT RESISTANCE THERMOMETER DETECTOR

BT_J1-1A,1B 0235

0415 CD

BRG THERMOCOUPLE JOURNAL 1 TURBINE

BT_J1-2A,2B 0235

0415 CD


BT_J2-1A,1B 0235

0415 CD


BT_J2-2A,2B 0235

0415 CD


BT_J3-1A,1B 0235

0415 CD


BT_J3-2A,2B 0235

0415 CD


BT_TA1-2A,2B 0235

0415 CD

T.C. METAL TEMP. THRUST ACTIVE BRG 1 TURBINE

BT_TA1-5A,5B 0235

0415 CD

T.C.METAL TEMP. THRUST ACTIVE BRG 1 TURBINE

BT_TA1-8A,8B 0235

0415 CD

T.C.METAL TEMP.THRUST ACTIVE BRG 1 TURBINE

BT_TI1-2A,2B 0235

0415 CD

T.C.METAL TEMP.THRUST INACTIVE BRG 1 TURBINE

BT_TI1-5A,5B 0235

0415 CD

T.C.METAL TEMP.THRUST INACTIVE BRG 1 TURBINE

BT_TI1-9A,9B 0235

0415 CD

T.C.METAL TEMP.THRUST INACTIVE BRG 1 TURBINE.

CT_BD-1 A037

0432 IAR

INLET AIR HGT TEMPERTURE THERMOCOUPLE TYPE K - CHROMEL/ALUMEL THERMOCOUPLE

CT_DA-1,2 0637

0415 CD

COMPRESSOR TEMPERATURE DISCHARGE ANNULUS THERMOCOUPLE K TYPE

CT_IF-1,2 0637

0415 CD

COMPRESSOR TEMPERATURE INLET FLANGE THERMOCOUPLE K TYPE

CT_IF-3/R 0637

0415 CD

RESISRANCE THERMOMETER DETECTOR COMPRESSOR TEMPERATURE -INLET FLANGE

FA2-1 0991

0477 FPU

CONTROLE AIR PURGE GAS FILTER





SYSTEM SYMBOLE DESCRIPTION FG-1 0929

0422 GF

GAS SUPPLY FILTER NOMINAL FILTRATION 1.5 MICRONS

FH14-1 0564

0422 GF

HYD.SUPPLY FILTER-SPLITTER VALVE FILTRATION:15 MICRONS

FH15-1 0567

0422 GF

TRANSFERT VALVE SERVO HYD.SUPPLY FILTER FILTRATION:15 MICRONS

FH2-1,2 0908

0434 HS

HYDRAULIC SUPPLY FILTER FILTRATION:0,5 MICRONS

FH6-1 0905

0469 IGV

IGV SERVO HYDRAULIC SUPPLY FILTER FILTRATION:40 MICRONS (SINTERED METAL FILTER ELEMENT)

FH7-1 0991

0422 GF

GAS FUEL SERVO HYDRAULIC SUPPLY FILTER FILTRATION:40 MICRONS (SINTERED METAL FILTER ELEMENT)

HM3-1 0548

0469 IGV

VARIABLE INLET GUIDE VANE SYSTEM CYLINDER SETTING 34-2° TO 84+2° ON VIGV

LT_B1D-1A,1B 0637

0416 LO

LUBE OIL TEMPERATURE RETURN BEARING 1 THERMOCOUPLE K TYPE

LT_B2D-1A,1B 0637

0416 LO


LT_B3D-1A,1B 0637

0416 LO


LT_BT1D-1A,1B 0637

0416 LO

LUBE OIL TEMPERATURE THRUST BEARING 1 THERMOCOUPLE K TYPE

LT_G1D ALTERNATEUR

0416 LO

LUBE TEMPERATURE BEARING 4 THERMOCOUPLE K TYPE GENERATOR

LT_G2D ALTERNATEUR

0416 LO

LUBE TEMPERATURE BEARING 5 THERMOCOUPLE K TYPE GENERATOR

LT_OT-1A 0938

0416 LO

LUBE OIL TANK TEMPERATURE LOW RESISTANCE THERMOMETER DETECTOR

LT_OT-2A 0938

0416 LO

LUBE OIL TANK TEMPERATURE NORMAL RESISTANCE THERMOMETER DETECTOR

LT_TH-1A,1B 0637

0416 LO

LUBE OIL TEMPERATURE TURBINE HEADER. THERMOCOUPLE K TYPE

LT_TH-2A,2B 0637

0416 LO

LUBE OIL TEMPERATURE TURBINE HEADER THERMOCOUPLE K TYPE

LT_TH-3A,3B 0637

0416 LO

LUBE OIL TEMPERATURE TURBINE HEADER THERMOCOUPLE TYPE K

MG1-1 0513

0422 GF

GAS FUEL NOZZLE PRIMARY

MG1-2 0513

0422 GF

FUEL GAS NOZZLE-SECONDARY

MG1-3 0513

0422 GF

FUEL GAS NOZZLE-TRANSFER

PH1 0627

0434 HS

MAIN HYDRAULIC SUPPLY PUMP DRIVEN BY ACCESSORY GEAR RATED FLOW:17,1 GPM AT 1500 PSIG -1422 RPM

PH2 0627

0434 HS

AUXILIARY HYDRAULIC SUPPLY PUMP RATED FLOW:12 GPM AT 1500 PSIG - 1450 RPM DRIVEN BY A C MOTOR 88 HQ

SLI-1,2 1104

0426 FP

FIRE ALARM STROBE

TT_IB-1 0637

0415 CD

TURBINE TEMPERATURE -INNER BARREL- 3 THERMOCOUPLE K TYPE

TT_WS1AO-1,2 0637

0415 CD

TURBINE TEMPERATURE -WHEELSPACE 1 ST STAGE AFT -(OUTER) THERMOCOUPLE K TYPE

TT_WS1FI-1,2 0637

0415 CD

TURBINE TEMPERATURE -WHEELSPACE 1 ST STAGE FWD -(INNER) THERMOCOUPLE K TYPE

TT_WS2AO-1,2 0637

0415 CD

TURBINE TEMPERATURE - WHEELSPACE 2nd STAGE AFT -(OUTER) THERMOCOUPLE K TYPE

TT_WS2FO-1,2 0637

0415 CD

TURBINE TEMPERATURE - WHEELSPACE 2nd STAGE FWD -(OUTER) THERMOCOUPLE K TYPE

TT_WS3AO-1,2 0637

0415 CD

TURBINE TEMPERATURE - WHEELSPACE 3rd STAGE AFT -(OUTER) THERMOCOUPLE K TYPE

TT_WS3FO-1,2 0637

0415 CD

TURBINE TEMPERATURE - WHEELSPACE 3rd STAGE FWD -(OUTER) THERMOCOUPLE K TYPE

TT_XD-1to24 0623

0415 CD

TURBINE EXHAUST TEMPERATURE THERMOCOUPLE K TYPE





SYSTEM SYMBOLE DESCRIPTION VA13-3,4 0991

0477 FPU

GAS FUEL SYSTEM PURGE VALVE AIR ACTUATED BY 20PG

VA14 1044

0417 CSA

BEARING SEALING AIR VALVE NORMAL: .BOTTOM(11 TH STAGE) TO COMMON (BEARING) OPEN .TOP(5 TH STAGE) CLOSED

VA17-1 1026

0442 TCW

FALSE START DRAIN VALVE-COMBUSTION WRAPPER OPEN = NORMAL

VA17-2 1026

0442 TCW

FALSE START DRAIN VALVE-EXHAUST FRAME OPEN = NORMAL

VA20-1 A037

0432 IAR

INLET HEATING CONTROL VALVE 8.00 INCH ANSI FLANGE CONNECTION

VA2-1to4 1022

0417 CSA

11TH STG. COMPRESSOR BLEED VALVE NORMAL = OPEN

VA30-1 A037

0432 IAR

INLET HEATING DRAIN VALVE 2.00 INCH ANSI FLANGE CONNECTION

VA40-1 A037

0432 IAR

INLET HEATING CONTROL VALVE VOLUME BOOSTER

VAB1 0947

0434 HS

HYDRAULIC SYSTEM AIR BLEED VALVE (MAIN)

VAB2 0947

0434 HS

HYDRAULIC SYSTEM AIR BLEED VALVE (AUX.)

VCK3-1 0947

0434 HS

HYDRAULIC PUMP CHECK VALVE FOR MAIN PUMP

VCK3-2 0947

0434 HS

HYDRAULIC PUMP CHECK VALVE FOR AUXILIARY PUMP

VCK7-1,2 A053

0417 CSA

TURBINE SHELL COOLING AIR BLOWER CHECK VALVE

VGC-1 0509

0422 GF

GAS CONTROL VALVE - SERVO VALVE 65GC, LVDT 96GC-1,2 BODY 6 INCH - RATING 300 LB-ASA - STROKE 1.73+0.04/-0 INCH

VGD-1 0567

0422 GF

GAS TRANSFER VALVE RATING 300 LB-ASA; STROKE 2 INCH +0.04/0 BODY 2.5IN

VGS-3 0564

0422 GF

GAS FUEL SPLITTER VALVE RATING 300 LB-ASA; STROKE 2.25 INCH +0.04/0 BODY 2.5IN

VH12-1 0509

0422 GF

GAS FUEL DUMP VALVE - GAS CONTROL VALVE -HYDRAULICALLY OPERATED

VH3-1 0548

0469 IGV

IGV TRIP VALVE

VH5 0507

0422 GF

VSR SECURITY DISCHARGE VALVE

VM15-1 A037

0432 IAR

INLET HEATING ISOLATION VALVE

VM4 1052

0434 HS

HYDRAULIC FILTER TRANSFER VALVE

VPR2-1 1023

0416 LO

BEARING HEADER PRESSURE REGULATOR VALVE SETTING:25 +2/-0 PSIG

VPR3-1 1005

0434 HS

HYDRAULIC SUPPLY PUMP (PH1) COMPENSATOR SETTING 1500 +20/-0 PSIG

VPR41-1 A037

0432 IAR

TURBINE IAH CONTROL VALVE I/P INST AIR PRESSURE REGULATION SET 45,00 +/- 2,00 PSIG

VPR44-3,4 0991

0477 FPU

AIR PRESS REGULATOR-GAS FUEL PURGE VALVE SETTING 33.35 +0/-2.9 PSIG

VR1 1016

0416 LO

MAIN LUBE OIL PUMP PRESSURE RELIEF VALVE SETTING:100 +2/-0 PSIG

VR21 0947

0434 HS

MAIN HYDRAULIC SUPPLY PUMP PRESSURE RELIEF VALVE SETTING:1650±20 PSIG

VR22 0947

0434 HS

AUXILIARY HYDRAULIC SUPPLY PUMP PRESSURE RELIEF VALVE SETTING:1650±20 PSIG

VSR-1 0507

0422 GF

FUEL GAS STOP/RATIO VALVE SERVO-VALVE 90SR - LVDT 96SR-1,2 BODY 6 INCH - RATING 300 LB-ASA - STORKE 3.49+0.04/-0 INCH

VTR1 1035

0420 CW

BRG HEADER TEMPERATURE REGULATER VALVE NORMAL = B TO E OPEN ; C CLOSED START TO CLOSE B TO E AT 129.2±2.88°F

WT_TL-1,2 0637

0420 CW

RESISTANCE THERMOMETER DETECTOR WATER SYSTEM TEMPERATURE TURBINE SUPPORT LEGS

GE Power Systems

1 GLOSSARY OF TERMINOLOGYC00023

GLOSSARY OF TERMINOLOGY(Mark IV, Mark V Gas Turbine Control System)

An understanding of the Mark IV and V gas turbinecontrol system requires a knowledge of the terminol-ogy used in the electrical control system and for themechanics of the gas turbine. This glossary is di-vided into part (A) Mark IV and V Electrical ControlTerminology, and part (B) Gas Turbine Terminolo-gy.

A. MARK IV AND MARK VELECTRICAL CONTROL

TERMINOLOGY

Address The identification code that distin-guishes one memory location or input/output portfrom another.

Address Bus A bus used to transmit the identifi-cation code that distinguishes one memory locationor I/O port from another.

Algorithm Refer to CONTROL ALGORITHM

Analog A continuous signal or a representationof a quantity that can have any value.

Application Application-oriented computer pro-grams, such as the Sequencer Code and Control Al-gorithms.

Software which are customized to the needs ofeach installation.

Array Systematic arrangement of numbers ordata in tabulated form.

ASCII Abbreviation for American StandardCode for Information Interchange. Each characteris assigned a number between 32 and 127.

ASM-86 A low-level programming language de-signed for the Intel 8086 microprocessor. ASM-86is used in the Mark IV computer operating system

to perform operations which require a fast execu-tion time.

Assembler A computer program that convertsassembly language programs into a form (machinelanguage) that the computer can understand. Theassembler translates mnemonic instruction codesinto binary numbers, replaces names with theirbinary equivalents, and assigns locations inmemory to data and instructions.

Assembly Language A programmming lan-guage in which the programmer can use mnemonicinstruction codes, labels, and names to refer direct-ly to their binary equivalents. The assembler is alow-level language, since each assembly languageinstruction translates directly into a specific ma-chine language instruction.

Asynchronous Operation of a switching net-work by a free-running signal. Completion of oneinstruction triggers the next instruction.

Back-plane The internal wiring of a module be-tween pins of the cards located in the module. Somemodules have a “flow-soldered” back-plane, whichis a printed circuit card that the other cards pluginto.

Baud A measure of the rate of data flow transfer.The number of signal elements (bits) transmittedper second. (2400 Baud transfers 2400 Bits = 300Bytes/sec.)

Binary A system of numbers using 2 as a base.(In contrast to the decimal system, which uses 10 asa base).

Bit A single binary digit which can be in either oftwo states (0/ or 1).

Bootstrap Technique for loading first instruc-tions of a program into memory and then usingthese instructions to bring in the rest of the pro-gram.

GE Power Systems

2GLOSSARY OF TERMINOLOGY C00023

BRAM Battery-backed Random AccessMemory is used to retain field editable softwareduring power outages for a given length of time.

Bus A group of parallel lines that connect two ormore devices.

Byte A data element consisting of 8 bits.

Checksum A logical sum of data that is includedin a record as a guard against recording or transmis-sion errors.

Clock The pulse generator which controls thetiming of switching circuits in the microprocessor.Hardware architecture and programming are otherfactors in determining the rate of data manipula-tion.

Coding The writing of programs in a languagethat is comprehensible to a computer system.

Cold Junction The junction between the ther-mocouple wire and the screw terminals on the ther-mocouple modules generates an EMF at point oftermination called the “cold junction”.

Compiler A program that converts a program ina high-level (i.e. procedure-oriented) language intoan assembly or machine language program.

Control Algorithm A PLM-86 ApplicationSoftware program that performs a specific func-tion, such as speedcontrol or vibration protection.

Control Bus The bus carries commands fromand to the CPU for control of the operating system(i.e. read, write, etc.).

Control Constants The subset of “Constants”that are used in the Control Algorithms and the Se-quencer Code to define gains, time constants, off-sets, etc. Each Control Constant can be called by itsSignal Name as shown in the Elementary.

CPU Central Processing Unit, the heart of thecomputer system, consists of storage elements(registers), arithmetic unit (computation circuits),

control block (instruction-decoding, execution andtiming) and I/O.

Cycle The process of powering-down, then pow-ering-up a processor; (i.e. moving the toggleswitch on the processor’s power supply to first theDISABLE position, then the ENABLE position).The processor will re-initialize when it is poweredback up.

Data Information that is processed by a micro-processor according to its Code. Generally, the mi-croprocessor’s input, output and ‘workspace’information.

Database The organized collection of Data andConstants that are important to field service per-sonnel.

Data Bus A bus used to transfer coded informa-tion to and from the CPU memory storage and pe-ripheral devices.

Differential Input An analog input which has ahigh impedance to ground on input wires.

Downloading The processor’s operation whichcopies information from one section of a proces-sor’s Memory into a different section of the sameMemory or into another processor’s Memory. If aController is ‘cycled’ (powered-down, then pow-ered-up), the <RST> Sequencer Code is down-loaded from the Communicator <C> to theController.

“Dumb Terminal” Terminal for data input/out-put to/from Host Computer; (by strict definition:No internal data storage/manipulation)

Editor A program that manipulates text materialand allows the user to make corrections, additions,deletions, and other changes.

EPROM Erasable Programmable Read OnlyMemory can be erased by exposure to ultravioletlight.

EEPROM Electrically Erasable ProgrammableRead Only Memory is used to store the field edit-

GE Power Systems


able Application Software so that it will not be lostduring a power outage.

Firmware A method of system control programdesign in which all control instructions are con-tained in ROM or PROM.

Handshaking A method of controlling datatransfers in which the transmitting device generatesa data ready signal. This signal directs the receivingdevice to accept the data. The receiving device thengenerates a data accepted signal to inform the trans-mitting device that it may remove the data and pro-ceed.

Hardware Physical equipment forming a com-puter system (as opposed to the Software).

Hexadecimal A system of numbers using 16 as abase (In contrast to the decimal system which uses10 as a base.)

High-Level Language A programming lan-guage in which the statements represent proceduresrather than single machine instructions. PLM-86 isthe high-level language used within the Mark IVsystem. A high-level language requires a compilerthat translates each statement into a series of ma-chine language instructions.

IDATA A Database array dedicated to storing in-teger variable Signal Names, such as speed (TNH)or fuel stroke reference (FSR).

Instruction A group of bits that defines a com-puter operation and is part of the instruction set.

Instruction Set The set of general-purposeinstructions available with a given computer — theset of inputs to which the CPU will produce aknown response during the instruction fetch cycle.

Interpreter A program that fetches and executesinstructions written in a high-level language. An in-terpreter executes each instruction as soon as itreads the instruction; it does not produce an objectprogram, as a compiler does.

Interrupt A computer input that temporarilysuspends the normal sequence of operations andtransfers computer control to an Interrupt ServiceRoutine.

Interrupt Service Routine A program that per-forms the actions required to respond to an inter-rupt.

IVAR A Database array dedicated to storing inte-ger data.

LDATA A Database array dedicated to storinglogic data Signal Names, such as “complete se-quence” (L3) or “flame detected” (L28FD).

LVAR A Database array dedicated to storing log-ic data.

Linking Loader A loader that will enter a seriesof program and subroutines into memory and pro-vide the required interconnections.

Low-Level Language A language in which eachstatement is directly translated into a single ma-chine language instruction.

MDATA A Database array dedicated to storingpre-defined miscellaneous data Signal Names.

MEM A Medium Electronics Module can con-tain up to 24 circuit cards. The Communicator <C>is a MEM.

Machine Language The programming lan-guage that the computer can directly understandwith no translation other than numeric conversions.A machine language program can be loaded intomemory and executed. The value of every bit in ev-ery instruction in the program must be specified.

Membrane Switch One of the pushbuttonswhich are beneath the overlay on the Operator In-terface Module.

Memory The section of a computer which storesinformation (i.e. code, data and constants) in binaryform. Each item in the Memory has a unique ad-dress that the CPU can use to access it.

GE Power Systems


Microcomputer A computer whose CPU is amicroprocessor plus memory and input/output cir-cuitry.

Microprocessor A central processing unit gen-erally consisting of an arithmetic and logic unit,control block and register array, and a memory stor-age system.

Modem A device that adds or removes a carrierfrequency to an existing signal which allows data tobe transmitted or received on a high frequencychannel.

Modular Programming A programming meth-od whereby the entire task is divided into logicallyseparate sections or modules.

MOV A Metal Oxide Veristor. A zener-oxide de-vice that suppresses voltage spikes.

Multiplexing A process of transmitting morethan one signal at a time on a single link via time-sharing (i.e. serial) or frequency-sharing (i.e. paral-lel).

MVAR A Database array dedicated to storingmiscellaneous data.

Object Program (Object Code) The programthat is the output of a translator program (such as anassembler or compiler). Usually a machine lan-guage program ready for execution.

Off-line A function performed with the turbinestopped and/or the control disconnected from theprocess.

Operating System System software that con-trols the overall operation of a computer system andperforms such tasks as memory allocation, inputand output distribution, interrupt processing, andtask scheduling.

Optical Isolation A semiconductor device con-sisting of an LED and a photodiode or phototrans-istor in close proximity. Current through the LEDcauses an internal light emission that forces cur-rent flow in the phototransistor. Voltage differ-

ences have no effect because the devices areelectrically separated.

Page A subdivision of Memory containing 64K(i.e. 65,0/0/0/ bytes).

Party Line A large number of devices connectedto a single line originating in a CPU.

PLM-86 A high-level language designed forsystems and application programming of the Intel8086 microprocessor. Control programs algo-rithms are written in PL/M-86.

Port The point where the I/O is in contact withthe outside world.

Programming The implementation of the con-trol function of a processing system as a sequenceof control signals that is organized into words andstored in memory.

PROM Programmable Read Only Memory isused to store software which is not field adjustableand will not be lost during a power outage.

PROM Programmer A piece of equipment thatstores Software in a PROM.

Processor A microcomputer (a microprocessorplus Memory and Input/Output circuitry) used inthe Mark IV panel. The Communicator <C> andthe Controllers <RST>.

Protocol A procedure for data communication.

RAM Random Access Memory can be read andwritten to during operation and must be backed-upto retain its contents during a power outage.

Real Time In synchronization with the actual oc-currence of events.

Real Time Operation A data processing tech-nique which allows the machine to use informationas it becomes available, as opposed to batch proces-sing at a time unrelated to the time the informationis generated.

Refresh The process of restoring the contents ofa dynamic memory before they are lost.

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Register A temporary small scale memory used bythe CPU for logic, arithmetic or transfer operations.

RS232 An IEEE communication standard usedfor communication between <C>, <R>, <S>, <T>and the panel mounted printer. It is also availablefor remote communication.

RS422 An IEEE communication standard usedfor remote communication.

Rung A series of Sequencer Code commands(i.e. pseudo-contacts) which result in a store state-ment (i.e. pseudo-coil).

Sampling Rate The frequency that a given pro-gram is run. Some control algorithms are run fourtimes every second.

SEM A Small Electronics Module contains up to12 circuit cards. Controllers <RST> are SEM’s.

Sequencer Code The set of instructions that per-forms the turbine’s sequencing functions.

Serial Link An interface between two computersystems that permits one of the systems to transmitdata to, and receive data from, the other system.

Single Ended Input An input which has a highimpedance to ground on one of the two incomingwires.

Softswitch One of the six pushbuttons, located atthe right of the CRT display, which are assigned afunction by the display which currently appears onthe screen.

Software Computer programs.

Subroutine A sub-program that can be reachedfrom one or more places in a main program.

Stack A data structure used for temporary stor-age which receives data on the top of the stack andpushes existing data further down in the stack. Datais removed from the top of the stack creating a last-in, first-out arrangement.

Stall A cessation of processor operation (due tomalfunction).

String A sequence of character codes stored se-quentially in Memory. The Relay Ladder DiagramRungs consist of one or more strings.

TTL Transistor-Transistor Logic is the mostwidely used bi-polarity technology for digital inte-grated circuits.

Utility Program A program that provides basicfunctions, such as loading and saving programs,initiating program execution, observing and chang-ing the contents of memory locations, or settingbreakpoints and tracing.

Voting Voting in the Mark IV means that the con-trol will respond to the majority logic from the threeControllers.

Word Sixteen consecutive bits which the com-puter can manipulate in a single cycle.

Wire Wrap Wiring within modules is termi-nated on the card or relay socket pins by wrappingthe wire around the pins.

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GAS TURBINE TERMINOLOGY

Accessory Compartment A sheet metal housewith access doors which may be located on thesame base as the turbine or on a separate base. Itcontains the mechanical accessories needed to sup-port the prime mover operation.

Accessory Coupling A fluid or grease filledflexible coupling which drives the accessory gearfrom (the forward end of) the prime mover.

Accessory Gear Encompasses a number of gearswhich drive most of the gas turbine accessories atthe proper speeds and which connects the turbine toits starting device. The gear is driven by the startingdevice, and then by the turbine when the unit reach-es self-sufficient speed. Common items driven bythis gear are: liquid fuel pump, water pump, mainlube pump, main hydraulic pump, main atomizingair compressor.

Accessory Gear Box Refers to the complete ac-cessory gear assembly.

Accumulator A hydro-pneumatic device de-signed to absorb a hydraulic shock and to deliver aregulated force (in the form of pressure and flow)during transient demands on a system.

Acid Removal Filter The machine part thatneutralizes acid in the lube oil supply.

Actuator A self-contained device designed todeliver a controlled or regulated force in order toactivate some other device.

Aft End The exhaust end of the gas turbine.

Aftercooler The atomizing air cooler down-stream of the main atomizing air compressor.

Air Separator The device which removes largeparticulate matter from an air supply via an inertialor centrifugal force.

Ambient Air Air surrounding the gas turbinehousing which enters the turbine to support com-bustion.

Annular Space or Annulus The ring like spacebetween the combustion liner and the flow shield.

Anti-Icing System Preheating of the inlet air toprevent ice formation in the inlet system.

Atomizing Air High pressure air which is usedto break up liquid fuel into small droplets to im-prove the combustion.

Aux. Hydraulic Supply Pump The motor driv-en high pressure pump used to supply servo pres-sure during start-up or emergency conditions.

Aux. Lube Pump Provides lubricating oil dur-ing start-up and shutdown, and serve as a standbyto the main pump. An AC motor is usually thedrive source.

Axial Flow A (gas turbine) compressor whichmoves air axially through a series of rotor and sta-tor compressor blades. The rotating elementsimpart momentum to the air mass, and the statorelements convert that momentum to pressure inconjunction with the converging walls of the com-pressor casing.

Base Load The load at the rated temperaturecontrol setpoint at which the turbine can be oper-ated to maintain the recommended parts life expec-tancy.

Bearing The stationary machine part which con-tains the journal bearing liner.

Bearing Feed Header The section of the lube oilpiping, downstream of the oil filters, which carrieslubrication to the individual turbine bearings.

Bearing Seal A general term identifying a meansof preventing oil leakage from a bearing.

Bellmouth The flared bell-shaped cast inletwhich provides an even airflow distribution to thecompressor through the inlet guide vanes.

Black Start The means of starting a turbine with-out incoming AC power.

Blade A rotating or stationary airfoil in an axialcompressor.

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Blow Off Valve A valve which bypasses air fromthe compressor around the regenerator and the highand low pressure turbines (i.e. two (2) shafts gasturbine) to reduce available energy and preventoverspeed during a sudden loss of load. It is primar-ily used on two shaft, generator drives.

Brittle The loss of resiliency in the parent metaldue to aging, extreme cold or chemical action.

Brake Horsepower The horsepower developedat the load coupling.

Buckets Airfoil elements mounted radially onthe rotor wheel to transfer energy from the workingmedium to the turbine rotor.

Burnishing The process of smoothing a metalsurface by means of a mechanical action with noloss of material. This normally occurs on plainbearing surfaces.

Bypass Valve A device which regulates the flowof a fluid in: A) A fuel bypass valve on a liquid fuelsystem using a positive displacement pump or, B)An air control valve used for compressor pulsationprotection.

Centrifugal Separator A device used to re-move dust from the gas turbine cooling and seal-ing air system. Separation is achieved by acentrifugal action.

Chamfer A beveled edge (i.e. by the removal ofsome of the gear material at an angle from the topland to the bottom land at the ends of the teeth.

Check Valve A device which allows fluid flow inonly one (1) direction.

CO2 Carbon dioxide, used as a fire extinguishingmedium.

Combustor or Combustion Chamber The me-chanical component of the combustion system inwhich the combustion takes place (increasing thetemperature of the working medium).

Combustion Liner The chamber where chemicalenergy is released and added to the gas flow path.

Combustion System A system consisting of fuelnozzles, spark plugs, flame detectors, crossfiretubes, combustion liners, transition pieces and acombustion casing or wrapper.

Compression Ratio The ratio of the compressordischarge pressure to the inlet pressure.

Compressor The mechanical component whichis used to increase the pressure of the working me-dium within its structure.

Compressor Discharge Casing Contains thelast stages of the compressor stator blades and isused to:

— Join the compressor and turbine stators

— Support the forward end of the combustionwrapper

— Provide an inner support for the first stageturbine nozzles.

— May provide support for a bearing

Control Compt. (Control CAB) The compart-ment which contains the gas turbine electrical con-trols and protection equipment.

Cooling and Sealing Air A system which pro-vides air pressure for cooling and sealing variousturbine components.

Cooling Water Pump Provides cooling waterflow for the system. A gear box or electric motordrives the pump.

Cooling Water Radiator The on or off base wa-ter/air or water/water heat exchanger.

Coupling A component which connects a drivencomponent to the drive source. Examples: Acces-sory Gear Coupling, Load Coupling, Pump Cou-pling, Starting Motor Coupling, etc.

Coupling Comp. A housing for the load cou-pling.

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Cranking The turning of the turbine rotor duringstart-up or shutdown.

Crossfire Tubes The piping which interconnectsthe combustion chambers on multiple combustionchamber turbines. These tubes also allow flamepropagation from the two (2) spark plug ignitedcombustors to the other chambers.

Cycle Thermal The ratio of the net work outputto the total heat input = [ Work of Turbine - Work ofEfficiency Compressor ]/Heat Input.

Diaphragm The stationary element containing aset of nozzles used to expand the working mediumand direct it against the rotating blades.

Diffuser The section designed to increase thearea of the flowpath to convert flow velocity to stat-ic fluid pressure.

Distance Piece A hollow cylindrical shaft usedto couple the axial-flow compressor to the firststage turbine wheel.

Eductor A device used for evacuating an en-closed space usually by means of air purge.

Electrostatic A device used for removing oilparticles from an air/oilmixture using the chargedparticle Precipitator method.

Emergency Stop An immediate de-activation ofthe fuel system due to an emergency electrical ormechanical device or done manually.

Emergency Lube Oil Pump The back-up lubeoil pump to the main pump. It uses the 125 Vdc bat-tery to power the motor.

Evaporator Cooling Liquid (usually water) isadded to an air supply, and the resultant evaporationcools the air mass and increases its mass per unitvolume.

Exhaust Diffuser The component which slowsthe exhaust gas exit from the last turbine stage to re-cover energy, and reduce losses.

Exhaust Frame The machine part which usuallysupport the aft journal bearing. The air dischargedfrom the exhaust diffuser is directed to the turningvanes. Air-cooled, internal struts maintain positionof the bearing.

Exhaust Hood The component which surroundsthe aft bearing area and is bolted to the turbine caseaft flange. It assists in guiding air flow in to the turn-ing vanes.

Exhaust Plenum An enclosed cavity which re-ceives discharged exhaust gases after the gases exitfrom the load turbine wheel.

Exhaust Ports Machine bosses on the compressorcasing which extracts air for cooling and sealing.

Exhaust Pressure Drop Exhaust duct losses.

Exhaust Stack The exhaust assembly which caninclude silencing sections.

Exit Guide Vanes Guide vanes at the exhaustend of the load turbine which direct the gas flow tothe exhaust.

Expansion Joints Devices that allow thermalexpansion.

Extraction Valves Devices used to assist in pre-venting compressor surge by allowing air to be ex-tracted during off-design periods from anintermediate compressor stage.

Filters Components normally used to removesolid particulate matter in a given size range froman air/fluid supply and from lube oil.

Fin Fan (Cooling Fan) A mechanically or elec-tric motor driven air fan used tocool the water run-ning through the radiators.

Firing Temp The temperature of the air mass atthe inlet of the first stage turbine nozzle.

Flame Detectors Sensors (usually ultraviolet)used to detect flame.

Flow Divider A device which distributers fuelflow equally to the fuel nozzles.

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Fluid A general term used to describe a liquid orgas.

Fuel Forwarding Skid The off-base pumpingunit used to transfer, condition and control the flowof liquid fuel to the turbine.

Fuel, Gas Either natural gas with a high heat con-tent or manufactured gas.

Fuel, Light Distillate (Also known as No. 2fuel.) A volatile distillate fuel having good com-bustion properties, clean burning and readily atom-ized. Preheating is usually not necessary.

Fuel Nozzle The device that injects fuel into thecombustion chamber.

Fuel Oil Stop Valve A spring-closed, hydrauli-cally opened device used as a positive shutoff ofliquid fuel.

Fuel Pump, Main The shaft driven, high pres-sure, liquid fuel pump.

Fuel, Residual Low volatility petroleum prod-ucts remaining at the end of a refinery distillationprocesses. All residual fuels require heating forpumping, filtering and proper air atomization at thefuel nozzle.

Fuel Treatment The process of treating residualfuel to eliminate or inhibit contaminants.

GAC Abbreviation for the Generator AuxiliaryCompartment containing high voltage switch gearand excitation.

Gib Block A steel block welded to the turbinebase which has adjusting bolts for axial and trans-verse locating of the turbine. Provision is made fora gib key in the gib block.

Gib Key The key for the gib block (i.e. describedabove). It is machined as an integral part of the low-er half of the exhaust frame.

Heat Consumption The heat consumed at ratedoutput (i.e. BTU/hr.).

Heat Exchanger/Cooler The heat transferequipment used to extract excessive heat from oneworking fluid and transmit it to another non-work-ing fluid for eventual dissipation to the atmosphere.

Heat Rate The ratio of input energy to output en-ergy (i.e. BTU/BHP-HR).

Heat Recovery System The means of recover-ing heat which would otherwise be lost during theprocess.

Heating Value The heat content of a given fuel(i.e. BTU/lb.).

High Pressure Turbine The first stage turbine(that drives the compressor on 2-shaft gas turbines).

Hot Gas Path A path of flow of the hot gasesconsisting of the combustion chambers, transitionpieces, turbine nozzles and buckets, and the ex-haust section.

Hydraulic Ratchet A form of turning gearwhich turns the rotor slightly at periodic intervals.

Inductor Alternator A permanent magnet typeof AC generator connected to the compressor shaft.

Inlet Guide Vane The guide vanes at the inlet tothe compressor which direct and control the airflow to the first stage of the axial flow compressor.

Inlet Plenum An enclosed cavity that directs theinlet air to the gas turbine.

Inlet Pressure Drop The inlet duct pressure drop(in inches of water).

Inlet Temperature The inlet air temperature tothe gas turbine compressor.

Journal Bearing The part that supports theweight of the rotating shaft during normal operation.

Labyrinth Packing A seal designed with mul-tiple rows of (aluminum alloy) teeth located atthe extremities of the bearing assemblies. Seal-ing air is circulated between the shaft and the sealto prevent oil from passing the seal and spreadingalong the shaft.

GE Power Systems


Lagging The thermal and/or acoustic coveringor enclosure.

Lifting Trunnion Extensions which are inte-grally cast as part of the casing and used to holdslings for lifting purposes.

Lighting Transformer A device usuallyassociated with backfeeding the generator outputof 13.8KV and reducing it to 480/V 3-phase.

Load Shaft The low pressure turbine shaft.

Load Turbine Nozzle The variable angle nozzlebetween the high pressure and low pressure turbinewheels on 2-shaft turbines which is to aproportionenergy distribution between the turbines.

Low Pressure Turbine The load turbine.

Lube Oil Header The main lube oil pipingwhich feeds the turbine bearings, gears, cou-pling, etc.

LVDT Abbreviation for Linear Variable Differ-ential Transformer.

Mist Eliminator A device which removes smalloil droplets from the oil tank vent system prior tothe discharge of the vapor in to the atmosphere.

Model Defines the gas turbine frame size.

Nozzle/Diaphragm Assembly A combinationof the nozzle and the air control device between theturbine stages at the inner side wall.

Nozzle Segment A small number of nozzle parti-tions made as an assembly: multiple assemblieswill constitute a complete nozzle assembly.

Off-Base A part which is not mounted on the ac-cessory, turbine or generator base.

On-Base A part which is mounted on th accesso-ry, turbine or generator base.

Outer Combustion Casing A cover that pro-vides a pressure vessel and an air flow path.

Overspeed Bolt A spring loaded sliding rod,which is located in the accessory gear box monutedon the shaft connected to the turbine rotor, and me-chanically senses a rotor overspeed condition andgenerates a trip independent of the electrical over-speed protection system.

Pad Support pads located on all base mountedassemblies.

Partition The airfoil shaped stator portion of thenozzle assembly.

Peak Load The load reached at the peak exhausttemperature control setpoint (above the base loadsetpoint) which produces more power but reducesthe life expectancy of the turbine parts.

Peak Reserve A short term rating (seldom used)for getting maximum power, recognizing that thisdrastically reduces the life of the hot section turbineparts.

Platform The portion of a turbine bucket be-tween the airfoil shape and the shank.

Plenum An enclosure which contains a volumeof air (i.e. inlet) or exhaust gas (i.e. exhaust).

Power Plant A comprehensive term for the com-ponents which are contained in an integrated powersystem.

Pre-cooler The air cooler upstream of the mainatomizing air compressor.

Pre-selected Load An adjustable, pre-desig-nated load point between spinning reserve and baseload.

Pressure Ratio The ratio of the compressor dis-charge pressure to the inlet pressure.

Pulsation Protection A mechanical network de-signed to prevent surge/pulsation during off-speedconditions of the compressor.

Pump, Centrifugal A non-positive displace-ment pump designed to use a rotor impeller in anenclosure as a means of transferring a fluid fromone place to another.

GE Power Systems


Pump, Gear A positive displacement pump thatconsists of a drive gear and driven gear mounted ina housing. The working medium travels from theintake port around the outside of the gear to the out-let port.

Regenerative Cycle The working cycle whichrecovers a portion of the exhaust heat to reduce thecycle heat input required to read cycle operatingtemperatures. The working medium passes throughcompressor, regenerator, combustor, turbine andregenerator.

Regenerator A heat exchanger used to transferheat from the exhaust gas to the working fluid be-fore it enters the combustor.

Rotor The rotating part of an assembly which isusually surrounded by a stator or stationary casing.

RTD Abbreviation for a Resistance TemperatureDetector.

SFC Specific fuel consumption (i.e. lbs/BHP-HR) defined for a given fuel heating value.

Shaft Horsepower The power developed at theinput or output shaft.

Shank The portion of a bucket between the plat-form and the dovetail.

Shroud A segmented part located adjacent to theblade tips which is used to limit the working fluidleakage.

Silencer A section of the inlet or exhaust of a gasturbine designed to reduce the sound level of airpassing through it.

Simple Cycle A cycle where the working fluidpasses directly through the compressor, combustorand turbine (without heating/cooling).

Single Shaft Turbine A gas turbine whose rotat-ing components, (compressor and turbine) are ar-ranged on one shaft.

Soleplates Individually grouted-in foundationplates used for mounting and supporting the pads ofthe gas turbine bases.

Spinning Reserve The minimum load controlpoint based on generator output.

Stage The combination of one row of statorblades or nozzles with one row of rotor blades orbuckets.

Starting Clutch The (overrunning, hydraulical-ly positioned jaw) clutch which connects the torqueconverter or turning gear output to the accessorygear box and disengages when the turbine reachesself-sustaining speed.

Starting Device The machine part used to pro-duce adequate torque for the starting system. Sometypes of starting devices are:

1. Diesel Engine

2. Electric Motor

3. Steam Turbine

4. Natural Gas Expansion Turbine

5. Turbine Impingement

6. Air motor

Stator The stationary part of an assembly usuallysurrounding a rotating component or rotor.

Stub Shaft A hollow cylindrical section integralwith the first stage compressor wheel.

Thermocouple A pair of dissimilar metalsjoined in series to form a closed circuit, which willgenerate a thermo-electric current when heated.

Thrust Bearing An active or inactive machinepart which absorbs the axial thrust of the rotatingshaft.

Tie Bolt A large bolt used to assemble the com-pressor rotor wheels.

Torque Converter A hydraulic device coupledto the turbine starting means which transfers and



GE Power Systems


amplifies torque causing turbine compressor shaftrotation during start up.

Transition Piece A thin walled duct used toconduct the combustion gases from the circularcombustion chambers to the annular turbinenozzle passage.

Turbine Stage A set of stationary nozzles andone row of moving buckets mounted on a wheel.The working medium expands through the station-ary nozzle to a lower pressure causing kinetic ener-gy to be transfered to the moving buckets.

Turbine Wheels Discs on the gas turbineshaft which are used to mount buckets on thewheel periphery.

Turning Gear The machine part which is used tobreak the turbine away while starting and rotate theshaft during cooldown and inspection.

Two-shaft Turbine A turbine arrangementwhere the high pressure and low pressure turbinestages are only coupled aerodynamically and run atdifferent speeds.

Valve, Pressure Regulating A valve designedfor continuous automatic control of pressure.

Valve, Relief A valve that automatically main-tains a maximum, predetermined pressure by dis-charging or bypassing the fluid in a system.

Valve, Servo A hydraulically powered valvewith provisions for direct control (i.e. position-ing) in direct relation with a primary control of acomparatively low level of force. Used for pro-portional control.

Valve, Solenoid A valve specifically designed tocontrol the flow of fluid by means of the magneticaction of an electric coil on a movable core orplunger, which actuates the valve stem or pilotneedle. Used for on-off control.

Valve, Temp. Regulating A self-acting valvedesigned for controlling the flow of fluids via athermostatic element located in the fluid.

Vane An airfoil used to direct the flow of air or gas.

Water Removal Filter A device which removessuspended water from the lube oil.

Wheelspace Temperature The temperature ofthe air in close proximity to the surface of the tur-bine wheel below the platform surface of the tur-bine buckets.

A00029b 1 BASIC CONTROL DEVICE FUNCTION NUMBERS

BASIC CONTROL DEVICE FUNCTION NUMBERSAMERICAN NATIONAL STANDARDS INSTITUTE

1 MASTER ELEMENT 50 INSTANTANEOUS OVERCURRENT orRATE–of–RISE RELAY

2 SEQUENCE TIMER 51 AC TIME OVERCURRENT RELAY

3 CHECKING RELAY 52 AC CIRCUIT BREAKER or CONTACTOR

4 MASTER RELAY 55 POWER FACTOR RELAY

5 STOPPING DEVICE 57 SHORT CIRCUITING or GROUNDING DEVICE

6 STARTING CIRCUIT BREAKER 59 OVERVOLTAGE RELAY

8 CONTROL POWER DISCONNECTING DEVICE 60 VOLTAGE or CURRENT BALANCE RELAY

10 UNIT SEQUENCE SWITCH 62 STOPPING or OPENING TIMER RELAY

12 OVERSPEED DEVICE 63 LIQUID or GAS PRESSURE or VACUUM

13 SYNCHRONOUS SPEED DEVICE 64 GROUND PROTECTIVE RELAY

14 SPEED RELAY 65 GOVERNOR

15 SPEED or FREQUENCY MATCHING DEVICE 66 NOTCHING or JOGGING DEVICE

18 ACCELERATING or DECELERATING DEVICE 67 AC DIRECTIONAL OVERCURRENT RELAY

20 SOLENOID VALVE 68 BLOCKING RELAY

21 DISTANCE RELAY 69 PERMISSIVE CONTROL DEVICE

23 TEMPERATURE CONTROL DEVICE 70 ELECTRICALLY OPERATED RHEOSTAT

25 SYNCHRONISM CHECK DEVICE 71 LIQUID or GAS LEVEL RELAY

26 TEMPERATURE SENSING DEVICE 72 DC CIRCUIT BREAKER or CONTACTOR

27 UNDERVOLTAGE 75 POSITION CHANGING MECHANISM

28 FLAME DETECTOR 77 PULSE TRANSMITTER

30 ANNUNCIATOR RELAY 80 LIQUID or GAS FLOW RELAY

32 DIRECTIONAL POWER RELAY 81 FREQUENCY RELAY

33 POSITION SWITCH 82 DC RECLOSING RELAY

34 MASTER SEQUENCE DEVICE 83 AUTOMATIC SELECTIVE CONTROL orTRANSFER RELAY

37 UNDERCURRENT or UNDERPOWER RELAY 84 OPERATING MECHANISM

38 BEARING PROTECTIVE DEVICE 85 CARRIER or PILOT–WIRE RECEIVER RELAY

39 MECHANICAL CONDITION MONITOR 86 LOCK–OUT RELAY

40 FIELD RELAY 87 DIFFERENTIAL PROTECTIVE RELAY

41 FIELD CIRCUIT BREAKER 88 AUXILIARY MOTOR or MOTOR GENERATOR

43 MANUAL TRANSFER or SELECTOR DEVICE 89 LINE SWITCH

45 ATMOSPHERIC CONDITION MONITOR 90 REGULATING DEVICE

46 REVERSE–PHASE or PHASE–BALANCECURRENT RELAY

91 VOLTAGE DIRECTIONAL RELAY

47 PHASE–SEQUENCE VOLTAGE RELAY 93 FIELD–CHANGING CONTACTOR

48 INCOMPLETE SEQUENCE RELAY 94 TRIPPING or TRIP–FREE RELAY

49 MACHINE or TRANSFORMER THERMALRELAY

96 TRANSDUCER

A00029b 2 BASIC CONTROL DEVICE FUNCTION NUMBERS



GE Power SystemsGenerator

Revised, June 2001GEK 95149C


International Conversion Tables

Category To convert from To Multiply by +

ACCELERATION Ft/sec2 meter/sec2 3.048 E-01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . In/sec2 meter/sec2 2.540 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

AREA Ft2 meter2 9.290 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . In2 meter2 6.452 E–04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TORQUE

dyne⋅cm newton meter 1.000 E-07. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . kilogram-force⋅meter newton meter 9.807 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . lb-force⋅inch newton meter 1.130 E-01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf⋅foot newton meter 1.356 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ozf⋅foot newton meter 7.062 E-03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TORQUE/LENGTH lbf⋅ft/in newton m/m 5.338 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf⋅in/in newton m/m 4.448 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ELECTRICITYandMAGNETISM

amp hr coulomb 3.600 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . faraday (chem) coulomb 9.650 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gauss tesla 1.000 E–04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gilbert amp-turn 7.958 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . maxwell weber 1.000 E–08. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . oersted amp/meter 7.958 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . unit pole weber 1.257 E–07. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

ENERGY(Includes Work)

Btu* joule 1.054 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft⋅lb-force joule 1.356 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . kilowatt hr joule 3.600 E+06. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . watt⋅sec joule 1.000 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft⋅poundal joule 4.214 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FORCE

kg-force newton 9.807 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . oz-force newton 2.780 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lb-force newton 4.448 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . poundal newton 1.383 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

FORCE/LENGTH lb-force/in newton/meter 1.751 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lb-force/ft newton/meter 1.459 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

HEAT

Btu* in/sec ft2 deg F watt/meter K 5.189 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu* in/hr ft2 deg F water/meter K 1.441 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu* /ft2 joule/meter2 1.135 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu* /hr ft2 deg F joule/kg K 5.674 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu*/lbm deg F joule/kg K 4.184 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu*/sec ft2 deg F watt/meter2 K 2.043 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . cal/cm2 joule/meter2 4.184 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cal/cm2 sec watt/meter2 4.184 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cal/cm sec deg C watt/meter K 4.184 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cal*/g joule/kg 4.184 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . cal*/g deg C joule/kg K 4.184 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

LENGTH

foot meter 3.048 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . inch meter 2.540 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . foot millimeter (mm) 3.048 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . inch millimeter (mm) 25.40 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

+E Indicates the power of 10 by which the number must be multiplied, i.e., 4.047E+03 = 4.047 x 103.*Thermochemical


GE Power Systems

GEK 95149C International Conversion Tables

Category To convert from To Multiply by +

MASSoz mass (av) kilogram 2.835 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lb-mass (av) kilogram 4.536 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ton (2000 lbm) kilogram 9.072 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

MASS/VOLUME(Includes Density)

lbm/ft3 kilogram/meter3 1.602 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbm/in3 kilogram/meter3 2.768 E+04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . oz-mass (av)/in3 kilogram/meter3 1.730 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . lb-mass (av)/gal kilogram/meter3 1.198 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . g/cm3 kilogram/meter3 1.000 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

POWER

Btu*/sec watt 1.054 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu*/min watt 1.757 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Btu*/hr watt 2.929 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cal*/sec watt 4.184 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cal*/min watt 6.973 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft⋅lb force/hr watt 3.766 E–04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft⋅lb force/min watt 2.260 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft⋅lb force/sec watt 1.356 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . hp (elec) watt 7.460 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

PRESSURE(Force/Area)

atm (760 Torr) pascal 1.013 E+05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . bar pascal 1.000 E+05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . dyne/cm2 pascal 1.000 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gram (force)/cm2 pascal 9.807 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . in of Hg (60 F) pascal 3.377 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . in of water (60 F) pascal 2.488 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lb-force/ft2 pascal 4.788 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf/ft2 kg/m2 4.882 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf/in2 (psi) pascal 6.895 E+03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf/in2 kg/cm2 7.037 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Torr (mm Hg, 0 C) pascal 1.333 E+02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

TEMPERATUREdegree Celsius (°C) degree Kelvin (K) TK = tC + 273.15. . . . . . . . . . . . . . . . . . . . . . . . . degree Farenheit (°F) degree Celsius tC = (tF - 32)/1.8. . . . . . . . . . . . . . . . . . . . . . . . . degree Celsius degree Farenheit tF = (tC ⋅ 1.8)+32. . . . . . . . . . . . . . . . . . . . . . . . . . . . .

VELOCITY(Includes Speed)

ft/hr meter/sec 8.467 E–05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft/min meter/sec 5.080 E–03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft/sec meter/sec 3.048 E–01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . in/sec meter/sec 2.540 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

VISCOSITYft2/sec meter2/sec 9.290 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbm/ft sec pascal–sec 1.488 E+00. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . lbf sec/ft2 pascal–sec 4.788 E+01. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

VOLUME(Includes Capacity)

ft3 meter3 2.832 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gallon (US) meter3 3.785 E–03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . inch3 meter3 1.639 E–05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . liter meter3 1.000 E–03. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . oz (US fluid) meter3 2.957 E–05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

VOLUME/TIME(Includes Flow)

ft3/min meter3/sec 4.719 E–04. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ft3/sec meter3/sec 2.832 E–02. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . in3/min meter3/sec 2.731 E–07. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . gal/min meter3/sec 6.309 E–05. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

+E Indicates the power of 10 by which the number must be multiplied, i.e., 4.047E+03 = 4.047 x 103.*Thermochemical

Gas Turbine Operation

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