GE Gas Turbine Training Manual

Technology for Gas Turbines

Siemens Power Generation GE Gas Turbine Training

Siemens Power Generation

Alpharetta, GA

September, 2006

GE Gas Turbine Training

GE GAS TURBINE CONTROLS PHILOSOPHY

Training Program Presented by

Turbine Technology Services Corporation 424 E. Central Blvd., Ste. 316

Orlando, FL 32801 Tel: 407-677-0813 Fax: 407-386-6293


GE Gas Turbine Training Siemens Power Generation

This text and the classroom instruction are designed to acquaint the attending students with GE Gas Turbine Controls Philosophy and will focus on equipment originally manufactured by the General Electric Company (hereafter OEM). The courseware does not purport to be complete nor is it intended to be specific for the products of the OEM or other contributing companies. TTS will accept no liability whatsoever for work undertaken on the basis of this text or associated classroom instruction. The OEM instruction books, including current revisions of the Control Specifications, should always be used whenever fieldwork is undertaken.

TMS. All rights Reserved.


Siemens Power Generation Table of Contents

Table of Contents

Course Introduction..............................................................................Section 1

Introduction to Gas Turbine Controls Philosophy GE Gas Turbine Fleet ...........................................................................Section 2 GE Control System Evolution..............................................................Section 3 GE Control System Fundamentals ......................................................Section 4 GE Control System Documentation ....................................................Section 5


Introduction 1.0

INTRODUCTION


Course Introduction 1.0 Siemens Power Generation

Siemens Power Generation

September 2006

GE Gas Turbine Training GE GAS TURBINE CONTROLS PHILOSOPHY

Equipment Models: GE Gas Turbine Controls: SpeedtronicTM Applications: Generator Drive Prerequisite It is highly recommended that participant attending this seminar have some experience operating or maintaining General Electric gas turbines, or have previously attended a TTS or GE training course on the same subject. Goal The goal of this course is to introduce the SpeedtronicTM Control System as applied to General Electric manufactured gas turbines, through a better understanding of the normal operation of the control and protection systems. Objectives Upon successful completion of this school, using the text materials provided, the gas turbine instruction books and unit schematic piping diagrams, control specifications and electrical elementary diagrams, the participant should be able to: 1. Identify GE Unit Types eg. MS5001 2. Identify GE SpeedtronicTM Control System eg. SpeedtronicTM Mark II 3. Understand GE Gas Turbine Design 4. Understand Gas Control Loops eg. Speed Control


Introduction to GE Gas Turbine Controls Philosophy - Course Outline 1.1

Course Outline

(Subject titles are general and times are approximate)

Course Introduction Explain the goal and objectives for the course. Introduction to GE Gas Turbine Controls Philosophy GE Gas Turbine Fleet GE Control System Evolution

• Fuel Regulator • SpeedtronicTM Mark I • SpeedtronicTM Mark II • SpeedtronicTM Mark II with ITS • SpeedtronicTM Mark IV • SpeedtronicTM Mark V • SpeedtronicTM Mark VI

GE Control System Fundamentals

• Basic Design • Startup Control • Speed Control • Temperature Control • Fuel Control

o Liquid Fuel o Gas Fuel

• IGV Control • Protection

o Trip Circuit o Overspeed o Over Temperature o Flame Detection o Combustion Monitor


Introduction to GE Gas Turbine Controls Philosophy - Course Outline 1.2

GE Control System Documentation

1.1 Piping and Instrumentation Drawing (PI&D) 1.2 Device Summary 1.3 Control Specification 1.4 Turbine Elementary 1.5 Turbine Connection Diagram 1.6 Motor Control Center Connection Diagram 1.7 Generator control Panel Connection Diagram 1.8 Control Sequence Program (CSP) 1.9 CSP Cross Reference 1.10 Alarm List 1.11 I/O Reports

Review


GE Gas Turbine Fleet 2.0

GE GAS TURBINE FLEET

GAS TURBINE AND COMBINED CYCLE PRODUCTS

GEEnergy

The Power of Technology, Experience and Innovation

The world demands a reliable supply of clean, dependable power. Always on the cutting edge of gas

turbine technology, GE offers a wide array of technological options to meet the most challenging

energy requirements. Using an integrated approach that includes parts, service, repair and project

management, we deliver results that contribute to our customers’ success. And our reputation for

excellence can be seen in everything we do.

MS6001FA

CC 117.7 MW 50 Hz 6,240 6,582CC 118.1 MW 60 Hz 6,250 6,593SC 75.9 MW 50 Hz 9,760 10,295SC 75.9 MW 60 Hz 9,795 10,332

2

2

6

6

8

8

10

11

12

13

14

16

GE ENERGYGAS TURBINE AND COMBINED CYCLE PRODUCTS

CC 520 MW 50 Hz 5,690 6,000

Btu/kWh kJ/kWh

CC 400 MW 60 Hz 5,690 6,000

CC 412.9 MW 50 Hz 5,880 6,202

CC 280.3 MW 60 Hz 5,950 6,276

CC 262.6 MW 60 Hz 6,090 6,424SC 171.7 MW 60 Hz 9,360 9,873

CC 390.8 MW 50 Hz 6,020 6,350SC 255.6 MW 50 Hz 9,250 9,757

CC 193.2 MW 50 Hz 6,570 6,930SC 126.1 MW 50 Hz 10,100 10,653

CC 130.2 MW 60 Hz 6,800 7,173SC 85.1 MW 60 Hz 10,430 11,002

CC 67.2 MW 50 Hz 6,281 6,627CC 67.2 MW 60 Hz 6,281 6,627SC 45.4 MW 50 Hz 9,315 9,830SC 45.3 MW 60 Hz 9,340 9,855

CC 64.3 MW 50 Hz 6,950 7,341CC 64.3 MW 60 Hz 6,960 7,341SC 42.1 MW 50/60 Hz 10,642 11,226

MS9001H

MS7001H

MS9001FB

MS7001FB

MS7001FA

MS9001FA

MS9001E

MS7001EA

MS6001C

MS6001B

Heavy Duty

Small Heavy-Duty and Aeroderivative Gas Turbine Products Overview

IGCC (Integrated Gasification Combined Cycle) Overview

NOTE: All ratings are net plant based on ISO conditions and natural gas fuel.All CC ratings shown above are based on a 1 GT/1 ST configuration.

8

OutputHeat Rate

World’s Most Advanced Combined Cycle Gas Turbine Technology

GE’s H System™—the world’s most advanced combined cycle system and the first capable of breaking

the 60% efficiency barrier—integrates the gas turbine, steam turbine, generator and heat recovery steam

generator into a seamless system, optimizing each component’s performance. Undoubtedly the leading

technology for both 50 and 60 Hz applications, the H delivers higher efficiency and output to reduce the

cost of electricity of this gas-fired power generation system.

Closed-Loop Steam Cooling

Open loop air-cooled gas turbines have a significant temperature drop across the first stage nozzles, which

reduces firing temperature and thermal efficiency. The closed-loop steam cooling system allows the turbine

to fire at a higher temperature for increased performance. It is this closed-loop steam cooling that enables

the H System™ to achieve 60% fuel efficiency capability while maintaining adherence to the strictest low NOx

standards and reducing CO2 emissions. Additionally, closed-loop cooling also minimizes parasitic extraction

of compressor discharge air, thereby allowing more air to flow to the combustor for fuel premixing, thereby

enabling lower emissions.

H System™

2

H S

YS

TE

M™

An MS9001H is seen during

assembly in the factory.

Baglan Bay Power Station is the

launch site for GE’s H System™.

RDC

2790

3-13

-03

PSP3

0462

-05

520 5,690 6,000 60.0% 1 x MS9001H

MS9001H/MS7001H COMBINED CYCLE PERFORMANCE RATINGS

Net PlantOutput (MW)

S109H

50 H

z60

Hz

(Btu/kWh)Heat Rate

(kJ/kWh)Net PlantEfficiency

GT Number& Type

400 5,690 6,000 60.0% 1 x MS7001HS107H

Single Crystal Materials

The use of these advanced materials and Thermal Barrier Coatings ensures that components will stand

up to high firing temperatures while meeting maintenance intervals.

Dry Low NOx Combustors

Building on GE’s design experience, the H System™ employs a can-annular lean pre-mix DLN-2.5

Dry Low NOx (DLN) Combustor System. Fourteen combustion chambers are used on the 9H, and

12 combustion chambers are used on the 7H. GE DLN combustion systems have demonstrated

the ability to achieve low NOx levels in several million hours of field service around the world.

Small Footprint/High Power Density

The H System™ offers approximately 40% improvement in power density per installed megawatt

compared to other combined cycle systems, once again helping to reduce the overall cost of

producing electricity.

Thoroughly Tested

The design, development and validation of the H System™ has been conducted under a regimen of extensive

component, sub-system and full unit testing. Broad commercial introduction has been controlled to follow

launch units demonstration. This thorough testing approach provides the introduction of cutting edge tech-

nology with high customer confidence.

3

H S

YS

TE

M™

World’s first H turbine is transported

through Wales to Baglan Bay Power Station.

PSP3

0246

-10

RDC

2791

6-09

-09

A 9H gas turbine is

readied for testing.

World’s Most Experienced Advanced Technology Gas Turbines

With over ten million hours of operation, our F class turbines have established GE as the clear industry

leader for successful fired hours in advanced technology gas turbines. Representing the world’s largest,

most experienced fleet of highly efficient gas turbines, designed for maximum reliability and efficiency

with low life cycle costs, our F class turbines are favored by both power generators and industrial

cogenerators requiring large blocks of reliable power.

Introduced in 1987, GE’s F class gas turbines resulted from a multi-year development program using

technology advanced by GE’s aircraft engine team and GE Global Research. GE continually advances

this technology by incrementally improving the F class product to attain ever higher combined cycle

efficiencies, while maintaining reliability and availability.

F Class

4

F C

LA

SS

Dry Low NOx combustor systems allow

GE’s F Class turbines to meet today’s strict

environmental emissions requirements.

RDC

2730

5-02

a

An MS9001FA gas turbine

ships from the plant.

PSP3

0027

-06

5

F C

LA

SS

Our F class gas turbines, including the 6F (either 50 or 60 Hz), the 7F (60 Hz) and the 9F (50 Hz), offer

flexibility in cycle configuration, fuel selection and site adaptation. All F class gas turbines include an

18-stage axial compressor and a three-stage turbine, and they feature a cold-end drive and axial exhaust,

which is beneficial for combined cycle arrangements where net efficiencies over 58% can be achieved.

F/FA/FB EXPERIENCE

0

2000

4000

6000

8000

10000

12000

14000

’95 ’96 ’97 ’98 ’99 ’00 ’01 ’02 ’03 ’04 ’05

FIRE

D H

OU

RS IN

TH

OU

SAN

DS

YEAR

11,84411,594

10,327

9,061

7,7946,859

5,7904,899

4,1863,575

2,989

Half of all 6FA installations are located in

Europe. This CHP plant is owned by Porvoo,

Finland.

PSP3

0114

PSP3

0210

-01

World’s Most Advanced Air-Cooled Gas Turbine

The FB is the latest evolutionary step in GE’s proven F series. Taking F technology to a new level of output

and efficiency, we’ve applied our cutting-edge technology, including the materials developed for the

H System™, and the experience gained in over ten million advanced gas turbine fired hours. The result is a

large combined cycle system designed to provide high performance and low electrical cost.

Improved output and efficiency means better fuel economy and reduced cost of producing electricity. With

today’s competitive markets and unpredictable fuel prices, this—now more than ever—is the key to success.

MS7001FB and MS9001FB

6

MS

70

01

FB

an

d M

S9

00

1F

B

This MS7001FB is shown in

the factory.

This MS9001FB is seen on half shell

during assembly.

PSP3

0251

-39

PSP3

0510

-01

Hunterstown, PA 7FB launch site.

PSP3

0371

-02

7

MS

70

01

FB

an

d M

S9

00

1F

B

In developing the FB, we followed a specific course that significantly improved the key driver of efficiency—

firing temperature. The FB firing temperature was increased more than 100 degrees Fahrenheit over GE’s FA

technology, resulting in combined cycle efficiency rating improvements of better than one percentage

point. Output improvements of more than 5% were also achieved. These improvements equate to more MW

per MBtu of natural gas burned.

The use of advanced turbine materials, such as Single Crystal First Stage Buckets, ensures that components

can stand up to the higher firing temperatures of the FB without an increase in maintenance intervals.

Providing the basis of process rigor, Six Sigma methodologies were used to assure a highly reliable robust

design optimized for lowest cost of electricity. Indeed, in developing the FB, we were able to maintain many

of the proven features of the world’s most successful advanced technology turbine, the F/FA.

An MS7001FB is

seen in test cell.

PSP3

0266

-02

PSP3

0299

412.9 5,880 6,202 58.0% 1 x MS9001FB


S109FB

50 H

z

(Btu/kWh)Heat Rate


GT Number& Type

60 H

z

825.4 5,884 6,206 58.0% 2 x MS9001FBS209FB

280.3 5,950 6,276 57.3% 1 x MS7001FBS107FB

562.5 5,940 6,266 57.5% 2 x MS7001FBS207FB

MS7001FB/MS9001FB COMBINED CYCLE PERFORMANCE RATINGS

8

MS

60

01

FA,

MS

70

01

FA a

nd

MS

90

01

FA

MS6001FA, MS7001FA and MS9001FA

Proven Performance in a Mid-Size Package

The highly efficient gear-driven 6FA gas turbine is a mid-size version of the well-proven 7FA and 9FA. Its

output range, high exhaust energy, full packaging and robust design ideally suit applications ranging from

cogeneration and district heating to pure power generation in combined cycle and Integrated Gasification

Combined Cycle (IGCC).

To meet the need for mid-size power blocks with high performance in combined heat and power

applications, the high-speed 6FA produces 75.9 MW of simple cycle power at 35% efficiency and

117 MW of combined cycle power at 54.7% net efficiency. In IGCC operation, gross plant efficiencies

can reach up to 46%.

A classic example of GE’s evolutionary designs, the 6FA is a 2/3 scale of the 7FA. Its aerodynamically

scaled 18-stage axial design reduces combustion chambers from 14 to 6. A cold-end drive allows exhaust

gases to be directed axially into the HRSG. With over 860,000 operating hours and 61 units installed or on

order, the 6FA provides major fuel savings over earlier mid-range units in base-load operation. Adaptable

to single or multi-shaft configurations, it burns a variety of fossil fuels, which can be switched after start-up

without sacrificing performance. On natural gas the available Dry Low NOx (DLN) system can achieve NOx

emissions of 15 ppm.

Industry Standard for 60 Hz Power in All Duty Cycles

The wide range of power generation applications for the 7FA gas turbine includes combined cycle, cogenera-

tion, simple cycle peaking and IGCC in both cycle and base load operation with a wide range of fuels. Its high

reliability—consistently 98% or better—provides customers more days of operation per year while minimizing

overall life cycle cost.

RDC

2783

4-34

117.7 6,240 6,582 54.7% 1 x MS6001FA

MS6001FA COMBINED CYCLE PERFORMANCE RATINGS

MS6001FA SIMPLE CYCLE PERFORMANCE RATINGS


S106FA

50 H

z

(Btu/kWh)Heat Rate


GT Number& Type

60 H

z

237.9 6,170 6,508 55.3% 2 x MS6001FAS206FA

118.1 6,250 6,593 54.6% 1 x MS6001FAS106FA

237.5 6,210 6,550 54.9% 2 x MS6001FAS206FA

(MW) 75.9 75.9

50 Hz Power Generation

Output


(Btu/kWh) 9,760 9.795(kJ/kWh) 10,295 10,332

Heat Rate

15.6:1 15.7:1Pressure Ratio

(lb/sec) 447 449(kg/sec) 203 204

Mass Flow

(rpm) 5,231 5,254Turbine Speed

(ºF) 1,117 1,118(ºC) 603 603

Exhaust Temperature

PG6111FA PG6111FAModel Designation

KEPCO’s Seoinchon Plant, one

of the world’s largest combined

cycle plants, has operated

for more than 40,000 hours in

daily start/stop cyclic duty.

9As an industry leader in reducing emissions, the 7FA’s DLN-2.6 combustor (proven in hundreds of thousands

of operating hours) produces less than 9 ppm NOx and CO—minimizing the need for exhaust cleanup sys-

tems and saving millions for our customers.

With 100s of units in operation, GE continually makes incremental design enhancements to improve output,

efficiency, reliability and availability—for new units and upgrades to existing units. GE adds customer value

with power augmentation equipment that provides additional gas turbine performance in summer peak

demand periods—including inlet cooling, steam injection, and peak firing.

Proven Excellence in Reliable 50 Hz Combined Cycle Performance

Power producers around the world require reliable power generation—which makes the 9FA the 50 Hz gas

turbine of choice for large combined cycle applications. As an aerodynamic scale of the highly successful

7FA gas turbine, the 9FA provides key advantages that include a fuel-flexible combustion system and higher

output performance.

The 9FA gas turbine is configured with the robust DLN-2.0+. Ideally suited for diverse fuels, this combustor

is the industry leader in pollution prevention for 50 Hz combined cycle applications with greater than 56%

efficiency, achieving less than 25 ppm NOx.

The 9FA can be configured to meet site and power requirements. For re-powering applications with space

limitations, it can be configured in a single-shaft combined cycle arrangement with the generator and steam

turbine. For large combined cycle or cogeneration plants where flexible operation and maximum perform-

ance is the prime consideration, it can be arranged in a multi-shaft configuration where one or two gas

turbines are combined with a single steam turbine to produce power blocks of 390 or 786 MW.

MS

60

01

FA, M

S7

00

1FA

an

d M

S9

00

1FA

262.6 6,090 6,424 56.0% 1 x MS7001FA




S107FA

60 H

z

(Btu/kWh)Heat Rate


GT Number& Type

529.9 6,040 6,371 56.5% 2 x MS7001FAS207FA

(MW) 171.7


Output

(Btu/kWh) 9,360(kJ/kWh) 9,873

Heat Rate

16.0:1Pressure Ratio

(lb/sec) 981(kg/sec) 445

Mass Flow

(rpm) 3,600Turbine Speed

(ºF) 1,114(ºC) 601

Exhaust Temperature

PG7241FAModel Designation

390.8 6,020 6,350 56.7% 1 x MS9001FA




S109FA

50 H

z

(Btu/kWh)Heat Rate


GT Number& Type

786.9 5,980 6,308 57.1% 2 x MS9001FAS209FA

(MW) 255.6


Output

(Btu/kWh) 9,250(kJ/kWh) 9,757

Heat Rate


(lb/sec) 1,413(kg/sec) 641

Mass Flow


(ºF) 1,116(ºC) 602

Exhaust Temperature

PG9351FAModel Designation

Fuel-Flexible 50 Hz Performer

The MS9001E gas turbine is GE’s 50 Hz workhorse. With more than 390 units, it has accumulated over

14 million fired hours of utility and industrial service, many in arduous climates ranging from desert heat

and tropical humidity to arctic cold. Originally introduced in 1978 at 105 MW, the 9E has incorporated

numerous component improvements. The latest model boasts an output of 126 MW and is capable of

achieving more than 52% efficiency in combined cycle.

Whether for simple cycle or combined cycle application, base load or peaking duty, 9E packages are

comprehensively engineered with integrated systems that include controls, auxiliaries, ducts and silencing.

They are designed for reliable operation and minimal maintenance at a competitively low installed cost.

Like GE’s other E-class technology units, the Dry Low NOx combustion system is available on 9E, which can

achieve NOx emissions under 15 ppm when burning natural gas.

With its flexible fuel handling capabilities, the 9E accommodates a wide range of fuels, including natural

gas, light and heavy distillate oil, naphtha, crude oil and residual oil. Designed for dual-fuel operation,

it is able to switch from one fuel to another while running under load. It is also able to burn a variety of

syngases produced from oil or coal without turbine modification. This flexibility, along with its extensive

experience and reliability record, makes the 9E well suited for IGCC projects.

In simple cycle, the MS9001E is a reliable, low first-cost machine for peaking service, while its high

combined cycle efficiency gives excellent fuel savings in base load operations. Its compact design

provides flexibility in plant layout as well as the easy addition of increments of power when a phased

capacity expansion is required.

MS9001E

10

MS

90

01

E

The MS9001E gas turbine

is designed to attain high

availability levels and low

maintenance costs, resulting

in extremely low total cost

of ownership.

RDC

2621

3-12

193.2 6,570 6,930 52.0% 1 x MS9001E

MS9001E COMBINED CYCLE PERFORMANCE RATINGS

MS9001E SIMPLE CYCLE PERFORMANCE RATINGS


S109E

50 H

z

(Btu/kWh)Heat Rate


GT Number& Type

391.4 6,480 6,835 52.7% 2 x MS9001ES209E

(MW) 126.1


Output

(Btu/kWh) 10,100(kJ/kWh) 10,653

Heat Rate



Mass Flow


(ºF) 1,009(ºC) 543

Exhaust Temperature

PG9171EModel Designation

11

MS

70

01

EA

Time-Tested Performer for 60 Hz Applications

With more than 750 units in service, the 7E/EA fleet has accumulated tens of millions of hours of service

and is well recognized for high reliability and availability.

With strong efficiency performance in simple and combined cycle applications, this 85 MW machine is

used in a wide variety of power generation, industrial and cogeneration applications. It is uncomplicated

and versatile; its medium-size design lends itself to flexibility in plant layout and fast, low-cost additions

of incremental power.

With state-of-the-art fuel handling equipment, advanced bucket cooling, thermal barrier coatings and

a multiple-fuel combustion system, the 7EA can accommodate a full range of fuels. It is designed for dual-

fuel operation, able to switch from one fuel to another while the turbine is running under load or during

shutdown. 7E/EA units have accumulated millions of hours of operation using crude and residual oils.

In addition to power generation, the 7EA is also well suited for mechanical drive applications.

MS7001EA

An MS7001EA is shown on half shell

during assembly.

GT2

0821

130.2 6,800 7,173 50.2% 1 x MS7001EA

MS7001EA COMBINED CYCLE PERFORMANCE RATINGS

MS7001EA SIMPLE CYCLE PERFORMANCE RATINGS


S107EA

60 H

z

(Btu/kWh)Heat Rate


GT Number& Type

263.6 6,700 7,067 50.9% 2 x MS7001EAS207EA

(MW) 85.1 (hp) 115,630


Output

Mechanical Drive

(Btu/kWh) 10,430 (Btu/shp-hr) 7,720(kJ/kWh) 11,002

Heat Rate


(lb/sec) 648 (lb/sec) 659(kg/sec) 294 (kg/sec) 299

Mass Flow

(rpm) 3,600 (rpm) 3,600Turbine Speed

(ºF) 997 (ºF) 999(ºC) 536 (ºC) 537

Exhaust Temperature

PG7121EA M7121EAModel Designation

Reliable and Rugged 50/60 Hz Power

The MS6001B is a performance proven 40 MW class gas turbine, designed for reliable 50/60 Hz power

generation and 50,000 hp class mechanical drive service. With availability well documented at 97.1% and

reliability at 99.3%, it is the popular choice for efficient, low installed cost power generation or prime movers

in mid-range service.

With over 980 units in service, the versatile and widely used 6B gas turbine has accumulated over

45 million operating hours in a broad range of applications: simple cycle, heat recovery, combined cycle,

and mechanical drive. It can be installed fast for quick near-term capacity.

The rugged and reliable 6B can handle multiple start-ups required for peak load. It can accommodate a

variety of fuels and is well suited to IGCC. In combined cycle operation the 6B is a solid performer at nearly

50% efficiency. It is also a flexible choice for cogeneration applications capable of producing a thermal

output ranging from 20 to 400 million Btu/hr.

Like all GE heavy-duty gas turbines, the 6B has earned a solid reputation for high reliability and environ-

mental compatibility. With a Dry Low NOx combustion system, the 6B is capable of achieving less than

15 ppm NOx on natural gas.

With its excellent fuel efficiency, low cost per horsepower and high horsepower per square foot, the MS6001B

is an excellent fit for selective mechanical applications.

MS6001B

12

MS

60

01

B

An MS6001B rotor is

seen on half shell.

RDC

2465

6-03

64.3 6,950 7,341 49.0% 1 x MS6001B

MS6001B COMBINED CYCLE PERFORMANCE RATINGS

MS6001B SIMPLE CYCLE PERFORMANCE RATINGS


S106B

50 H

z

(Btu/kWh)Heat Rate


GT Number& Type

60 H

z

130.7 6,850 7,225 49.8% 2 x MS6001BS206B

261.3 6,850 7,225 49.8% 4 x MS6001BS406B

64.3 6,960 7,341 49.0% 1 x MS6001BS106B

130.7 6,850 7,225 49.8% 2 x MS6001BS206B

261.3 6,850 7,225 49.8% 4 x MS6001BS406B

50/60 Hz Power Generation

Output

Mechanical Drive

Heat Rate


Mass Flow

Turbine Speed

Exhaust Temperature

PG6581B M6581BModel Designation

(MW) 42.1 (hp) 58,380

(lb/sec) 311 (lb/sec) 309(kg/sec) 141 (kg/sec) 140

(rpm) 5,163 (rpm) 5,111

(ºF) 1,018 (ºF) 1,011(ºC) 548 (ºC) 544

(Btu/kWh) 10,642 (Btu/shp-hr) 7,650(kJ/kWh) 11,226

MS6001C

High Efficiency 45 MW Class Gas Turbine

The 6C meets the need for low-cost electricity production in heat recovery operations for both 50 and 60 Hz—

including industrial cogeneration, district heating, and mid-sized combined-cycle power plants.

Consistent with GE’s evolutionary design philosophy, the 6C incorporates technologies that have been validated

in service worldwide. This evolutionary approach ensures users of the 6C that they are receiving advanced

but well-proven technology. The Frame 6C builds on the experience and performance of GE’s Frame 6B

technology, proven in more than 45 million hours of service, and also incorporates key features of GE’s

advanced F technology.

The turbine includes components that provide high reliability and maintainability, such as a 12-stage compressor

with fewer parts and removable blades and vanes. NOx emissions are limited to 15 ppm dry when operating

on natural gas, and 42 ppm when burning light distillate with water injection.

Improved operability features include less than 50%

turndown while maintaining emissions guarantees, fast

and reliable starts in 13 minutes, and three stages of

compressor guide vanes for high efficiency at part load.

The 6C also features an F-class modular arrangement

and a Mark VI Speedtronic control system.

13

MS

60

01

C

67.2 6,281 6,627 54.3% 1 x MS6001C

MS6001C COMBINED CYCLE PERFORMANCE RATINGS

MS6001C SIMPLE CYCLE PERFORMANCE RATINGS


S106C

50 H

z

(Btu/kWh)Heat Rate


60 H

z

136.1 6,203 6,544 55.0% 2 x MS6001CS206C

67.2 6,281 6,627 54.3% 1 x MS6001CS106C

136.1 6,203 6,544 55.0% 2 x MS6001CS206C

(MW) 45.4 45.3

50 Hz

Output

60 Hz

(Btu/kWh) 9,315(kJ/kWh) 9,830

9,3409,855

Heat Rate



270122

Mass Flow

(rpm) 7,100 7,100Turbine Speed

(ºF) 1,078(ºC) 581

1,078581

Exhaust Temperature

PG6591CModel Designation

GT Number& Type

PSP3

0646

-02

Akenerji Kemalpasa-Izmir Turkey

206C Combined-Cycle—COD since November 2005

Rigorous field validation tests conducted at the Kemalpasa 6C launch

site confirmed the outstanding operability of the turbine—high

efficiency and low emissions.

A Broad Portfolio of Packaged Power Plants

GE provides a broad range of power packages from 5 MW to nearly 50 MW for simple cycle, combined

cycle or cogeneration applications in the utility, private and mobile power industries. Marine applications

for these machines range from commercial fast ferries and cruise ships to military patrol boats, frigates,

destroyers and aircraft carriers.

Oil & Gas

GE is a world leader in high-technology turbine products and services for the oil & gas industry.

We offer full turnkey systems and aftermarket solutions for production, LNG, transportation, storage,

refineries, petrochemical and distribution systems.

Small Heavy-Duty and Aeroderivative Gas Turbines

14

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AE

RO

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RIV

AT

IVE

GA

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SMALL HEAVY-DUTY GAS TURBINES

Output Pressure Turbine Speed Exhaust Temp.Exhaust Flow

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GE5 5,500 11,130 11,740 14.8:1 16,630 43.1 19.6 1,065 574

GE10 11,250 10,884 11,481 15.5:1 11,000 104.7 47.5 900 482

MS5001 26,830 12,028 12,687 10.5:1 5,094 276.1 125.2 901 483

GE5 7,510 8,080 — 14.6:1 12,500 44.2 20.0 1032 556

GE10 15,575 10,543 — 15.5:1 7,900 103.3 46.9 903 484

MS5002C 38,005 8,814 — 8.8:1 4,670 274.1 123.4 963 517

MS5002E 43,690 8,650 — 10.8:1 4,670 311.7 141.4 948 509

*ISO conditions – natural gas – electrical generator terminals **ISO conditions – natural gas – shaft output

(kW) Ratio (rpm) (lb/sec) (kg/sec) (ºF) (ºC)Heat Rate

(Btu/kWh)

Output Pressure Turbine Speed Exhaust Temp.Exhaust Flow(shp) Ratio (rpm) (lb/sec) (kg/sec) (ºF) (ºC)

Heat Rate(Btu/shp-h)

(kJ/kWh)

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GE Energy’s Oil & Gas products

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midstream, downstream

and distribution applications

around the world.

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AERODERIVATIVE GAS TURBINES60

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LM6000PD Sprint 46,824 8,235 8,686 30.7:1 3,600 290 132 837 447

LM6000PD 42,336 8,308 8,763 29.3:1 3,600 278 126 846 452

LM6000PD (liquid fuel) 40,200 8,415 8,876 28.1:1 3,600 268 122 857 458

LM2500RC 33,394 8,753 9,235 23:1 3,600 201.9 91.6 976 524

LM2500RD 33,165 8,774 9,257 23:1 3,600 201 91 977 525

LM2500PE 23,292 9,315 9,825 19.1:1 3,600 153 69 992 533

LM1600PE 13,769 9,735 10,268 20.2:1 7,900 104 47 894 479

LM2500PH 27,763 8,391 8,850 19.4:1 3,600 167 76 922 494

LM2000PS 17,606 9,587 10,112 15.6:1 3,600 139 63 886 474

LM6000PC 43,471 8,112 8,557 29.1:1 3,600 282 128 824 440

LMS100PB 98,196 7,582 7,872 40:1 3,600 456 207 782 417

LMS100PA 98,816 7,569 7,986 40:1 3,600 458 207.6 780 416

LM6000PC Sprint* 50,080 8,434 8,896 31.3:1 3,600 299 136 819 437

LMS100PA 98,894 7,563 7,979 40:1 3,000 458 208 782 416

LMS100PB 98,359 7,569 7,873 40:1 3,000 456 207 783 417

LM6000PC Sprint* 50,041 8,461 8,925 31.5:1 3,627 302 137 813 434

LM6000PC 42,890 8,173 8,621 29.2:1 3,627 284 129 817 436

LM6000PD Sprint 46,903 8,272 8,725 30.9:1 3,627 292 132 834 446

LM6000PD (liquid fuel) 40,400 8,452 8,915 28.5:1 3,627 272 123 853 456

LM6000PD 41,711 8,374 8,833 29.3:1 3,627 279 127 838 448

LM2500RC 32,916 8,880 9,369 23:1 3,600 202 92 976 524

LM2500RD 32,689 8,901 9,391 23:1 3,600 201 91 977 525

LM2500PH 26,463 8,673 9,148 19.4:1 3,000 168 76 927 497

LM2000PE 22,346 9,630 10,158 18.0:1 3,000 154 70 1001 538

LM1600PE 13,748 9,749 10,283 20.2:1 7,900 104 47 915 491

LM6000PC 59,355 5,941 — 29.1:1 3,600 282 127.9 824 440

LM2500RC 45,740 6,435 — 23:1 3,600 202 92.0 980 527

LM2500RD 45,417 6,450 — 23:1 3,600 200.9 91.1 981 527

LM2500PE 31,164 6,780 — 19.5:1 3,600 152 69.0 976 524

LM2000PE 24,146 6,992 — 15.6:1 3,600 138.6 62.9 885 474

LM1600PE 19,105 7,016 — 20.2:1 7,900 104.3 47.3 915 491

*Sprint 2002 deck is used with water injection to 25 ppmvd for power enhancement. NOTE: Performance based on 59ºF amb. Temp., 60% RH, sea level, no inlet/exhaust losses

on gas fuel with no NOx media unless otherwise specified

Output Pressure Turbine Speed Exhaust Temp.Exhaust Flow(hp) Ratio (rpm) (lb/sec) (kg/sec) (ºF) (ºC)

Heat Rate(Btu/shp-h)

Output Pressure Turbine Speed Exhaust Temp.Exhaust Flow(kW) Ratio (rpm) (lb/sec) (kg/sec) (ºF) (ºC)

Heat Rate(Btu/kWh) (kJ/kWh)

LM2000PS 17,674 9,779 10,315 16.0:1 3,000 142 64 894 479

The Next Generation Power Plant

Making Environmental Compliance Affordable

Integrated Gasification Combined Cycle (IGCC) technology is increasingly important in the world energy

market, where low cost opportunity feedstocks such as coal, heavy oils and pet coke are the fuels of choice.

And IGCC technology produces low cost electricity while meeting strict environmental regulations.

The IGCC gasification process “cleans” heavy fuels and converts them into high value fuel for gas turbines.

Pioneered by GE almost 30 years ago, IGCC technology can satisfy output requirements from 10 MW to

more than 1.5 GW and can be applied in almost any new or re-powering project where solid and heavy

fuels are available.

Optimal Performance

For each gasifier type and fuel, there are vast numbers of technical possibilities. Integrated Gasification

Combined Cycle (IGCC) systems can be optimized for each type of fuel as well as site and environmental

requirements. Using knowledge gained from successfully operating many IGCC units, GE has optimized

system configurations for all major gasifier types and all GE IGCC gas turbine models.

Experience

GE engages experts from throughout the gasification industry at both operating and research levels to

develop the most economical and reliable approaches to IGCC technology. Using the same combined cycle

technology for IGCC that we use for conventional systems, GE offers extensive experience and high levels

of reliability.

IGCC

16

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This 550 MW IGCC is located at the Saras oil

refinery in Sardinia. The three GE 109E single-

shaft combined cycle units have accumulated

over 12,000 hours of syngas operation.

PSP3

0120

Model Syngas Power Rating Model Syngas CC Output Power

Gas Turbines IGCC

GE10 10 MW (50/60 Hz) GE10 14 MW (50/60 Hz)

6B 42 MW (50/60 Hz) 106B 63 MW (50/60 Hz)

7EA 90 MW (60 Hz) 107EA 130 MW (60 Hz)

9E 150 MW (50 Hz) 109E 210 MW (50 Hz)

6FA 90 MW (50/60 Hz) 106FA 130 MW (50/60 Hz)

7FA 197 MW (60 Hz) 107FA 280 MW (60 Hz)

9FA 286 MW (50 Hz) 109FA 420 MW (50 Hz)

7FB 232 MW (60 Hz) 207FB 750 MW (60 Hz)

GE GAS TURBINES FOR IGCC APPLICATIONS

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GE Value

GE is a leading global supplier of power generation technology, energy services and management

systems, with an installed base of power generation equipment in more than 120 countries. GE Energy

provides innovative, technology-based products and service solutions across the full spectrum of the

energy industry.

Industries Served:

■ Commercial and industrial power generation

■ Distributed power

■ Energy management

■ Oil & Gas

■ Petrochemical

■ Gas compression

■ Commercial marine power

■ Energy rentals

Our people, products and services provide enhanced performance, competitive life-cycle costs and

continuous technological innovation with unmatched experience. Our Customer-Centric approach,

combined with Six Sigma quality methodology, assures that customer needs are defined up front and

that performance against customer expectations is measured and managed every step of the way.

17

GE Value

GE is a leading global supplier of power generation technology, energy services and management

systems, with an installed base of power generation equipment in more than 120 countries.

GE Energy provides innovative, technology-based products and service solutions across the full

spectrum of the energy industry.

Our people, products and services provide enhanced performance, competitive life cycle costs

and continuous technological innovation with unmatched experience. Our Customer-Centric

approach, combined with Six Sigma quality methodology, assures that customer needs

are defined up front and that performance against customer expectations is measured and

managed every step of the way.

Industries Served:■ Commercial and industrial

power generation

■ Distributed power

■ Energy management

■ Oil & Gas

■ Petrochemical

■ Gas compression

■ Commercial marine power

■ Energy rentals

GE Energy

4200 Wildwood ParkwayAtlanta, GA 30339

gepower.com

GEA 12985E (06/05)

GAS TURBINE AND COMBINED CYCLE PRODUCTS

GE Energy

GER-3434D

GE Power Generation

GE Gas Turbine Design Philosophy

D.E. Brandt R.R. Wesorick GE Industrial & Power Systems Schenectady, NY

GER-3434D

GE GAS TURBINE DESIGN PHILOSOPHY D.E. Brandt, R.R. Wesorick

GE Industrial 8c Power Systems Schenectady, NY

INTRODUCTION Several important design philosophies have

enabled the GE family of heavy-duty gas turbines to achieve worldwide market leadership. These design philosophies have been important in achieving continuous advances in the state-of- the-art gas turbine technology, and they will continue to guide technological developments. This paper will review the significance of certain GE design philosophies and development objectives for the flange-to-flange gas turbine.

The major elements of this philosophy are the evolution of designs, use of geometric scaling, and thorough preproduction development. The evolution of designs has been highly successful, and this approach will continue to be the basis for further progress. One result of the evolutionary approach is a family of axial-flow compressors whose flow, pressure ratio, and efficiency have been improved in several discrete steps, while retaining the proven reliability of existing designs. The historical development of these compressors will be described. Another result of the evolutionary approach is the MS7001 turbine. It has been improved in performance through six models, the A, B, C, E, EA, F and FA.

A second, highly successful principle of GE’s product line has been geometric scaling of both compressors and turbines. Scaling is based on the principle that one can reduce or increase the physical size of a machine while simultaneously increasing or decreasing rotational speed to produce an aerodynamically and mechanically similar line of compressors and turbines. Application of scaling has allowed the develop ment of the product line by the use of proven compressor and turbine designs. Machines such as the MS1002, MS5001, MS6001, and MS9001 were designed utilizing scaling which maintained geometric similarity with counterpart components in MS3002 and MS7001 units. This results in constant temperatures, pressures,

blade angles, and stresses. Additionally, important cycle parameters are maintained, such as pressure ratio and efficiency. If the scale factor is defined as the ratio of the diameters, then shaft speed varies as the inverse of that ratio. Linear dimensions vary directly as the scale factor; the airflow and power vary with the square of the scale factor; and the weight varies with the cube of the scale factor (Table 1). The vibratory frequencies of the blading, relative to rotational speed and centrifugal stress levels, are the same for all scaled compressors and turbines. Thus, the application of scaling allows maximum uti- lization of available experience.

Table 1 SCALING RATIOS

Scale Fat tor 0.5 1 2

Pressure Ratio 1 1 1 Efficiency 1 1 1 RPM 2 1 0.5 Velocities 1 1 1 Flow 0.25 1 4 Power 0.25 1 4 Weight 0.125 1 8 Stresses 1 1 1 Freq/ROM 1 1 1 Tip Speed 1 1 1

GT202,5

A third element of the GE design philosophy is thorough development. This involves design analysis, quality manufacturing, testing, and feedback from field experience. This philosophy is evidenced by GE’s substantial investment in development and test facilities.

There are several other important considerations which have produced the combination of construction features found in GE-designed heavy-duty gas turbines. For example, the use of relatively common materials such as grey iron and nodular iron in the casings, and low-alloy steel compressor and turbine wheels, allows fab-

1

GER-3434D

rication in many locales using foundry and forg- ing technology common to several equipment industries.

The subjects of fuel flexibility, packaging, and maintenance are also important design considerations and are discussed in other papers. This paper will focus on the development philosophy of the three major gas turbine elements: the compressor, the combustor, and the turbine.

GAS TURBINE DESCRIPTION

The Gas Turbine Cycle

The gas turbine cycle is a constant flow cycle with a constant addition of heat energy. It is commonly referred to as the Brayton Cycle after George Brayton. Figure 1 illustrates this cycle as it is plotted on temperature entropy coordi- nates. The constant pressure lines diverge with increasing temperature and entropy. This diver- gence of the constant pressure lines make the simple cycle gas turbine possible. For all common gas turbines in use today, the lower pressure represents atmospheric pressure, and the upper pressure represents the pressure after compression of the air. Air is compressed from state 1 to state 2 in an axial flow compressor, while heat is added between states 2 and 3 in a combustor. Work is then derived from the expansion of the hot combustion gases from states 3 to 4. Since the expansion from states 3 to 4 yield more work than that required to com- press the air from states 1 to 2, useful work is produced to drive a load such as a generator.

GT17355A

Figure 1. Ideal Brayton Cycle

Figure 1 illustrates the common open cycle gas turbine which is nearly universal for power generation, mechanical drive, and aircraft applications. Other cycles such as reheat cycles and pumped storage cycles represent variations on that illustrated in Fig. 1.

Gas Turbine Configuration

Figure 2 illustrates an MS7001FA gas turbine. It is typical of all gas turbines in commercial operation today. Gas turbines with multiple shafts, such as the heavy duty MS3002 and MS5002, and aero-derivative gas turbines, are modifications of the configurations shown in Fig. 2. While these modifications require considerable design and mechanical innovation, the basic description of the gas turbine remains unchanged.

In the compressor section, air is compressed to many atmospheres pressure by the means of a multiple-stage axial flow compressor. The compressor design requires highly sophisticated aerodynamics so that the work required to com- press the air is held to an absolute minimum in order to maximize work generated in the turbine. Of particular interest in the design of any compressor is its ability to manage stall of its aerodynamic components. In starting the gas turbine, the compressor must operate from zero speed to full speed. It is essential that the varying air flow within the compressor be so controlled that damage does not occur from avoid- able stalling during part speed operation, and that stalling is absolutely prevented at full speed. During low speed operation, the inlet guide vanes are closed to limit the amount of air flowing through the compressor, and provisions for bleeding air from the compressor are provided at one or more stages. This reduces the strength of the stalling phenomena during part speed operation, which avoids compressor damage. The compressor aerodynamics are such that at full speed operation, no stalling should occur. Because sufficient margin exists between normal operating conditions and those conditions which would result in stall, General Electric gas turbines do not experience stall phenomena during normal full speed operation.

The combustor of a gas turbine is the device that accepts both highly compressed air from the compressor and fuel from a fuel supply so

GER-3434D

RDC36333

Figure 2. MS7001FA simple cycle gas turbine

that continuous combustion can take place. This raises the temperature of the working gases to a very high level. This combustion must take place with a minimum of pressure drop and emission production. The very high temperature gases flow from the combustor to the first stage turbine nozzles.

It is in the turbine that work is extracted from the high pressure, high temperature working fluid as it expands from the high pressure developed by the compressor down to atmospheric pressure. As the gases leave the combustor, the temperature is well above that of the melting point of the materials of construction in the nozzles and first stage buckets. Extensive cooling of the early stages of the turbine is essential to ensure adequate component life. While the hot gases cool as they expand, the temperature of the exhaust gases is still well above that of the original ambient conditions. The elevated temperature of the exhaust gases means that considerable energy is still available for boiling and superheating water in a combined cycle bottom- ing plant. It is this use of the exhaust energy that results in the dramatic improvement in cycle efficiencies between simple cycle turbine and combined cycle systems.

AXIAL COMPRESSOR

Aerodynamic Development

GE’s experience with compressor design spans several decades. The original heavy-duty

design of the axial-flow compressor was based on experience with the development of the TG180 aircraft jet engine during the mid-1940s. In the late 1940s a prime mover was designed based on the TG180 and intended for use in pipeline pumping and industrial power applications. This prime mover, the earliest model of the MS3002, was a 5000-hp gas turbine with a compressor airflow of 37 kg/set (81.5 lb/set) . The original MS3002 compressor did not require bleed valves, variable-inlet guide vanes, or variable-angle stator vanes for the turbine to accelerate and operate over a wide speed range without compressor surge. El Paso Natural Gas Company purchased 28 of these turbines which, after 30 years of operation, have accumulated an average of over 200,000 hours each.

In 1955, the design of a new compressor was undertaken to better satisfy the electrical power generation market; this design resulted in higher airflow and higher efficiency. Blade air-foils, an improvement over the NACA 65 series profile, were tapered in chord and camber and specified a root thickness of 13.5% of chord to provide ruggedness. Air extraction ports were added to the fourth and tenth stages to avoid surge while the compressor accelerated to rated speed. This design, used in the original MS5000, produced an airflow rate of 72.4 kg/set (159.2 lb/set) and a pressure ratio of 6.78 at 4860 rpm. Compressor airflow was later increased by raising the rotational speed to 5100 rpm and open-

3

GER-3434D

ing the inlet guide vanes, resulting in the basic MS5001M design which has led to today’s modern compressors.

Starting with the MS5001M, the family of compressors in GE’s present product line has been developed for single-shaft units by increasing the diameter of the inlet stage to increase the airflow and pressure ratio. For the MS5001N, the first three stages of the MS5001M were redesigned, and a stage was added at the inlet. The fixed inlet guide vane was replaced with a variable guide vane to adjust the airflow at start-up and provide higher firing temperature at reduced load for regenerative-cycle and combined-cycle applications. The MS5001N compressor operated at a pressure ratio of 9.8. It was tested at GE’s aircraft engine compressor facility at Lynn, Massachusetts, where flow, pressure ratio, efficiency, start-up characteristics, full-speed surge margin, and mechanical integrity were established. - :$“r M-‘Fr -‘%

-A L ____e_- a------- -(B 1 I I ,Y, I , I

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GT01645N

Figure 3. Growth in compressor air flow

GTOlllOH

Figure 4. Growth in compressor pressure ratio

The MS5001N and P, the MS7001A and B, and the MS9001B are essentially the same aerodynamic design, with increases in airflow and pressure ratio shown in Fig. 3 and 4. Figure 5

illustrates the mechanical configurations associated with these compressors. The MS5001N compressor, which runs at 5,100 rpm, was scaled to 3,600 rpm with over a 100% increase in airflow, and used in the MS7001A design. The flow and pressure ratio have been increased further in the MS7001C and MS7001E by redesigning the first four stages. A modification made to the stators of stages 1 through 8 was applied to the MS7001E, MSgOOlE, and MS6001 to improve underfrequency operation. Figure 6 shows how the power available during underfrequency conditions was improved by this modification. With the current production compressor, this power reduction is unnecessary because of the improved part-speed surge margin in the compressor. The slight fall-off in power results from reduced airflow at lower speed.

I~~~~~------~ MSfWlS

MS7001 12.29c AREA

MS7OOlE / MS7001 E to MS7001 FA

GTO4142E

Figure 5. Evolution of compressor design

Percent Rated Power 75

122OF Day (50%)

50

- Production 1 /

/ /

/I

/ Old Compressor (Surge Limited)

I I I I 57 56 59 60

Generator Line Frequency - Hz

c

GT01646A

Figure 6. MS7001 under-frequency power (peak load, hot day 50C (122F)

4

GEW3434D

A further improvement in the output of the MS7001E machine was made by simply increasing the outer diameter of the compressors. This has resulted in a 3.7% increase in flow and a new designation of MS7001EA, as illustrated in Fig. 3, 4 and 5.

In 1986, GE introduced a new gas turbine the, MS7001F, and its derivative, the MS9001F; in 1990, the uprated MS7001FA and MS9001FA (Fig. 7); and in 1993, the scaled MS6001FA. The compressor for the MS7001FA is an axial-flow, 18-stage compressor with extraction provisions at stages 9 and 13. The compressor aerodynamic and mechanical design closely follows the 17- stage MS7001E, but with an additional zero stage. For convenience in maintaining this relationship, the MS’7001FA compressor stages are numbered 0 through 17 rather than 1 through 18.

is‘ -. yfm-.-+. ,\

i

RDC26662

Figure 7. MS9001FA gas turbine

The MS7001FA compressor was developed by first scaling the diameters of the MS7001E, then increasing the annulus area an additional amount to achieve the desired flow, and lastly adding a 0 stage. As a result, the MS7001FA is aerodynamically similar to the MS7001E, and most of the blading is identical to the MS7001E except for length. Stages 0 and 1 have been designed for operation in transonic flow using design practices applied by aircraft gas turbine designers. As a result of using this conservative design approach, variable stators in addition to variable-inlet guide vanes are not required for surge control. The MS9001FA and MS6001FA are direct scales of the MS7001FA.

The 7EC compressor, although introduced later, uses a similar approach by adding a zero stage directly to the 7EA compressor. As shown in Fig. 5, the aft stages are the same as 7EA. The

9EC is a direct scale of the 7EC for the 50 Hz size.

Table 2 lists some of the parameters of these axial compressors. By starting with an efficient, reliable design and improving this design in a gradual manner, improved overall compressor performance has been achieved without sacrificing reliability or mechanical integrity.

Table 2 COMPRESSOR ROTOR DESIGN PARAMETERS

Compressor Tip Turbine th.Qut o&meter

unn F,Ssp”n., Inchcw (mm) GM Y2,Z MS!mlP 1~0 49.1 (1247.1) 5100 28.3

MS7wlS 10=(333) 88.5 (1766.31 ww 80.0

MSBOO1S 1~Wl 63.6 (2120.9) 3ooo 84.7

Ms6oo1s 1114(34D) 60.1 (1272.5) 51w 38.3

USmOlE 1114(34D) 70.9 (1BOO.q 3600 75.6

Ms7oolEA 1120 (341) 71.3 (1611.0) 3600 63.5

MSBWlE 1114(340) 85.1 (2161 S) 3000 118.9

MS6WlFA l~(ssl) 56.1 (1425.5) 5236 70.1

MS7001 FA ==(391) 81.8 po72.q 3600 166.4

MSBOOIFA ~282(38’) 97.9 (24B6.q 3000 226.5

MS7DOlEC l22? (374) 78.1 (lBE3.7) 2.600 116.0

MSB001EC 1227 (374) B3.7(2360.0) woo 168.2

Thorough testing is essential for the development of modern axial compressors. In GE’s manufacturing facility in Greenville, South Carolina, a standard MS7001 compressor (Fig. 8) is used as a loading device for testing prototype gas turbines and as a compressor development vehicle. The facility has been constructed with nozzles for measuring airflow, valves for regulating airflow, and flow straighteners in the inlet duct.

GTl0271

Figure 8. MS7001 load test of axial-flow compressor

GER-3434D

The discharge system includes parallel discharge valves for coarse and fine adjustment of the pressure ratio. Provisions for standard extraction, bleed flow, and flow measurement have also been made. For test flexibility, some of the controls for the load compressor have also been made to protect the equipment in case of trips.

Test measurements include flow in and out of the compressor, inlet and discharge pressures and temperatures, and interstage pressures and temperatures needed to design stage-by-stage characteristics. Dynamic data are measured to evaluate rotating stall, surge, and blade stresses.

Tests are run over a wide range of speeds and pressure ratios to generate a performance map, start-up characteristics, stress data, blade dynamic characteristics, and to design surge margins. Since 1968, seven full-scale compressor development programs have been conducted by GE. Results include computer models which permit design improvement analysis. As a result of these tests, the performance and operating characteristics of GE compressors can be predicted with considerable accuracy throughout the operating range.

Mechanical Construction

GE axial compressors have proven to be durable, stable, and reliable. The design also offers important versatility for optimizing compressor wheel material characteristics, cost, and service conditions.

TCZO178A TCZO178A

Figure 9. MS5001 compressor rotor stacking Figure 9. MS5001 compressor rotor stacking

Each stage of the compressor is an individual Each stage of the compressor is an individual bladed disk (Fig. 9). The use of this construc- bladed disk (Fig. 9). The use of this construction allows some weight reduction bv contour- tion allows some weight reduction bv contour-

ing the wheels, thereby reducing the mass which must be accelerated during start-up. The disks are assembled with a number of axial tie-bolts, with the bolt-circle diameter selected to produce a dynamically stiff rotor and good torque transmission. The stiffness and mass of GE rotors insures that the first bending critical speed is above the running speed. The wheels are positioned radially by a rabbet fit near the bore. Axial clearance is provided between the wheel rims to allow for thermal expansion during start-

up. Application requirements have resulted in

several important mechanical design features in the axial compressor. In models with air-cooled turbine buckets, the last-stage wheel has been adapted to provide an extraction to supply the necessary cooling air for the turbine and rotor buckets (Fig. 10). The system was designed and carefully tested to extract air without disturbing the main compressor flowpath. The extraction system is a radial in-flow turbine which accepts compressor air at the outer diameter entrance with low-pressure loss, and completely guides the flow to a radial direction so it enters the rotor bore without swirl. The guide slots in the wheel eliminate free-vortex flow in the extraction system, providing aerodynamic stability over the entire range of compressor operation.

GTO1412

Figure 10. Last-stage wheel with cooling-air extraction

Higher-cycle pressure ratios produce higher compressor-discharge temperatures; the MS7001E compressor-discharge temperature increased by 31.6C (57F) over the MS7001B when the pressure ratio was raised from 9.6 to 11.5. To compensate for the temperature

6

increase, higher-strength material (CrMoV) is used in the last compressor stage. This material has the high-temperature strength compatible with a wheel life of 30 years at base load.

Gas turbine rotors are designed for may thousands of starts. Start-up and shutdown thermal stress, material properties, and material quality are considered in the design. Additionally, the material quality of each wheel is ensured by very stringent process controls and ultrasonic inspection procedures. Compressor wheels with turbine-grade materials, such as CrMoV, receive high-speed proof testing similar to our long- standing practice for turbine wheels.

Each wheel is spun in a pit after being cooled below its fracture appearance transition temperature (FATT) . The wheel is then in a brittle condition and would fail if a serious flaw existed. A hot spin, with the wheel temperature well above the FATT, is also used to enhance the life of the wheel. The speed is sufficiently high to plastical- ly yield the bore, producing a residual compres- sive stress at the bore when the wheel is brought to rest. During subsequent operation of the machine, the residual stress reduces the bore tensile stress, producing enhanced low-cycle fatigue life (Fig. 11).

oPER*TING STRESS WTHo”T

PEAK TANGENTIAL STRESS - %

GT01424A

Figure 11. Improvements due to hot spinning

The remainder of the compressor wheels are made of three basic grades of steel, CrMo, NiCrMo, and NiCrMoV the principal alloying elements. Processing of these alloys produces a balance of desired material properties including tensile strength and fracture toughness. Fracture toughness is important for good cyclic life of wheels, especially in low ambient environments. Since 1970, optimization of these materi-

GER-3434D

als has resulted in a 35% improvement in fracture toughness (Fig. 12). The banded area shows the evolution of the minimum and maximum observed values for low-temperature fracture toughness.

FGXlU~~

,50 Toughness , I

-40°F (4%) r

150

KSlfi loo MPaLoO #

GTO1647, A

The same proven alloys and construction techniques have been employed in the MS6001FA, MS7001FA and MS9001FA designs, a very trouble free and reliable design.

M-ULTIPLE-COMBUSTION SYSTEM

Design

A typical reverse-flow multiple-combustion system, similar to those in most of the GE heavy- duty gas turbines, is shown in Fig. 13. This system is a product of years of intensive development and successful field application. In the combustor, a highly turbulent reaction occurs at temperatures above 19826 (3600F). The essential feature of the combustor is to sta- bilize the flame in a high-velocity stream where sustained combustion is difficult. The combustion process must be stable over the wide range of fuel flows required for ignition, start-up, and full power. It must perform within desirable ranges of emissions, exit temperature, and fuel properties, and must minimize the parasitic pressure drop between compressor and turbine. The combustion hardware must be mechanically simple, rugged, and small enough to be properly cooled by the available air. This hardware must have acceptable life and be accessible,

7

GER-3434D

maintainable, and repairable. GE’s reverse-flow, multiple-combustion system is short, compact, lightweight, and is mounted within the flange-to- flange machine on the same turbine base. This multi-combustor concept has allowed full machine size and operating conditions to be applied to combustor systems during laboratory development testing.

GT03619

Figure 13. Reverse-flow combustion system

While model tests are useful for locating areas of high pollutant formation, such models do not allow prediction of other operating characteristics. Since a scale model does not reproduce chemical reactions, heat release rates, and aerodynamic mixing, neither mathematical nor geometric modeling has proven satisfactory for combustion development. In addition, aerodynamic mixing, which is achieved by jet penetration from the walls of the combustor, is more difficult in a larger-diameter combustor burner. For this reason, good emissions performance, which depends strongly on aerodynamic mixing, cannot be predicted from scale model tests. A practical combustor can only be developed in full-scale tests.

Almost all laboratory testing of development work can be done on a single-burner test stand at full operating conditions, with only a fraction of the fuel and air of a complete gas turbine. All GE heavy-duty gas turbines except the MS1002 are designed to use multiple combustion chambers offering significant adaptability such as:

l Small diameter permitting careful control of the airflow patterns for smoke and NOx reduction.

l The design allows control of the gas path profile.

l Combustor diameter can readily be increased to accommodate combustion of the low heating value gas fuels.

l Combustor length can be provided for residual fuels.

l The design is readily adaptable to modifrca- tions, such as water injection.

l The components are small enough to be adequately cooled.

As a result, all GE gas turbines, with their fully developed combustion systems, are shipped from the factory fully tuned, precluding the need for start-up adjustments or field testing.

The combustion chamber diameters are not scaled for the different turbine models. Only two combustion liner diameters for non-DLN applications are used for the GE product line: a 268 mm (10.7-in.) diameter for the MS3000, MS5000, and MS6000; and a 358 mm (14.3-in.) diameter for the MS7000 and MS9000. The combustion liners for the MS5001N, MS6001, MS7001B and MS7001E are shown in Fig. 14.

GT01422A

Figure 14. Combustion liner comparison

The number of combustors, however, is adjusted proportionally to the machine airflow divided by the pressure ratio, e.g., the MS9001E uses 14 combustors compared to 10 on the MS7001E because the 9E airflow is 1.44 times as large.

The MS7001FA combustion system consists of 14 combustion chambers. The liners are constructed in a manner identical to the MS7001E liners but are 30% thicker and 210 mm (8.4 in.) shorter. The MS7001FA liners are constructed of Hastelloy-X material, as are the other product line liners, with the addition of HS-188 in the aft

8

GER-3434D

278 mm (11.1 in.) portion and the application of thermal barrier coating to the internal surface. These additions provide for improved high-temperature strength and a reduction of metal temperatures and thermal gradients. The MS6001FA uses six combustors and the MS9001FA uses 18 .

GTlB104

Figure 15. Combustion liner cap

Dynamic

0.5 k Pressure

I Standard Single Nozzle System

0.3 psi

0.2 Multinozzle System

0.1

Frequency (Hz)

GT15267A

Figure 16. Multi-and single-fuel nozzle combustion noise

The liner cap is changed from the MS7001E design to accomodate six fuel nozzles instead of one (Fig. 15). This multi-fuel-nozzle arrangement was selected because of the superior field experience with multi-fuel-nozzle systems on an operating MS7001 gas turbine in utility service with water injection for NOx control. This test, confirmed by extensive laboratory full-scale combustion tests, clearly demonstrated the reduced combustion noise (dynamic pressure) level achieved when operating with multi-fuel instead of single-fuel-nozzle systems (Fig. 16). This noise reduction reduced wear in the combustion system so that combustion inspection intervals of a tested machine could have been

extended from 3,000 to 12,000 hours. Additionally, multi-fuel-nozzles result in a shorter flame, and the MS7001FA combustion system is 575 mm (23 in.) shorter than the MS7001E system. The six fuel nozzles are mounted directly on the combustion end cover and require no more piping connections than a single fuel nozzle because of manifolding integral with the cover.

The combustion ignition system uses two spark plugs and two flame detectors, along with cross fire tubes. Ignition in one of the chambers produces a pressure rise which forces hot gases through the cross-fire tubes, propagating ignition to other chambers within one second. Flame detectors, located diametrically opposite the spark plugs, signal the control system when ignition has been completed. Because of the relative simplicity and reliability of this technique, it is used in all GE heavyduty gas turbines.

Fuel is distributed into the combustion chambers by fuel nozzles. For gas, the fuel nozzle is a simple cap with accurately drilled metering holes. Liquid fuels are metered by a positivedis- placement, gear-element flow divider. Liquids are either pressure-atomized or air-atomized if better smoke performance is required. Residual fuel and crudes generally require atomizing air to achieve acceptable smoke performance.

The size of the combustion liners provides the space required to completely burn residual fuel. Lighter fuels are also easily burned in these liners. Smaller-diameter GE combustors allow penetration of air jets into the combustor at acceptable pressure drops. Jet penetration is necessary to mix the air with the fuel quickly and obtain complete combustion without forming soot in fuel-rich pockets. The highly stir-red flame produced by these jets also reduces radiation to the liner walls, with beneficial effect on liner life.

The combustion liner is carefully cooled to tolerate high-temperature gases a few millime- ters from the combustor liner wall. As firing temperatures increase, more air is needed to combine with the fuel for adequate combustion, and less air is available for liner wall cooling. This has been offset by a more efficient cooling system and by reducing the surface area (length) of the liner. Louver cooling, which has been highly successful and reliable over the years, has been replaced by slot cooling in the

GER-3434D

turbines with the highest firing temperatures. The slot cooling method reduces liner metal temperatures by 139C (250F) compared to an equivalent louver system, and is the standard cooling method in aircraft gas turbines.

The length of the combustor provides time to complete the combustion reaction for the variety of fuels burned in the turbine and then dilute the combustion products with excess air to form a temperature profile acceptable to the downstream turbine components. The temperature profile of hot gases entering the turbine sections is carefully developed to provide maximum life for the nozzles and buckets. The average radial profile from the combustors will produce lower temperatures near the bucket root where the centrifugal stress is maximum, and at the outer sidewall where nozzle bending stresses are also at a maximum.

The transition piece, which channels the high-temperature gas from the combustion liner to the first-stage turbine nozzle, is small enough to be cooled by air flowing from the compressor. This provides effective cooling of the transition piece for firing temperatures up to 1OlOC (1850F). The outer portion of the transition piece near the first-stage nozzle is less effectively cooled, and at firing temperatures above 1OlOC ( 1850F) jet-film cooling is added.

The MS6001FA, MS7001FA and MS9001FA transition piece is constructed of two major assemblies (Fig. 17)) which is unique to these machines. The inner transition piece is surrounded by a perforated sleeve with the same general shape as the transition piece. This perforated sleeve forms an impingement cooling shell causing jets of compressor discharge air to be directed onto the transition piece body. The air, after impinging on the transition piece body, then flows forward in the space between the impingement sleeve and transition piece into the annulus between the flow sleeve and the combustion liner. It then joins additional air flowing through bypass holes provided in the flow sleeve to provide the air for the combustion/cooling/ dilution processes (Fig. 17). The impingement sleeve is fabricated of- AISI-304 stainless steel, the transition piece body of Nimonic 263, and the aft frame of cast FSX414. The internal surface of the transition piece has a thermal barrier coating to minimize metal

Figure 17. Transition piece GTI 5365

temperatures and thermal gradients. Higher firing temperatures require combus-

tors that release more energy in a given volume. High volumetric heat release rates, which depend on higher turbulent mixing in the combustor primary zone, are achieved by raising the combustor pressure drop. As mixing has increased in combustors, the turbulence generated by combustion may cause broad-frequency- banded noise. While this is generally “white noise,” it is possible for the combustion flame to couple with the acoustic characteristics of the combustor volume or fuel system components to generate unacceptable pure tone frequencies, or acoustic waves.

100 -

104 Hz

Pressure Fluctuation

lIl0AR IPeak-to-Peak)

100 200 300 400 500 600 Frequency - Hz

Figure 18. Combustor dynamic pressure spectrum

The characteristic frequency of the waves is established by the combustor geometry or external equipment such as the fuel pump. One example of this phenomenon is shown by a

10

GER-3434D

spectrum of the dynamic pressure within a combustion chamber while burning natural gas (Fig. 18). When the chamber pressure near the fuel nozzle rises, the fuel flow is reduced. Conversely, a decrease in pressure near the fuel nozzle causes an increase in fuel flow. Amplified pressure oscillations occur when a low fuel-nozzle pressure drop permits this fuel flow oscillation. These dynamic pressures can be damaging to the combustion hardware. Comprehensive testing under actual operating conditions is necessary to develop systems in which these pure tone frequencies are avoided.

In order to determine an acceptable range of fuel-nozzle pressure drops, stability maps (Fig. 19) have been developed from tests run in our Gas Turbine Development Laboratory. This map is used to select fuel-nozzle designs which ensure stable system operation.

lffir

1.04 -

FUEL NOZZLE NO COMWJSTOR

GASPPRESSURE RATIO

COMBUSTOR OSCILLATIONS

.cm .cm OOB 010 012 FUEL AIR RATIO

GT01425A

Figure 19. Combustor dynamic pressure stability (gas fuel)

Development Testing

The Gas Turbine Development Laboratory has six test stands which operate at full machine conditions in either simple-cycle or regenerative-cycle configurations. The stands are equipped to inject water, steam, or inert gas for emissions reduction. Tests may run using gaseous or liquid propane, methane, distillates, blended residuals, or heavy residual fuels. A low heating value fuel facility is also available with the capability to blend fuel and inert gases for a heating value range of 3353 to 4098 kJ/m9 (90 to 110 Btu/ft3). The main test bay is shown in Fig. 20. Since laboratory testing of combustion components and systems can be performed under full machine conditions, we are able to achieve excellent correlations between laboratory and field performance.

Figure 20. Gas turbine development laboratory main test bay

Additional cold-flow testing is conducted at the GE Research and Development Center on scale models of all new combustion systems (Fig. 21). These models are used to measure the flow distribution from the compressor discharge diffuser to the individual combustion chambers. Model testing is useful for measurements of static pressure recovery and flow visualization to ensure flow stability in the vicinity of the combustion chamber.

GTOOS16

Figure 2 1. Combustion system scale model

After laboratory development of combustors,

testing is completed on a production turbine at

full load conditions. This turbine is extensively

instrumented to evaluate the combustor perfor-

mance and to permit comparison with the

results of the single-burner test. Measurements

are made of the gas temperature profile at the

entrance to the first-stage nozzle, metal tempera-

11

GER3434D

tures and vibratory response of the hardware,

combustor pressure drop, and dynamic pres-

sures in combustors, fuel lines, and atomizing-

air piping. Lightoff, cross-firing, and control

characteristics are also measured. Emissions

from the turbine exhaust are determined,

including smoke and particulate matter, to com-

pare with laboratory tests and theoretical predic-

tions. Water and steam injection systems are test-

ed to determine the amount of water or steam

required to meet emissions standards. Years of

gas turbine combustor development experience

have shown that this combination of laboratory

and machine testing is essential to the produc-

tion of a reliable combustion system.

Dry Low No, Development GE Power Generation’s Dry Low NO, (DLN)

development is a multi-faceted program to provide combustors, controls, and fuel systems that significantly reduce emissions from both the current gas turbine product line and existing field machines. There are many programs that provide products to meet current emissions codes and prepare for more stringent requirements in the future. The available DLN products for the MS600lB, 700lEA, and 900lE machines are designed to meet 15 ppmvd at 15% O2 of NO,. This DLN technology has been extended to produce equivalent products for the MS700lFA and MS900lFA class machines. More advanced DLN systems are being developed to meet 9 ppmvd at 15% 02 of NO,.

The Dry Low NO x system is a sophisticated system that requires close integration of a staged, premixed combutor, the gas turbine’s SPEEDTRONICTM controls, and the fuel and associated sytems. Thus, there are two principal measures of performance. The first one is emissions- the base load levels of NO, and CO that can be achieved on both gas and oil fuel, and how these levels vary across the load ranges of the gas turbine. The second measure is operability- the smoothness and reliability of combustor mode changes, the ability to load and unload the machine without restriction, the capability to switch from one fuel to another and back again, and the response to rapid transients (e.g., generator breaker open events or

rapid swings in load). GE’s design goal is to make the DLN system operate so that the gas turbine operator does not know such a system is installed, i.e. it is “transparent” to the user.” To date, a significant portion of the design and development effort has focused on operability.

The Dry Low NO, combustor, shown in the cross section in Fig. 22, is a two-staged premixed combustor designed for use with natural gas fuel and capable of operation on liquid fuel. As shown, the combustion system comprises four major components: fuel injection system, liner, venturi, and cap/centerbody. These are arranged to form two stages in the combustor. In the premixed mode, the first stage serves to thoroughly mix the fuel and air and to deliver a uniform, lean, unburned fuel-air mixture to the second stage.GE Dry Low NO, combustion systems are currently operating in 60 field machines, As of June ‘94, they have accumulated over 200,000 operating hours.

PRIMARY FUEL NOZZLES

(6)

LEAN *ND PREYWYG DlL”TlcIH ZONE

PWYAR” LON

SECOHDAR” FUEL NOZZLE

(1)

END COVER

GTI 505OA

Figure 22. Dry low NO, combustor

TURBINE

Background

Increasing firing temperature has been the most significant development thrust for turbines over the past 30 years. Baseload firing temperature capability has increased from 816C (1500F) in 1961, when the MS5000 package power plant was introduced, to 1288C (2350F) today in the MS600lFA, MS700lFA, and MSSOOIFA machines. The base rated power of the MS7000 has increased since the first model was shipped in 1971, from the 46MW MS700lA to the 83.5- MW MS700lEA. Seventy percent of this increase

12

has been accomplished through higher firing temperature; the remainder from increases in airflow because of compressor developments.

Higher turbine firing temperatures are achieved by improved nozzle and bucket materials and by the air-cooling of this hardware. Concurrent development in alloy corrosion and oxidation resistance and bucket surface protection systems have played a significant role in supporting firing temperature increases.

Aerodynamics

GE gas turbines are characterized as a high energy-per-stage design, which requires a high stage pressure ratio. This results in the two or three turbine stages typical of GE heavyduty gas turbines, instead of the five stage low energy-per- stage design common in competing machines.

The temperature of the first of three high energy-per-stage buckets will be approximately 55C (100F) lower than the first of five low energy-per-stage buckets. As shown in Fig. 23, for a given wheel speed, firing temperature, and turbine output, higher energy-per-stage turbines have fewer stages than lower energy-per-stage turbines . This results in a larger energy drop (hence reduction in temperature) per stage

TemD mm

1900

leoo

1700 16w

OF ,500

I

,400 13w 12w 1100 Iwo

suoc I I I I I R 18 28 38 48 56

Turbine Bucket Stage

GT01649D

Figure 23. Bucket metal temperatures

and, therefore, lower bucket metal temperatures.

Since high energy-per-stage turbines have inherently lower metal temperatures for a given firing temperature, it follows that less cooling air needs to be supplied in order to provide satisfactory metal temperatures and component lives. The greater amount of cooling air which must be supplied to a lower energy-per-stage turbine

GER-3434D

bucket imposes a greater performance penalty upon that design. Conversely, for the same cooling airflow, the high energy-per-stage turbine bucket will inherently have a lower metal temperature, and hence, longer life.

Turbine Cooling

The thermal efficiency and specific output of a gas turbine are strongly influenced by two cycle parameters, pressure ratio and firing temperature (Fig. 24). Thermal efficiency increases up to stoichiometric firing temperature levels and pressure ratios of 5O:l or 60:1, in an ideal cycle where losses for turbine cooling are not considered. Since superalloys begin to melt at about 12OOC (2200F), the hot-gas-path components must be cooled to maintain metal temperatures well below this temperature. For this rea-

44

42 1 40

5%

E36- .* g Y 34. z

E 32 f

(1 i4PC) ‘ggy 2085’F * ‘;c$“,“,‘;l 0

m&l 0 30 16 ‘6

P

IB (~ ‘I I. 12 1 2 12

10 10

en8

:Lm 40 200 SpeclflC ovtpti - KwLbLsec

I I I loo iw 400 Km

Uwrn~seC

GT01651A

?igure 24. No compressor extraction flow (ideal flow)

1

40

38 I

s 36- I J E = 2 34- g w 5 32- E St t- 30-

y&y ‘:g$’ ‘g&y

I’&?? 30 J)30

30 16 18 76

‘6 1 16 18 ‘4 14 14

~~

12 12 12

10 10

8 888

281 1 1 40 100 200

Specific Output - KWlLblSec ! 1

100 200 400

GT01652A

Figure 25. Compressor extraction flows as needed (real flow)

13

GER-3434D

son, air is extracted from the compressor and used to cool these components.

While substantial performance gains can be realized by increased firing temperature, a comparison of Figs. 24 and 25 shows that performance improvements are also possible at fixed firing temperatures by use of higher-temperature materials to reduce cooling losses. More efficient cooling systems will also improve performance.

Beginning in the early 196Os, air-cooled first- stage nozzles were introduced into GE heavy- duty designs. Nozzle metal temperatures were maintained at about 843C (1550F), as firing temperatures were raised to take advantage of stronger bucket alloys. By the late 196Os, turbine baseload firing temperatures were near 91 OC ( 1670F), and significant firing temperature increases depended on cooling first-stage buckets. With future increases in mind, the MS7001 was designed to be readily adaptable to bucket cooling.

Several important criteria were selected for air-cooled turbines. First, the bucket air-cooling circuit is entirely internal to the rotor, starting with radially inward extraction from the inner diameter of the compressor gas path. As the compressor acts as a centrifuge for dirt, the internal extraction point minimizes the amount

17th Stage \ L Compressor 1 ~%fiJ Compressor

Extraction Discharge Flow

GT21402A

Figure 26. Internal cooling circuit

of foreign matter taken into the cooling circuit. The internal circuit, shown in Fig. 26, eliminates the need for additional seals or packings between the rotor and stator to contain the cooling air, producing the highest possible integrity of the circuit. Second, metering of the air is accomplished by the buckets themselves because the cooling circuit has a much greater flow area than the bucket cooling holes. This provides the highest pressure drop for efficient heat transfer

in the bucket. Additionally, metering of air at the buckets allows the cooling flow to increase if the buckets are damaged. This allows ash-forming heavy fuels to be burned without concern for external plugging of the bucket cooling system.

Cooled buckets and advanced air-cooled first- stage nozzles were shipped in MS7001B turbines beginning in 1972. A baseload firing temperature of 1004C (1840F) was established, 106C (190F) higher than the MS7001A uncooled bucket design. In the FA model of the MS7001, nozzle and bucket cooling have been further developed to provide a baseload firing temperature of 12886 (2350F). The first-stage bucket is convectively cooled via serpentine passages with turbulence promoters formed by coring techniques during the casting process (Fig. 27). The cooling air leaves the bucket through holes in the tip as well as in the trailing edge. The second-stage bucket is cooled by convective heat transfer using STEM (Shaped Tube Electrode Machining) drilled radial holes with all the cooling air exiting through the tip. The first-stage nozzle contains a forward and aft cavity in the vane, and is cooled by a combination of film, impingement, and convection techniques in both the vane and sidewall regions (Fig. 28). There are a total of 575 holes in each of the 24 segments. The second-stage nozzle is cooled by convection. The advanced cooling techniques applied in the MS7001FA turbine components are the result of extensive aircraft engine development, as well as correlative field testing performed on cooled components in current production heavy-duty machines. In addition, hot cascade tests were performed on MS7001FA

GT15360

Figure 27. First-stage bucket cooling passages

14

GT153S2

Figure 28. First-stage nozzle cooling

first-stage components to validate the heat transfer design assumptions.

Bucket Design

Buckets are subjected to a gas force which provides torque to the rotor. Relatively small variations in these gas forces can cause bucket vibration. Coincidence of resonance between these periodic gas forces and bucket natural modes must be avoided at full operating speed; however, resonance cannot be avoided at all speeds, particularly during starting and shutdown. Effective vibration control is required, therefore, to produce reliable turbine designs. All GE-designed turbines incorporate two

~np~c+md l Vibn(icm MC& c.nnlfaim l -pho

~6wlulshmk .Tlem.¶ls hruh*l wheel ‘-3 -‘c

GT196WA

Figure 29. MS6001 second stage bucket

important features to suppress resonant vibration-the long-shank bucket and the bucket tip shroud. Fig. 29 shows these features on the

GER-3434D

MS6001B bucket. The bucket shank, which joins the bucket air-

foil and the dovetail, is a significant fraction of the overall bucket length. Damping is introduced near the bucket midspan by placing axial pins underneath the bucket platform between adjacent buckets. On first-stage buckets, the damping provided by these pins virtually eliminates all vibration involving tangential motion and significantly reduces vibration in other modes. The shank has a second important advantage in providing an effective thermal isolation between the gas path and the turbine wheel dovetail. The dovetail is maintained at a low temperature, and because the shank is a uniform, unrestrained section, stress concentra- tions in the dovetail are minimized.

The integral tip shroud is the second major vibration control feature of GEdesigned buckets and is used on the second and third stages. Individual bucket shrouds are interlocked to form a continuous band during operation. The natural tendency for the buckets to untwist under centrifugal load is used to force the mat- ing faces of adjacent shrouds together, providing coulomb damping. The tip restraint provided by the continuous shroud band totally eliminates the most sensitive mode of vibration, the first flexural.

Service experience now provides a factual record. Since 1962, when shanks were introduced, no bucket of this design has experienced a vibration failure in the dovetail or wheel rim. The long shank and tip shroud remain remark- able innovations in vibration suppression.

The development of turbine stages which are vibration free requires sophisticated interaction between the aerodynamic design and testing dis- ciplines. For free-standing buckets the calculation of frequencies is relatively routine; however, the amplitude of vibration response of buckets to aerodynamic stimulus is not easily determined without extensive test correlations. When the complexities of variable boundary conditions at platform and tip shroud are introduced into the assembly, analytical predictions become even more uncertain. Extensive test experience is required, therefore, to produce a reliable design.

Several test techniques are used to ensure adequate margin against vibration. For simple

15

GER-3434D

stationary-bench testing, a bucket is mounted on a heavy mass and driven at natural modes by a harmonic external force. Such tests provide useful data on expected modes, frequencies,

GTO3396

Figure 30. Fourier analysis of bucket impulse excitation

and optimum strain gauge locations in prepara- tion for wheelbox tests. More extensive information on bucket mode shapes is determined by Fourier analysis of impulse excitation (Fig. 30).

Wheelbox testing is one of several important steps used to produce reliable turbine designs. The wheelbox (Fig. 31) is one of the major test facilities in GE’s Gas Turbine Development Laboratory. It is a large evacuated chamber in which full turbine stages are run throughout the operating speed range in order to determine bucket vibration response. Gas-force excitation is simulated by an array of nozzles which direct high-velocity air jets at the buckets. This facility is capable of handling the full range of rotor sizes produced and can operate over a speed range of zero to 7,500 rpm. Vibration data from

GTOI 403

Figure 3 1. Wheelbox facility

strain gauges mounted on the buckets is fed through slip rings into the processing facility, where both tape recordings and on-line analyses are accomplished.

MATERIALS

Design Stress and Material Properties

The nature of the design process requires serious consideration to the relationship between predicted machine conditions such as stress, strain, and temperature, and the capability of the component materials to withstand those conditions. Engineers will utilize the most appropriate analytical methods and the most precise mechanical and thermal boundary conditions in the design effort. They will then modify the analytical results by factors of safety, correlations, or experience to arrive at the specific value for stress and temperature for assessing

MATERIAL PROPERTY (+3fl)

50% (MEAN)

TEMPERATURE

GTW843A

Figure 32. Statistical nature of material properties

component life. This value is understood to be a reasonably close and conservative approxima- tion. It is of particular significance that this value is specific, and that it becomes the standard against which the design and materials are measured to judge acceptability.

Figure 32 illustrates the variability of material properties. If many tests are run at a specific temperature, a scattering of the property about some mean value is noted. It should also be noted that there is finite probability (generally greater than 5%) that values for the measured property can fall outside of the scatterband of actual data. This characteristic of material prop-

16

erties requires the engineer to determine just what value of the properly will be used to judge the acceptability of the design. Should the average value, the lower scatterband value, or some other value be used? It is clear that a proper and detailed understanding of the properties pos- sessed by the materials of construction is required if a component is to be properly designed.

The GE gas turbine designer goes to great lengths and considerable expense to develop information similar to that shown in Fig. 32. More than ten million dollars over the past 20 years has been invested to develop a large body of data so that the behavior of the critical materials of construction can be described with con-

siderable confidence. In characterizing a material property, our practice is to obtain data from several different heats, to account for chemistry variations; from several heat-treat lots, to account for heat-treat variables; and from several sources (cast-to-size bars, test slabs, and actual parts), to account for grain size and other part- related variables. Once all this is accomplished, a material property value is typically selected so that at least 99% of the sample at a given temperature will have a greater strength than that utilized for life prediction. This prudent approach in evaluating life is the foundation of ensuring reliability of the product.

Since the general nature of material behavior variability has been addressed, it is appropriate now to discuss several specific material behavior topics that are significant to the gas turbine design engineer and the user. Discussion of these topics, creep/rupture and fatigue- will aid the operator in understanding the operating and repair options associated with the gas turbine, especially in nozzle, bucket, and combustion hardware.

Creep/Rupture Fig. 33 represents the classic creep/rupture

strain-versus-time relationship characteristic of metallic materials. This characteristic is important whenever a material is operating under stress at temperatures greater than 50% of the melting temperature (measured on the absolute scale), as is the case with the high-temperature components of a gas turbine. The designer his- torically has utilized data such as those por-

STRAIN (c) PRIMARY

TIME (t-) A Tr

GER-3434D

Gil-A

Figure 33. Strain accumulation during the standard creep test (constant stress and temperature)

GTlt6845

Figure 34. Surface cracking in IN-738 (after 1.2% creep strain at 732C, 1350F)

r

Fatigue Test Temp * 1600°F

Maximum (871%)

StreSS

KS1 ii MPa i:/ ;\/-;;;;;

lo3 10’ 10 5 10 6 10’ Cycles to Failure

Figure 35. Effect of preexposure in air on 871C (1600F) high-cycle fatigue Iife of cast IN-738

trayed in Fig. 33 to establish the design criteria. If distortion was important (as in a nozzle deflecting downstream into the buckets), a creep strain criterion would be chosen. If actual

17

GER-3434D

separation was important (as in bucket vane sep aration), then time to rupture would be the chosen criterion.

Research by GE gas turbine materials engineers has shown that rupture time, shown in Fig. 33, is not in itself a failure criterion. Figure 34 illustrates the degree of cracking developed in the cast nickel-base superalloy IN-738 when it has accumulated 1.2% creep strain at 732C (1350F). This cracking developed well before actual rupture of the test specimen. We have observed that creep cracking develops in nickel- and cobalt-base superalloys at approximately the onset of the tertiary stage of creep (see Fig. 33). For this reason, a time-to-rupture criterion is not utilized when designing against failure; instead, a creep strain criterion is chosen to avoid creep cracking. This criterion follows from the recog- nition that multiple loading modes occur in a gas turbine, and that creep-induced damage has a deleterious effect upon fatigue life, as illustrated in Fig. 35.

Thermal Fatigue Thermal fatigue is the single most frequent

cause of machine repair or failure, and understanding it requires substantial analytical, experimental, and metallurgical effort. Cracking and crack-induced failures of nozzle and combustion hardware are prime examples of this phenomenon. Thermal fatigue-induced cracking finds its genesis in the operationally induced transient and steady-state gradients that are most generally associated with cooled hardware. Neither can be eliminated, but their impact can be mitigated by judicious design and careful operation.

Figure 36 illustrates a typical nozzle vane pitch cross section with lines of constant temperature superimposed. The significant consideration is the thermal gradients in the part in combination with the temperature. Both the thermal stress and the temperature associated with this gradient cause fatigue damage during both transient and steady-state operation. Thus, this gradient must be evaluated with much care in order to achieve an acceptable design. Figure 37 illustrates a strain-versus-temperature trajec- tory for a cooled part after normal operation of a gas turbine from start-up through full load to shutdown. Note that the maximum strains do

18

Figure 36. Cooled nozzle vane showing isotherms (typical)

NLXlll.¶ Shutdown

I

TenSlIe (+I

Strain 0

Compresswe (4

GTOS847C

Normal AmA

Temp

GTO6848A

Figure 37. Fit-stage bucket leading edge strain/temperature variations (normal start-up and shutdown)

not coincide with the maximum temperature of the cycle. For this reason, complex material-testing procedures must be utilized to properly understand the thermal fatigue requirements of a given design and control sequence.

Start/Stop Transient Effects The control functions provided with the GE

gas turbines are set to limit the impact of the start/stop cycle. The duration and severity of light-off spikes are controlled so that only low strains develop in turbine components without impeding light-off and cross firing. Acceleration and fired shutdown functions are also designed to have a minimum impact upon part life. Great effort has been expended to understand the impact of start/stop cycles on cyclic life. Field tests on an MS5002 unit and the MS9001E prototype incorporated a variety of start/stop char-

GER-3434D

acteristics to explore their impact upon cyclic life. Fully instrumented hot section components were incorporated to provide experimental cor- relation. The results of these efforts clearly demonstrated that the major deleterious cyclic effect is caused by machine trips, especially trips from full load. Fig. 38 compares the impact upon strain range for a normal start/stop cycle with a cycle containing a full-load trip. While a full-load trip is not catastrophic in itself, the resultant life reduction is equivalent to that of approximately 10 normal shutdowns. A reduction in fatigue life by a factor of 10 is substantial

TENSILE l-1

STRAIN 0

COYPRESSIVE (-I

GTO6850

Figure 38. Leading edge strain/temperature (firststage turbine bucket)

and certainly warrants careful and detailed attention to those machine factors that cause trips, especially the control, fuel, and auxiliary systems. Slowing the acceleration adds an additional 60% on the fatigue life of nozzles and buckets.

Corrosion Resistance Development A two-pronged program was implemented in

the 1970s to improve the corrosion resistance of the buckets. The first approach was to increase the corrosion resistance of the base alloy itself, while still satisfying strength requirements. This program resulted in introduction of IN-738. The second program was the development of the first generation of long-life coatings. In the mid to late 1970s platinum-chromium-aluminide diffusion-type coatings were introduced. These alloy and coating improvements have increased corrosion resistance ninefold over the base alloy

used in the late 196Os, and they have increased the range of permissible fuels.

Coated and uncoated IN-738 buckets are shown in Fig. 39. These two buckets were run simultaneously in an MS5002 located in the Arabian desert, one of the most corrosive environments in the world. These buckets operated for 24,731 hours in a unit burning sour gas with

Uncoated PtAl Coated RDCZ6B82

Figure 39. First-stage turbine buckets (coated and uncoated IN-738 - 25,000 service hours)

3.5% sulfur. The terrain surrounding the site contains up to 3% alkali metals which frequently contaminate the inlet air during dust storms. In this environment the Pt-Cr-Al coating doubles the corrosion life of the IN-738 bucket.

Although the combination of IN-738 and Pt- Cr-Al coatings has offered a substantial improvement in corrosion resistance, improvements continue in first-stage bucket materials and manufacturing processes, with the intent of producing machines of increased performance capability and greater fuels flexibility. Two recent developments have been phased into production, the first is Vacuum Plasma Spray (VPS) coatings, the second is GTD-111 bucket alloy.

The GE patented vacuum plasma spray coatings are overlay-type coatings, which offer better control of coating composition than diffusion coatings. These coatings were laboratory tested for mechanical strength and corrosion resistance and also rainbow field tested where a number of coatings were run side by side on the same machines for comparative evaluations. All of these data established that VPS coatings are extremely attractive for improving bucket corrosion resistance. With full qualifications of this

19

GER-3434D

process, GE has introduced this coating into first-stage bucket production. VPS coatings were further improved by the addition of an aluminide coating to both external (airfoil) and internal (cooling) surfaces for first stage MS6001, MS7001, and MS9001 buckets (all models). The aluminide layer improves oxidation resistance.

Improvements continue in bucket alloys, the most recent of which is GTD-111 in equiaxed, directionally solidified, and single crystal forms. This alloy increases metal temperature capability with equal or better strength than IN-738 and displays comparable corrosion resistance. Much of the development work on this alloy was done in the late 1970s and it is now our standard first- stage alloy for all designs; in the MS6001FA, MS7001FA and MS9001FA it is used on all three stages.

Mechanical Properties of Coatings and Substrate

Much analysis has been done toward understanding the effect of our VI’S coatings on substrate mechanical properties. It has been determined that these coatings have little or no effect on substrate tensile or creep behavior. Vacuum plasma spray coatings have their largest impact on low-cycle fatigue (LCF) . The GE-patented coatings can, in some cases, cause 2-to-1 life improvements compared to similar uncoated materials, as shown in Fig. 40. Without exception, life improvements have been observed in cases where the VPS coating exhibits superior ductility. Optimizing corrosion resistance of

10

Coated

Total ’ Strain Range

%

10'

Uncoated Average

I I I 10’ 102 103 104 1

GTO72528

Figure 40. IN-738 low-cycle fatigue at 1600F (871C)

20

coatings does not lead easily to ductile composi- tions. Current and future work is aimed at over- coming this obstacle by identifying coating com- positions which have high corrosion resistance while maintaining acceptable levels of ductility.

PROTOTYPE TESTING The history of instrumented testing under

loaded conditions began in 1965 with the MS5001 at the Schenectady plant outdoor test site and again in 1968 with the MS3002 on the factory load test stand. This was followed by a fully instrumented MS7001A prototype unit tested at the LILCO Shoreham utility site. In 1971, at the compressor load facility in the Greenville plant, the MS7001B was tested with over 1300 channels of instrumentation. Again, in 1974 and 1976, this facility was used for testing the MS7001C and the MS7001E with comparable instrumentation. In 1979-80, prototype testing of the MS6001 was accomplished with two instrumented units. One had limited stator sensors and was tested in Montana at a Montana- Dakota Utility Company site, and the other unit, with almost 2200 channels of instrumentation, was load tested at Schenectady. In the span of one and a half years of testing, the unit achieved 235 fired starts and over 281 fired hours of operation while generating over five million kWh of electricity. The MS9001E design was tested at a customer site in Germany in 1980 and 1981. In 1982, the second prototype was tested at an Electricity Supply Board Company site in Dublin and at customer sites in Germany and Ireland.

During the 1980s the design of the MS7001F gas turbine was supported by a three-phase test program:

Phase I - Fundamental studies and component tests

Phase II - Factory prototype tests Phase III- Field prototype test

The Phase I effort included the development and application of advanced analytical methods and computer techniques to accurately predict three-dimensional viscous fluid dynamics, boundary layer heat transfer, dynamic response of blading, dynamic response of complex systems, and complex material behavior. Where practical, the results of these advanced analytical tools were checked on models and components

GER-34343D

to ensure the accuracy of the predictions. Examples include hot cascade testing of the first-stage nozzle; liquid crystal studies of the first-stage nozzle and bucket to verify heat transfer assumptions; flow testing of the rotor cooling circuit and other components; materials behavior testing under calculated strain/time/temperature cycles; dynamic response wheelbox testing of all turbine buckets; exhaust system flow testing; and maintainability studies. A major effort permitted complete and thorough development of the combustor prior to actually operating the machine. Field testing of selected materials and configurations was included in Phase I to gain manufacturing and operating experience.

Phase II was largely aimed at verifying the compressor performance and obtaining component and system performance and operating data. During this phase, a full compressor map was developed, including surge margin. Also during this phase, extensive rotor and stator instrumentation was included to measure temperatures, pressures, hot-gas-path profiles, blading dynamic behavior, and system dynamic behavior.

The Phase III test involved a full-load test at a customer site. The primary objective was to verify all design and performance parameters. Metal, cooling circuit, and gas path temperatures; cooling circuit and cycle pressures; and component and system dynamic behavior were all determined under both transient and steady- state conditions. Cycle and emissions performance were also determined under normal steady-state conditions.

Each of the component and system data bases developed during Phase II and Phase III were compared with the analytical predictions before the MS7001F design was fully validated for commercial application. This testing involved investi- gations with firing temperatures of 1288C (2350F), justifying the uprate of the MS7001F at 150 MW to the MS’7001FA at 166 MW. It also jus- tified the MS9001FA rating of 226 MW and MS6001FA rating of 68.8 MW.

A similar sequence of prototype testing has been completed for the MS9001F. The first prototype machine was tested at Greenville in 1991. It is now commercial at Electricite’ de France (EDF) in Paris, France having completed its full load, f u 11 y instrumented prototype tests in 1992.

“F TECHNOLOGY OPERATING EXPERIENCE”

As ofJune 1994, the MS’7001F prototype unit at Virginia Power has accumulated more than 22,000 hours in combined cycle operation with a reliability level of 98%. Twenty additional 7F technology units are now in service, yielding similar performance. Clearly this experience has been due in large part to the stability and quality of the design process used to create this family of gas turbines.

SUMMARY Reliable heavy-duty gas turbines have resulted

from GE’s design philosophy, based on a firm analytical foundation and the experience of years of gas turbine operation in the field. On this basis, successful designs are carefully scaled to larger or smaller size. Scaling has been used to produce similar designs that range from 25 to 200 MW. Evolution of proven designs has resulted from improved components and materials which have been applied prudently and carefully to increase power and thermal efficiency. Finally, designs are carefully tested and demonstrated in extensive development facilities, and by fully instrumented prototype machines in order to provide full confirmation of the design under actual operating conditions.

0 1994 GE Company

31

LIST OF FIGURES GEK3434D

Figure 1. Figure 2. Figure 3. Figure 4. Figure 5. Figure 6. Figure 7. Figure 8. Figure 9. Figure 10. Figure 11. Figure 12. Figure 13. Figure 14. Figure 15. Figure 16. Figure 17. Figure 18. Figure 19. Figure 20. Figure 2 1. Figure 22. Figure 23. Figure 24. Figure 25. Figure 26. Figure 27. Figure 28. Figure 29. Figure 30. Figure 31. Figure 32. Figure 33. Figure 34. Figure 35. Figure 36. Figure 37.

Figure 38. Leading edge strain/ temperature (first-stage turbine bucket) Figure 39. First-stage turbine buckets (coated and uncoated IN-738 - 25,000 service hours) Figure 40. In-738 low-cycle fatigue at 1600 F (871 C)

The Brayton Cycle MS7001FA Simple Cycle Gas Turbine Growth in compressor air flow (IS0 conditions) Growth in compressor pressure ratio (IS0 conditions) Evolution of compressor design MS7001 under-frequency power (peak load, hot day 50C (122F) MS9001FA gas turbine MS7001 load test of axial-flow compressor MS5001 compressor rotor stacking Last-stage wheel with cooling-air extraction Improvements due to hot spinning Fracture toughness of compressor rotor steels Reverse-flow combustion system Combustion liner comparison Combustion liner cap Multi- and single-fuel nozzle combustion noise Transition piece Combustor dynamic pressure spectrum Combustor dynamic pressure stability (gas fuel) Gas turbine development laboratory main test bay Combustion system scale model Dry Low NO, combustor Bucket metal temperature No compressor extraction flow (ideal flow) Compressor extraction flows as needed (real flow) Internal cooling circuit First-stage bucket cooling passages First-stage nozzle cooling MS6001 second stage bucket Fourier analysis of bucket impulse excitation Wheelbox facility Statistical nature of material properties Strain accumulation during the standard creep test (constant stress and temperature) Surface cracking in IN-738 (after 1.2% creep strain at 732C, 1350F) Effect of pre-exposure in air on 871C (1600F) high-cycle fatigue life of cast IN-738 Cooled nozzle vane showing isotherms (typical) First-stage bucket leading edge strain/temperature variation (normal start-up and shutdown)

LIST OF TABLES

Table 1 Table 2

Scaling Ratios Compressor Rotor Design Parameters

For further information, contact your GE Field Sales Represen ta tie or write to GE Power Generation Marketing

GE Industrial & Power Systems

Genera/ Electric Company Building 2, Room 1158 One River Road Schenectady, NY 12345

9/94 (500)

GE Power Systems

GE AeroderivativeGas Turbines - Designand Operating Features

G.H. BadeerGE IADGE Power SystemsEvendale, OH

GER-3695E

g

Contents

Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Selection of Aeroderivative Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

LM1600 Gas Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4LM2500 Gas Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5LM2500+ Gas Turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5LM6000 Gas Turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6LM6000 Sprint™ System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8STIG™ Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Design and Operation of GE Aeroderivative Gas Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . 12Design Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Operating Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Ratings Flexibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Performance Deterioration and Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16

Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Advances in Aircraft Engine Technology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

GE Aeroderivative Gas Turbines - Design and Operating Features

GE Power Systems ■ GER-3695E ■ (10/00) i


GE Power Systems ■ GER-3695E ■ (10/00) ii

AbstractAeroderivative gas turbines possess certain tech-nical features inherent in their design heritagewhich offer operational and economic advan-tages to the end user. This paper presents anoverall description of GE's current LM series ofaeroderivative gas turbines with power outputranging from 13 to 47 MW. It discusses opera-tional and economic considerations resultingfrom GE’s aeroderivative gas turbine designphilosophies, and the value of these considera-tions in a customer’s gas turbine selectionprocess.

GE's total research and development budget foraircraft engine technology is approximately onebillion dollars a year. Today’s entire GE gas tur-bine product line continues to benefit from thisconstant infusion research and developmentfunding. Advances are constantly being madewhich improve GE’s gas turbine benefits to thecustomer.

IntroductionHeadquartered in Cincinnati, OH, GE’sIndustrial Aeroderivative Gas Turbine Division(GE-IAD) manufactures aeroderivative gas tur-bines for industrial and marine applications.GE Power Systems sells and services the current

gas turbine products, which include theLM1600, LM2500, LM2500+ and LM6000. Inaddition, the LM2000 is offered as an integrat-ed packaged product including an LM2500 gasturbine at reduced rating.

Figure 1 presents the performance characteris-tics for power generation applications, whileFigure 2 presents the product line’s perform-ance characteristics for mechanical drive appli-cations.

GE’s aeroderivative industrial products are pro-duced in two configurations:

■ Gas turbine, made up of a GE-suppliedgas generator and power turbine

■ Gas generator, which may be matchedto an OEM-supplied power turbine.

These turbines are utilized in simple cycle,STIG™ (Steam Injected Gas Turbine) applica-tions for power enhancement, or integratedinto cogeneration or combined-cycle arrange-ments. GE also produces a variety of engine-mounted, emissions control technologies,described in Figure 3.

Selection of Aeroderivative EnginesPrior to commencing production of a newaeroderivative gas turbine based on the current


GE Power Systems ■ GER-3695E ■ (10/00) 1

GE INDUSTRIAL AERODERIVATIVE GAS TURBINE PERFORMANCE CHARACTERISTICSGENERATOR DRIVE GAS TURBINE RATINGS

OUTPUT HEAT RATE EXHAUST FLOW EXHAUST TEMP. FREQUENCYMODEL FUEL kWe Btu/kWhr kJ/kWhr lb/s kg/s deg F deg C Hz

LM1600PA G 13750 9624 10153 103 46.7 910 488 50/60D 13750 9692 10225 103 46.7 928 498 50/60

LM2000 G 18000 9377 9892 139 63 886 474 60LM2500PE G 22800 9273 9783 152 69 974 523 60

D 22800 9349 9863 152 69 994 534 60LM2500PK G 30700 8815 9300 192 87.2 959 515 50/60

D 29600 8925 9415 189 85.8 965 518 50/60LM2500PV G 30240 8598 9071 186 84.3 931 499 60

D 28850 8748 9229 182 82.5 941 505 60LM6000PC G 43315 8198 8648 277 126 845 451 60

D 42111 8293 8748 276 125 851 455 60G 42665 8323 8779 277 126 845 451 50D 41479 8419 8881 276 125 851 455 50

LM6000PD G 42227 8246 8698 275 125 841 449 60D 41505 8331 8787 273 124 854 457 60G 41594 8372 8830 275 125 841 449 50D 40882 8458 8921 273 124 854 457 50

Figure 1. GE aeroderivative product line: generator drive gas turbine performance characteristics

line of aircraft engines, GE considers the fol-lowing factors:

■ Market forecast for marine andindustrial engines

■ Projected performance and pricecompetitiveness of the new line ofaeroderivative engines

■ Degree of difficulty involved inconverting the aircraft engines designinto the new, aeroderivativeconfiguration.

The last point is extremely important. In orderto keep a new aeroderivative product’s overall

cost as low as possible, the aircraft engine cho-sen as the basis for this line must be convertiblefrom aircraft to marine and industrial usage:

■ With very few changes to its originaldesign

■ Using parts which are mass-producedfor the aircraft application.

Figure 4 shows the operating hours accrued foreach of the GE parent engines in flight applica-tions and their derivative engines in industrialand marine service. For example, the LM2500and its parent aircraft engine have over 63 mil-lion hours of operating experience and have



GE INDUSTRIAL AERODERIVATIVE GAS TURBINE PERFORMANCE CHARACTERISTICSMECHANICAL DRIVE GAS TURBINE RATINGS*

OUTPUT HEAT RATE EXHAUST FLOW EXHAUST TEMP.MODEL FUEL sHP kWs Btu/HPhr kJ/kWhr lb/s kg/s deg F deg C

LM1600PA G 19200 14320 6892 9750 103 46.7 910 488D 19200 14320 6941 9820 103 46.7 928 498

LM2500PE G 31200 23270 6777 9587 152 69 974 523D 31200 23270 6832 9665 152 69 994 534

LM2500PK G 42000 31320 6442 9114 192 87.2 959 515D 40500 30200 6522 9227 189 85.8 965 518

LM2500PV G 42000 31320 6189 8756 186 84.3 931 499D 40100 29900 6297 8909 182 82.5 941 505

LM6000PC G 58932 43946 6002 8490 277 126 845 451D 56937 42458 6095 8621 276 125 851 455

LM6000PD G 57783 43089 6026 8524 275 125 841 449D 56795 42352 6088 8611 273 124 854 457

*ISO (15C, 60% RH, SEA LEVEL, NO LOSSES), BASE LOAD, AVERAGE NEW ENGINE

Figure 2. GE aeroderivative product line: mechanical drive gas turbine performance characteristics

ENGINE MOUNTED NOx ABATEMENT METHODS

MODELGAS

GENERATORGAS

TURBINESIMPLE CYCLE

COMBINED CYCLE STIG

WATER INJECTION

STEAM INJECTION DLE

LM1600 X X X X X X X XLM2000 X X X X X X X XLM2500 X X X X X X X X

LM2500+ X X X X X X XLM6000 X X X X X X

Figure 3. GE aeroderivative product line: available equipment arrangements

QUANTITY OPERATING HOURS QUANTITY OPERATING HOURSLM1600 (F404) 3400 7,000,000 146 3,500,000

LM2500 (TF39/CF6-6) 1130 32,300,000 1767 31,200,000

LM6000 (CF6-80C2) 2806 58,700,000 300 3,200,000

Data as of February, 2000

AIRCRAFT AERODERIVATIVE

Figure 4. Aircraft and aeroderivative engine operating experience as of February 2000

demonstrated excellent reliability. All GEAeroDerivative engines benefit from this com-bined experience.

The following sections will introduce and sum-marize the key characteristics of each of theindividual LM model gas turbines. Configur-ation terminology and arrangement options aredefined in Figure 5.

The following features are common to all LMmodel gas turbines:

■ A core engine (compressor,combustor, and turbine)

■ Variable-geometry for inlet guide andstator vanes

■ Coated combustor dome and liner

■ Air-cooled, coated, high-pressureturbine (HPT) blading

■ Uncooled power turbine blading

■ Fully tip-shrouded power turbine rotorblading

■ Engine-mounted accessory gearboxdriven by a radial drive shaft.

The LM1600 and LM6000 are dual-rotor units.A rotor consists of a turbine, drive shaft, and

compressor. The low-pressure rotor consists ofthe low-pressure turbine (LPT), which drivesthe low-pressure compressor (LPC) via a con-centric drive shaft through the high-pressurerotor. The high-pressure rotor is formed by thehigh-pressure turbine driving the high-pressurecompressor (HPC). The LM2000, LM2500 andLM2500+ are single-rotor machines that have

one axial-flow compressor, and an aerodynami-cally coupled power turbine.

The LM1600, and LM6000 employ electronical-ly operated, variable-bleed valves arranged inthe flow passage between the low- and high-pressure compressors to match the LPC dis-charge airflow to the HPC. These valves arefully open at idle and progressively close to zerobleed at approximately 50% power. The posi-tion of these variable-geometry controls is afunction of the LP rotor speed, HP rotor speedand inlet air temperature.

Aeroderivative engines incorporate variablegeometry in the form of compressor inlet guidevanes that direct air at the optimum flow angle,and variable stator vanes to ensure ease of start-ing and smooth, efficient operation over theentire engine operating range.



Combustor

HPC

ExhaustInlet

Fuel

LPC HPT

LPT

PT

Load Load

Variable Stators

Variable Bleed

Variable IGV

Core Engine

Figure 5. Gas turbine terminology and arrangement

Aeroderivative turbines are available with twotypes of annular combustors. Similar to thoseused in flight applications, the single annularcombustor features a through-flow, venturiswirler to provide a uniform exit temperatureprofile and distribution. This combustor config-uration features individually replaceable fuelnozzles, a full-machined-ring liner for long life,and an yttrium-stabilized zirconium thermalbarrier coating to improve hot corrosive resist-ance. In 1995, a dry, low emissions (DLE) com-bustor was introduced to achieve low emissionswithout the use of fuel diluents, such as water orsteam.

The LM1600, LM2000, LM2500, and LM2500+all include an aerodynamically coupled, high-efficiency power turbine. All power turbines arefully tip-shrouded. The LM1600 PT andLM2500+ High Speed Power Turbine (HSPT)feature a cantilever-supported rotor. The powerturbine is attached to the gas generator by atransition duct that also serves to direct theexhaust gases from the gas generator into thestage one turbine nozzles. Output power istransmitted to the load by means of a couplingadapter on the aft end of the power turbinerotor shaft. Turbine rotation is clockwise whenviewed from the coupling adapter looking for-ward. Power turbines are designed for frequent

thermal cycling and can operate at constantspeed for generator drive applications, and overa cubic load curve for mechanical drive appli-cations. The LM6000 power turbine drives boththe LPC and the load device. This feature facil-itates driving the load from either the front oraft end of the gas turbine shaft.

All of the models have an engine-mounted,accessory drive gearbox for starting the unitand supplying power for critical accessories.Power is extracted through a radial drive shaftat the forward end of the compressor. Drivepads are provided for accessories, including thelube and scavenge pump, the starter, the vari-able-geometry control, and the liquid fuelpump.

LM1600 Gas Turbine The LM1600 gas turbine consists of a dual-rotorgas generator and an aerodynamically coupledpower turbine. The LM1600 is shown in Figure6, and consists of a three-stage, low-pressurecompressor; a seven-stage, variable-geometry,high-pressure compressor; an annular combus-tor with 18 individually replaceable fuel nozzles;a single-stage, high-pressure turbine; and a sin-gle-stage, low-pressure turbine. The gas genera-tor operates at a compression ratio of 22:1.



Figure 6. LM1600 gas turbine

The LM1600 incorporates variable-geometry inits LPC inlet guide vanes and HPC stator vanes.Four electronically operated, variable-geometrybleed valves match the discharge airflowbetween the LPC and HPC. In industrial appli-cations, the nozzles and blades of both the HPTand LPT are air-cooled and coated with“CODEP,” a nickel-aluminide-based coating, toimprove resistance to oxidation, erosion, andcorrosion. For marine applications, HPT noz-zles are coated with a thermal barrier coating,LPT nozzles are coated with CODEP and theblades of both the HPT and LPT are coatedwith PBC22. The two-stage power turbineoperates at a constant speed of 7,000 rpm overthe engine operating range for generator driveapplications, and over a cubic load curve formechanical drive applications.

LM2500 Gas Turbine The LM2500 gas turbine consists of a single-rotor gas turbine and an aerodynamically cou-pled power turbine. The LM2500 (Figure 7)consists of a six-stage, axial-flow design com-pressor, an annular combustor with 30 individu-ally replaceable fuel nozzles, a two-stage, high-pressure turbine, and a six-stage, high-efficiencypower turbine. The gas generator operates at acompression ratio of 18:1.

The inlet guide vanes and the first six-stages ofstator vanes are variable. In both stages of the

high-pressure turbine, the nozzles and bladesare air-cooled. For industrial applications, thenozzles are coated with CODEP and the bladesare coated with platinum-aluminide to improveresistance to erosion, corrosion and oxidation.

The six-stage power turbine operates at a nomi-nal speed of 3,600 rpm, making it ideal for 60Hz generating service. Alternatively, it can beused in 50 Hz service without the need to add aspeed reduction gear. The LM2500 can alsooperate efficiently over a cubic load curve formechanical drive applications.

The LM2500 gas turbine is also offered at an18MW ISO rating as an integrated packagedproduct called the LM2000 with an extendedhot-section life for the gas turbine.

LM2500+ Gas Turbine The first LM2500+, a design based on the verysuccessful heritage of the LM2500 gas turbine,rolled off the production line in December1996. The LM2500+ was originally rated at 27.6MW, for a nominal 37.5% thermal efficiency atISO, no losses and 60 Hz. Since that time, its rat-ing has continually increased to reach its cur-rent level of 31.3 MW and 41% thermal effi-ciency. An isometric view of the LM2500+ gasturbine, including the single annular combus-tor (SAC), is shown in Figure 8.

The LM2500+ has a revised and upgraded com-




pressor section with an added zero stage forincreased flow and pressure ratio, and revisedmaterials and design in the HP and power tur-bines. The gas generator operates at a compres-sion ratio of 22:1. The inlet end of the LM2500+design is approximately 13 inches/330 mmlonger than the current LM2500, allowing forretrofit with only slight inlet plenum modifica-tions. In addition to the hanging support foundon the LM2500, the front frame of theLM2500+ has been modified to provide addi-tional mount link pads on the side. This allowsengine mounting on supports in the base skid.

The LM2500+ is offered with two types of powerturbines: a six-stage, low speed model, with anominal speed of 3600 rpm; or a two-stage highspeed power turbine (HSPT).

The LM2500+ six-stage power turbine displaysseveral subtle improvements over the L2500model from which it was derived:

■ Flow function was increased by 9%, inorder to match that of the HPC.

■ Stage 1, 5 and 6 blades as well as thestage 1 nozzle were redesigned.

■ Disc sizing was increased for all of thestages.

■ Spline/shaft torque capability wasincreased.

■ Casing isolation from flow path gasesby use of liners stages 1-3.

The LM2500+ two-stage HSPT has a designspeed of 6100 rpm, with an operating speedrange of 3050 to 6400 rpm. It is sold formechanical drive and other applications wherecontinuous shaft output speeds of 6400 rpm aredesirable. When the HSPT is used at 6,100 rpmto drive an electric generator through a speedreduction gear, it provides one of the bestoptions available for power generation applica-tions at 50 Hz.

Both the six-stage and two-stage power turbineoptions can be operated over a cubic load curvefor mechanical drive applications.

In 1998, a version of LM2500+ was introducedto commercial marine application. The only dif-ferences between the marine and industrial ver-sions to address the harsher environment are asfollows:

■ Stage 1 HPT nozzle coating

■ Stage 1 HPT shroud material andcoating.

LM6000 Gas Turbine The LM6000 turbine (Figure 9) consists of a five-stage LPC; a 14-stage HPC, which includes sixvariable-geometry stages; an annular combustorwith 30 individually replaceable fuel nozzles; a



Figure 8. LM2500+ gas turbine

two-stage, air-cooled HPT; and a five-stage LPT.The overall compression ratio is 29:1. TheLM6000 does not have an aerodynamically cou-pled power turbine.

The LM6000 is a dual-rotor, “direct drive” gasturbine, derived from the CF6-80C2, high-bypass, turbofan aircraft engine. The LM6000takes advantage of its parent aircraft engine’slow-pressure rotor operating speed of approxi-mately 3,600 rpm. The low-pressure rotor is thedriven-equipment driver, providing for directcoupling of the gas turbine low-pressure systemto the load, as well as the option of either coldend or hot end drive arrangements.

The LM6000 maintains an extraordinarily highdegree of commonality with its parent aircraftengine, as illustrated in Figure 10. This is unlikethe conventional aeroderivative approachwhich maintains commonality in the gas gener-

ator only, and adds a unique power turbine. Bymaintaining high commonality, the LM6000offers reduced parts cost and demonstrated reli-ability.

The status of the LM6000 program, as ofFebruary 2000, includes:

■ 300 units produced since introductionin 1991

■ 208 units in commercial operation

■ First DLE combustor in commercialoperation producing less than 25 ppmNOx - 1995

■ High time engine =50,829 hours

■ 12 month rolling average engineavailability = 96.8%

■ Engine reliability = 98.8%

■ Exceeded 3.1 million operating hours




LPCompressor

HPCompressor

HPTurbine

LPTurbine Power

Turbine

LPCompressor

HPCompressor

HPTurbine

LPTurbine

Common Unique

Generator or Compressor

Generator or Compressor AlternateGenerator or Compressor

LM6000 Approach

Traditional Approach

Common

Figure 10. LM6000 concept

■ Variable speed mechanical drivecapability – 1998

■ Dual fuel DLE in commercialoperation – 1998

■ LM6000 PC Sprint™ System incommercial operation - 1998

In mid-1995, GE committed to a major productimprovement initiative for the LM6000. Newmodels designated as LM6000 PC/PD were firstproduced in 1997, and included a significantincrease in power output (to more than 43MW) and thermal efficiency (to more than42%); dual fuel DLE; and other improvementsto further enhance product reliability.

LM6000 Sprint™ System Unlike most gas turbines, the LM6000 is prima-rily controlled by the compressor dischargetemperature (T3) in lieu of the turbine inlettemperature. Some of the compressor dis-charge air is then used to cool HPT compo-nents. SPRINT™ (Spray Inter-cooled Turbine)reduces compressor discharge temperature,thereby allowing advancement of the throttle tosignificantly enhance power by 12% at ISO, andgreater than 30% at 90°F (32°C) ambient tem-peratures.

The LM6000 Sprint™ System is composed of

atomized water injection at both LPC and HPCinlet plenums. This is accomplished by using ahigh-pressure compressor, eighth-stage bleedair to feed two air manifolds, water-injectionmanifolds, and sets of spray nozzles, where thewater droplets are sufficiently atomized beforeinjection at both LPC and HPC inlet plenums.Figure 11 displays a cross-section of the LM6000Sprint™ System. Figure 12 provides the Sprint™Gas Turbine expected performance enhance-ment, relative to the LM6000-PC.

Since June 1998, when the first twoSprint™units began commercial operation, tenother installations have gone into service. As ofFebruary 2000, LM6000 Sprint™ Gas Turbine(Figure 13) operating experience exceeds20,000 hours. Sprint™ System conversion kitsfor LM6000 PC models are now available forthose considering a potential retrofit.

STIG™ Systems STIG™ (Steam Injected Gas Turbine) systemsoperate with an enhanced cycle, which useslarge volumes of steam to increase power andimprove efficiency. See Figure 14 for STIG™ sys-tem performance enhancements at ISO baseload conditions.

In the STIG™ cycle, steam is typically producedin a heat recovery steam generator (HRSG) and



8th StageBleed Air Piping

WaterMetering

Valve

24 SprayNozzles

Air atomized spray - Engine supplied air - Droplet diameter less than 20 microns

Orifice

AirManifold

Water Manifold

AirManifold

23 SprayNozzles

Figure 11. LM6000 Sprint™ flow cross section

is then injected into the gas turbine. TheSTIG™ system offers a fully flexible operatingcycle, since the amount of steam injected canvary with load requirements and steam avail-ability. Also, steam can be injected with the gasturbine operating from 50% power to full load.

A typical STIG™ cycle is shown in Figure 15. The

installation includes a steam-injected gas tur-bine, coupled with an HRSG which can be sup-plementally fired. The control system regulatesthe amount of steam sent to process and, typi-cally, the excess steam is available for injection.Figure 16 shows the steam injection capabilityfor the various models.



Sea level, 60% Rel Hum, 5" Inlet/10" Exhaust losses Natural Gas with Water Injection to 25 ppm

25000

30000

35000

40000

45000

50000

55000

40 50 60 70 80 90 100

Engine Inlet Temperature deg F

Sh

aft

Po

wer

kW SPRINT

Base LM6000-PC

30%

12% TM

Figure 12. LM6000 Sprint™ gas turbine performance enhancement

Figure 13. LM6000 Sprint™ gas turbine

Standard Base Load, Sea Level, 60% RH, - Natural Gas - 60 Hertz -4 in. (102mm) Inlet/10 in. (254mm) Exhaust Loss - Average Engine at the Generator Terminals*

Model Dry Rating (MWe) %Thermal Efficiency (LHV) STIG Rating (MWe) %Thermal Efficiency (LHV)

LM1600 13.3 35 16 37LM2000 18 35 23.2 39LM2500 22.2 35 27.4 39

*3% margin on Eff. Included

Figure 14. STIG™ system performance enhancement – generator drive gas turbine performance



Gas turbine~

Air

Fuel SteamHRSG

To process

Exhaust

H2O

Figure 15. Typical STIG™ cycle

Standard Base Load, Sea Level, 60% RH, - Natural Gas - 60 Hertz -4 in. (102mm) Inlet/10 in. (254mm) Exhaust Loss - 25 PPM NOx

Steam Flows -lb/hr (kg/hr)Model Rating (MWe)* %Thermal Efficiency* Fuel Nozzle Compressor Discharge

LM1600 16 37 11540 (5235) 9840 (4463)LM2000 23.2 39 14558 (6604) 15442 (7005)LM2500 27.4 39 18300 (8301) 31700 (14379)

LM2500+ 32.5 40 23700 (10750)LM6000 42.3 41.1 28720 (13027)

* Average Engine at generator terminals (2.5% on LM1600 Gen, 2.0% on all others Gen, 1.5% GB included)

Figure 16. STIG™ steam flow capability – generator drive gas turbine performance

HP Steam to combustor for

NOx abatement

HP Steam for power augmentation

Figure 17. STIG™ system steam injection ports

The site at which steam is injected into the gasturbine differs according to the design of theparticular model. For instance, in both theLM1600, LM2000 and LM2500, steam is inject-ed into the high-pressure section via the com-bustor fuel nozzles and compressor dischargeplenum. See Figure 17 for the location of steaminjection ports on an LM2500 gas turbine. ASTIG™ system is not planned for the LM6000,beyond that steam injected through the fuelnozzles for NOx abatement.

Emissions NOx emissions from the LM1600, LM2000,LM2500, LM2500+ and LM6000 can bereduced using on-engine water or steam injec-tion arrangements, or by the incorporation ofDLE combustion system hardware. The intro-duction of steam or water into the combustionsystem:

■ Reduces NOx production rate

■ Impacts the gas turbine performance

■ Increases other emissions, such as COand UHC

■ Increases combustion system dynamicactivity which impacts flame stability

■ The last item results in a practicallimitation on the amount of steam orwater which can be used for NOxsuppression.

Figure 18 lists the unabated NOx emission levelsfor the GE Aeroderivative gas turbines when

burning either natural gas or distillate oil.Depending on the applicable federal, state,country and local regulations, it may be neces-sary to reduce the unabated NOx emissions.

Figure 19 shows GE’s current, guaranteed mini-mum NOx emission levels for various controloptions. With steam or water-injection and sin-gle fuel natural gas, the LM2500 can guaranteeNOx emissions as low as 15 ppm. For applica-tions requiring even lower NOx levels, othermeans, such as selective catalytic reduction(SCR), must be used.

In 1990, GE launched a Dry Low EmissionsCombustor Development program for itsaeroderivative gas turbines. A premixed com-bustor configuration (Figure 20), was chosen toachieve uniform mixing of fuel and air. Thispremixing produces a reduced heating valuegas, which will then burn at lower flame tem-peratures required to achieve low NOx levels.Increased combustor dome volume is used toincrease combustor residence time for com-plete reaction of CO and UHC. DLE combus-tors feature replaceable premixer/nozzles andmultiple burner modes to match low demand.



ISO - Base Load - SAC CombustorUnabated NOx Emissions (ppmvd ref.15% O2)

Model Natural Gas Distillate Oil LM1600 127 209LM2000 129 240LM2500 179 316

LM2500+ 229 346LM6000 205 403

Figure 18. GE aeroderivative gas turbine unabated NOx emissions

Figure 19. Minimum NOx emission guarantee levels – wet and dry emissions control options

In order to achieve low emissions throughoutthe operating range, fuel is staged through theuse of multiple annuli. The LM1600 uses a dou-ble annular configuration, while all other mod-els use a triple annular construction.

Factory testing of components and engineassembly on an LM6000 gas turbine was com-pleted in 1994. These tests demonstrated lessthan 15 ppm NOx, 10 ppm CO and 2 ppm UHCat a firing temperature of 2350°F/1288°C atrated power of 41 MW.

The Ghent power station in Belgium becamethe first commercial operator to use theLM6000 fitted with the new DLE combustor sys-tem. A milestone was reached in January 1995when the station achieved full power at 43 MWwith low emissions of 16 ppm NOx, 6 ppm COand 1 ppm UHC. As of today, the high timeLM6000 engine has accumulated over 34,000hours.

By the end of 1999, there were 3 LM1600, 58LM2500, 27 LM2500+, and 30 LM6000 gas tur-bines equipped with the DLE combustion sys-tem in service worldwide.

Today, GE continues its DLE technology devel-

opment on the Dual Fuel DLE front.Completely dry operation has been achieved ongas and distillate fuels on two LM6000 enginesin the United Kingdom. Operating on liquidfuel, NOx and CO emission levels have been lessthan 125 ppm and 25 ppm, respectively. GEcontinues to do research on reducing liquidfuel to NOx levels below 65 ppm , with the goalof achieving this by the end of the year 2000. Byearly 2001, GE plans to release a Dual Fuel DLEsystem on the LM2000, LM2500 and LM2500+gas turbines.

Design and Operation of GEAeroderivative Gas Turbines

Design Features GE Aeroderivative gas turbines combine hightemperature technology and high pressureratios with the latest metallurgy to achieve sim-ple-cycle efficiencies above 40%, the highestavailable in the industry.

It is essential to GE’s aeroderivative design phi-losophy that an industrial or marine aeroderiv-ative gas turbine retain the highest possibledegree of commonality with the flight engine



Combustion Liner

Heat Shield

Premixer

Figure 20. DLE combustor

on which the aeroderivative is based. Thisresults in a unique and highly successfulapproach to on-site preventive and correctivemaintenance, including partial disassembly ofthe engine and replacement of componentssuch as blades, vanes and bearings. On-sitecomponent removal and replacement can beaccomplished in less than 100 manhours.Complete gas generators and gas turbines canbe made available within 72 hours (guaran-teed), with the complete unit replaced andback on-line within 48 hours. The hot-sectionrepair interval for the aeroderivative meets theindustrial demand of 25,000 hours on naturalgas. The LM engines have been adapted tomeet the important industrial standards ofASME, API, NEC, ISO9001, etc., consistent withtheir aircraft engine parentage.

Other advantages related to the evolution fromthe flight application are the technical require-ments of reduced size and low weight. Theaeroderivatives’ rotor speeds (between 3,000and 16,500 rpm) and casing pressure (20 to 30atmospheres) may appear high when comparedwith other types of gas turbines. However, thehigh strength materials specified for the aircraftengine are capable of handling these pressuresand rotor speeds with significant stress margins.For example, cast Inconel 718, commonly usedfor aircraft engine casing material, has a yieldstrength of 104 ksi (717 kN/m2) at1200°F/649°C, while cast iron commonly usedin other types of gas turbine casings has a yieldstrength of 40 ksi at 650°F (276 kN/m2 at343°C).

The aeroderivative design, with its low support-ed-weight rotors – for example, the LM2500 HProtor weighs 971 lbs/441 kg – incorporatesroller bearings throughout. These do notrequire the large lube oil reservoirs, coolers andpumps or the pre-and post-lube cycle associated

with other bearing designs. Roller bearingshave proven to be extremely rugged and havedemonstrated excellent life in industrial serv-ice. Although bearings generally provide reli-able service for over 100,000 hours, in practice,it is advisable to replace them when they areexposed during major repairs, or, at an estimat-ed 50,000 hours for gas generators and 100,000hours for power turbines.

The high-efficiency aeroderivative is an excel-lent choice for simple-cycle power generationand cyclic applications such as peaking power,which parallels aircraft engine use. With starttimes in the one-minute range, the aeroderiva-tive is ideal for emergency power applications ofany sort.

With its inherently low rotor inertias, and thevariety of pneumatic and hydraulic startingoptions available, the GE Aeroderivative enginehas excellent “black start capability,” meaningthe ability to bring a “cold iron” machine on-line when a source of outside electrical power isunavailable. An additional benefit of having lowrotor inertias is that starting torques and powerrequirements are relatively low, which in turnreduces the size and installed cost of either thepneumatic media storage system or the dieselor gasoline engine driven hydraulic systems. Forexample, the LM2500 starting torque is lessthan 750 ft-lbs (1,017 N-m), and its air con-sumption during a typical start cycle is between2,000 and 2,600 SCFM (56,600 and 73,600l/min).

Fuels Natural gas and distillate oil are the fuels mostfrequently utilized by aeroderivatives. Theseengines can burn gaseous fuels with heating val-ues as low as 6,500 Btu/lb (15,120 kJ/kg).Recently, an LM6000 with a single, annularcombustor was modified to operate on mediumBtu (8,000-8,600 Btu/lb ~ 18,600-20,000 kJ/kg)



fuel. It demonstrated that it could operate withlower NOx emissions without requiring flame-quenching diluents such as water or steam.

As part of GE’s Research and DevelopmentProgram, an LM2500 combustor, modified toutilize low heating value biomass fuel, has beenoperated in a full annular configuration atatmospheric pressure. A sector of the annularcombustor design was then tested at gas turbineoperating pressures. Ignition, operability, gastemperature radial profiles, temperature varia-tions and fuel switching were in acceptableranges when operated on simulated biomassfuel. Low NOx is a by-product since low heatingvalue fuel is essentially the same as operating ina lean premix mode like the DLE combustor.

Operating Conditions The climatological and environmental operat-ing conditions for aeroderivatives are the sameas for other types of gas turbines. Inlet filtrationis necessary for gas turbines located in areaswhere sand, salt and other airborne contami-nants may be present.

At the extreme ends of the ambient tempera-ture spectrum, the aeroderivative exhibits a lessattractive lapse rate (power reduction at off-ambient temperatures) than other types of gasturbines. However, the LM aeroderivative doeshave a “constant power” performance optionwhich can be applied in areas where theextremes are encountered for extended periodsof time.

Ratings Flexibility All turbines, including aeroderivatives, have“base ratings”. In the case of GE’s aeroderiva-tives, when natural gas is used as the fuel andthe engine is operated at the base power tur-bine inlet temperature control setting, its baserating corresponds to a hot-section repair inter-val of approximately 25,000 hours. The LM2000

is an exception; at its base rating the hot-sectionrepair interval is approximately 50,000 hours.

Aeroderivatives utilize the same basic hardwareas aircraft engines, which are designed to oper-ate reliably at firing temperatures much higherthan the corresponding aeroderivative base rat-ing temperatures. By taking advantage of theextensively air cooled hot-gas-path componentstypically found in aircraft engines, aeroderiva-tive models can operate at higher temperaturesand power levels than their base rating.

The LM2500 will be used as an example, withthe other LM products having similar charac-teristics. Figure 21 illustrates the full capability ofthe LM2500 as a function of ambient tempera-ture. In the ambient temperature region above55°F/13°C, the LM2500’s maximum capabilityis limited by the maximum allowable tempera-ture at the power turbine inlet. Figure 21 alsoshows the availability of additional power abovethe ISO base rating of the unit.

In order to achieve this increased power, opera-tion at increased cycle temperature is necessary.As with any gas turbine, the hot-gas-path sectionrepair interval (HSRI) of the LM2500 is relatedto the cycle temperature. Figure 22 presents therelationship between output power, power tur-



Figure 21. LM2500 maximum power capability

bine inlet temperature and estimated timebetween hot-section repairs. The ISO rating tem-perature corresponds to the curve for an esti-mated 25,000 hours between hot-section repairswhen burning natural gas fuel. Figure 22 alsoshows that power is available for applicationsrequiring more power than is available when lim-iting the temperature to that associated with the25,000 hours curve. However, those LM2500s uti-lizing this additional power will require more fre-quent hot-section repair intervals.

The LM2500, like any gas turbine operating at aconstant cycle temperature, has more poweravailable at lower ambient temperatures than athigher ambient temperatures. This is shown inFigure 22 by the sloping lines of constant hot-section repair intervals (constant power turbineinlet temperature). There are, however, manyapplications in the industrial market that can-not use all of the power that is available at thelower ambient temperatures. In these cases, theoperating characteristic of “constant power,”regardless of the ambient temperature, is moreconsistent with the actual requirements of theinstallation.

Figure 23 shows an example of an application

where constant power, rather than variablepower, is required over a specific ambient tem-perature range. This figure clearly shows thatthe LM2500 is capable of producing this powerover the full ambient temperature range.However, the estimated hot-section repair inter-val for this type of operation is not apparent inFigure 23, since when operating during highambient temperature conditions, the power tur-bine inlet temperature corresponds to shorterintervals than when operating at lower ambienttemperatures.

An ambient temperature profile for the partic-

ular site is needed to determine the duration ofoperation at the various power turbine inlettemperatures. Once this ambient temperatureinformation is available, an estimate of the hot-section repair interval for this power level andparticular site can be made. If the operator doesnot provide duty cycle estimates, it is generallyassumed that a unit operates continuously for8,600 hours per year for any given site.

To carry this example further, assume the ambi-ent temperature profile for this particular siteresults in an estimated hot-section repair inter-val of 25,000 hours for this power level.

Comparison of operation at constant tempera-ture and constant power level is shown in Figure24. Since both curves result in an estimated hot-



Figure 22. Effect of increased power rating onLM2500 hot-section repair interval

Figure 23. LM2500 constant power rating

section repair interval of 25,000 hours, poten-tial power at low ambient temperatures hasbeen traded for more potential power at higherambient temperatures. Again, for an applica-tion where the required power is independentof the ambient temperature, a constant powerrating results in trading off the higher power atlow ambient temperatures for extended con-stant power at higher ambient temperatures.

Performance Deterioration and Recovery Deterioration of performance in GEAeroderivative (LM) industrial gas turbines hasproven to be consistent over various enginelines and applications. Total performance loss isattributable to a combination of “recoverable”(by washing) and “non-recoverable” (recover-able only by component replacement or repair)losses.

Recoverable performance loss is caused by foul-ing of airfoil surfaces by airborne contami-nants. The magnitude of recoverable perform-ance loss is determined by site environment andcharacter of operations. Generally, compressorfouling is the predominant cause of this type ofloss. Periodic washing of the gas turbine, eitherby on-line wash or crank-soak wash procedures,will recover 98% to 100% of these losses. The

severity of the local environment and opera-tional profile of the site determine the frequen-cy of washing.

Studies of representative engines in variousapplications show a predictable, nonrecover-able performance loss over long-term use.Deterioration experience is summarized inFigure 25 for power and heat rate for an LMaeroderivative gas turbine operating on naturalgas fuel.

This figure illustrates long-term, non-recover-able deterioration, not losses recoverable bywashing. Power deterioration at the 25,000-hour operating point is on the order of 4%;heat rate is within 1% of “new and clean” guar-antee. These deterioration patterns are refer-enced to the “new and clean” base rating guar-antee, although actual as-shipped engine per-formance is generally better than the guaranteelevel.

Generally, HPT components are replaced at25,000 hour intervals for reasons of blade lifeand performance restoration. The result ofreplacement of the HPT components is 60% ormore restoration of the non-recoverable per-formance loss, depending on the extent of workaccomplished. Over 80% recovery can beachieved if limited high-pressure compressor



Figure 24. LM2500 constant PT inlet temperatureand constant power operation

Figure 25. LM2500 field trends – power and heatrate deterioration

repairs are performed at the same time.General overhauls at about 50,000-hour inter-vals entail more comprehensive componentrestorations throughout the engine, and mayresult in nearly 100% restoration of the non-recoverable performance.

When using liquid fuel, which is more corrosivethan natural gas, a similar but more rapid pat-tern of deterioration occurs, resulting inapproximately the same 3% to 5% level at thetypical 12,500-hour liquid-fuel HPT repair inter-val.

Maintenance FeaturesIn an operator’s life cycle cost equation, the

most important factors are engine availabilityand maintenance cost. To enhance these con-siderations in regard to its aeroderivativeengines, GE has invested considerable effort indeveloping features to optimize the result ofthis equation. GE’s aeroderivatives’ uniquedesigns allow for maintenance plans with thefollowing features:

■ Borescope inspection capability. Thisfeature allows on-station, internalinspections to determine thecondition of internal components,thereby increasing the intervalbetween scheduled, periodic removalsof engines. When the condition of theinternal components of the affectedmodule has deteriorated to such anextent that continued operation is notpractical, the maintenance programcalls for exchange of that module.

■ Modular design. Using their flightheritage to maximum advantage,aeroderivative engines are designed toallow for on-site, rapid exchange ofmajor modules within the gas turbine.The elapsed time for a typical HPT

and combustion module replacementis 72 hours. This exchange allows thegas turbine to operate for anadditional 25,000 hours.

■ Compactness. The GE AeroDerivativeengines have inherited modestdimensions and lightweightconstruction that generally allows foron-site replacement in less than 48hours.

■ Monitoring and Diagnostics Servicesare made available by establishingdirect phone connections from thecontrol system at the customers' sitesto computers in GE's LM monitoringcenter. These services link theexpertise at the factory with theoperations in the field to improveavailability, reliability, operatingperformance, and maintenanceeffectiveness. Monitoring of keyparameters by factory experts allowsearly diagnosis of equipment problemsand avoidance of expensive secondarydamage. The ability for serviceengineers to view real-time operationsin many cases results in acceleratedtroubleshooting without requiring asite visit (Figure 26).



Figure 26. Monitoring and Diagnostic services: GEengineer remotely monitoring a unit

The integration of all of the features notedabove enables the operator to monitor the con-dition of the engine, maximize uptime, andconduct quick maintenance action. To learn ingreater depth about the maintenance of the GEAeroderivative gas turbines, refer to GER-3694,“Aeroderivative Gas Turbine Operating andMaintenance Considerations.”

Advances in Aircraft EngineTechnologyGE Aircraft Engines invests over $1 billionannually in research and development, much ofwhich is directly applicable to all of GE’saeroderivative gas turbines. In particular, con-sistent and significant improvement has beenmade in design methodologies, advanced mate-rials and high-temperature technologies. Areasof current focus are presented in Figure 27. Asthese technological advances are applied toindustrial uses, GE’s aeroderivative enginesbenefit from continual enhancement to attaingreater power, efficiency, reliability, maintain-ability and reduced operating costs.

In 1993, GE Aircraft Engines began testing thenew, ultra-high thrust, GE90, high bypass fanengine (Figure 28). The thrust level demonstrat-ed at initial certification was 87,400 pounds(376,764 N), and since then, has reached athrust level of 110,000 pounds.

The advanced technologies proven in the GE90engine include wide-chord composite fanblades, short durable 10-stage HPC, compositecompressor blades and nacelles, and a dual-dome annular combustor. These attributes con-tribute to delivering economic advantages oflow fuel consumption, low noise and emissions,reliability of a mature engine, and growth capa-bility to over 100,000 pounds thrust.

In 1995, the GE90 engine entered commercialservice on a Boeing 777 aircraft operated byBritish Airways. One year later, a growth versionof this engine, rated at 90,000 pounds of thrust,was certified and delivered. By 2000, GE90engines had realized a major landmark, havingaccumulated more than one million flighthours since entry into service. After loggingone million flight hours, and fueled by strongmarket interest and customer commitments,the Boeing Company and GE introduced twonew, longer range models, powered by thenewly introduced, growth derivative GE90-115Bengine.

SummaryGE’s continued investment in R&D aircraftengine technology enables the LM series of gasturbines to maintain their leadership positionin technology, performance, operational flexi-bility, and value to the customer. Offered inpower output from 13 to 47 MW, and having the



• Components– Multi-Hole Combustion Liner– Dual Annular Combustors– Aspirating Seals– Counter Rotating Turbines– Fiber Optic Controls– High Temperature Disks– MMC Frames/Struts– Model Based Controls– Composite Wide Chord Fan Blades– Swept Airfoils– Lightweight Containment– High Torque Shafts– Magnetic Bearings

• Metals– High temperature Alloys

• N5. N6, R88DT, MX4– Intermetallic Alloys

• NiAl, TiAl, Orthorhombic Ti– Structural Ti Castings

• Non-metals– Polymeric Composites

• PMR 15 Case• Composite Fan Blade

– High Temperature Polymerics (700oF/371oC)– Thermal Barrier Coatings

• Advanced Materials– Metal Matrix Composites (MMC)– Ceramic Matrix Composites

• Advanced Processes– Dual Alloy Disks– Spray Forming– Laser Shock Peening– Translational friction Weld– Braiding– Resin Transfer Molding– Waterjet Machining– Superplastic Forming/Diffusion Bonding– Robust Material Processes

• Technology Aids– Six Sigma Processes– Remote Monitoring & Diagnostics– Concurrent Engineering/Manufacturing– Design Engineering Workstations– Computational Fluid Dynamics– Process– Modeling– Stereolithography Apparatus– Virtual Reality– Advanced Instrumentation– New Product Introduction Methods

Figure 27. New processes and technologies

Figure 28. GE90 high-bypass fan engine on Boeing 777

ability to operate with a variety of fuels andemission control technologies, GE’s aeroderiva-tive gas turbines have gained the widest accept-ance in the industry, with total operating expe-rience in excess of 41million hours. These tur-bines have been selected for a multitude of

applications, from power generation tomechanical drive, for the exploration, produc-tion and transmission of oil and gas, as well asmarine propulsion systems including transport,ferryboat, and cruise ship installations.



List of FiguresFigure 1. GE aeroderivative product line – generator drive gas turbine performance

Figure 2. GE aeroderivative product line – mechanical drive gas turbine performance

Figure 3. Available GE aeroderivative product line equipment arrangements

Figure 4. Aircraft and aeroderivative engine operating experience as of February 2000

Figure 5. Gas turbine terminology and arrangement



Figure 8. LM2500+ gas turbine


Figure 10. LM6000 concept

Figure 11. LM6000 Sprint™ flow cross-section

Figure 12. LM6000 Sprint™ performance enhancement

Figure 13. LM6000 Sprint™ gas turbine

Figure 14. STIG™ System performance enhancement- generator drive gas turbine performance

Figure 15. Typical STIG™ cycle

Figure 16. STIG™ steam flow capability generator drive gas turbine performance

Figure 17 LM2500 STIG™ steam injection ports

Figure 18. GE aeroderivative gas turbine unabated NOx emissions

Figure 19. Minimum NOx emission guarantee levels - wet and dry emissions control options

Figure 20. DLE combustor

Figure 21. LM2500 maximum power capability

Figure 22. Effect of increased power rating on LM2500 hot-section repair interval

Figure 23. LM2500 constant power rating

Figure 24. LM2500 constant PT inlet temperature and constant power operation

Figure 25. LM2500 field trends - power and heat rate deterioration

Figure 26. Monitoring and Diagnostic Services: GE engineer remotely monitoring a unit.

Figure 27. New processes and technologies

Figure 28. GE90 high-bypass fan engine on Boeing 777




GE Control System Evolution 3.0

GE CONTROL SYSTEM EVOLUTION


GE Control System Evolution 1

MICROPROCESSOR BASED SPEEDTRONIC MARK IV

GAS TURBINE CONTROL SYSTEM

INTRODUCTION The object of this section is to give some historic background of the evolution that led to the SPEEDTRONIC Mark IV system. It will also tabulate the pertinent functional features of Mark I, Mark II and Mark IV, and highlight the salient features of the Mark IV system. It will touch on the new technologies that have made possible a more comprehensive operator interface, a 2-to-1decrease in system unavailability, and an order of magnitude improvement in application flexibility while at the same time increasing the life of the gas turbine.

Background Since the initial prototype field installation in 1968 on an MS 5001 gas turbine, the SPEEDTRONIC control system evolved from Mark I through Mark II to Mark IV, from a combination of discrete solid state components, meters, relays and drop-or light-type annunciators, to a system of redundant microprocessors, CRT monitor, and output relays. The primary objective of these developments has always been to improve overall gas turbine life, reliability, availability, application flexibility, and serviceability.

Evolution Summary A gas turbine control system is quite complex, and a number of systems have been used since the original MS 3001 power generation unit was first commissioned in 1948. The SPEEDTRONIC Mark I control was developed in 1965, and was first installed on production machines starting in 1968. It was the first GE Co. solid state (with discrete components) analog control system, using about 50 printed circuit boards, and it was coupled with relay type sequential and output logic. This section summarizes the major systems that have been used to control GE gas turbines since their inception. The tabulation is set up referenced to the approximate dates of production, but some systems were used concurrently: 1. Fuel Regulator 1948 to 1970 2. Mechanical Controls 1954 to 1960 3. SPEEDTRONIC Mark I 1968 to 197 4. SPEEDTRONIC Mark II 1975 to 1982 5. SPEEDTRONIC Mark II with ITS* 1980 to 1984 6. SPEEDTRONIC Mark IV 1983 to 1992 The following is an overview of the basic control requirements, and it describes how each of the key systems operates (including turbine sensors). Only the functions of the devices are provided, without details of how the devices work. This applies primarily to the heavy duty gas turbine type, even though much of it is similar for the aircraft derivative type.



BASIC CONTROL REQUIREMENTS The Gas Turbine control system is designed to crank the turbine, bring it to purging speed (approx. 20%), fire it, and then bring the unit to operating speed. On generator drives, the control system synchronizes the gas turbine to the line. For compressor or process drives, it checks the process constraints and then loads the gas turbine to the appropriate point. This sequence must occur automatically, and is done while minimizing the thermal stresses in the gas turbine hot gas path parts and associated hardware. The total control system can be divided into four functional subsystems: 1. Control 2. Protection 3. Sequencing 4. Power Supply The control subsystem is the predominant, and it must perform six basic functions: 1. Set start-up and normal fuel limits 2. Control turbine acceleration 3. Control turbine speed 4. Limit internal turbine temperatures 5. Control variable inlet guide vanes 6. Control 2nd stage nozzle (2-shaft units only) Only one control function (or system) can control the fuel flow to the gas turbine at a time. The control systems feed a "minimum value gate", whose output is used as the input by the fuel control system. A minimum value is used to provide the safest operation of the turbine.

CONTROLS

Start-up Control The gas turbine control system sets fuel limits during start-up for optimum ignition and crossfire, and to prevent excessive thermal shock. Figure 3-4 is a typical curve showing fuel limits, speed, and exhaust temperature vs. time. The control sets the upper fuel limit as a function of speed and time events. At typically l8 to 20% speed, a fuel to air ratio is selected that will produce an approximately l000 øF temperature rise in the combustors. After flame detection, the fuel flow limit is reduced to a warm-up value for about a minute to provide slow heating of the turbine section parts. After the warm-up period, the fuel flow is slowly increased to bring the turbine to operating speed. The gradual fuel increase is designed to minimize thermal shock. The start-up control will set a maximum fuel limit after the unit is at rated speed, preventing the start-up control from limiting fuel via the minimum value gate.



Speed Control The gas turbine may have two types of speed governors: droop or isochronous. The droop governor is used on generator drives, and is required to provide system stability. Figure 1-5 illustrates the droop governor operation. For a unit operating isolated with a fixed speed set point, the speed of the turbine would droop 4% if the load was increased from zero to rated. The speed regulation (or droop governor) is provided by a proportional controller. The governor has an adjustable setpoint, with its maximum point called the high speed stop (HSS), and its minimum point called the low speed stop (LSS). The isochronous governor provides a constant turbine speed independent of load changes. This governor is used on mechanical drive units, and may be used on a generator drive that is on a small system. The isochronous governor could be shown by a "family" of horizontal lines instead of sloping lines. Isochronous control is produced by a proportional plus integral controller. A minimum fuel limit is provided to prevent speed control from causing a "flame out" during a system disturbance. During a normal "fired" shutdown, minimum fuel provides a cooldown period with minimum flame to minimize thermal shock that would occur if flame was abruptly extinguished.

Temperature Control The internal temperature limit is at the entrance plane to the first stage nozzle, and is called the "firing" temperature. This temperature is not measured directly in the turbine section flow path, since the high temperatures shorten sensor life and large temperature gradients exist. The firing temperature is calculated by measuring turbine exhaust temperature and compressor discharge pressure (which represents the pressure drop through the turbine). This also corrects for ambient temperature variations, since cold air is denser than warm air. For the same load, the compressor discharge pressure will be higher on a cold day than on a warm day. On a cold day, the turbine section has a higher pressure drop and temperatures. The exhaust temperature must be held lower, in order to maintain the same firing temperature. Figure 1-6 shows a plot of exhaust temperature vs. compressor discharge pressure for constant firing temperature. A similar curve can be developed by using the fuel flow signal in place of compressor discharge pressure (See Figure 1-7).

Protection The protection system is designed to trip the turbine by stopping fuel flow when critical parameters are exceeded, or control equipment fails. Fuel flow is stopped by a minimum of two separate devices; the stop valve is the primary, and the control valve is the secondary. The stop and control valves are closed by both electrical and hydraulic signals. The more complex protective systems are listed below: 1. Overtemperature 2. Overspeed 3. Loss of Flame 4. Vibration 5. Combustion monitor (not part of early protective requirements, but now is a standard)



Other protective functions are required, such as low lube oil pressure or high lube oil temperature. Although equally important, these protective functions can be performed by simpler components. The protective system monitors the turbine during start-up and operation. A start-up is aborted if any of the protection systems are still in a "trip" state at the time the turbine is given a "start" signal, and/ or a protection system fault or failure is detected. An alarm will occur if critical levels are reached or if any portion of the protective system fails.

Sequencing Sequential circuits are provided to sequence the turbine, the generator, the starting device, and the auxiliaries during start-up, running, shutdown, and cooldown. The sequential system monitors the protective system and other major systems such as the fuel, hydraulic, and trip oil systems, and generates logic signals which permit the turbine to start and stop in a prescribed manner. These logic signals include speed level signals, speed set point control, load capacity selection, fuel selection, starting means control, and the system functional timers.

Power Supply The power supply must be reliable and non-interruptable, and DC storage batteries are used as the primary supply for control power, and for backup DC motor-driven pumps. AC power is required for the ignitors, and can be supplied from the batteries with a DC/AC inverter when required to provide "black start" capability.

EVOLUTION OF THE SPEEDTRONIC CONTROL SYSTEM

Fuel Regulator The fuel regulator control system is a combination of mechanical, hydraulic, electrical, and pneumatic control devices which were supplied by various vendors. The fuel regulator is a control device, but fuel does not pass through the fuel regulator. The primary control signal is called VCO (Variable Control Oil) pressure. Zero fuel flow occurs below 40 psig, and maximum fuel setting is at 200 psig. Fuel limits are determined by setting mechanical stops for the various limiting values, and these adjustments are located on the fuel regulator. The turbine speed is sensed by a 3-phase tachometer generator, whose output is rectified to provide a DC voltage proportional to speed. This speed signal is used by the governor circuits to provide droop governing, as isochronous control was rarely used. The operator controls the speed set point with a motor driven potentiometer. The turbine exhaust temperature is sensed by 12 control thermocouples connected in parallel to measure an average exhaust temperature. The exhaust signal is changed to an air pressure value before it is fed to the fuel regulator to limit VCO. The turbine firing temperature can be calculated by biasing the exhaust temperature signal with either a VCO or PCD (compressor discharge pressure) value.



Valve or fuel pump stroke positioning is done by low pressure hydraulics (300 psig) and a hydraulic positioning servo. There is no position feedback loop back to the control system. VCO is the position set point for the hydraulic positioning servo. The latest overtemperature protection for the fuel regulator units used two (2) to six (6) exhaust thermocouples which are separate from the control thermocouples, and grouped into two channels with an isothermal alarm and trip setting. One channel indicating a high value can cause a trip. Earlier systems used two sensing bulbs with a pneumatic output in the exhaust duct. Overspeed protection is provided by a mechanical overspeed bolt trip mechanism. Vibration protection systems utilized velocity (seismic) type sensors, which is also the same for Mark I, Mark II and Mark IV applications. The latest flame detectors detect ultraviolet radiation in the combustion liners. Two or more detectors are provided for turbine start-up and redundancy, but flame detection by only one detector is required to operate the turbine. On older units, thermopiles and the exhaust thermocouples were used to detect flame. Sequencing is provided by using 125 Vdc relays along with the turbine switches for pressure, temperature, and position. The power supply is the unit battery at 125 Vdc.

SPEEDTRONIC Mark I & Mark II The Mark I and Mark II system is an electro-hydraulic control system. The electric portion is determined by analog calculation of operational amplifiers ("op amps"). High pressure (1200 to 1500 psig) hydraulic oil actuated devices are again used to position valves. A major difference between Mark I and Mark II is the change in electrical components; Mark I used mostly discrete components, while Mark II uses mostly integrated circuits. The primary control signal is designated VCE (Variable Control "EMF") voltage. Zero fuel flow occurs at 4 units of VCE, and maximum flow is at 18 to 20 VCE. For Mark I, the 0-20 VCE represented 0-20 volts on the circuit boards, while in Mark II, it was only 0-10 volts due to the microelectronics. Fuel limits are determined by adjusting potentiometers in the analog circuits. The turbine speed is sensed by magnetic pickups close to a 60 toothed wheel. The pulses pass through a pulse rate to analog convertor for the use by the operational amplifiers. The Mark I system uses two (2) pickups: one for control and a comparator input, and the other for speed relays and a comparator input to detect failures. The Mark II also uses two pickups, but the pulse signals are added by capacitors. This method still provides a speed signal with one failed pickup, but the failed pickup would cause an alarm. The operator controls the speed setpoint with a 10 or 12 bit reversing binary counter, and a digital to analog converter to provide an analog signal to an operational amplifier.



The temperature control has a complex history, and the key characteristics are outlined on the temperature control facts sheet. It should be noted that to control at a constant firing temperature, PCD bias has become the preferred method of exhaust temperature biasing. Valve positioning is done with high pressure hydraulics and controlled by an electrohydraulic servo valve using LVDTs (Linear Variable Differential Transformers) to provide position feedback for closed loop control. Redundancy has been achieved by using a two coil type servo valve and in most cases, two LVDTs. The controls can function with just one servovalve coil and/ or LVDT working. Overtemperature protection generally uses two (2) to six (6) dedicated exhaust thermocouples separate from the control thermocouples and grouped into two channels. Any channel exceeding the trip setting will cause a turbine trip. The primary overspeed protection is provided by three magnetic pickups driving separate tuned circuits. Two channels would have to sense an overspeed in order to trip the turbine. On most units, the mechanical overspeed bolt is used as a backup, and is set to trip at a higher speed than the electronic trip speed. The magnetic pickups for the overspeed protection are separate from the control pickups. Flame detection employs ultraviolet radiation detectors similar to the later fuel regulator systems. The sequencing in the Mark I utilizes 28 Vdc relays, while in the Mark II, digital logic software provides the sequencing. Both control systems use relays where required for isolation, solenoid valves, or customer signal interfacing. The primary source of energy for the control power supplies is the unit battery, which is float-charged by a charger connected to the 120 Vac 50/60 Hz panel board. The final bus voltages for Mark I are +50 Vdc, +28 Vdc, +12 Vdc, -50 Vdc and sometimes -12 Vdc. The final bus voltages on the Mark II are +28 Vdc, + 12Vdc, +5.3 Vdc, and -12 Vdc.

SPEEDTRONIC Mark II with "ITS" The ITS (Integrated Temperature System) system eliminated some of the control functions from the op amps, and transfers them to a microprocessor. The control calculations are made by a digital computer instead of an analog computer. The control functions performed by the ITS include temperature control, inlet guide vane control, nozzle control for the two shaft units, water or steam injection control, and overtemperature protection with an analog backup separate from the control thermocouples. The ITS is not the first gas turbine application of microprocessors, as the first application was a combustion monitor in 1974. The combustion monitor did not provide control, but provided a shutdown or trip logic if a combustion problem was detected inside the turbine. The ITS system also includes the combustion monitor function. The ITS system contains software sequencing, where logic decisions are made by the microprocessor based on a defined program.

The ITS system requires a separate power supply input from the unit battery. The final bus voltages are +28 Vdc, +15 Vdc, +5 Vdc, and -15 Vdc.

SPEEDTRONIC Mark IV The Mark IV system is a microprocessor based, electro-hydraulic control system. The microprocessor portion performs digital control calculations based on input signals from turbine sensors and the control program. The microprocessor hardware will provide an analog voltage for a servo valve driver, with its closed loop analog position feedback from an LVDT. Redundancy is built in with three microprocessor controllers called <R>, <S>, and <T> which provide basic control, and a fourth called <C> which provides communications. <RST> is the common abbreviation for the three identical but independent controllers. The system can safely and reliabily control with two (2) of the three (3) controllers operating. The name of the primary fuel control signal is FSR (Fuel Stroke Reference). Zero fuel flow is at 0% FSR, and maximum fuel flow is at l00% FSR. Fuel flow limits are set by adjusting control constants visible on a CRT monitor display. The turbine speed is sensed by three magnetic pickups (one for each controller) facing a 60-tooth wheel. The pulses pass through a pulse rate to digital converter for use by the microprocessor for speed control calculations. The speed setpoint is in software, using a reversing binary counter stored in memory. The temperature control is similar to ITS; however, each of the <RST> controllers sees only one third of the exhaust thermocouples. <C> receives temperature information from each <RST> controller, and <C> tells each controller how to correct its temperature measurement, so that it is equal to a true average value. The primary overspeed protection is based on speed measurements by the speed control pickups. Overtemperature protection is based on the temperature measured by the control thermocouples, with redundancy provided by the three (3) controllers. Valve position control is by high pressure hydraulic oil flow regulated by a three (3) coil servovalve. Each controller drives one of the three coils, and LVDTs provide position feedback. Flame detection is the same as Mark II. Sequencing is done in software, similar to ITS. Relays are used for isolation, solenoid valves, and other interfacing. The Mark IV has six (6) power supplies, one each for <RST> and <C>, and two (2) power supplies for the relays. All power supplies are fed from the unit battery. AC power is required for the CRT and the printer. The table shown in Figure 1-8 outlines the key differences between Mark I, Mark II, and Mark IV.



SPEEDTRONIC CONTROL SYSTEM FEATURE EVOLUTION COMPONENTS Mark I Mark II Mark IV

Discrete Transistors (few ICs)

Max use of integrated circuits

Microprocessors -(four)

Meters Meters CRT Display*

Indicator Lights Indicator Lights CRT Display*

Annunciator Annunciator CRT Display*

Relay Sequential Solid State Seq. Software Seq.

Relay Output Relay Output Relay Output Dual/(Single) LVDT Dual/(Single) LVDT Dual LVDT

2 Coil Servovalve 2 Coil Servovalve 3 Coil Servovalve Exh.Thermocouples Exh.Thermocouples Exh.Thermocouples 12 Iron-Constantan 12 Chromel-Alumel 13-24 Chromel-Alumel (13-17 w/"ITS")

(depends on Model Series)

Panel: 36x36x90 in. Panel: 36x36x90 in. "ITS": 54x36x90 in

Panel: 54x36x90 in

Control Functions

Signal: 0(4)-20 Signal: 0(4)-20 Signal: 0-100% units units

units

Fuel (VCE) Fuel (VCE) Fuel (FSR)

Inlet Guide Vanes Inlet Guide Vanes Inlet Guide Vanes 2nd Stg. Nozzle 2nd Stg. Nozzle 2nd Stg. Nozzle

Steam/Water Inject. Steam/Water Inject.

Steam/Water Inject.

Start-up Temp.Suppr Start-up Temp.Track Start-up Accel.Cont Monitoring

Vibration Vibration Vibration Combustion monitor Combustion monitor Turbine Wheelspaces Turbine Wheelspaces Water/Steam Inject. Water/Steam Inject.



Adjustments-Controls and Sequential

Potentiometers, etc Potentiometers, etc Software logic rewiring logic rewiring Constants Software Ladder Diagrams

Availability/ Reliability Very good Very good Excellent 'Redundancy by

Association' 'Redundancy by 3 input /output vote, on-line

computer hardware repair

*Note: English and Metric units available (with "ITS")

PHILOSOPHY AND DESIGN CRITERION FOR SPEEDTRONIC MARK IV CONTROL The control design criteria has always been to strive for high starting reliability, maximum turbine life, and high unit availability. The Mark IV design is a very fault-tolerant system that has demonstrated a substantial forced outage rate improvement over the Mark I and Mark II designs.

Design Objective of SPEEDTRONIC Mark IV The primary objective of SPEEDTRONIC Mark IV is improved application flexibility, an enhanced operator interface, a substantial decrease in gas turbine outage rate, and a further softening of the start-up thermal cycle. The reliability objective is met in part by a tenfold increase in fault tolerance of the control devices and panel circuits, and is achieved by utilizing distributed microprocessors. The improved gas turbine life objective is met by optimum programming of the starting cycle. The SPEEDTRONIC Mark IV system is based on the microprocessors for both control and sequential functions, as well as the execution of the operator interface. Figure 1-8 shows some of the key features of the SPEEDTRONIC Control System evolution. Microprocessors have been used in General Electric gas turbine controls, starting with the combustion monitor. Their use also includes application to water and steam injection equipment, data-logging, temperature control, automatic synchronizing, and the DATATRONIC* remote control and condition monitoring system. * Trademark of the General Electric Co, USA If one section of the electronics fails, the turbine continues to run under the control of the remaining sections. The failed section can be diagnosed, repaired, and returned to service while the gas turbine continues to run. In this way the fault tolerance of the system is restored to the original level.

This is achieved by distributing control functions among four microcomputers; three <RST> are identical control sections, and the fourth <C> handles communications. Powerful on-line diagnostics indicate which section is faulty, right down to the circuit board level. System repair is enhanced with the gas turbine running, and mean-time-to-repair is predicted to be three to four hours. It is estimated that the Mark IV control will not cause a plant shutdown more often than once in ten years. In addition, the system is capable of utilizing redundant sensor inputs, which significantly reduces forced outages caused by faulty sensors. More details on how these results were accomplished are presented later in the manual, along with a description of the initial experiences obtained by running gas turbines with the new system. It was also important to find an approach that would allow keeping the present panel size, even though the computing power needed was greatly increased as compared to a non-redundant control. Due to inclusion of a number of new functions such as combustion monitoring, synchronizing, and water/ steam injection, the latest SPEEDTRONIC Mark II panel had grown to 54" from the original 36" size. This was accomplished by carefully modularizing the hardware, so that one basic control panel configuration would cover all turbine types and applications. Each module was designed for automated manufacture and test. Despite the increase in electronic functions, calculations show that because of the fault tolerant design, the failure rate was lower than previous controls, and less than one in ten of these failures would cause a forced outage. As an optimized starting cycle has been applied to the Mark II control, the SPEEDTRONIC Mark IV control represents a major step in industrial control flexibility, allowing GE to readily incorporate the latest gas turbine cycle improvements. The resulting panel shown in Figure 1-3, is distincitive in its difference from previous control panels (Figures 1-1 & 1-2). The membrane switches and the CRT monitor display simplify the panel front considerably, while bringing more information to the operator. The biggest engineering challenge was software. Not only must the software accommodate the many different types of controls, but it must also be able to diagnose faults while on-line. After a repair, it must recover and re-initialize, so that the repaired section can be returned to service without any major shift in the turbine operating point. The software is the other key to accomplishing the primary Mark IV objective of dramatically improved control availability. Figure 1-9 shows a block diagram of the basic Mark IV arrangement. The three control sections <R>, <S>, & <T> are called <RST>, signifying that they are identical, but yet completely independent processors. Each of them has inputs and outputs, and its own power supply. The fourth section is called <C> for communicator. It is in communication with the <RST> sections over three independent communication channels (3 pairs). In this way, a Áfailure in one section of <RST> is much less likely to cause damage to another control section than if <R>, <S>, & <T> were allowed to communicate directly with one another. The <C> communicator also interfaces with the operator through the membrane switches and CRT monitor. In the case of remote control, <C> communicates with the remote computers.

Critical sensors are distributed to the <RST> controllers so that each section has an independent assessment of turbine condition. For example, three individual speed signals are sent from the gas turbine to the control system, one for each of <R>, <S>, & <T>. Each of these sections sends its values to <C>, which calculates the median value, and sends a correction bias back to <RST>. Under normal conditions, the turbine will be controlled by the median of all the exhaust thermocouples. If there is some failure, each section of <RST> can make its own independent assessment of the proper fuel limit, and the gas turbine will continue to run after a barely perceptible disturbance. Sensors that are not critical to the operation are brought directly into <C>. This avoids extra I/O (input/ output) and processing in <RST>, simplifying these computers and making them more reliable. The same reasoning is applied to the major portion of the operator interface, since it is not critical to the operation. Should the communicator <C> or the CRT monitor fail, the alpha-numeric auxiliary display and its associated pushbuttons (located in the upper right corner of the control insert) are utilized. They can be used to monitor and operate the unit, and control the load until the repair can be made. Outputs from the three sections must be logic voted; ordinarily two (2) out of three (3) are required. Critical sequential outputs, such as the command to close the stop valve, are voted by properly connecting the contacts of three independent relays. The turbine will trip if any two (or all three) of <RST> indicates 'trip'. This trip function is accomplished as follows: Run =(R*S + S*T + T*R) NOTE: * = "AND" ; + = "OR" Some of the less critical outputs are voted in dedicated logic, while others are brought out through <C>. The signals for continuous control, such as setting the fuel flow, IGVs (inlet guide vanes), etc. are outputs such as the error signal for a servovalve. The servovalve is designed with three independent coils, and the outputs of <RST> are summed by the ampere-turns of the servovalve's magnetic circuit. Each of the outputs is limited in magnitude, such that any two signals can override a third. If the turbine is on temperature control, and then <S> fails such that it drives the maximum current (typically 8 mA) through the fuel servovalve in the direction to increase fuel. The actual fuel flow to the turbine will increase slightly, causing the temperature to exceed the setpoint slightly in <R> and <T>. The <RT> promptly call for a decrease in fuel, and together the <RT> are able to override the false signal caused by <S>. The resulting transient is typically so small that the system doesn't reach the alarm limit. The steady state value is parameter dependent (except for temperature control which is an integrating system), so that the error is not detectable. Figure 1-10 shows such a trace of exhaust temperature (Tx) and servovalve currents with three transients when: a) the electronics fail b) that section is powered down c) the section is returned to service



Operator Interface The operator interface consists of the control panel insert and an optional printer in a roll-out drawer. Section 2 illustrates these items in more detail. The industrial grade membrane ('push button') switches have better reliability than the older dedicated switches with hand wiring. Pushing the pad ('button') on the membrane switch "arms" the command, and is acknowledged by a flashing LED and a "beep". The operator then pushes the "execute" switch, which causes the controls to respond and turns the LED on steady. If more than three (3) seconds pass after the "arm command" was given before the operator pushes the "execute" button, the flashing LED goes out, and the "execute" command will be ignored. The normal display on the CRT monitor tracks the current status of the turbine. During start-up, the speed and condition of the starting means are displayed. While loading the turbine, the starting means information is deleted since it is of no interest, and load level data such as Tx, etc. is displayed. The lower left corner of the display is reserved for alarms, and the text of the three (3) latest alarms appears here along with the quantity of acknowledged alarms. The lower right corner gives the current value of any three (3) parameters that the operator wants to display. Operators consider this feature of being able to select any of a large number of parameters for special monitoring particularly handy. The CRT displayed alarm messages are very useful in diagnosing problems with the turbine. The alarms are not combined; instead of the 'Flame Detector Trip or Trouble' used on SPEEDTRONIC Mark I & II, the Mark IV message might read as follows: Date Time Status Description 08AUG83 14:05:22.72 "1" LOSS OF FLAME There is a separate button for silencing the horn while staying with the "status display". To acknowledge, clear, and review, the "Alarm" display is selected so the details of the alarm can be observed for further action. One display shows the 'state' of all the logic functions, including turbine mounted switches, internal logic, and output relays. Similarly the values from all sensors and actuators can be displayed. This detailed information is presented by selecting pages from the display menu. Any display can be copied by the roll-out printer by pushing the "copy" button. Since there are almost 200 pages on the display, only a few can be described here in more detail. One important feature of the display is that it almost eliminates the necessity for entering the SPEEDTRONIC Mark IV panel to make settings and diagnose problems. The majority of this work is accomplished from the panel front. That is important from a reliability point of view; one bad move inside the old style control system can cause the turbine to trip. With Mark IV, most settings are made by using the "Control Constants" display. If the operator wishes to change the value for pre-selected load, he will go to the control constants display and find the proper page.



The CRT will label one of the undedicated "soft" switches for entering the adjust mode. We call these switches "soft" switches, since their function varies and is dependent on the software. Pressing this "soft" switch will cause the Mark IV to ask for the password, as not everyone should be allowed to adjust control constants! After entering the proper password number, the operator aligns the cursor in front of the constant to be changed, and uses the increase or decrease switches to make the adjustment. This process can be learned in a few minutes, and is a lot easier than the older method of hooking up voltmeters to the proper points and adjusting potentiometers. Another feature of Mark IV is that the settings are easily recorded using the printer. Operators find the demand display particularly useful,and up to 64 values from one to two pages in the Mark IV data base can be selected and displayed on the CRT. Selection is made directly from the panel front by inputting the signal name using the membrane switch keyboard. The display can be printed automatically at regular intervals if the operator desires. There is a dedicated button on the membrane switch called "history",and pushing this button will cause the historical log to be printed. It looks back in time from the present time or, if the unit is tripped, from the most recent trip. The time increments are arranged in a pseudo logarithmic manner to concentrate on the latest data near the time of trip. Each of the ten frames of data includes turbine speed, turbine speed reference, fuel control reference, compressor discharge pressure, all exhaust thermocouple temperatures, and all alarms. The SPEEDTRONIC Mark IV has a standard option to interface with remote control and condition monitoring systems. With the addition of a DCM system and/ or a maintenance computer, these remote controls can give a very comprehensive historical record, including that of component service lives, part numbers, etc.

Field Changes The purpose of the field change capability is to facilitate required changes with appropriate precautions. Changes or adjustments are normally required in three areas: 1) the control algorithm constants (such as references and gains), 2) the position servos calibration, and 3) the sequencing logic, which frequently requires minor changes during the installation and start-up to match special customer site requirements. The safeguards are as follows: a) A User Password identification code is required for entering b) The rate of change of constants is limited, if turbine is running c) The adjustment ranges of critical parameters are limited d) Servo calibration is permitted only in 'OFF' or 'CRANK' e) Any sequencing changes should only be made if turbine is not running The control constants can be changed by requesting the 'CONTROL CONSTANTS' display and entering the password * code. Most constants are displayed in engineering units. The operator selects the page containing the constant to be changed, and then places the cursor on that constant. Pressing the "INCR" or "DECR" soft switch will then cause the selected constant to increase or decrease.

* NOTE: A Master Password Code, known only to a few key owner persons, is used to enter the User ID Password into EEPROM, and thus allows the customer to change the 'key' at his discretion. The control constants and sequencing data are stored in two sets of EEPROM, a primary and a backup set. There is a sequencing editor in the Mark IV panel to facilitate making changes to the sequencing logic. A 'dumb' terminal is required and is plugged into the RS232 port on the processor card in the <C> communicator module. A simple editor consisting of eight (8) display commands and three (3) editing commands is then used to examine and modify the appropriate 'rung' of the relay ladder diagram. In this simple editor, the elements of the 'rung' are displayed as instructions and also as graphics. Experience has shown that a field engineer or maintenance person is comfortable with this editor after a few hours of training and usage. After completing control constant and/ or sequencing changes, the revisions to the primary EEPROM set should be printed out from the panel and retained for review and incorporation into the drawings. Once the changes have been verified to be correct, the data in the primary EEPROM set may be copied into the backup set by performing a backup operation in the panel.

ADVANTAGES OF SPEEDTRONIC MARK IV CONTROL Microcomputer technology has been applied to the Mark IV gas turbine control system and provides improved availability, reliability, application flexibility, quality, and monitoring capability over traditional solid state controls.

Availability Common methods used to achieve high availability are: 1. Selection of highly reliable components 2. Redundancy by association 3. Redundancy by duplication of components 4. Reduction of the number of potential "single points" that can cause a trip An example of redundancy by association is: when operating on speed control, the temperature control will act as a back up in case the speed control fails. Temperature control will limit fuel flow and prevent an overtemperature trip, and the operation of the unit is not interrupted. Examples of redundancy by duplication include the two speed pick ups on Mark II, separate thermocouples for control and protection, and two coils of a servo valve. A few industrial customers may duplicate complete systems such as overtemperature, and use four channels instead of two. In the few cases where a single point failure cannot be avoided, a highly reliable component is selected, such as the unit battery.



Availability of the control panel is a function of the number and duration of forced outages caused by failures in the control panel hardware and/ or software. Both the number and duration of such outages are of concern to gas turbine owners. The SPEEDTRONIC Mark IV control reduces these outages by virtue of the fault tolerance, quick on-line diagnostics and repair, and recovery time. This section deals with calculations and extrapolations from past experience. The calculations of failure rates for the hardware are based on Military (MIL) Specification criteria for component failure rates, and weighted with experience from similar electronic boards. Increased automation in board manufacture, modular construction, cable connections, and thorough automatic testing indicate that the average MTBF (mean time between failures) will improve. The diagnostics have the beneficial effect of keeping people out of the panel, and reducing the MTTR (mean time to repair). We are estimating between 3 and 4 hours for MTTR at the present time. It is expected that the average number of years between an electronic failure in the control panel will be about 50% better than the earlier control panels, or about 1.5 years. Of these failures, about l in 10 will cause a forced outage according to calculations. We have set our goal target at a 10:1 improvement in control panel forced outage rate, or 10 years between forced outages caused by the electronics. The relative forced outage rate of SPEEDTRONIC Mark II and Mark IV & Mark IV with redundant sensors is shown in Figure 1-11. One of the most difficult factors to assess is the reaction of operators and maintenance personnel; and will they follow General Electric's recommendation of on-line service? This will depend on their confidence at the time of the failure, which will depend on training and their assessment of the cost and risk of shutting down compared to effecting an on-line computer hardware repair. General Electric's position is that the improved availability is of prime importance to most users, and that they will utilize the built-in capability of the panel for on-line repair. Another issue is how long the panel will be left in a partially disabled state before doing the on-line repair. With a partial failure, a second failure is more likely to cause a forced outage. The panel is more vulnerable during this period, and statistical analysis provides some meaningful advice. If the panel is repaired within 24 hours, there is no significant reduction in availability. If the panel is left without repair until it finally causes a forced outage, the potential 10:1 improvement is almost completely negated. With the MTTR estimated at 3 to 4 hours, it seems reasonable for an owner to be able to repair the control panel in this period of time. It depends on three factors: 1) Simple and accurate diagnostics 2) Knowledgable and trained personnel 3) Spare parts availability on site The diagnostics are designed to be used easily by typical plant operators and maintenance personnel.

Sensors The reliability of sensors has not been included in the foregoing description of availability of the control panel. With SPEEDTRONIC Mark IV, more redundant sensors can be added to improve the

overall control availability. Making the sensors redundant decreases the sensor-induced forced outage rate in heavy duty turbines by about 50%. However, some of the sensors can not be replaced with the turbine running, because of their location, temperature environment, and proximity to moving parts. When the influence of sensors is combined with the Mark IV panel, the mean-time-to-forced-outage interval is estimated at three years. This assumes good maintenance, particularly for the sensors. If a critical sensor has an MTBF of three years, and if all three sensors are working, the first failure should occur in one year and will not shut down the turbine. The next failure of either of the remaining sensors will probably shut the turbine down. This second occurrence will happen, on the average, in only an additional six months. It is extremely important to replace sensors as soon as possible after a failure. In fact, if no service is performed on sensors until there is a forced outage, there will be more outages than without the redundant sensors.

Reliability The Mark IV control system utilizes three computers identified as "controllers <R>, <S>, and <T>", which contain identical software and hardware. These controllers perform all the critical control calculations that are required for turbine operation. The circuitry of each controller is designed to drive its outputs in a fail safe direction in the unlikely event of a computer stall or power failure. The reliable means of protecting against random component failures is the “two (2) out of three (3) voting logic” concept. If a failure occurs affecting only one controller, then the turbine will continue to operate with the remaining two controllers. The fourth computer "communicator <C>" monitors <RST> and initiates an alarm when there is a discrepancy between the controllers. This alarm is audible and is displayed on the CRT. Each controller <R>, <S>, and <T> makes its own assessment of turbine operation. This is accomplished by distributing critical sensors between them, while <C> monitors the signals seen by <R>,<S>, and <T> and performs a majority vote. When a component failure is detected, the maintenance can be scheduled. In most cases the system can be returned to service while the turbine remains operational.

Flexibility In addition to the application flexibility that allows the Mark IV system to adapt to a wide variety of unusual applications, the system allows easy conversion to Metric equivalent readouts simply by selecting 'Metric' at the operator interface.

Quality The Mark IV system wiring, circuit cards, and modules are arranged in a structured "Max. Case" format. "Max Case" means that the circuitry is designed for the maximum functional requirements, with all cards and modules in pre-arranged locations according to the application requirements. The hardware, the interface between hardware and software, and the computer operating system become repetitive systems applied the same way on almost every application. This standardization allows on-and off-line diagnostics to enhance field troubleshooting.



An in-house software test system is available to thoroughly test application software before shipment. A file of as-shipped software is stored in-house to document the customer's system. Standardization of hardware is made possible by microcomputer technology. This hardware is used independent of the application software, which varies from order to order. The CRT monitor and the membrane switches on the Operator Interface Module are highly reliable. The module is of fixed design which can be tested with built-in off-line diagnostics.

Operation and Monitoring The CRT microprocessor monitoring system provides operations and maintenance personnel with a vast amount of information. The CRT is very useful in diagnosing problems with the turbine, since alarm information is not grouped together, but displayed as specific, time oriented information. Detailed information such as internal logic values, output relay status, and output values of all sensors and actuators is displayed by selecting pages from the display menu. Any display can be copied by the roll-out printer by pressing the "copy" button. The most important feature of the CRT operator interface is that it makes a vast amount of information readily available for monitoring turbine operation. This type of display also avoids the necessity for people to enter the Mark IV panel to make settings and diagnose problems. This is important from a reliability and quality viewpoint, since it is no longer necessary to connect voltmeters and calibrators to make control setting changes. In the Mark IV system, it is possible to change control constants by simply entering the password that normally blocks the adjust mode, and make the adjustment using the soft switches.

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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

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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

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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

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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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GER-3658D

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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GER-3658D

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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GER-3658D

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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GER-3658D

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-

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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.

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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.

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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

GE Power Systems

SPEEDTRONIC™Mark VI Turbine Control System

Walter BarkerMichael CroninGE Power SystemsSchenectady, NY

GER-4193A

g

Contents

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Architecture. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1Triple Redundancy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2I/O Interface. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3General Purpose I/O . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3Application Specific I/O. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4Operator Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7Software Maintenance Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8Communications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

Communication Link Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Time Synchronization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Diagnostics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11Codes and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Safety Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Printed Wire Board Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12CE – Electromagnetic Compatibility (EMC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12CE – Low Voltage Directive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Humidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Elevation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Gas Contaminants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Dust Contaminants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Seismic Universal Building Code (UBC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Manuals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

SPEEDTRONIC™ Mark VI Turbine Control System

GE Power Systems � GER-4193A � (10/00) i


GE Power Systems � GER-4193A � (10/00) ii

IntroductionThe SPEEDTRONIC™ Mark VI turbine controlis the current state-of-the-art control for GE tur-bines that have a heritage of more than 30 yearsof successful operation. It is designed as a com-plete integrated control, protection, and moni-toring system for generator and mechanicaldrive applications of gas and steam turbines. It isalso an ideal platform for integrating all powerisland and balance-of-plant controls. Hardwareand software are designed with close coordina-tion between GE’s turbine design engineeringand controls engineering to insure that your con-trol system provides the optimum turbine per-formance and you receive a true “system” solu-tion. With Mark VI, you receive the benefits ofGE’s unmatched experience with an advancedturbine control platform. (See Figure 1.)

ArchitectureThe heart of the control system is the ControlModule, which is available in either a 13- or 21-slot standard VME card rack. Inputs arereceived by the Control Module through termi-nation boards with either barrier or box-typeterminal blocks and passive signal conditioning.

Each I/O card contains a TMS320C32 DSPprocessor to digitally filter the data before con-version to 32 bit IEEE-854 floating point format.The data is then placed in dual port memorythat is accessible by the on-board C32 DSP onone side and the VME bus on the other.

In addition to the I/O cards, the ControlModule contains an “internal” communicationcard, a main processor card, and sometimes aflash disk card. Each card takes one slot exceptfor the main processor that takes two slots.Cards are manufactured with surface-mountedtechnology and conformal coated per IPC-CC-830.

I/O data is transmitted on the VME backplanebetween the I/O cards and the VCMI cardlocated in slot 1. The VCMI is used for “inter-nal” communications between:

� I/O cards that are contained within itscard rack

� I/O cards that may be contained inexpansion I/O racks called InterfaceModules

� I/O in backup ProtectionModules

� I/O in other Control Modules used intriple redundant controlconfigurations

� The main processor card

The main processor card executes the bulk ofthe application software at 10, 20, or 40 msdepending on the requirements of the applica-tion. Since most applications require that spe-


GE Power Systems � GER-4193A � (10/00) 1

Figure 1. Benefits of Speedtronic™ Mark VI

• Over 30 years experience

• Complete control, protection, andmonitoring

• Can be used in variety of applications

• Designed by GE turbine and controlsengineering

cific parts of the control run at faster rates (i.e.servo loops, pyrometers, etc.), the distributedprocessor system between the main processorand the dedicated I/O processors is very impor-tant for optimum system performance. A QNXoperating system is used for real-time applica-tions with multi-tasking, priority-driven preemp-tive scheduling, and fast-context switching.

Communication of data between the ControlModule and other modules within the Mark VIcontrol system is performed on IONet. TheVCMI card in the Control Module is the IONetbus master communicating on an Ethernet10Base2 network to slave stations. A unique pol-ing type protocol (Asynchronous DrivesLanguage) is used to make the IONet moredeterministic than traditional Ethernet LANs.An optional Genius Bus™ interface can be pro-vided on the main processor card in Mark VISimplex controls for communication with theGE Fanuc family of remote I/O blocks. Theseblocks can be selected with the same softwareconfiguration tools that select Mark VI I/Ocards, and the data is resident in the same data-base.

The Control Module is used for control, pro-tection, and monitoring functions, but someapplications require backup protection. Forexample, backup emergency overspeed protec-tion is always provided for turbines that do nothave a mechanical overspeed bolt, and backupsynch check protection is commonly providedfor generator drives. In these applications, theIONet is extended to a Backup ProtectionModule that is available in Simplex and tripleredundant forms. The triple redundant versioncontains three independent sections (powersupply, processor, I/O) that can be replacedwhile the turbine is running. IONet is used toaccess diagnostic data or for cross-trippingbetween the Control Module and the

Protection Module, but it is not required fortripping.

Triple RedundancyMark VI control systems are available inSimplex and Triple Redundant forms for smallapplications and large integrated systems withcontrol ranging from a single module to manydistributed modules. The name Triple ModuleRedundant (TMR) is derived from the basicarchitecture with three completely separate andindependent Control Modules, power supplies,and IONets. Mark VI is the third generation oftriple redundant control systems that were pio-neered by GE in 1983. System throughputenables operation of up to nine, 21-slot VMEracks of I/O cards at 40 ms including voting thedata. Inputs are voted in software in a schemecalled Software Implemented Fault Tolerance(SIFT). The VCMI card in each ControlModule receives inputs from the ControlModule back-plane and other modules via “itsown” IONet.

Data from the VCMI cards in each of the threeControl Modules is then exchanged and votedprior to transmitting the data to the mainprocessor cards for execution of the applicationsoftware. Output voting is extended to the tur-bine with three coil servos for control valves and2 out of 3 relays for critical outputs such ashydraulic trip solenoids. Other forms of outputvoting are available, including a median selectof 4-20ma outputs for process control and 0-200ma outputs for positioners.

Sensor interface for TMR controls can be eithersingle, dual, triple redundant, or combinationsof redundancy levels. The TMR architecturesupports riding through a single point failure inthe electronics and repair of the defective cardor module while the process is running. Addingsensor redundancy increases the fault tolerance



of the overall “system.” Another TMR feature isthe ability to distinguish between field sensorfaults and internal electronics faults.Diagnostics continuously monitor the 3 sets ofinput electronics and alarms any discrepanciesbetween them as an internal fault versus a sen-sor fault. In addition, all three main processorscontinue to execute the correct “voted” inputdata. (See Figure 2.)

I/O InterfaceThere are two types of termination boards. Onetype has two 24-point, barrier-type terminalblocks that can be unplugged for field mainte-nance. These are available for Simplex andTMR controls. They can accept two 3.0 mm2

(#12AWG) wires with 300 volt insulation.Another type of termination board used onSimplex controls is mounted on a DIN rail and

has one, fixed, box-type terminal block. It canaccept one 3.0 mm2 (#12AWG) wire or two 2.0mm2 (#14AWG) wires with 300 volt insulation.

I/O devices on the equipment can be mountedup to 300 meters (984 feet) from the termina-tion boards, and the termination boards mustbe within 15 m (49.2’) from their correspon-ding I/O cards. Normally, the terminationboards are mounted in vertical columns in ter-mination cabinets with pre-assigned cablelengths and routing to minimize exposure toemi-rfi for noise sensitive signals such as speedinputs and servo loops.

General Purpose I/ODiscrete I/O. A VCRC card provides 48 digitalinputs and 24 digital outputs. The I/O is divid-ed between 2 Termination Boards for the con-tact inputs and another 2 for the relay outputs.(See Table 1.)

Analog I/O. A VAIC card provides 20 analoginputs and 4 analog outputs. The I/O is dividedbetween 2 Termination Boards. A VAOC is ded-icated to 16 analog outputs and interfaces with1 barrier-type Termination Board or 2 box-typeTermination Boards. (See Table 2.)

Temperature Monitoring. A VTCC card pro-vides interface to 24 thermocouples, and aVRTD card provides interface for 16 RTDs. Theinput cards interface with 1 barrier-type



PS

<R>Control Module

X

PS

Y

PS

<T>Control Module

Z

<S>Control Module

Ethernet

Protection Module

Backup Protection1. Emergency Overspeed2. Synch Check Protection

Primary Controllers 1. Control 2. Protection 3. Monitoring

CIMPLICITY R Display SystemWindows NT TM Operating System

Ethernet

Unit Data Highway

Operator / MaintenanceInterface

Communications To DCS1. RS232 Modbus Slave/Master2. Ethernet TCP-IP Modbus Slave3. Ethernet TCP-IP GSM

Redundant UnitData Highway(if required)

To Other GEControl Systems

P.S.CPUI/O

P.S.CPUI/O

P.S.CPUI/O

Ethernet - IONet

Softw

are

Votin

g

Ethernet - IONet

Ethernet - IONet

Figure 2. Mark VI TMR control configurationTB Type I/O Characteristics

TBCI Barrier 24 CI 70-145Vdc, optical isolation, 1ms SOE

2.5ma/point except last 3 input are 10ma / point

DTCI Box 24 CI 18-32Vdc, optical isolation, 1ms SOE

2.5ma/point except last 3 input are 10ma/point

TICI Barrier 24 CI 70-145Vdc, 200-250Vdc, 90-132Vrms, 190-264Vrms(47-63Hz), optical isolation 1ms SOE, 3ma / point

TRLY Barrier 12 CO Plug-in, magnetic relays, dry, form “C” contacts

6 circuits with fused 3.2A, suppressed solenoid outputs

Form H1B: diagnostics for coil currentForm H1C: diagnostics for contact voltage

Voltage Resistive Inductive

24Vdc 3.0A 3.0 amps L/R = 7 ms, no suppr. 3.0 amps L/R = 100 ms, with suppr

125Vdc 0.6A 0.2 amps L/R = 7 ms, no suppr.

0.6 amps L/R = 100 ms, with suppr

120/240Vac 6/3A 2.0 amps pf = 0.4

DRLY Box 12 CO Same as TRLY, but no solenoid circuits

Table 1. Discrete I/O

To Other GEControl Systems

Redundant UnitData Highway

(Required)

<R>Control Module

<S>Control Module

<T>Control Module

P.S.CPUI/O

P.S.CPUI/O

P.S.CPUI/O

Protection Module

Communications to DCS1. RS232 Modbus Slave/Master2. Ethernet TCP-IP Modbus Slave3. Ethernet TCP-IPGSM

Primary Controllers1. Control2. Protection3. Monitoring

Backup Protection1. Emergency Overspeed2. Synch Check Protection

Operator MaintenanceInterface

Unit Data Highway

Ethernet

Ethernet

Ethernet - IONet

Softw

are

Votin

g

Ethernet - IONet

Ethernet - IONet

CIMPLICITY® Display SystemWindows NT™ Operating System

Termination Board or 2 box-type TerminationBoards. Capacity for monitoring 9 additionalthermocouples is provided in the BackupProtection Module. (See Table 3.)

Application Specific I/OIn addition to general purpose I/O, the MarkVI has a large variety of cards that are designedfor direct interface to unique sensors and actu-ators. This reduces or eliminates a substantialamount of interposing instrumentation inmany applications. As a result, many potentialsingle-point failures are eliminated in the mostcritical area for improved running reliabilityand reduced long-term maintenance. Directinterface to the sensors and actuators alsoenables the diagnostics to directly interrogatethe devices on the equipment for maximumeffectiveness. This data is used to analyze deviceand system performance. A subtle benefit ofthis design is that spare-parts inventories are

reduced by eliminating peripheral instrumenta-tion. The VTUR card is designed to integrateseveral of the unique sensor interfaces used inturbine control systems on a single card. Insome applications, it works in conjunction withthe I/O interface in the Backup ProtectionModule described below.

Speed (Pulse Rate) Inputs. Four-speed inputsfrom passive magnetic sensors are monitored bythe VTUR card. Another two-speed (pulse rate)inputs can be monitored by the servo cardVSVO which can interface with either passive oractive speed sensors. Pulse rate inputs on theVSVO are commonly used for flow-divider feed-back in servo loops. The frequency range is 2-14k Hz with sufficient sensitivity at 2 Hz todetect zero speed from a 60-toothed wheel. Twoadditional passive speed sensors can be moni-tored by “each” of the three sections of theBackup Protection Module used for emergencyoverspeed protection on turbines that do nothave a mechanical overspeed bolt. IONet isused to communicate diagnostic and processdata between the Backup Protection Moduleand the Control Module(s) including cross-trip-ping capability; however, both modules will ini-tiate system trips independent of the IONet.(See Table 4 and Table 5.)

Synchronizing. The synchronizing system con-sists of automatic synchronizing, manual syn-chronizing, and backup synch check protec-tion. Two single-phase PT inputs are provided



Analog I/O

TB Type I/O Characteristics

TBAI Barrier 10 AI

2 AO

(8) 4-20ma (250 ohms) or +/-5,10Vdc inputs

(2) 4-20ma (250 ohms) or +/-1ma (500 ohms) inputs

Current limited +24Vdc provided per input

(2) +24V, 0.2A current limited power sources

(1) 4-20ma output (500 ohms)

(1) 4-20ma (500 ohms) or 0-200ma (50 ohms) output

TBAO Barrier 16 AO (16) 4-20ma outputs (500 ohms)

DTAI Box 10 AI

2 AO

(8) 4-20ma (250 ohms) or +/-5,10Vdc inputs

(2) 4-20ma (250 ohms) or +/-1ma (500 ohms) inputs

Current limited +24Vdc available per input(1) 4-20ma output (500 ohms)

(1) 4-20ma (500 ohms) or 0-200ma (50 ohms) output

DTAO Box 8 AO (8) 4-20ma outputs (500 ohms)

Table 2. Analog I/O

VTUR I/O Terminations from Control Module


TTUR Barrier 4 Pulse rate

2 PTs

Synch relays

2 SVM

Passive magnetic speed sensors (2-14k Hz)

Single phase PTs for synchronizing

Auto/Manual synchronizing interface

Shaft voltage / current monitor

TRPG*

TRPS*TRPL*

Barrier 3 Trip solenoids

8 Flame inputs

(-) side of interface to hydraulic trip solenoids

UV flame scanner inputs (Honeywell)

DTUR Box 4 Pulse Rate Passive magnetic speed sensors (2-14k Hz)

DRLY

DTRT

Box 12 Relays Form “C” contacts – previously described

Transition board between VTUR & DRLY

Table 4. VTUR I/O terminations from ControlModule

Temperature Monitoring


TBTC Barrier 24 TC Types: E, J, K, T, grounded or ungrounded

H1A fanned (paralleled) inputs, H1B dedicated inputs

DTTC Box 12 TC Types: E, J, K, T, grounded or ungrounded

TRTD Barrier 16 RTD 3 points/RTD, grounded or ungrounded

10 ohm copper, 100/200 ohm platinum, 120 ohm nick

H1A fanned (paralleled) inputs, H1B dedicated inputs

DTAI Box 8 RTD RTDs, 3 points/RTD, grounded or ungrounded

10 ohm copper, 100/200 ohm platinum, 120 ohm nick

Table 3. Temperature Monitoring

on the TTUR Termination Board to monitorthe generator and line busses via the VTURcard. Turbine speed is matched to the line fre-quency, and the generator and line voltages arematched prior to giving a command to close thebreaker via the TTUR.

An external synch check relay is connected inseries with the internal K25P synch permissiverelay and the K25 auto synch relay via theTTUR. Feedback of the actual breaker closingtime is provided by a 52G/a contact from thegenerator breaker (not an auxiliary relay) toupdate the database. An internal K25A synchcheck relay is provided on the TTUR; however,the backup phase / slip calculation for this relayis performed in the Backup Protection Moduleor via an external backup synch check relay.Manual synchronizing is available from an oper-ator station on the network or from a synchro-scope.

Shaft Voltage and Current Monitor. Voltage canbuild up across the oil film of bearings until adischarge occurs. Repeated discharge and arc-ing can cause a pitted and roughened bearingsurface that will eventually fail through acceler-ated mechanical wear. The VTUR / TTUR cancontinuously monitor the shaft-to- ground volt-age and current, and alarm at excessive levels.Test circuits are provided to check the alarmfunctions and the continuity of wiring to thebrush assembly that is mounted between theturbine and the generator.

Flame Detection. The existence of flame eithercan be calculated from turbine parameters thatare already being monitored or from a directinterface to Reuter Stokes or Honeywell-typeflame detectors. These detectors monitor theflame in the combustion chamber by detectingUV radiation emitted by the flame. The ReuterStokes detectors produce a 4-20ma input. ForHoneywell flame scanners, the Mark VI suppliesthe 335Vdc excitation and the VTUR / TRPGmonitors the pulses of current being generated.This determines if carbon buildup or othercontaminates on the scanner window are caus-ing reduced light detection.

Trip System. On turbines that do not have amechanical overspeed bolt, the control canissue a trip command either from the mainprocessor card to the VTUR card in the ControlModule(s) or from the Backup ProtectionModule. Hydraulic trip solenoids are wired withthe negative side of the 24Vdc/125Vdc circuitconnected to the TRPG, which is driven fromthe VTUR in the Control Module(s) and thepositive side connected to the TREG which isdriven from the VPRO in each section of theBackup Protection Module. A typical system tripinitiated in the Control Module(s) will causethe analog control to drive the servo valve actu-ators closed, which stops fuel or steam flow andde-energizes (or energizes) the hydraulic tripsolenoids from the VTUR and TRPG. If cross-tripping is used or an overspeed condition isdetected, then the VTUR/TRPG will trip oneside of the solenoids and the VPTRO/TREGwill trip the other side of the solenoid(s).

Servo Valve Interface. A VSVO card provides 4servo channels with selectable current drivers,feedback from LVDTs, LVDRs, or ratio metricLVDTs, and pulse-rate inputs from flow dividerfeedback used on some liquid fuel systems. InTMR applications, 3 coil servos are commonly



VPRO I/O Terminations from Backup Protection Module


TPRO Barrier 9 Pulse rate

2 PTs

3 Analog inputs

9 TC inputs

Passive magnetic speed sensors (2-14k Hz)

Single phase PTs for backup synch check

(1) 4-20ma (250 ohm) or +/-5,10Vdc inputs(2) 4-20ma (250 ohm)

Thermocouples, grounded or ungrounded

TREG*

TRES*

TREL*

Barrier 3 Trip solenoids

8 Trip contact in

(+) side of interface to hydraulic trip solenoids

1 E-stop (24Vdc) & 7 Manual trips (125Vdc)

Table 5. VPRO I/O terminations from BackupProtection Module

used to extend the voting of analog outs to theservo coils. Two coil servos can also be used.One, two, or three LVDT/Rs feedback sensorscan be used per servo channel with a high select,low select, or median select made in software. Atleast 2 LVDT/Rs are recommended for TMRapplications because each sensor requires an ACexcitation source. (See Table 6 and Table 7.)

Vibration / Proximitor® Inputs. The VVIB cardprovides a direct interface to seismic (velocity),Proximitor®, Velomitor®, and accelerometer(via charge amplifier) probes. In addition, DCposition inputs are available for axial measure-ments and Keyphasor® inputs are provided.Displays show the 1X and unfiltered vibrationlevels and the 1X vibration phase angle. -24vdcis supplied from the control to each Proximitorwith current limiting per point. An optional ter-

mination board can be provided with active iso-lation amplifiers to buffer the sensor signalsfrom BNC connectors. These connectors can beused to access real-time data by remote vibra-tion analysis equipment. In addition, a directplug connection is available from the termina-tion board to a Bently Nevada 3500 monitor.The 16 vibration inputs, 8 DC position inputs,and 2 Keyphasor inputs on the VVIB are divid-ed between 2 TVIB termination boards for3,000 rpm and 3,600 rpm applications. Fastershaft speeds may require faster sampling rateson the VVIB processor, resulting in reducedvibration inputs from 16-to-8. (See Table 8.)

Three phase PT and CT monitoring. The VGENcard serves a dual role as an interface for 3phase PTs and 1 phase CTs as well as a special-ized control for Power-Load Unbalance andEarly-Valve Actuation on large reheat steam tur-bines. The I/O interface is split between theTGEN Termination Board for the PT and CTinputs and the TRLY Termination Board forrelay outputs to the fast acting solenoids. 4-20ma inputs are also provided on the TGEN formonitoring pressure transducers. If an EX2000Generator Excitation System is controlling thegenerator, then 3 phase PT and CT data is com-municated to the Mark VI on the networkrather than using the VGEN card. (See Table 9.)

Optical Pyrometer Inputs. The VPYR card moni-




TSVO Barrier 2 chnls. (2) Servo current sources

(6) LVDT/LVDR feedback

0 to 7.0 Vrms

(4) Excitation sources

7 Vrms, 3.2k Hz

(2) Pulse rate inputs (2-14k Hz) *only 2 per VSVO

DSVO Box 2 chnls. (2) Servo current sources

(6) LVDT/LVDR feedback 0 to 7.0 Vrms


7 Vrms, 3.2k Hz

(2) Pulse rate inputs (2-14k Hz)

*only 2 per VSVO


TSVO Barrier 2 chnls. (2) Servo current sources

(6) LVDT/LVDR feedback

0 to 7.0 Vrms


7 Vrms, 3.2k Hz

(2) Pulse rate inputs (2-14k Hz) *only 2 per VSVO

DSVO Box 2 chnls. (2) Servo current sources

(6) LVDT/LVDR feedback 0 to 7.0 Vrms


7 Vrms, 3.2k Hz

(2) Pulse rate inputs (2-14k Hz)

*only 2 per VSVO

Table 6. VSVO I/O terminations from Control Module

VVIB I/O Terminations from Control Module


TVIB Barrier 8 Vibr.

4 Pos.

1 KP

Seismic, Proximitor,Velomitor, accelerometercharge amplifier

DC inputs

Keyphasor

Current limited –24Vdc

provided per probe

Table 8. VVIB I/O terminations from ControlModule

Nominal Servo Valve Ratings

CoilType

NominalCurrent

CoilResistance

Mark VIControl

#1 +/- 10 ma 1,000 ohms Simplex & TMR

#2 +/- 20 ma 125 ohms Simplex


#4 +/- 40 ma 89 ohms TMR

#5 +/- 80 ma 22 ohms TMR


#7 +/- 120 ma 75 ohms TMR

Table 7. Nominal servo valve ratings

tors two LAND infrared pyrometers to create atemperature profile of rotating turbine blades.Separate, current limited +24Vdc and –24Vdcsources are provided for each Pyrometer thatreturns four 4-20ma inputs. Two Keyphasors areused for the shaft reference. The VPYR andmatching TPYR support 5,100 rpm shaft speedsand can be configured to monitor up to 92 buck-ets with 30 samples per bucket. (See Table 10.)

Operator InterfaceThe operator interface is commonly referred toas the Human Machine Interface (HMI). It is aPC with a Microsoft® Windows NT® operatingsystem supporting client/server capability, aCIMPLICITY® graphics display system, aControl System Toolbox for maintenance, and asoftware interface for the Mark VI and othercontrol systems on the network. (See Figure 3.)It can be applied as:

� The primary operator interface forone or multiple units

� A backup operator interface to theplant DCS operator interface

� A gateway for communication links toother control systems

� A permanent or temporarymaintenance station

� An engineer’s workstation

All control and protection is resident in theMark VI control, which allows the HMI to be anon-essential component of the control system.It can be reinitialized or replaced with theprocess running with no impact on the controlsystem. The HMI communicates with the mainprocessor card in the Control Module via theEthernet based Unit Data Highway (UDH). Allanalog and digital data in the Mark VI is acces-sible for HMI screens including the high reso-lution time tags for alarms and events.

System (process) alarms and diagnostics alarmsfor fault conditions are time tagged at framerate (10/20/40 ms) in the Mark VI control andtransmitted to the HMI alarm management sys-tem. System events are time tagged at framerate, and Sequence of Events (SOE) for contactinputs are time tagged at 1ms on the contactinput card in the Control Module. Alarms can




TGEN Barrier 2 PTs

3 CTs

4 AI

3 Phase PTs, 115Vrms

5-66 Hz, 3 wire, open delta

1 Phase CTs, 0-5A(10A over range) 5-66 Hz

4-20ma (250 ohms)

or +/-5,10Vdc inputsCurrent limited +24Vdc/input

TRLY Barrier 12 CO Plug-in magnetic relays

previously described

Table 9. VGEN I/O terminations from ControlModule

Figure 3. Operator interface graphics: 7FA Mark VI


TPYR Barrier 2 Pyrometers (8) 4-20ma (100 ohms)

(2) Current limited

+24Vdc sources(2) Current limited

-24Vdc sources

(2) Keyphasor inputs

Table 10. VPYR I/O terminations from Control Module

be sorted according to ID, Resource, Device,Time, and Priority. Operators can add com-ments to alarm messages or link specific alarmmessages to supporting graphics.

Data is displayed in either English or Metricengineering units with a one-second refreshrate and a maximum of one second to repaint atypical display graphic. Operator commandscan be issued by either incrementing / decre-menting a setpoint or entering a numericalvalue for the new setpoint. Responses to thesecommands can be observed on the screen onesecond from the time the command was issued.Security for HMI users is important to restrictaccess to certain maintenance functions such aseditors and tuning capability, and to limit cer-tain operations. A system called “UserAccounts” is provided to limit access or use ofparticular HMI features. This is done throughthe Windows NT User Manager administrationprogram that supports five user account levels.

Software Maintenance ToolsThe Mark VI is a fully programmable controlsystem. Application software is created from in-house software automation tools which selectproven GE control and protection algorithmsand integrate them with the I/O, sequencing,and displays for each application. A library ofsoftware is provided with general-purposeblocks, math blocks, macros, and applicationspecific blocks. It uses 32-bit floating point data(IEEE-854) in a QNX operating system withreal-time applications, multitasking, priority-driven preemptive scheduling, and fast contextswitching.

Software frame rates of 10, 20, and 40 ms aresupported. This is the elapsed time that it takesto read inputs, condition the inputs, executethe application software, and send outputs.Changes to the application software can be

made with password protection (5 levels) anddownloaded to the Control Module while theprocess is running. All application software isstored in the Control Module in non-volatileflash memory.

Application software is executed sequentiallyand represented in its dynamic state in a ladderdiagram format. Maintenance personnel canadd, delete, or change analog loops, sequenc-ing logic, tuning constants, etc. Data points canbe selected and “dragged” on the screen fromone block to another to simplify editing. Otherfeatures include logic forcing, analog forcing,and trending at frame rate. Application soft-ware documentation is created directly fromthe source code and printed at the site. Thisincludes the primary elementary diagram, I/Oassignments, the settings of tuning constants,etc. The software maintenance tools (ControlSystem Toolbox) are available in the HMI andas a separate software package for virtually anyWindows 95 or NT based PC. The same toolsare used for EX2000 Generator ExcitationSystems, and Static Starters. (See Figure 4 andFigure 5.)

CommunicationsCommunications are provided for internal datatransfer within a single Mark VI control; com-munications between Mark VI controls andpeer GE control systems; and external commu-nications to remote systems such as a plant dis-tributed control system (DCS).

The Unit Data Highway (UDH) is an Ethernet-based LAN with peer-to-peer communicationbetween Mark VI controls, EX2000 GeneratorExcitation Controls, Static Starters, the GEFanuc family of PLC based controls, HMIs, andHistorians. The network uses Ethernet GlobalData (EGD) which is a message-based protocolwith support for sharing information with mul-



tiple nodes based on the UDP/IP standard(RFC 768). Data can be transmitted Unicast,Multicast or Broadcast to peer control systems.Data (4K) can be shared with up to 10 nodes at25Hz (40ms). A variety of other proprietaryprotocols are used with EGD to optimize com-munication performance on the UDH.

40 ms is fast enough to close control loops onthe UDH; however, control loops are normallyclosed within each unit control. Variations ofthis exist, such as transmitting setpointsbetween turbine controls and generator con-trols for voltage matching and var/power-factor

control. All trips between units are hardwiredeven if the UDH is redundant.

The UDH communication driver is located onthe Main Processor Card in the Mark VI. This isthe same card that executes the turbine appli-cation software; therefore, there are no poten-tial communication failure points between themain turbine processor and other controls ormonitoring systems on the UDH. In TMR sys-tems, there are three separate processor cardsexecuting identical application software fromidentical databases. Two of the UDH drivers arenormally connected to one switch, and theother UDH driver is connected to the otherswitch in a star configuration. Network topolo-gies conform to Ethernet IEEE 802.3 standards.

The GE networks are a Class “C” PrivateInternet according to RFC 1918: AddressAllocation for Private Internets – February1996. Internet Assigned Numbers Authority(IANA) has reserved the following IP addressspace 192.168.1.1: 192.168.255.255 (192.168/16 prefix).

Communication links from the Mark VI toremote computers can be implemented fromeither an optional RS232 Modbus port on themain processor card in Simplex systems, orfrom a variety of communication drivers fromthe HMI. When the HMI is used for the com-munication interface, an Ethernet card in theHMI provides an interface to the UDH, and asecond Ethernet card provides an interface tothe remote computer.

All operator commands that can be issued froman HMI can be issued from a remote computerthrough the HMI(s) to the Mark VI(s), and theremote computer can monitor any applicationsoftware data in the Mark VI(s). Approximately500 data points per control are of interest to aplant control system; however, about 1,200



Figure 4. Software maintenance tools – card configuration

Relay Ladder Diagram Editorfor Boolean Functions

Figure 5. Software maintenance tools – editors

points are commonly accessed through thecommunication links to support programmingscreen attributes such as changing the color ofa valve when it opens.

Communication Link Options Communication link options include:

� An RS-232 port with Modbus SlaveRTU or ASCII communications fromthe Main Processor Card. (Simplex:full capability. TMR: monitor data only– no commands)

� An RS-232 port with Modbus Master /Slave RTU protocol is available fromthe HMI.

� An RS-232/485 converter (half-duplex) can be supplied to convertthe RS-232 link for a multi-dropnetwork.

� Modbus protocol can be supplied onan Ethernet physical layer with TCP-IPfor faster communication rates fromthe HMI.

� Ethernet TCP-IP can be supplied witha GSM application layer to support thetransmission of the local high-resolution time tags in the control to aDCS from the HMI. This link offersspontaneous transmission of alarmsand events, and common requestmessages that can be sent to the HMIincluding control commands andalarm queue commands. Typicalcommands include momentary logicalcommands and analog “setpointtarget” commands. Alarm queuecommands consist of silence (plantalarm horn) and reset commands aswell as alarm dump requests that causethe entire alarm queue to betransmitted from the Mark VI to theDCS.

� Additional “master” communicationdrivers are available from the HMI.

Time SynchronizationTime synchronization is available to synchro-nize all controls and HMIs on the UDH to aGlobal Time Source (GTS). Typical GTSs areGlobal Positioning Satellite (GPS) receiverssuch as the StarTime GPS Clock or other time-processing hardware. The preferred timesources are Universal Time Coordinated (UTC)or GPS; however, the time synchronizationoption also supports a GTS using local time asits base time reference. The GTS supplies atime-link network to one or more HMIs with atime/frequency processor board. When theHMI receives the time signal, it is sent to theMark VI(s) using Network Time Protocol(NTP) which synchronizes the units to within+/-1ms time coherence. Time sources that aresupported include IRIG-A, IRIG-B, 2137, NASA-36, and local signals.

DiagnosticsEach circuit card in the Control Module con-tains system (software) limit checking, high/low(hardware) limit checking, and comprehensivediagnostics for abnormal hardware conditions.System limit checking consists of 2 limits forevery analog input signal, which can be set inengineering units for high/high, high/low, orlow/low with the I/O Configurator. In addition,each input limit can be set for latching/non-latching and enable/disable. Logic outputsfrom system limit checking are generated perframe and are available in the database (signalspace) for use in control sequencing and alarmmessages.

High/low (hardware) limit checking is provid-ed on each analog input with typically 2 occur-rences required before initiating an alarm.These limits are not configurable, and they are



selected to be outside the normal controlrequirements range but inside the linear hard-ware operational range (before the hardwarereaches saturation). Diagnostic messages forhardware limit checks and all other hardwarediagnostics for the card can be accessed withthe software maintenance tools (Control SystemToolbox). A composite logic output is providedin the data base for each card, and anotherlogic output is provided to indicate a high/low(hardware) limit fault of any analog input orthe associated communications for that signal.

The alarm management system collects andtime stamps the diagnostic alarm messages atframe rate in the Control Module and displaysthe alarms on the HMI. Communication linksto a plant DCS can contain both the software(system) diagnostics and composite hardwarediagnostics with varying degrees of capabilitydepending on the protocol’s ability to transmitthe local time tags. Separate manual reset com-mands are required for hardware and system(software) diagnostic alarms assuming that thealarms were originally designated as latchingalarms, and no alarms will reset if the originalcause of the alarm is still present.

Hardware diagnostic alarms are displayed onthe yellow “status” LED on the card front. Eachcard front includes 3 LEDs and a reset at thetop of the card along with serial and parallelports. The LEDs include: RUN: Green; FAIL:Red; STATUS: Yellow.

Each circuit card and termination board in thesystem contains a serial number, board type,and hardware revision that can be displayed; 37pin “D” type connector cables are used to inter-face between the Termination Boards and theJ3 and J4 connectors on the bottom of theControl Module. Each connector comes withlatching fasteners and a unique label identify-

ing the correct termination point. One wire ineach connector is dedicated to transmitting anidentification message with a bar-code serialnumber, board type, hardware revision, and aconnection location to the corresponding I/Ocard in the Control Module.

PowerIn many applications, the control cabinet ispowered from a 125Vdc battery system andshort circuit protected external to the control.Both sides of the floating 125Vdc bus are con-tinuously monitored with respect to ground,and a diagnostic alarm is initiated if a ground isdetected on either side of the 125Vdc source.

When a 120/240vac source is used, a powerconverter isolates the source with an isolationtransformer and rectifies it to 125Vdc. A diodehigh select circuit chooses the highest of the125Vdc busses to distribute to the PowerDistribution Module. A second 120/240vacsource can be provided for redundancy.Diagnostics produce an under-voltage alarm ifeither of the AC sources drop below the under-voltage setting. For gas turbine applications, aseparate 120/240vac source is required for theignition transformers with short circuit protec-tion of 20A or less.

The resultant “internal” 125Vdc is fuse-isolatedin the Mark VI power distribution module andfed to the internal power supplies for theControl Modules, any expansion modules, andthe termination boards for its field contactinputs and field solenoids. Additional 3.2A fuseprotection is provided on the terminationboard TRLY for each solenoid. Separate 120Vacfeeds are provided from the motor control cen-ter for any AC solenoids and ignition trans-formers on gas turbines. (See Table 11.)



Codes and StandardsISO 9001 in accordance with Tick IT by Lloyd'sRegister Quality Assurance Limited. ISO 9000-3 Quality Management and Quality AssuranceStandards, Part 3: Guidelines for the Appli-cation of ISO 9001 to Development Supply andMaintenance of Software.

Safety Standards UL 508A Safety Standard Industrial ControlEquip.

CSA 22.2 No. 14 Industrial Control Equipment

Printed Wire Board Assemblies UL 796 Printed Circuit Boards

UL recognized PWB manufacturer,

UL file number E110691

ANSI IPC guidelines

ANSI IPC/EIA guidelines

CE - Electromagnetic Compatibility (EMC) EN 50081-2

Generic Emissions StandardsEN 50082-2:1994

Generic Immunity Industrial EnvironmentEN 55011

Radiated and Conducted EmissionsIEC 61000-4-2:1995

Electrostatic Discharge SusceptibilityIEC 6100-4-3: 1997

Radiated RF Immunity

IEC 6100-4-4: 1995Electrical Fast Transient Susceptibility

IEC 6100-4-5: 1995Surge Immunity

IEC 61000-4-6: 1995Conducted RF Immunity

IEC 61000-4-11: 1994Voltage Variation, Dips, and Interruptions

ANSI/IEEE C37.90.1Surge

CE - Low Voltage Directive EN 61010-1

Electrical Equipment, Industrial MachinesIEC 529

Intrusion Protection Codes/NEMA 1/IP 20

Reference the Mark VI Systems Manual GEH-6421, Chapter 5 for additional codes and stan-dards.

EnvironmentThe control is designed for operation in an air-conditioned equipment room with convectioncooling. Special cabinets can be provided foroperation in other types of environments.

Temperature:Operating 0° to +45°C +32° to +113°F

Storage -40° to +70°C -40° to +158°F

The control can be operated at 50∞C duringmaintenance periods to repair air-conditioningsystems. It is recommended that the electronicsbe operated in a controlled environment tomaximize the mean-time-between-failure(MTBF) on the components.

Purchased commercial control room equipmentsuch as PCs, monitors, and printers are typicallycapable of operating in a control room ambientof 0° to +40°C with convection cooling.

Humidity5% to 95% non-condensing

Exceeds EN50178: 1994



SteadyState

Voltage

Freq. Load Comments

125Vdc(100 to144Vdc)

10.0 A dc Ripple <= 10V p-pNote 1

120vac

(108 to132vac)

47 - 63Hz 10.0 A rms Harmonic distortion < 5%

Note 2

240vac

(200 to264vac)

47 - 63 Hz 5.0 A rms Harmonic distortion < 5 %

Note 3

Table 11. Power requirements

Elevation Exceeds EN50178: 1994

Gas Contaminants EN50178: 1994 Section A.6.1.4 Table A.2 (m)

Dust Contaminants Exceeds IEC 529: 1989-11 (IP-20)

Seismic Universal Building Code (UBC) Section 2312 Zone 4

DocumentationThe following documentation is available forMark VI Turbine Controls. A subset of this doc-umentation will be delivered with each controldepending on the functional requirements ofeach system.

Manuals � System Manual for SPEEDTRONICTM

Mark VI Turbine Control (GEH-6421)

� Control System Toolbox, forConfiguring a Mark VI Controller(GEH-6403)

Configuring the Trend Recorder (GEH-6408)

System Data Base for System Toolbox(GEI-100189)

System Data Base Browser (GEI-100271)

Data Historian (used for trip history)(GEI-100278)

� Communications To RemoteComputers / Plant DCS

RS232 Modbus Slave From ControlModule

Modbus CommunicationsImplementation UCOC2000 - I/ODrivers, Chapter 2

Communication Links From HMI:

RS232 Modbus Master/Slave, EthernetModbus Slave, Ethernet TCP-IP GSM HMI

SPEEDTRONIC™ Application Manual -Chapter 7 (GEH-6126), Ethernet TCP-IPGEDS Standard

Message Format (GSM) (GEI-100165)

� Operator/Maintenance Interface HMI

HMI for SPEEDTRONIC™ TurbineControls

Application Manual (GEH-6126)

Cim Edit Operation Manual (GFK-1396)

User Manual (GFK-1180)

Cimplicity HMI For Windows NTTrending Operators

Manual (GFK-1260)

� Turbine Historian System Guide(GEH-6421)

� Standard Blockware Library (SBLIB)

� Turbine Blockware Library(TURBLIB)

Drawings � Equipment Outline Drawing AutoCAD

R14

� Equipment Layout Drawing AutoCADR14

� I/O Termination List (ExcelSpreadsheet)

� Network one-line diagram (ifapplicable)

� Application Software Diagram(printout from source code)

� Data List For Communication Link ToDCS



List of FiguresFigure 1. Benefits of Speedtronic™ Mark VI

Figure 2. Mark VI TMR control configuration

Figure 3. Operator interface graphics: 7FA Mark VI

Figure 4. Software maintenance tools – card configuration

Figure 5. Software maintenance tools – editors

List of TablesTable 1. Discrete I/O

Table 2. Analog I/O

Table 3. Temperature Monitoring

Table 4. VTUR I/O terminations from Control Module

Table 5. VPRO I/O terminations from Backup Protection Module

Table 6. VSVO I/O terminations from Control Module

Table 7. Nominal servo valve ratings

Table 8. VVIB I/O terminations from Control Module

Table 9. VGEN I/O terminations from Control Module

Table 10: VPYR I/O terminations from Control Module

Table 11: Power requirements




GE Control System Fundamentals 4.0

GE CONTROL SYSTEM FUNDAMENTALS

GE Power Systems

1 FUNDAMENTALS OF SPEEDTRONICMARK V CONTROL SYSTEM

A00100

FUNDAMENTALS OF SPEEDTRONICMARK 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

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

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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.

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

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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

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

SP

EE

D N

O L

OA

D F

SR

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


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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

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

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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

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


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SORTHIGHEST

TOLOWEST

AVERAGEREMAINING

REJECTHIGHANDLOW

REJECTLOWTC’s

TTXDR

TTXDS

TTXDT

TTXD2

TTXM

QUANTITY

<RST

TOCOMBUSTIONMONITOR

OF TC’s USED

TEMPERATURECONTROL

REFERENCE

MINSELECT

CORNER

CPD

SLOPE

ISOTHERMAL

FSR

TEMPERATURE CONTROL

MEDIANSELECT

SLOPE

CORNER

FSRMIN

FSRMAX

TTRXB

TTXM

GAIN

FSR

<RST> <RST>

FSRT

Figure 9 Temperature Control Schematic

id0032

+

++

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

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

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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

Fig

ure 14 S

ervo P

ositio

nin

g L

oo

ps

<QTBA>ANALOGOUTPUT

POSTION FEEDBACK

FUEL

HYDRAULICACTUATOR

HIGHPRESSURE

OIL

TORQUEMOTOR

EXCITATION

SERVOVALVE

LVDT

LVDT

EXCITATION

POSTION FEEDBACK

<R>

<S>

<T>

REF

REF

REF

D/A

D/A

D/A

3.2KHZ

3.2KHZ

TBQCANALOG

INPUT

id0026

TCQC

TCQC

TCQC

3.2KHZ

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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-

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.

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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

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

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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

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.

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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.

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

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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.

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-

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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.

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

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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-

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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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-

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-

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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.

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 K1 = 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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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.


GE Control System Documentation 5.0

GE CONTROL SYSTEM DOCUMENTATION


Piping & Instrumentation Drawing (P&ID) 5.1

PIPING & INSTRUMENTATION DRAWING (PI&D)


Device Summary 5.2

DEVICE SUMMARY

SAM

PLE


Control Specification 5.3

CONTROL SPECIFICATION


Control Specification - Mark I Sample 5.3.1

MARK I Sample

SAM

PLE


Control Specification - Mark II Sample 5.3.2

MARK II Sample

SAM

PLE


Control Specification - Mark IV Sample 5.3.3

MARK IV Sample

SAM

PLE


Control Specification - Mark V Sample 5.3.4

MARK V Sample

SAMPLE


Turbine Elementary 5.4

TURBINE ELEMENTARY


Turbine Elementary - Fuel Regulator 5.4.1

Fuel Regulator


Turbine Elementary - Speedtronic Mark I 5.4.2

Speedtronic Mark I


Turbine Elementary - Speedtronic Mark II 5.4.3

Speedtronic Mark II


Turbine Elementary - Speedtronic Mark IV 5.4.3

Speedtronic Mark IV


Turbine Connection Diagram 5.5

TURBINE CONNECTION DIAGRAM


MCC Connection Diagram 5.6

MOTOR CONTROL CENTER CONNECTION DIAGRAM


Generator Control Panel Connection Diagram 5.7

GENERATOR CONTROL PANEL CONNECTION DIAGRAM


Control Sequence Program 5.8

CONTROL SEQUENCE PROGRAM

MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: Title Page ³Units³ Reference ³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ ³ ³ R E Q U I S I T I O N I N F O R M A T I O N ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ ³ ³ ³ ³ ³ ³ CUSTOMER : Multi-Customer ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ STATION NAME : Singapore ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ STATION LOCATION : Singapore ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ APPLICATION : GAS TURBINE ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ TURBINE MODEL : MS6001B - GEN DRIVE ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ TURBINE S/N : XXXXX ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ CUSTOMER UNIT NO. : Unit #1 ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ REQUISITION NO. : Axxxxxxxx ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ SHOP ORDER NO. : xxxxxxx ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ DESIGN MEMO NO. : xxxxxxx ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ENGINEER : Reqn. Engr. ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ ³ ³ ³ ³ ³ ³ PANEL TYPE : TMR ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ BBL REVSION : 1.3 ³ ³ ³ ³ ³ ³ ³ ³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ ³ ³ P R O C E S S O R O P T I O N S ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ ³ IDP VERSION : ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ OPTIONS ACTIVE : No options active ³ ³ ³ ³ ³ ³ ³ ³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 002 ³ SH NO. 001 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: Help Page ³Units³ Reference ³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ ³ ÄÄÄÄÂÄÄÄÄ ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ ³ º D O C U M E N T R E A D I N G A I D º ³ ³ ³ ³ ÇÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¶ ³ ³ ³ ³ º º ³ ³ ³ ³ º 1. Current Segment (CSP only) º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ ³ ³ º º ³ ³ ³ ³ º 2. Engineering Units Column º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ º º ³ ³ ³ ³ º 3. Reference Infomation Column º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ ³ º º ³ ³ ³ ³ º 4. Rung Number º ÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ³ÄÄÄÄÄÄÄ´ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÀÄÄÄÄÄÄ> <<< Rung Number 136 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º TMV - Time Delay º ³ ³ ³ L4 Input L0ºInput º ³ ³ ³ ÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ º ù º ³ ³ ³ K4Y 0ºFinal ÚÄÄÄÄ¿ ù º L4Y ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄ´B ³ ù statº ³ ³ ³ º ³ A>BÃÄÄÄ´ ÃÄÂÄÄ×ÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ º ÚÄ´A ³ 0 ù ³ º ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍ» º ³ ÀÄÄÄÄÙ Ä´/ÃÄÙ º ³ ³ ³ º 5. Rung º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ> º ÀÄÄÄÄÄÄÄ¿ ù º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍ¼ º dt + ³ ù Currº1 T4Y ³ ³ ³ º ÄÄÄÄOÄÄÄÄÄÄÁÄÄ´ ÃÄÂÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ ³ ³ ³ º +³ ÚÄÄ¿ 0 ù ³ º ³ ³ ³ º ³ ³-1³ Ä´/ÃÄ´ º ³ ³ ³ º ÀÄ´z ÃÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» º ÀÄÄÙ º ³ ³ ³ º 6. Rung Cross-reference ÇÄÄÄÄÄÄÄÄÄÄÄ¿ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ ³ ³ ³ ³ K4Y -- TIME DELAY sec ³= +1.0 sec ³ ³ ³ ³ ³ L4 -- MASTER PROTECTIVE SIGNAL LOGIC³ ³ ³ SEQ_TRB1 -131 ³ ³ ³ ³ ³ ³ L4Y -- T.D. LOSS OF MASTER PROTECTIVE LOGIC³ ³ ³ SEQ_TRB2 82, L28FDT SEQ_TRB2 79, L28FDTX ³ ³ ³ SEQ_TRB1 182, L2DWZ2 SEQ_TRB1 174, L48DSX ³ ³ ³ SEQ_TRB1 148, L63QTX SEQ_TRB1 143, L4ETR_FLT ³ ³ ³ SEQ_TRB1 139, L3CP_ALM SEQ_TRB1 -136, L4Y ³ ³ ³ SEQ_TRB1 130, L4S SEQ_TRB1 103, L4_RLYT ³ ³ ³ SEQ_TRB1 95, L3STCK1 SEQ_TRB1 44, L1X ³ ³ ³ ³ ³ ³ T4Y -- T.D. LOSS OF MASTER PROTECTIVE sec ³ ³ ³ SEQ_TRB1 -136, L4Y ³ ³ ³ ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ ºCross-reference Notes: ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º---------------------- º ³ ³ ³ ºa. The "=" indicates K14Y is a control constant. Value is 1.0 sec º ³ ³ ³ º º ³ ³ ³ ºb. L4Y is written to by the current rung, so the complete "where used" list is shown. º ³ ³ ³ º This takes the form: º ³ ³ ³ º º ³ ³ ³ º SEQ_TRB1 95, L3STCK1 º ³ ³ ³ º º ³ ³ ³ º This means that an L4Y "contact" is used in the L3STCK1 rung, which is located in º ³ ³ ³ º segment SEQ_TRB1, rung number 95. In the Signal Index Document, this list is always shown. º ³ ³ ³ º º ³ ³ ³ ºc. L4 is not written by the current rung, so only the origin is shown. This takes the form: º ³ ³ ³ º º ³ ³ ³ º SEQ_TRB1 -131 º ³ ³ ³ º º ³ ³ ³ º This means that the "coil" for the L4 "contact" used in this rung is located in segment º ³ ³ ³ º SEQ_TRB1, rung 131. The "-" before the 131 indicates that L4 is "written" (originates) º ³ ³ ³ º at that rung. The cross-reference for rung 131 contains the complete "where used" list for L4.º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ <<< Rung Number 137 >>> ³ ³ ³ ³ ³ ³ L71QH_ ³ ³ ³ L71QH ALM ³ ³ ³ ÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ L71QH -- LUBE OIL TANK LEVEL HIGH LOGI ³ Q_QD1_CI15 ³ ³ ³ ³ ³ L71QH_ALM -- LUBE OIL LEVEL HIGH ALARM LOGI ³ ALARM 109 ³ ³ SEQ_TRB1 -80, L71QH_ALM ³ ³ ³ ³ ÄÄÄÄÄÂÄÄÄÄÄ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ ³ º 7. Alarm and I/O information º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ³ÄÄÄÄÄÄÄÙ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ ºNotes: ALARM 109 indicates that L71QH_ALM is the driver for alarm 109. º ³ ³ ³ º Q_QD1_CI15 indicates L71QH is a contact input (no. 15) in the <QD1> core.º ³ ³ ³ º (see IO.ASG file for abbreviations) º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. 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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ <<< Rung Number 4 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º L14TV1 - SPEED LOGIC SENSING º ³ ³ ³ º º ³ ³ ³ ºTNH ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÂÄÄÁ True ³ L14HRº ³ ³ ³ ºTNK14HR1 ³ ³ AóB ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B False³ º ³ ³ ³ ºTNK14HR2 ³ ³ AòC ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14HP1 ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14HPº ³ ³ ³ ºTNK14HP2 ³ ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ºTNK14HF1 ÃÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B AòB ³ L14HFº ³ ³ ³ ºTNK14HF2 ³ ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14HM1 ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14HMº ³ ³ ³ ºTNK14HM2 ³ ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14HA1 ÃÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B AòB ³ L14HAº ³ ³ ³ ºTNK14HA2 ³ ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14HS1 ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14HSº ³ ³ ³ ºTNK14HS2 ³ ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ºTNK14HC1 ÃÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B AòB ³ L14HCº ³ ³ ³ ºTNK14HC2 ³ ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14HT1 ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14HTº ³ ³ ³ ºTNK14HT2 ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ZERO 0ºSpeed ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÂÄÄÁ True ³ L14PRº ³ ³ ³ ºLK14PR1 ³ ³ AóB ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B False³ º ³ ³ ³ ºLK14PR2 ³ ³ AòC ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºLK14P11 ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14P1º ³ ³ ³ ºLK14P12 ³ ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ºLK14P21 ÀÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14P2º ³ ³ ³ ºLK14P22 ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ZERO 1ºSpeed ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ L14LRº ³ ³ ³ ºTNK14LR1 ³ ³ AóB ÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B False³ º ³ ³ ³ ºTNK14LR2 ³ ³ AòC ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ ³ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ºTNK14LA1 ÃÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B AòB ³ L14LAº ³ ³ ³ ºTNK14LA2 ³ ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14LS1 ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14LSº ³ ³ ³ ºTNK14LS2 ³ ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄ¿ ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ºTNK14LX1 ÃÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄ´B AòB ³ L14LXº ³ ³ ³ ºTNK14LX2 ³ ³ FalseÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄ(ÄÄĆ AóC ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºTNK14LY1 ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ True ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B AòB ³ L14LYº ³ ³ ³ ºTNK14LY2 ³ FalseÃÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄĆ AóC ³ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 005 ³ SH NO. 004 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ L14HA -- HP Speed - Accelerating speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HC -- Auxiliary Cranking Speed Relay LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HF -- HP Speed - At field flashing speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HM -- HP Speed - Minimum Firing Spd LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HP -- HP Speed - Spare speed signal LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HR -- HP Speed - Zero Speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HS -- HP Speed - Min operating speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14HT -- Cooldown Slow Roll Start Speed Relay LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14LA -- LP Shaft at Acceleration Speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14LR -- LP Speed - Zero speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14LS -- LP Speed - Min operating speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14LX -- LP Speed - spare LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14LY -- LP Speed - spare LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14P1 -- Starting Device above Min Speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14P2 -- Starting Device above Cranking Speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ L14PR -- Starting Device Zero Speed LOGIC³ ³ ³ SEQ_TRB1 -4 ³ ³ ³ ³ ³ ³ LK14P11 -- Diesel Speed Level Detect : 14P1 Pick-up Setpnt % = 1³.7 % ³ ³ ³ ³ ³ LK14P12 -- Diesel Speed Level Detect : 14P1 D.O. Setpnt % = 1³8 % ³ ³ ³ ³ ³ LK14P21 -- Diesel Speed Level Detect : 14P2 Pick-up Setpnt % = 9³.0 % ³ ³ ³ ³ ³ LK14P22 -- Diesel Speed Level Detect : 14P2 D.O. Setpnt % = 8³.0 % ³ ³ ³ ³ ³ LK14PR1 -- Diesel Speed Level Detect : 14PR Pick-up Setpnt % = 0³0 % ³ ³ ³ ³ ³ LK14PR2 -- Diesel Speed Level Detect : 14PR D.O. Setpnt % = 0³1 % ³ ³ ³ ³ ³ TNH -- HP Turbine Speed % ³ ³ ³ SEQ_TRB1 -3 ³ ³ ³ ³ ³ ³ TNK14HA1 -- HP Spd Level Detect: 14HA Pick Up Setpoint % = 5³.0 % ³ ³ ³ ³ ³ TNK14HA2 -- HP Spd Level Detect: 14HA Drop Out Setpoint % = 4³.0 % ³ ³ ³ ³ ³ TNK14HC1 -- HP Spd Level Detect: 14HC Pick Up Setpoint % = 6³.0 % ³ ³ ³ ³ ³ TNK14HC2 -- HP Spd Level Detect: 14HC Drop Out Setpoint % = 5³.0 % ³ ³ ³ ³ ³ TNK14HF1 -- HP Spd Level Detect: 14HF Pick Up Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14HF2 -- HP Spd Level Detect: 14HF Drop Out Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14HM1 -- HP Spd Level Detect: 14HM Pick Up Setpoint % = 1³.0 % ³ ³ ³ ³ ³ TNK14HM2 -- HP Spd Level Detect: 14HM Drop Out Setpoint % = 1³.0 % ³ ³ ³ ³ ³ TNK14HP1 -- HP Spd Level Detect: 14HP Pick Up Setpoint % = 1³.0 % ³ ³ ³ ³ ³ TNK14HP2 -- HP Spd Level Detect: 14HP Drop Out Setpoint % = 1³.0 % ³ ³ ³ ³ ³ TNK14HR1 -- HP Spd Level Detect: 14HR Pick Up Setpoint % = 0³06 % ³ ³ ³ ³ ³ TNK14HR2 -- HP Spd Level Detect: 14HR Drop Out Setpoint % = 0³31 % ³ ³ ³ ³ ³ TNK14HS1 -- HP Spd Level Detect: 14HS Pick Up Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14HS2 -- HP Spd Level Detect: 14HS Drop Out Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14HT1 -- HP Spd Level Detect : 14HT Pick Up Setpoint % = 8³4 % ³ ³ ³ ³ ³ TNK14HT2 -- HP Spd Level Detect : 14HT Drop Out Setpoint % = 3³2 % ³ ³ ³ ³ ³ TNK14LA1 -- LP Spd Level Detect: 14LA Pick Up Setpoint % = 5³.0 % ³ ³ ³ ³ ³ TNK14LA2 -- LP Spd Level Detect: 14LA Drop Out Setpoint % = 4³.0 % ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 006 ³ SH NO. 005 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ TNK14LR1 -- LP Spd Level Detect: 14LR Pick Up Setpoint % = 8³4 % ³ ³ ³ ³ ³ TNK14LR2 -- LP Spd Level Detect: 14LR Drop Out Setpoint % = 3³2 % ³ ³ ³ ³ ³ TNK14LS1 -- LP Spd Level Detect: 14LS Pick Up Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14LS2 -- LP Spd Level Detect: 14LS Drop Out Setpoint % = 9³.0 % ³ ³ ³ ³ ³ TNK14LX1 -- LP Spd Level Detect: 14LX Pick Up Setpoint % = 6³.0 % ³ ³ ³ ³ ³ TNK14LX2 -- LP Spd Level Detect: 14LX Drop Out Setpoint % = 5³.0 % ³ ³ ³ ³ ³ TNK14LY1 -- LP Spd Level Detect: 14LY Pick Up Setpoint % = 8³4 % ³ ³ ³ ³ ³ TNK14LY2 -- LP Spd Level Detect: 14LY Drop Out Setpoint % = 3³2 % ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 007 ³ SH NO. 006 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ <<< Rung Number 5 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º EOS_GAS - GAS EMERGENCY OVERSPEED AND PROTECTION º ³ ³ ³ º º ³ ³ ³ º ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ º HPOS pickups³ ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ TNH_OSº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄ´ ÃÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ³ Convert mag ³ ³ º ³ ³ ³ º ³ ³ pickup pulses ³ ³ º ³ ³ ³ º LPOS pickups³ ³ to speed (%) ³ ³ TNL_OSº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄ´ ÃÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ÀÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ º ³ ³ ³ º IO Config ³ ÚÄÄÄÄÁÄÄ¿ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄ´Decode ³ ³ º ³ ³ ³ º Jumpers ³ ³ and ³ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄĆompare³ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ ³ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ º ³ ³ ³ º ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ º ³ ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ tnh_tp_sp º ³ ³ ³ º ³ ³emergency ÃÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ³ ³overspeed trip ³ ³ tnl_tp_sp º ³ ³ ³ º ³ ³setpoints ÃÄÂÄÅÄÄÄÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ³ ÀÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ ³ º ³ ³ ³ º ³ ³ ÚÄÄÄÄÄÄÄÄÙ ³ º ³ ³ ³ º IO Config ³ ÚÄÄÄÄÁÄÄ¿ ³ ÚÄÄÄÄ¿ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄ´Decode ³ ÀÄÄÁ ³ ³ l3lp º ³ ³ ³ º Jumpers ³ ³ and ³ 0 ³ A>BÃÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÅÄĆompare³ ÄÄÄ´B ³ ³ LP Shaft º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ ÀÄÄÄÄÙ ³ enable º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ º ³ ³ ³ º ùùùùùùùùùùùùùùùùù º ³ ³ ³ º 1% ù ù º ³ ³ ³ º ÄÄÄ´ ÃÄ¿ ù º ³ ³ ³ º TNH_OS +³+ ÚÄÄÄÄ¿ ù º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄOÄÄÄÄÁ ³ ³ l12h_tp1 º ³ ³ ³ º ³ tnh_tp_sp + ³ A>BÃÄÄÁÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ³ ÄÄÄÄÄÄÄÄÄÄÄOÄ´B ³ º ³ ³ ³ º ³ 4% +³ ÀÄÄÄÄÙ º ³ ³ ³ º ³ ÄÄÄÄÄ´ ÃÄÄÄÙ º ³ ³ ³ ºL83HOST_P ³ ù º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄ¿ º ³ ³ ³ º ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ ³ L14H_ZEº ³ ³ ³ º ³ 1.0% + ³ A<BÃÄÄÂÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ÄÄÄÄÄÄÄÄÄÄÄOÄ´B ³ ³ ³ º ³ ³ ³ º ³ 0.2% +³ ÀÄÄÄÄÙ ³ ³ º ³ ³ ³ º ³ ÄÄÄÄÄ´ ÃÄÄÄÙ ³ ³ º ³ ³ ³ º ³ ù ³ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ º ³ ³ ³ º ³ ÚÄÄÄÄ¿ ÚÄÄÄÄ¿ ³ÚÄÄÄ¿ º ³ ³ ³ º ÃÄ´rateÃÄÄÄÄÄÄÄÄÄÁ ³ À´ ³ 112h_tp2 º ³ ³ ³ º ³ ÀÄÄÄÄÙ -200%/s ³ A<BÃÄÄÄÄÁNDÃÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ³ ÄÄÄÄÄÄÄ´B ³ ³ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÙ ÀÄÄÄÙ º ³ ³ ³ º ³ ÚÄÄÄÄ¿ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ ³ l14h_mn º ³ ³ ³ º tnh_mn (IO Config) ³ A>BÃÄÄÄÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´B ³ º ³ ³ ³ º ÀÄÄÄÄÙ º ³ ³ ³ º ùùùùùùùùùùùùùùùùù º ³ ³ ³ º 1% ù ù º ³ ³ ³ º ÄÄÄ´ ÃÄ¿ ù º ³ ³ ³ º TNL_OS +³+ ÚÄÄÄÄ¿ ù º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄOÄÄÄÄÁ ³ ³ l12l_tp1 º ³ ³ ³ º ³ tnl_tp_sp + ³ A>BÃÄÄÁÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ³ ÄÄÄÄÄÄÄÄÄÄÄOÄ´B ³ º ³ ³ ³ º ³ 4% +³ ÀÄÄÄÄÙ º ³ ³ ³ º ³ ÄÄÄÄÄ´ ÃÄÄÄÙ º ³ ³ ³ ºL83LOST_P ³ ù º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄÄÄÄÙ ÚÄÄÄÄ¿ º ³ ³ ³ º ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁ ³ L14L_ZEº ³ ³ ³ º ³ 1.0% + ³ A<BÃÄÂÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ÄÄÄÄÄÄÄÄÄÄÄOÄ´B ³ ³ ³ º ³ ³ ³ º ³ 0.2% +³ ÀÄÄÄÄÙ ³ ³ º ³ ³ ³ º ³ ÄÄÄÄÄ´ ÃÄÄÄÙ ³ ³ º ³ ³ ³ º ³ ù ³ ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÙ ³ º ³ ³ ³ º ³ ÚÄÄÄÄ¿ ÚÄÄÄÄ¿ ³ÚÄÄÄ¿ º ³ ³ ³ º ÀÄ´rateÃÄÄÄÄÄÄÄÄÄÁ ³ À´ ³ l12l_tp2 º ³ ³ ³ º ÀÄÄÄÄÙ -200%/s ³ A<BÃÄÄÄÄÁNDÃÄÄÄÄÄÄ º ³ ³ ³ º ÄÄÄÄÄÄÄ´B ³ ³ ³ º ³ ³ ³ º ÀÄÄÄÄÙ ÀÄÄÄÙ º ³ ³ ³ º l12h_tp1 ÚÄÄÄÄÄÄÄ¿ L12H_Pº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ SET ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ AND ³ º ³ ³ ³ º ³ LATCH ³ º ³ ³ ³ ºL86MR_TCEA ÃÄÄÄÄÄÄÄ´ º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄ´ RESET ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ º ³ ³ ³ º l12h_tp2 ³ ÚÄÄÄÄÄÄÄ¿ L12H_ACCº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄ´ SET ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ³ AND ³ º ³ ³ ³ º ³ ³ LATCH ³ º ³ ³ ³ º ³ ÃÄÄÄÄÄÄÄ´ º ³ ³ ³ º ÃÄÄÄÄÄ´ RESET ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ º ³ ³ ³ º l12l_tp1 ³ ÚÄÄÄÄÄÄÄ¿ L12L_Pº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄ´ SET ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ³ AND ³ º ³ ³ ³ º ³ ³ LATCH ³ º ³ ³ ³ º ³ ÃÄÄÄÄÄÄÄ´ º ³ ³ ³ º ÃÄÄÄÄÄ´ RESET ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ º ³ ³ ³ º l12l_tp2 ³ ÚÄÄÄÄÄÄÄ¿ L12L_ACCº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ(ÄÄÄÄÄ´ SET ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ³ ³ AND ³ º ³ ³ ³ º ³ ³ LATCH ³ º ³ ³ ³ º ³ ÃÄÄÄÄÄÄÄ´ º ³ ³ ³ º ÃÄÄÄÄÄ´ RESET ³ º ³ ³ ³ º ³ ÀÄÄÄÄÄÄÄÙ º ³ ³ ³ ºL69LP_LR ÚÄÄÄ¿ ³ ÚÄÄÄÄÄÄÄ¿ L12L_LRº ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄo´ ÃÄÄÄ(ÄÄÄÄÄ´ SET ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º l14h_mn ³ ³ ³ ³ AND ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ LATCH ³ º ³ ³ ³ º L14L_ZE ³AND³ ³ ÃÄÄÄÄÄÄÄ´ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄ´ ³ ÀÄÄÄÄÄ´ RESET ³ º ³ ³ ³ º l3lp ³ ³ ÀÄÄÄÄÄÄÄÙ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º ÀÄÄÄÙ º ³ ³

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³ º L12H_P ÚÄÄÄÄ¿ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º L12H_ACC ³ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º L14H_ZE ÚÄÄÄ¿ ³ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ º ³ ³ ³ ºL97HP0T_BYP ³ANDÃÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄo´ ³ ³ ³ º ³ ³ ³ º L12L_P ÚÄÄÄ¿ ÀÄÄÄÙ ³ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ l12tp º ³ ³ ³ º L12L_ACC ³OR ³ ÚÄÄÄ¿ ³ OR ÃÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄ´ ÃÄÄÄÄ´ ³ ³ ³ º ³ ³ ³ º l3lp ÀÄÄÄÙ ³ANDÃÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³ ³ º ³ ³ ³ ºL4_XTP ÀÄÄÄÙ ³ ³ º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º L12L_LR ³ ³ º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ º ³ ³ ³ º K4_1* K4_3* ³ ³ º ³ ³ ³ º ÄÄÄÄ´ ÃÄÄÄÂÄÄÄ´ ÃÄÄÄÄÂÄÄÄÄÄÄÄÄÄÂÄo´ ³ º ³ ³ ³ º ³ ³ ³ ÀÄÄÄÄÙ L4_FBº ³ ³ ³ º K4_2* ³ K4_4* ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º ÄÄÄÄ´ ÃÄÄÄÁÄÄÄ´ ÃÄÄÄÄÙ º ³ ³ ³ º º ³ ³ ³ º 4ETR1* L4ETR1º ³ ³ ³ º ÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º 4ETR2* L4ETR2º ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º º ³ ³ ³ º 4PTR1* L4PTR1_FBº ³ ³ ³ º ÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º 4PTR2* L4PTR2_FBº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º 4PTR3* L4PTR3_FBº ³ ³ ³ º ÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º 4PTR4* L4PTR4_FBº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º *Relay contact on TCTG card º ³ ³ ³ º º ³ ³ ³ º Emergency trip PB circuit L5E_TCEAº ³ ³ ³ º ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄ< ³ ³ ³ º º ³ ³ ³ ºL30ALM ÚÄÄÄÄÄÄÄÄÄÄÄ¿ Audible Alarm º ³ ³ ³ >ÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´2 Hz PulsesÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÄÄÄÙ º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 008 ³ SH NO. 007 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ L12H_ACC -- TCEA HP Excessive acceleration trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12H_P -- TCEA HP Overspeed trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12L_ACC -- TCEA LP Excessive acceleration trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12L_LR -- LP shaft locked at breakaway - check HP speed LOGIC³ ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12L_P -- TCEA HP Overspeed trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L14H_ZE -- TCEA HP Zero speed LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L14L_ZE -- TCEA LP Zero speed LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L30ALM -- TCEA Audible alarm driver signal LOGIC³ CDB --> TCEA ³ ³ ³ ³ ³ L4ETR1 -- TCEA State of Trip Relay 1 LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4ETR2 -- TCEA State of Trip Relay 2 LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4PTR1_FB -- TCEA PTR Trip relay 1 status LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4PTR2_FB -- TCEA PTR Trip relay 2 status LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4PTR3_FB -- TCEA State of Bypass Relay 1 LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4PTR4_FB -- TCEA State of Bypass Relay 2 LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4_FB -- TCEA 4 Relay circuit status (Ext trips) LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L4_XTP -- TCEA Cross trip LOGIC³ CDB --> TCEA ³ ³ SEQ_TRB1 -118 ³ ³ ³ ³ ³ ³ L5E_TCEA -- TCEA 5E/PB Circuit Status LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L69LP_LR -- Rotor locked-inhibit LP breakaway check LOGIC³ CDB --> TCEA ³ ³ ³ ³ ³ L83HOST_P -- TCEA Overspeed Test, Offline LOGIC³ CDB --> TCEA ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L83LOST_P -- TCEA Overspeed Test, Offline LOGIC³ CDB --> TCEA ³ ³ ³ ³ ³ L86MR_TCEA -- TCEA Master Reset LOGIC³ CDB --> TCEA ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ L97HP0T_BYP -- Bypass zero HP speed trip LOGIC³ ³ ³ SEQ_TRB1 -92 ³ ³ ³ ³ ³ ³ TNH_OS -- High press shaft overspeed % T³EA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ TNL_OS -- Low pressure shaft overspeed mag pickup % T³EA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 009 ³ SH NO. 008 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ <<< Rung Number 6 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º L12HV2 - HP OVERSPEED º ³ ³ ³ º º ³ ³ ³ ºTNH_OS + ÚÄÄÄÄÄÂÄ¿ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄOÄÄÄÄÄÄÁ ³ ³ L12HFD_Cº ³ ³ ³ ºTNKHDIF ³ -³ ³ A>B ³ ÃÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄ(ÄÄ(ÄÄÄÄÂÄ´B ³ ³ º ³ ³ ³ º ³ ³ - ³ ÆÍÍÍÍÍµL³ º ³ ³ ³ º ÀÄÄ(ÄÄOÄ(ÄÁ ³A³ L12HFD_Pº ³ ³ ³ ºTNH ³ +³ ³ ³ A>B ³TÃÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄ´ ÀÄ´B ³C³ º ³ ³ ³ ºTNKHF ³ ÆÍÍÍÍÍµH³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄ´/ÃÄÄÄÄ(ÄÄÄÁ ³ ³ L12HFº ³ ³ ³ º ù ³ ³ A>B ³ ÃÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ º L83HF_INH ù ÃÄÄÄ´B ³ ³ º ³ ³ ³ º >ÄÄÄÄÄÄÄÄÄÄÄÙ ³ ÆÍÍÍÍÍµ ³ º ³ ³ ³ º ÀÄÄÄÁ ³ ³ L12Hº ³ ³ ³ ºTNKHOS ³ A>B ³ ÃÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´/ÃÄÂÄÄ´B ³ ³ º ³ ³ ³ ºTNKHOST ù ³ ÀÄÂÄÄÄÁÄ´ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ÃÄÙ ³RESET³ º ³ ³ ³ ºL86MR1_CPB ù ÀÄÄÂÄÄÙ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÙ º ³ ³ ³ º ÀÄÄÄÄÄÄÄÄÄ¿ º ³ ³ ³ ºL83HEOST_CMD ³ L83HEOST_CMDº ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄ´/Ã´ ÃÄÂÄÄÄÄ(ÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ º ù ù ù ³ÚÄÄ¿³ º ³ ³ ³ º ù ù ù À´ ³³ L83HOSTº ³ ³ ³ º ù ù ù ÚÓRÃÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ º ù ù ù ³ÀÄÄÙ º ³ ³ ³ ºL83HMOST_CMD ù ù ù ³ L83HMOST_CMDº ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄ´/ÃÄÁÄ´ ÃÄÁÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ ºL4 ù ³ L83HOST_Pº ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ º ù º ³ ³ ³ º ÚÄ´/ÃÄ¿ º ³ ³ ³ º "1" ³ ³ L83HF_INHº ³ ³ ³ º ÄÄÄ´/ÃÄÁÄ´ ÃÄÁÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ ºL28FDX ù ù ³ º ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄù ùùùùùùùùÄÁÄ> º ³ ³ ³ ºL12H_P L12H_P_ALMº ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ ºL12H_ACC L12H_ACC_ALMº ³ ³ ³ >ÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ LFALSE 0ºOS_BOLT L12HBLT_ALMº ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄ< ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L12H -- ALMTXT:'ELECTRICAL OVERSPEED TRIP - HP' LOGIC³ ALARM 038 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12HBLT_ALM -- ALMTXT:'OVERSPEED BOLT TRIP - HP' LOGIC³ ALARM 044 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12HF -- ALMTXT:'CONTROL SPEED SIGNAL LOSS - HP' LOGIC³ ALARM 214 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12HFD_C -- ALMTXT:'CONTROL SPEED SIGNAL TROUBLE - HP' LOGIC³ ALARM 039 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12HFD_P -- ALMTXT:'PROTECTIVE SPEED SIGNAL TROUBLE - HP' LOGIC³ ALARM 041 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12H_ACC -- TCEA HP Excessive acceleration trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12H_ACC_ALM -- ALMTXT:'PROTECTIVE MODULE ACCELERATION TRIP- HP' LOGIC³ ALARM 042 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L12H_P -- TCEA HP Overspeed trip LOGIC³ TCEA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ L12H_P_ALM -- ALMTXT:'PROTECTIVE MODULE OVERSPEED TRIP - HP' LOGIC³ ALARM 040 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L28FDX -- Flame Detection Control LOGIC³ ³ ³ SEQ_TRB1 -174 ³ ³ ³ ³ ³ ³ ³ ³ ³ L4 -- Master protective signal LOGIC³ ³ ³ SEQ_TRB1 -117 ³ ³ ³ ³ ³ ³ L83HEOST_CMD -- HP electrical overspeed test selection command LOGIC³ ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L83HF_INH -- HP Speed Signal Fault Enable or Inhibit LOGIC³ ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L83HMOST_CMD -- HP mechanical overspeed test selection command LOGIC³ ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L83HOST -- ALMTXT:'OVERSPEED TEST MODE SELECTED - HP' LOGIC³ ALARM 043 ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 010 ³ SH NO. 009 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ L83HOST_P -- TCEA Overspeed Test, Offline LOGIC³ CDB --> TCEA ³ ³ SEQ_TRB1 -6 ³ ³ ³ ³ ³ ³ L86MR1_CPB -- COMMAND PB Master reset LOGIC³ ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ TNH -- HP Turbine Speed % ³ ³ ³ SEQ_TRB1 -3 ³ ³ ³ ³ ³ ³ TNH_OS -- High press shaft overspeed % T³EA -> CDB ³ ³ SEQ_TRB1 -5 ³ ³ ³ ³ ³ ³ TNKHDIF -- Control Speed Signal Trouble Setpoint % = 6³5 % ³ ³ ³ ³ ³ TNKHF -- Speed Signal Fault % = 5³% ³ ³ ³ ³ ³ TNKHOS -- Overspeed Trip Setting for HP Turbine % = 1³0.0 % ³ ³ ³ ³ ³ TNKHOST -- HP OST Test Speed Setpoint Adjust % = 1³3.5 % ³ ³ ³ ³ ³ <<< Rung Number 7 >>> ³ ³ ³ ³ ³ ³ L3CO ³ ³ ³ MM_IO L14HSX L94X L3SFLT ³ ³ ³ ÄÄÄ´/ÃÄÄÄÄÄÄ´/ÃÄÄÄÄÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ L3SFL ³ ³ ³ ³ T_ALM ³ ³ ³ ÀÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L14HSX -- Auxiliary Signal to L14HS LOGIC³ ³ ³ SEQ_AUX -73.2 ³ ³ ³ ³ ³ ³ L3COMM_IO -- Common I/O Status (1=OK, 0=Lost Communications) LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ L3SFLT -- Control System Fault Trip LOGIC³ ³ ³ SEQ_TRB1 -7 ³ ³ ³ ³ ³ ³ L3SFLT_ALM -- ALMTXT:'START-UP SHUTDOWN <C> COMM FAILURE-TRIP' LOGIC³ ALARM 243 ³ ³ SEQ_TRB1 -7 ³ ³ ³ ³ ³ ³ ³ ³ ³ L94X -- Turbine Shutdown LOGIC³ ³ ³ SEQ_TRB1 -71.3 ³ ³ ³ ³ ³ ³ <<< Rung Number 8 >>> ³ ³ ³ OP_SYSTEM_LOGICS ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ <<< Rung Number 9 >>> ³ ³ ³ ³ ³ ³ L3VO L3VO L3VO L3VO ³ ³ ³ TE_R TE_S TE_T TE_Q ³ ³ ³ ÄÄÄ´ ÃÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L3VOTE_Q -- LCC <R,S,T> Composite Voting Status OK LOGIC³ ³ ³ SEQ_TRB1 -9 ³ ³ ³ ³ ³ ³ L3VOTE_R -- LCC <R> Voting OK LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ L3VOTE_S -- LCC <S> Voting OK LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ L3VOTE_T -- LCC <T> Voting OK LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ <<< Rung Number 10 >>> ³ ³ ³ ³ ³ ³ L3LI L3CO L3COM_ ³ ³ ³ NK_C MM_IO B ³ ³ ³ ÄÄÄ´ ÃÄÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L3COMM_IO -- Common I/O Status (1=OK, 0=Lost Communications) LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ L3COM_B -- Communications with OK LOGIC³ ³ ³ SEQ_TRB1 -10 ³ ³ ³ ³ ³ ³ L3LINK_C -- LCC <C> Link OK LOGIC³ OP_SYS_LOGIC ³ ³ ³ ³ ³ <<< Rung Number 11 >>> ³ ³ ³ ³ ³ ³ L3COM_ L3COM_ ³ ³ ³ B B_ALM ³ ³ ³ ÄÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L3COM_B -- Communications with OK LOGIC³ ³ ³ SEQ_TRB1 -10 ³ ³ ³ ³ ³ ³ L3COM_B_ALM -- ALMTXT:'COMMON IO COMMUNICATION LOSS' LOGIC³ ALARM 062 ³ ³ SEQ_TRB1 -11 ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 011 ³ SH NO. 010 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

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MKV Control Sequence Program S O F T W A R E Document created: 29-Nov-99 ÚÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ¿ ³ ³ Segment: F:\UNIT1\SEQ_TRB1³Units³ Reference³ ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ <<< Rung Number 12 >>> ³ ³ ³ ³ ³ ³ L86MR L86MR ³ ³ ³ 1_CPB 1_CPB ³ ³ ³ ÄÄÄ´ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ L86MR_ ³ ³ ³ ³ TCQA ³ ³ ³ ÃÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ L86MR_ ³ ³ ³ ³ DCC ³ ³ ³ ÃÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ L86MR_ ³ ³ ³ ³ TCEA ³ ³ ³ ÃÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ L86MR_ ³ ³ ³ ³ TCQB ³ ³ ³ ÀÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L86MR1_CPB -- COMMAND PB Master reset LOGIC³ ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ L86MR_DCC -- DCC Master Reset LOGIC³ CDB --> DCC ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ L86MR_TCEA -- TCEA Master Reset LOGIC³ CDB --> TCEA ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ L86MR_TCQA -- TCQA Master Reset LOGIC³ CDB --> TCQA ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ L86MR_TCQB -- TCQB Master Reset LOGIC³ CDB --> TCQB ³ ³ SEQ_TRB1 -12 ³ ³ ³ ³ ³ ³ <<< Rung Number 13 >>> ³ ³ ³ ³ ³ ³ ³ ³ ³ L43O_C L28FDX L3ADJ ³ ³ ³ ÄÄÄ´ ÃÄÄÄÄÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ L28FDX -- Flame Detection Control LOGIC³ ³ ³ SEQ_TRB1 -174 ³ ³ ³ ³ ³ ³ L3ADJ -- Auto calibrate permissive LOGIC³ ³ ³ SEQ_TRB1 -13 ³ ³ ³ ³ ³ ³ L43O_C -- Off, Crank, or Cooldown Mode Selected LOGIC³ ³ ³ SEQ_TRB1 -22.6 ³ ³ ³ ³ ³ ³ <<< Rung Number 14 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º COPY º ³ ³ ³ L3ADJ Enable º Copy Analog º LZZ ³ ³ ³ ÄÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ º ù º ³ ³ ³ ZERO 1ºinput ù outputº0 JADJ ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ ³ ³ ³ º º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ JADJ -- Calibration selection command pass code CNT15³ ³ ³ SEQ_TRB1 -14 ³ ³ ³ ³ ³ ³ L3ADJ -- Auto calibrate permissive LOGIC³ ³ ³ SEQ_TRB1 -13 ³ ³ ³ ³ ³ ³ <<< Rung Number 15 >>> ³ ³ ³ ÉÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ» ³ ³ ³ º COPY º ³ ³ ³ L3ADJ Enable º Copy Analog º LZZ ³ ³ ³ ÄÄÄ´/ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄ( ) ³ ³ ³ º ù º ³ ³ ³ ZERO 1ºinput ù outputº0 GSADJ_CMD ³ ³ ³ ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ×ÄÄÄÄÄ´ ÃÄÄÄÄÄÄÄ×ÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ ³ ³ ³ º º ³ ³ ³ ÈÍÍÍÍÍÍÍÍÍÍÍÍÍÍÍ¼ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ GSADJ_CMD -- Auto Calib Analog Forcing Command % ³ ³ ³ SEQ_TRB1 -15 ³ ³ ³ ³ ³ ³ L3ADJ -- Auto calibrate permissive LOGIC³ ³ ³ SEQ_TRB1 -13 ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ MARK V SPEEDTRONIC ³ G E N E R A L E L E C T R I C ³ Notes ³ ³ CONTROL SYSTEM ³ ³ ------- ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ C O M P A N Y ³ A "-" before a rung reference indicates³ ³BBL REV: 1.3 ³ ³ signal originates at that rung. ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ ³TYPE: T M R ³ APPLICATION: G A S T U R B I N E ³ Refer to the document reading aid on ³ ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÅÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄ´ sheet number 2 for further information.³ ³S.O: ³D.M: ³ TURBINE S/N: ³ SITE: ÃÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÂÄÄÄÄÄÄÄÄÄÄÄÄÄ´ ³ xxxxxxx ³ xxxxxxx ³ XXXXX ³ Multi-Customer ³ CONT. ON SH 012 ³ SH NO. 011 ³ ÀÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÄÁÄÄÄÄÄÄÄÄÄÄÄÄÄÙ

SAMPLE


CSP Cross Reference 5.9

CSP CROSS REFERENCE

g

GE

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tem

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AL

LIS

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csp_xref.doc

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1

AFKAP_SITE -- Site Average Ambient Pressure in Hg <0 in>

SEQ_TRB2 73

AFKPEFTD -- Exhaust Pressure Fault Time Delay sec <5.0 sec>

SEQ_TRB3 72

AFKPEMN -- Exhaust Pressure Minimum Value inH2O <-10 inH2O>

SEQ_TRB3 72

AFKPEMX -- Exhaust Pressure Maximum Value inH2O <35 inH2O>

SEQ_TRB3 72

AFKQG -- Compressor Inlet Flow Constant CNT09 <1.0 CNT09>

SEQ_AUX 118

AFKQPC -- INHG to INH20 CNT05 <8.0 CNT05>

SEQ_AUX 118

AFPAP -- Q -TBQB-037 Barometric press transmitter in Hg

SEQ_TRB2 73 SEQ_TRB3 16 SEQ_NOX 5 SEQ_AUX 16 SEQ_AUX 118

AFPAPX -- Selected Ambient Press (Const or Meas.) in Hg

SEQ_TRB2 -73 SEQ_TRB2 74

AFPAP_P -- Inlet Bleed Heat Ambient Pressure (psia) psi

SEQ_TRB3 -16 SEQ_TRB3 17 SEQ_TRB3 18

AFPBD -- C -CTBA-040 Cprsr bellmouth differential press transmitter [96BD-1] inH2O

SEQ_AUX 118

AFPCS -- C -CTBA-046 Inlet air total press transmitter [96CS-1] inH2O

SEQ_TRB2 74 SEQ_AUX 118

AFPEP -- C -CTBA-049 Exhaust press transmitter [96EP-1] inH2O

SEQ_TRB3 72

AFQ -- Compressor Inlet Air Flow lbs/s

SEQ_AUX -118

AFQD -- Compressor Inlet Dry Air Flow lbs/s

SEQ_AUX -118SA

MPL

E


Alarm List 5.10

ALARM LIST

g GE Power Systems

ALARM LIST

alarm_list.doc8/13/01

1

DROP# | SIGNAL NAME | ALARM TEXT------|--------------|---------------------------------------- 0 | L30DIAG_C | DIAGNOSTIC ALARM <C><Q> 1 | L30FORCED | FORCED LOGIC SIGNAL DETECTED 2 | LWLX4MIN | INJECTION TO FUEL RATIO LOW: 4 MIN AVG 3 | LWLXHR | INJECTION TO FUEL RATIO LOW: HOURLY AVG 4 | L30TXA_C | EXHAUST TEMPERATURE HIGH <C> 5 | L86TXT_C | EXHAUST OVERTEMPERATURE TRIP <C> 32 | L64D | BATTERY 125 V DC GROUND 33 | L27DZ_ALM | BATTERY DC UNDERVOLTAGE 34 | L43DIAG_ALM | OFFLINE DIAGNOSTICS RUNNING 35 | L43MAINT | MAINTENANCE - FORCING MODE ENABLED 36 | L5E_ALM | MANUAL TRIP - LOCAL 37 | L86MP | MASTER PROTECTIVE STARTUP LOCKOUT 38 | L12H | ELECTRICAL OVERSPEED TRIP - HP 39 | L12HFD_C | CONTROL SPEED SIGNAL TROUBLE - HP 40 | L12H_P_ALM | PROTECTIVE MODULE OVERSPEED TRIP - HP 41 | L12HFD_P | PROTECTIVE SPEED SIGNAL TROUBLE - HP 42 | L12H_ACC_ALM | PROTECTIVE MODULE ACCELERATION TRIP- HP 43 | L83HOST | OVERSPEED TEST MODE SELECTED - HP 44 | L12HBLT_ALM | OVERSPEED BOLT TRIP - HP 45 | L12L | ELECTRICAL OVERSPEED TRIP - LP 46 | L12LFD_C | CONTROL SPEED SIGNAL TROUBLE - LP 47 | L12L_P_ALM | PROTECTIVE MODULE OVERSPEED TRIP - LP 48 | L12LFD_P | PROTECTIVE SPEED SIGNAL TROUBLE - LP 49 | L12L_ACC_ALM | PROTECTIVE MODULE ACCELERATION TRIP- LP 50 | L83LOST | OVERSPEED TEST MODE SELECTED - LP 51 | L12LF | CONTROL SPEED SIGNAL LOSS - LP 52 | L12LBLT_ALM | OVERSPEED BOLT TRIP - LP 53 | L3A | TURBINE UNDERSPEED 54 | L4CT_ALM | CUSTOMER TRIP 55 | L3CP_ALM | CUSTOMER START INHIBIT 56 | L48 | TURBINE INCOMPLETE SEQUENCE 57 | L62TT2_ALM | FAILURE TO START 58 | L30FD_ALM | FAILURE TO IGNITE 59 | L28FD_ALM | FLAME DETECTOR TROUBLE 60 | L28FDT | LOSS OF FLAME TRIP 61 | L28FD_SD | CHAMBER FLAMED OUT DURING SHUTDOWN 62 | L3COM_B_ALM | COMMON IO COMMUNICATION LOSS 63 | L2SFT | STARTUP FUEL FLOW EXCESSIVE TRIP 64 | L60FSRG | FSR GAG NOT AT MAX LIMIT 65 | L3DWRF | LOSS OF EXTERNAL SETPOINT LOAD SIGNAL 66 | L3TFLT | LOSS OF COMPRESSOR DISCHARGE PRESS BIAS 67 | L30TFX | TURBINE AIR INLET TROUBLE 68 | L63TF1H_ALM | TURBINE AIR INLET DIFF PRESSURE ALARM 69 | L63TFH_ALM | TURBINE AIR INLET DIFF PRESS SHUTDOWN 70 | L63TFH_SENSR | TURBINE AIR INLET DIFF PRESS SW TROUBLE 71 | L52QA_ALM | AUX LUBE OIL PUMP MOTOR RUNNING 72 | L72QEZ_ALM | EMERGENCY LUBE OIL PUMP MOTOR RUNNING 73 | L63QQ1H_ALM | MAIN LUBE OIL FILTER DIFF PRESSURE HIGH 74 | L63QTX | LOW LUBE OIL PRESSURE TRIP 75 | L63QAL_ALM | LUBE OIL PRESSURE LOW 76 | L63QT_SENSR | LUBE OIL PRESSURE SWITCH TROUBLE 77 | L71QH_ALM | LUBE OIL LEVEL HIGH 78 | L71QL_ALM | LUBE OIL LEVEL LOW 79 | L26QN_ALM | LUBE OIL TANK TEMPERATURE LOW 80 | L26QA_ALM | LUBE OIL HEADER TEMPERATURE HIGH

SAM

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I/O Reports 5.11

I/O REPORTS

� IO Report for

DM No. : R05215

MERCK PHARM

WEST POINT, PA

Station : PA USA

Requisition No. : A88G800333

Shop Order No. : PPV581

Creator : JOSEPH V. STROBA

Technician : MIKE E. LAWSON

Drawing No. : 342A4576IO

Revision No. : 00

GE Industrial Control Systems

Salem, VA

SAM

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�&a0R�&a0C

USING THE I/O REPORT

Introduction

The I/O (Input/Output) report represents the job specific assignment of I/O termina

tions in

the SpeedtronicTM Mark V control panel. This report also contains I/O related informati

on including signal

name, scale type, cabling information, and device nomenclature.

termination points.

Note: I/O reports are arranged in alphanumeric order according to (1) core name, (2) car

d name, and (3) terminal

point numbers.

DM & Steam Turbine Numbers

Located in the bottom left-hand corner of each page of an I/O Report is a unique id

entification code that

represents both the individual job (site) and turbine frame size. This value is termed

the "DM" (Design Memo)

number for Gas Turbine applications and simply "Steam Turbine number" for Steam Turbine

applications.

Drawing Numbers

Located on the bottom right-hand side of each I/O report page is another unique ide

ntification code that

represents the document's "drawing number." Typically, this value will be represented a

s follows:

123A4567IO

Page 2

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�&a0R�&a0C

I/O REPORT INDEXES

The I/O Report catalogs signal transmissions into thirteen individual classificatio

ns. Some of these

alphanumeric and textual listings are too varied (Cable Number) or self-evident (Nomencl

ature) to

summarize. However, in a effort to promote understanding of this document, the followin

g records are

offered:

Note: These References Are Subject To Change.

TERMINAL BOARDS

Core Terminal Board Card Location Typical Device

C CTBA 6 ANALOG I/O (4/20ma input/output)

C TBCA 9 RTD INPUTS

C TBCB (OPTIONAL) 7 ANALOG INPUTS (0/1ma,4/20ma,RTD)

C TBQA (OPTIONAL) 8 THERMOCOUPLE INPUTS

CD DTBA 6 DIGITAL INPUT (Contacts 1 throug

h 46)

CD DTBB 7 DIGITAL INPUT (Contacts 47 throu

gh 96)

CD DTBC 8 DIGITAL OUTPUT (Solenoids/Relays

1 through 18; Relays 19 through 30)

CD DTBD 9 DIGITAL OUTPUT (Solenoids/Relays


P PTBA 6 PROTECTION I/O (Flame Detectors,Ov

erspeed,Synchronizing,

Trip Solenoid Dri

vers)

PD PDTB 1 PANEL POWER INPUTS

QD1 DTBA 6 DIGITAL INPUT (Contacts 1 throug

h 46)

QD1 DTBB 7 DIGITAL INPUT (Contacts 47 throu

gh 96)

QD1 DTBC 8 DIGITAL OUTPUT (Solenoids/Relays


QD1 DTBD 9 DIGITAL OUTPUT (Solenoids/Relays


(OPTIONAL CORE) QD2 DTBA 6 DIGITAL INPUT (Contacts 1 throug

h 46)

(OPTIONAL CORE) QD2 DTBB 7 DIGITAL INPUT (Contacts 47 throu

gh 96)

(OPTIONAL CORE) QD2 DTBC 8 DIGITAL OUTPUT (Solenoids/Relays


(OPTIONAL CORE) QD2 DTBD 9 DIGITAL OUTPUT (Solenoids/Relays


R TBQA 8 THERMOCOUPLE INPUTS

R TBQB 7 ANALOG INPUTS (PCD,VDC,Vibration)

R TBQC 9 ANALOG I/O (LVDT/R Monitoring,4/20

ma-IN,4-20/200ma-OUT)

S TBQD (OPTIONAL) 7 PROXIMITOR INPUTS

R,S,T QTBA 6 ANALOG IN/OUT (LVDT Excitation)

Page 3

SAM

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SIG

NAL

ABBR

EVIA

TION

(Alphanumeric Signal Abbreviations should be read in the following manner:

MAO01P = Milliamp Output, (Position 01, Positive)

Note: Signal abbreviations and terminal configurations below are offered as an should be considere

d representative only.

SIGNAL DESCRIPTION SIGNAL DESCRIPTI

ON -------- ---------------------------------------------- -------- ---------------------

------------------------

BUSPT1 Running Line Voltage Input #1 MPU1H Magnetic Pickup (1)

High

BUSPT2 Running Line Voltage Input #2 MPU1L Magnetic Pickup (1)

Low

BUSPT3 Running Line Voltage Input #2 OSHPIH Overspeed High Press

ure Shaft High

OSHPIL Overspeed High Press

ure Shaft Low

CI01 Contact Input (01 on Core)

BUS_A On Bus A P15A Positive 15 Amp.

ICOMA Common

CO01SOL Contact Output (01) Solenoid N15A Negative 15 Amp.

CO01NO Contact Output (01) Normally Open

CO01C Contact Output (01) Common POS01H Position Feedback (0

1) High (from LVDT)

CO01NC Contact Output (01) Normally Closed POS01L Position Feedback (0

1) Low (from LVDT)

CPDSPP Comp. Dischg. Press. Pos. Excitation,<S> RTD01A Resistance Temperatu

re Detector (01)

CPDSPN Comp. Dischg. Press. Neg. Excitation,<S> RTD01B Resistance Temperatu

re Detector (01)

CPDSP Comp. Dischg. Press. Pos. In,<S> RTD01C Resistance Temperatu

re Detector (01)

CPDSN Comp. Dischg. Press. Neg. In,<S>

SHVLTA Shaft Voltage Positi

ve *AC/DC Panel Power* SHVLTB Shaft Voltage Negati

ve

DCHI Direct Current High SHCURA Shaft Current Positi

ve DCLO Direct Current Low SHCURB Shaft Current Negati

ve AC1H Alternating Current (1) High

AC1N Alternating Current (1) Negative SPARE Spare Terminal (Non-

Active Software Input)

AC2H Alternating Current (1) High

AC2N Alternating Current (1) Negative SVO01 Servo Valve Output (

01)

SVOX1 Servo Valve Output (

X1)

FL1H Flame Detect (1) High SVOR1 Servo Valve Output (

R1)

FL1L Flame Detect (1) Low

TC01P Thermocouple (01) Po

sitive

GENPT1 Generator Line Voltage Input #1 TC01N Thermocouple (01) Ne

gative

GENPT2 Generator Line Voltage Input #2

GENPT3 Generator Line Voltage Input #3 TIC_l Time Tic (Low)

LVD01E Linr. Variable Diff. Transd. (01) Excitation TRP1 Trip Circuit Logic I

nput in 

LVD01L Linr. Variable Diff. Transd. (01) Low TRP2 Trip Circuit Logic I

nput in 

MAI01P Milliamp Input (01) Positive TTL1H Transistor Transisto

r Logic Input (1) High

MAI01N Milliamp Input (01) Negative TTL1L Transistor Transisto

r Logic Input (1) Low

MAI01E Milliamp Input (01) Excitation TTL1P Transistor Transisto

r Logic Input (1) Positive

TTL1N Transistor Transisto

r Logic Input (1) Negative

MAO01P Milliamp Output (01) Positive

MAO01N Milliamp Output (01) Negative VDC1RP DC Voltage Input (1)

Reference Positive

VDC1RN DC Voltage Input (1)

Reference Negative

VIB01H Vibration (01) High VDC1RH DC Voltage Input (1)

High

VIB01L Vibration (01) Low VDC1RL DC Voltage Input (1)

Low

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HEADER INDEX

The I/O Report immediately below is offered in order to provide a synopsis of an actual doc

ument's content.

HEADER DESCRIPTION

--------------------------------------------------------------------------------------------------------------------------

--------------------------------------------

Cable Also known as "J-Number". This value reveals which cable is carrying the I/O transmission. The cable may hav

e either Pyle National plug connectors or

Num hard wire to the panel. The cables are listed in the GEPG Cable Block Diagram if used.

Eg: J17

Pnt Conductor number of cable. Reveals which wire within the cable is carrying the described I/O transmission.

Eg: 14 (conductor number 14)

Wire Numbers assigned and maintained by GEPG to relate devices to wires.

Num Eg: 772

Interpos'g Interposing Terminal Board location. This is a reference of the Terminal Board most immediate to, yet still

outside of the Mark V control panel.

Term.Board Eg: TBQ 11

Core Core Processor designation: < R > - One of three Redundant Controllers (TMR) or

Name Single controller (Simplex)

< S > - One of three Redundant Controllers (TMR only)

< T > - One of three Redundant Controllers (TMR only)

< C > - Common Core

 - Protection Core,

<QD1> - Digital I/O for Redundant Controllers or Single controller < R >< S

>< T >(<Q>) Cores

<QD2> - OPTIONAL Digital I/O for < R >< S >< T >(<Q>) Cores

<PD> - Power Distribution Core

<CD> - Digital I/O for Common Core <C>

<PLU> - Power Load Unbalance Core (Large Steam Turbine only)

Term. Printed wire board equipped with Phoenix connectors. (See I/O Report Indexes for description of board). Term

ination screws are mounted on this hardware

device.

Board Eg: DTBB

Screw Wire termination point on Terminal board. Terminations can handle one (1) #12 AWG or two (2) #14 AWG wires p

er point for control I/O, 300 volt, 10 amp,

Num designed to UL, CSA and VDE. Features: captive screws, dead front for safety, 85% copper alloy with nickel p

lating.

These points are typically called "green screws" as the wires are connected and held via a series of screws

mounted in a green pre-drilled polymer brack

et.

I/O wire is to have 600V insulation rating.

Eg: 039

I/O Input/Output abbreviation (See Signal Abbreviation list on page 4). This alphanumeric value designates the

type of I/O being sent or received.

Abbrev. Example MAI01P = Milliamp Input #1 (Positive).

Eg: CI61

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�&a0R�&a0C

HEADER INDEX (cont.)

HEADER DESCRIPTION

--------------------------------------------------------------------------------------------------------------------------

--------------------------------------------

Device name The Device name describes the device that is interfaced with the Mark V control panel. This nomenclature is

based on American National

Institute ANSI (C37.2) and IEEE Industry Standards. Primary device nomenclature consists in general, of a 1

or 2 digit number,

plus (1 or) 2 letters. If two or more devices have similar functions and thus have the same basic name, all

must have a dash number. Eg: 26FD-1

Position and limit switches may have additional notations consisting of two letters, plus a number if requir

ed. The first letter indicates contact

condition (open or closed). The second letter is used to indicate end position (where contact condition is

or becomes as indicated by first letter).

See GEPG Device Summary for complete description of letters and devices.

Eg: 33FL-1/ac

Contact If the device listed is a contact, this record will provide its de-energized condition or "contact sense."

Sense Eg: NO = Normally Open,

NC = Normally Closed

C = Form C: Used in conjunction with NO and NC relay outputs.

Signal Software Signal name according to Mark V database. If the signal is not used, the signal name will be the ha

rdware name. Hardware points which are not

Name associated with a software point appear blank. Note: A signal may have multiple screw termination points and

thus may appear several times.

Eg: L59EA = Exciter Overvoltage

Scale Scale Type reflects the software point name's scaling used by the Operator Interface.

Type Eg: CIM = Contact Input

CIM_I = Contact Input inversion

TC = Thermocouple

LOG = Logical

MWATT = Megawatt.

Nomenclature Text formatted signal identification. This text describes the devices and or conditions associated with the

software signal.

Eg: Torque Adjuster Drive Motor.

System Line Voltage.

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Cable Wire Interpos'g Core Term Screw I/O Contact Signal Scale

Num Pnt Num Term Board Name Board Num Abbrev Device name Sense Name Type Nomencl

ature R

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----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

-------------------------------------------

5011 <C> CTBA 001 MAO01P DVAR DVAR MVAR GENERAT

OR VARS

5012 <C> CTBA 002 MAO01N DVAR DVAR MVAR GENERAT

OR VARS

5013 <C> CTBA 003 MAO02P DF_OUT DF FREQL GENERAT

OR FREQUENCY

5014 <C> CTBA 004 MAO02N DF_OUT DF FREQL GENERAT

OR FREQUENCY

5015 <C> CTBA 005 MAO03P DPF DPF PF GENERAT

OR POWER FACTOR

5016 <C> CTBA 006 MAO03N DPF DPF PF GENERAT

OR POWER FACTOR

5025 <C> CTBA 007 MAO04P DWATT DWATT MWATT GENERAT

OR MEGAWATTS

5026 <C> CTBA 008 MAO04N DWATT DWATT MWATT GENERAT

OR MEGAWATTS

5027 <C> CTBA 009 MAO05P INC_PT DV V64K GENERAT

OR VOLTS

5028 <C> CTBA 010 MAO05N INC_PT DV V64K GENERAT

OR VOLTS

<C> CTBA 011 MAO06P Q_C_MAO06

<C> CTBA 012 MAO06N Q_C_MAO06





















<C> CTBA 033 SPARE

<C> CTBA 034 SPARE

<C> CTBA 035 TIC_H

<C> CTBA 036 TIC_L

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v. ----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

------------------------------------------- ---

<C> CTBA 037 MAI01P C_C_MAI01

<C> CTBA 038 MAI01N C_C_MAI01

<C> CTBA 039 MAI01E C_C_MAI01

2355 <C> CTBA 040 MAI02E 96BD-1 AFPBD DPH2O Cprsr b

ellmouth differential press transmitter

2354 <C> CTBA 041 MAI02P 96BD-1 AFPBD DPH2O Cprsr b


NA <C> CTBA 042 MAI02N 96BD-1 AFPBD DPH2O Cprsr b





2330 <C> CTBA 046 MAI04E 96CS-1 AFPCS DPH2O Inlet a

ir total press transmitter

2331 <C> CTBA 047 MAI04P 96CS-1 AFPCS DPH2O Inlet a


NA <C> CTBA 048 MAI04N 96CS-1 AFPCS DPH2O Inlet a


2379 <C> CTBA 049 MAI05P 96EP-1 AFPEP DPH2O Exhaust

press transmitter

NA <C> CTBA 050 MAI05N 96EP-1 AFPEP DPH2O Exhaust

press transmitter

2378 <C> CTBA 051 MAI05E 96EP-1 AFPEP DPH2O Exhaust

press transmitter

























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----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

------------------------------------------- ---




6337 <C> CTBA 079 SHVLTA 96SV-1/curr TRANSMI

TTER - SHAFT VOLTAGE/CURRENT

6338 <C> CTBA 080 SHVLTB 96SV-1/curr TRANSMI


6340 <C> CTBA 081 SHCURA 96SV-1/volt TRANSMI


6339 <C> CTBA 082 SHCURB 96SV-1/volt TRANSMI


<C> CTBA 083 SPARE

<C> CTBA 084 SPARE

779 <C> TBCA 001 RTD01A DT-GSF-1 DTGSF1 TC Generat

or temp - stator coupling end

774-1 <C> TBCA 002 RTD01B DT-GSF-1 DTGSF1 TC Generat


778 <C> TBCA 003 RTD01C DT-GSF-1 DTGSF1 TC Generat














785 <C> TBCA 010 RTD04A DT-GSA-4 DTGSA4 TC Generat

or temp - stator collector end

774-1 <C> TBCA 011 RTD04B DT-GSA-4 DTGSA4 TC Generat


784 <C> TBCA 012 RTD04C DT-GSA-4 DTGSA4 TC Generat














795 <C> TBCA 019 RTD07A DT-GGC-10 DTGGC10 TC Generat

or temp - cold gas coupling end

774-1 <C> TBCA 020 RTD07B DT-GGC-10 DTGGC10 TC Generat


794 <C> TBCA 021 RTD07C DT-GGC-10 DTGGC10 TC Generat


797 <C> TBCA 022 RTD08A DT-GGC-11 DTGGC11 TC Generat

or temp - cold gas collector end

774-1 <C> TBCA 023 RTD08B DT-GGC-11 DTGGC11 TC Generat


796 <C> TBCA 024 RTD08C DT-GGC-11 DTGGC11 TC Generat


1781 <C> TBCA 025 RTD09A DT-GGH-18 DTGGH18 TC Generat

or temp - hot air coupling end

774-2 <C> TBCA 026 RTD09B DT-GGH-18 DTGGH18 TC Generat


1780 <C> TBCA 027 RTD09C DT-GGH-18 DTGGH18 TC Generat


1783 <C> TBCA 028 RTD10A DT-GGH-19 DTGGH19 TC Generat

or temp - hot air collector end

774-2 <C> TBCA 029 RTD10B DT-GGH-19 DTGGH19 TC Generat


1782 <C> TBCA 030 RTD10C DT-GGH-19 DTGGH19 TC Generat


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----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

------------------------------------------- ---

6703 <C> TBCA 031 RTD11A DT-GGH-12 DTGGC12 TC GENERAT

OR TEMP - COLD GAS COLL END

<C> TBCA 032 RTD11B DT-GGH-12 DTGGC12 TC GENERAT


6702 <C> TBCA 033 RTD11C DT-GGH-12 DTGGC12 TC GENERAT


5736 <C> TBCA 034 RTD12A DT-GGC-13 DTGGC13 TC GENERAT

OR TEMP - COLD GAS COUP END

<C> TBCA 035 RTD12B DT-GGC-13 DTGGC13 TC GENERAT


5735 <C> TBCA 036 RTD12C DT-GGC-13 DTGGC13 TC GENERAT


1775 <C> TBCA 037 RTD13A DT-GGH-15 DTGGH15 TC GENERAT

OR TEMP - HOT GAS COLL END

<C> TBCA 038 RTD13B DT-GGH-15 DTGGH15 TC GENERAT


1774 <C> TBCA 039 RTD13C DT-GGH-15 DTGGH15 TC GENERAT


5738 <C> TBCA 040 RTD14A DT-GGH-16 DTGGH16 TC GENERAT

OR TEMP - HOT GAS COUP END

<C> TBCA 041 RTD14B DT-GGH-16 DTGGH16 TC GENERAT


5737 <C> TBCA 042 RTD14C DT-GGH-16 DTGGH16 TC GENERAT


<C> TBCA 043 RTD15A C_C_RTD15

<C> TBCA 044 RTD15B C_C_RTD15

<C> TBCA 045 RTD15C C_C_RTD15
















5726 <C> TBCA 061 RTD21A AT-1/R C_C_RTD21 TC

5725 <C> TBCA 062 RTD21B AT-1/R C_C_RTD21 TC

5724 <C> TBCA 063 RTD21C AT-1/R C_C_RTD21 TC

5729 <C> TBCA 064 RTD22A AT-2/R C_C_RTD22 TC

5728 <C> TBCA 065 RTD22B AT-2/R C_C_RTD22 TC

5727 <C> TBCA 066 RTD22C AT-2/R C_C_RTD22 TC

5732 <C> TBCA 067 RTD23A AT-3/4 C_C_RTD23 TC

5731 <C> TBCA 068 RTD23B AT-3/4 C_C_RTD23 TC

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----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

------------------------------------------- ---



















9690 <C> TBCA 088 RTD30A CT-IF-3/R CTIFR TC Compres

sor temperature-inlet flange

9691 <C> TBCA 089 RTD30B CT-IF-3/R CTIFR TC Compres


9692 <C> TBCA 090 RTD30C CT-IF-3/R CTIFR TC Compres


459 <C> TBQA 001 TC01P TT-WS1FI-1 TTWS1FI1 TC Turbine

temperature-wheelspace 1st stg fwd inner

460 <C> TBQA 002 TC01N TT-WS1FI-1 TTWS1FI1 TC Turbine


1485 <C> TBQA 003 TC02P TT-WS1FI-2 TTWS1FI2 TC Turbine


1486 <C> TBQA 004 TC02N TT-WS1FI-2 TTWS1FI2 TC Turbine


<C> TBQA 005 TC03P BT-GJ1-1A BTGJ1_1 TC BRG MET

AL TEMP-GEN BRG #1

<C> TBQA 006 TC03N BT-GJ1-1A BTGJ1_1 TC BRG MET

AL TEMP-GEN BRG #1


AL TEMP-GEN BRG #1


AL TEMP-GEN BRG #1

443 <C> TBQA 009 TC05P TT-WS1AO-1 TTWS1AO1 TC Turbine

temperature-wheelspace 1st stg aft outer

444 <C> TBQA 010 TC05N TT-WS1AO-1 TTWS1AO1 TC Turbine






447 <C> TBQA 013 TC07P TT-WS2FO-1 TTWS2FO1 TC Turbine

temperature-wheelspace 2nd stg fwd outer

448 <C> TBQA 014 TC07N TT-WS2FO-1 TTWS2FO1 TC Turbine




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----- --- ----- ------------ ----- ----- ----- ------ -------------------- ------- ------------ ------ -------

------------------------------------------- ---


temperature-wheelspace 2nd stg aft outer








temperature-wheelspace 3rd stg fwd outer








temperature-wheelspace 3rd stg aft outer






temperature-wheelspace 3rd stg a


AL TEMP GEN BRG #2


AL TEMP GEN BRG #2


AL TEMP GEN BRG #2


AL TEMP GEN BRG #2

<C> TBQA 033 TC17P BT-RGP2-1A BTRGP2_1 TC BRG MET

AL TEMP RED GEAR PINION

<C> TBQA 034 TC17N BT-RGP2-1A BTRGP2_1 TC BRG MET


<C> TBQA 035 TC18P BT-RGP2-2A BTRGP2_2 TC BRG MET


<C> TBQA 036 TC18N BT-RGP2-2A BTRGP2_2 TC BRG MET


<C> TBQA 037 TC19P C_C_TC19

<C> TBQA 038 TC19N C_C_TC19

497 <C> TBQA 039 TC20P LT-TH-1A LTTH1 TC Lube oi

l thermocouple turbine header

498 <C> TBQA 040 TC20N LT-TH-1A LTTH1 TC Lube oi

l thermocouple turbine header





473 <C> TBQA 045 TC23P LT-B1D-A LTB1D TC Lube oi

l thermocouple #1 bearing drain

474 <C> TBQA 046 TC23N LT-B1D-A LTB1D TC Lube oi


475 <C> TBQA 047 TC24P LT-B2D-A LTB2D TC Lube oi


476 <C> TBQA 048 TC24N LT-B2D-A LTB2D TC Lube oi




7443 <C> TBQA 051 TC26P LT-RGCD-1A LTRGCD TC LO ther

mocouple red gear comb brg drain

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GE Gas Turbine Training Manual

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