GE Gas Turbine Training Manual
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Description
Technology for Gas Turbines
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
Siemens Power Generation
GE Gas Turbine Training
Technology for Gas Turbines
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.
GE Gas Turbine Training
Siemens Power Generation
Technology for Gas Turbines
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
Siemens Power Generation
Table of Contents
Technology for Gas Turbines
INTRODUCTION
Introduction
1.0
Technology for Gas Turbines
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
Course Introduction Siemens Power Generation
1.0
Technology for Gas Turbines
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
1.1
Technology for Gas Turbines
GE Control System Documentation 1.1 1.2 1.3 1.4 1.5 1.6 1.7 1.8 1.9 1.10 1.11
Piping and Instrumentation Drawing (PI&D) Device Summary Control Specification Turbine Elementary Turbine Connection Diagram Motor Control Center Connection Diagram Generator control Panel Connection Diagram Control Sequence Program (CSP) CSP Cross Reference Alarm List I/O Reports
Review
Introduction to GE Gas Turbine Controls Philosophy - Course Outline
1.2
Technology for Gas Turbines
GE GAS TURBINE FLEET
GE Gas Turbine Fleet
2.0
GE Energy
GAS TURBINE AND COMBINED CYCLE PRODUCTS
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.
GE ENERGY GAS TURBINE AND COMBINED CYCLE PRODUCTS
Heavy Duty
Heat Rate Btu/kWh kJ/kWh
Output
2
MS9001H
CC
520 MW
50 Hz
5,690
6,000
2
MS7001H
CC
400 MW
60 Hz
5,690
6,000
6
MS9001FB
CC
412.9 MW
50 Hz
5,880
6,202
6
MS7001FB
CC
280.3 MW
60 Hz
5,950
6,276
8
MS6001FA
CC CC SC SC
117.7 MW 118.1 MW 75.9 MW 75.9 MW
50 Hz 60 Hz 50 Hz 60 Hz
6,240 6,250 9,760 9,795
6,582 6,593 10,295 10,332
8
MS7001FA
CC SC
262.6 MW 171.7 MW
60 Hz 60 Hz
6,090 9,360
6,424 9,873
8
MS9001FA
CC SC
390.8 MW 255.6 MW
50 Hz 50 Hz
6,020 9,250
6,350 9,757
10
MS9001E
CC SC
193.2 MW 126.1 MW
50 Hz 50 Hz
6,570 10,100
6,930 10,653
11
MS7001EA
CC SC
130.2 MW 85.1 MW
60 Hz 60 Hz
6,800 10,430
7,173 11,002
12
MS6001B
CC CC SC
64.3 MW 64.3 MW 42.1 MW
50 Hz 60 Hz 50/60 Hz
6,950 6,960 10,642
7,341 7,341 11,226
13
MS6001C
CC CC SC SC
67.2 MW 67.2 MW 45.4 MW 45.3 MW
50 Hz 60 Hz 50 Hz 60 Hz
6,281 6,281 9,315 9,340
6,627 6,627 9,830 9,855
14
Small Heavy-Duty and Aeroderivative Gas Turbine Products Overview
16
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.
GE’s H System™—the world’s most advanced combined cycle system and the first capable of breaking
MS9001H/MS7001H COMBINED CYCLE PERFORMANCE RATINGS Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
50 Hz
World’s Most Advanced Combined Cycle Gas Turbine Technology
S109H
520
5,690
6,000
60.0%
1 x MS9001H
60 Hz
2 H SYSTEM™
H System™
S107H
400
5,690
6,000
60.0%
1 x MS7001H
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 Baglan Bay Power Station is the
standards and reducing CO2 emissions. Additionally, closed-loop cooling also minimizes parasitic extraction
launch site for GE’s H System™.
of compressor discharge air, thereby allowing more air to flow to the combustor for fuel premixing, thereby
PSP30462-05
enabling lower emissions.
An MS9001H is seen during
RDC27903-13-03
assembly in the factory.
Single Crystal Materials
3 H SYSTEM™
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 A 9H gas turbine is
Building on GE’s design experience, the H System™ employs a can-annular lean pre-mix DLN-2.5
readied for testing.
Dry Low NOx (DLN) Combustor System. Fourteen combustion chambers are used on the 9H, and
the ability to achieve low NOx levels in several million hours of field service around the world.
Small Footprint/High Power Density
RDC27916-09-09
12 combustion chambers are used on the 7H. GE DLN combustion systems have demonstrated
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.
PSP30246-10
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 technology with high customer confidence.
World’s first H turbine is transported through Wales to Baglan Bay Power Station.
F Class 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 PSP30027-06
efficiencies, while maintaining reliability and availability.
An MS9001FA gas turbine ships from the plant.
Dry Low NOx combustor systems allow GE’s F Class turbines to meet today’s strict environmental emissions requirements.
RDC27305-02a
F CLASS
4
Our F class gas turbines, including the 6F (either 50 or 60 Hz), the 7F (60 Hz) and the 9F (50 Hz), offer
5 F CLASS
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
11,844 11,594
12000
10,327 9,061
10000
7,794 6,859 5,790 4,899 4,186 3,575 2,989
8000 6000 4000 2000
’96
’97
’98
’99
’00
’01
’02
’03
’04
’05
YEAR
PSP30210-01
0 ’95
Half of all 6FA installations are located in Europe. This CHP plant is owned by Porvoo, PSP30114
FIRED HOURS IN THOUSANDS
14000
Finland.
MS7001FB and MS9001FB 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. This MS9001FB is seen on half shell during assembly.
Improved output and efficiency means better fuel economy and reduced cost of producing electricity. With
PSP30510-01
today’s competitive markets and unpredictable fuel prices, this—now more than ever—is the key to success.
PSP30371-02
Hunterstown, PA 7FB launch site. PSP30251-39
MS7001FB and MS9001FB
6
This MS7001FB is shown in the factory.
In developing the FB, we followed a specific course that significantly improved the key driver of efficiency—
7
firing temperature. The FB firing temperature was increased more than 100 degrees Fahrenheit over GE’s FA
Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
S109FB
412.9
5,880
6,202
58.0%
1 x MS9001FB
S209FB
825.4
5,884
6,206
58.0%
2 x MS9001FB
S107FB
280.3
5,950
6,276
57.3%
1 x MS7001FB
S207FB
562.5
5,940
6,266
57.5%
2 x MS7001FB
technology, resulting in combined cycle efficiency rating improvements of better than one percentage 60 Hz 50 Hz
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
PSP30299
PSP30266-02
seen in test cell.
MS7001FB and MS9001FB
MS7001FB/MS9001FB COMBINED CYCLE PERFORMANCE RATINGS
MS6001FA, MS7001FA and MS9001FA
50 Hz Power Generation
60 Hz Power Generation
Output
(MW)
75.9
75.9
Proven Performance in a Mid-Size Package
Heat Rate
(Btu/kWh) (kJ/kWh)
9,760 10,295
9.795 10,332
The highly efficient gear-driven 6FA gas turbine is a mid-size version of the well-proven 7FA and 9FA. Its
Pressure Ratio
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).
15.6:1
15.7:1
Mass Flow
(lb/sec) (kg/sec)
447 203
449 204
Turbine Speed
(rpm)
5,231
5,254
Exhaust Temperature
(ºF) (ºC)
1,117 603
1,118 603
PG6111FA
PG6111FA
Model Designation
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
MS6001FA COMBINED CYCLE PERFORMANCE RATINGS Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
S106FA
117.7
6,240
6,582
54.7%
1 x MS6001FA
S206FA
237.9
6,170
6,508
55.3%
2 x MS6001FA
S106FA
118.1
6,250
6,593
54.6%
1 x MS6001FA
S206FA
237.5
6,210
6,550
54.9%
2 x MS6001FA
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
60 Hz 50 Hz
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.
KEPCO’s Seoinchon Plant, one of the world’s largest combined cycle plants, has operated for more than 40,000 hours in
Industry Standard for 60 Hz Power in All Duty Cycles
daily start/stop cyclic duty.
The wide range of power generation applications for the 7FA gas turbine includes combined cycle, cogeneration, 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.
RDC27834-34
M S 6 0 0 1 FA , M S 7 0 0 1 FA a n d M S 9 0 0 1 FA
8
MS6001FA SIMPLE CYCLE PERFORMANCE RATINGS
MS7001FA SIMPLE CYCLE PERFORMANCE RATINGS 60 Hz Power Generation (MW)
171.7
As an industry leader in reducing emissions, the 7FA’s DLN-2.6 combustor (proven in hundreds of thousands
Heat Rate
(Btu/kWh) (kJ/kWh)
9,360 9,873
of operating hours) produces less than 9 ppm NOx and CO—minimizing the need for exhaust cleanup sys-
Pressure Ratio
tems and saving millions for our customers.
Mass Flow
(lb/sec) (kg/sec)
981 445
Turbine Speed
(rpm)
3,600
Exhaust Temperature
(ºF) (ºC)
1,114 601
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
9 M S 6 0 0 1 FA , M S 7 0 0 1 FA a n d M S 9 0 0 1 FA
Output
16.0:1
Model Designation
PG7241FA
with power augmentation equipment that provides additional gas turbine performance in summer peak
Proven Excellence in Reliable 50 Hz Combined Cycle Performance
MS7001FA COMBINED CYCLE PERFORMANCE RATINGS
60 Hz
demand periods—including inlet cooling, steam injection, and peak firing.
Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
S107FA
262.6
6,090
6,424
56.0%
1 x MS7001FA
S207FA
529.9
6,040
6,371
56.5%
2 x MS7001FA
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
MS9001FA SIMPLE CYCLE PERFORMANCE RATINGS
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
50 Hz Power Generation Output
(MW)
255.6
Heat Rate
(Btu/kWh) (kJ/kWh)
9,250 9,757
Pressure Ratio
17.0:1
Mass Flow
(lb/sec) (kg/sec)
1,413 641
Turbine Speed
(rpm)
3,000
Exhaust Temperature
(ºF) (ºC)
1,116 602
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 performance is the prime consideration, it can be arranged in a multi-shaft configuration where one or two gas
Model Designation
PG9351FA
MS9001FA COMBINED CYCLE PERFORMANCE RATINGS
50 Hz
turbines are combined with a single steam turbine to produce power blocks of 390 or 786 MW.
Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
S109FA
390.8
6,020
6,350
56.7%
1 x MS9001FA
S209FA
786.9
5,980
6,308
57.1%
2 x MS9001FA
MS9001E Fuel-Flexible 50 Hz Performer
MS9001E SIMPLE CYCLE PERFORMANCE RATINGS 50 Hz Power Generation
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
Output
(MW)
126.1
Heat Rate
(Btu/kWh) (kJ/kWh)
10,100 10,653
and tropical humidity to arctic cold. Originally introduced in 1978 at 105 MW, the 9E has incorporated Pressure Ratio
numerous component improvements. The latest model boasts an output of 126 MW and is capable of
12.6:1
Mass Flow
(lb/sec) (kg/sec)
Turbine Speed
(rpm)
3,000
Exhaust Temperature
(ºF) (ºC)
1,009 543
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.
Model Designation
922 418
PG9171E
They are designed for reliable operation and minimal maintenance at a competitively low installed cost. MS9001E COMBINED CYCLE PERFORMANCE RATINGS
Like GE’s other E-class technology units, the Dry Low NOx combustion system is available on 9E, which can
Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
Net Plant Efficiency
GT Number & Type
S109E
193.2
6,570
6,930
52.0%
1 x MS9001E
S209E
391.4
6,480
6,835
52.7%
2 x MS9001E
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
50 Hz
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.
The MS9001E gas turbine is designed to attain high availability levels and low
In simple cycle, the MS9001E is a reliable, low first-cost machine for peaking service, while its high
maintenance costs, resulting
combined cycle efficiency gives excellent fuel savings in base load operations. Its compact design
in extremely low total cost of ownership.
provides flexibility in plant layout as well as the easy addition of increments of power when a phased capacity expansion is required. RDC26213-12
MS9001E
10
MS7001EA Time-Tested Performer for 60 Hz Applications
11
MS7001EA SIMPLE CYCLE PERFORMANCE RATINGS
and is well recognized for high reliability and availability. With strong efficiency performance in simple and combined cycle applications, this 85 MW machine is
(MW)
85.1
(hp)
115,630
Heat Rate
(Btu/kWh) (kJ/kWh)
10,430 11,002
(Btu/shp-hr)
7,720
(lb/sec) (kg/sec)
659 299
Pressure Ratio
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.
Mechanical Drive
Output
12.7:1 (lb/sec) (kg/sec)
Turbine Speed
(rpm)
3,600
(rpm)
3,600
Exhaust Temperature
(ºF) (ºC)
997 536
(ºF) (ºC)
999 537
Model Designation
648 294
11.9:1
Mass Flow
PG7121EA
M7121EA
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 dualMS7001EA COMBINED CYCLE PERFORMANCE RATINGS
fuel operation, able to switch from one fuel to another while the turbine is running under load or during Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
60 Hz
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.
GT Number & Type
S107EA 130.2
6,800
7,173
50.2%
1 x MS7001EA
S207EA 263.6
6,700
7,067
50.9%
2 x MS7001EA
An MS7001EA is shown on half shell during assembly.
GT20821
Net Plant Efficiency
MS7001EA
60 Hz Power Generation
With more than 750 units in service, the 7E/EA fleet has accumulated tens of millions of hours of service
MS6001B Reliable and Rugged 50/60 Hz Power
MS6001B SIMPLE CYCLE PERFORMANCE RATINGS 50/60 Hz Power Generation Mechanical Drive
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
Output
(MW)
42.1
(hp)
Heat Rate
(Btu/kWh) (kJ/kWh)
10,642 11,226
(Btu/shp-hr) 7,650
reliability at 99.3%, it is the popular choice for efficient, low installed cost power generation or prime movers Pressure Ratio
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
58,380
12.2:1
12.0:1
Mass Flow
(lb/sec) (kg/sec)
Turbine Speed
(rpm)
5,163
(rpm)
5,111
Exhaust Temperature
(ºF) (ºC)
1,018 548
(ºF) (ºC)
1,011 544
Model Designation
311 141
(lb/sec) (kg/sec)
PG6581B
309 140
M6581B
MS6001B COMBINED CYCLE PERFORMANCE RATINGS
variety of fuels and is well suited to IGCC. In combined cycle operation the 6B is a solid performer at nearly Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
output ranging from 20 to 400 million Btu/hr.
50 Hz
50% efficiency. It is also a flexible choice for cogeneration applications capable of producing a thermal
Like all GE heavy-duty gas turbines, the 6B has earned a solid reputation for high reliability and environmental compatibility. With a Dry Low NOx combustion system, the 6B is capable of achieving less than 15 ppm NOx on natural gas.
60 Hz
Net Plant Efficiency
GT Number & Type
S106B
64.3
6,950
7,341
49.0%
1 x MS6001B
S206B
130.7
6,850
7,225
49.8%
2 x MS6001B
S406B
261.3
6,850
7,225
49.8%
4 x MS6001B
S106B
64.3
6,960
7,341
49.0%
1 x MS6001B
S206B
130.7
6,850
7,225
49.8%
2 x MS6001B
S406B
261.3
6,850
7,225
49.8%
4 x MS6001B
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.
An MS6001B rotor is seen on half shell. RDC24656-03
MS6001B
12
MS6001C High Efficiency 45 MW Class Gas Turbine
13
MS6001C SIMPLE CYCLE PERFORMANCE RATINGS
including industrial cogeneration, district heating, and mid-sized combined-cycle power plants.
Output
(MW)
45.4
45.3
Heat Rate
(Btu/kWh) (kJ/kWh)
9,315 9,830
9,340 9,855
Pressure Ratio
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
19.6:1
19.6:1
Mass Flow
(lb/sec) (kg/sec)
270 122
270 122
Turbine Speed
(rpm)
7,100
7,100
Exhaust Temperature
(ºF) (ºC)
1,078 581
1,078 581
Model Designation
advanced F technology. The turbine includes components that provide high reliability and maintainability, such as a 12-stage compressor
Heat Rate Net Plant Output (MW) (Btu/kWh) (kJ/kWh)
60 Hz 50 Hz
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
PSP30646-02
and a Mark VI Speedtronic control system.
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.
PG6591C
MS6001C COMBINED CYCLE PERFORMANCE RATINGS
with fewer parts and removable blades and vanes. NOx emissions are limited to 15 ppm dry when operating
Akenerji Kemalpasa-Izmir Turkey
60 Hz
Net Plant Efficiency
GT Number & Type
S106C
67.2
6,281
6,627
54.3%
1 x MS6001C
S206C
136.1
6,203
6,544
55.0%
2 x MS6001C
S106C
67.2
6,281
6,627
54.3%
1 x MS6001C
S206C
136.1
6,203
6,544
55.0%
2 x MS6001C
MS6001C
50 Hz
The 6C meets the need for low-cost electricity production in heat recovery operations for both 50 and 60 Hz—
Small Heavy-Duty and Aeroderivative Gas Turbines 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. RDC26874-04
We offer full turnkey systems and aftermarket solutions for production, LNG, transportation, storage, refineries, petrochemical and distribution systems. The powerful LM6000 is one of the most fuel-efficient simple cycle gas turbines in the world.
SMALL HEAVY-DUTY GAS TURBINES
Generator Drive*
Output (kW)
Mechanical Drive**
S M A L L H E AV Y - D U T Y a n d A E R O D E R I VAT I V E G A S T U R B I N E S
14
GE5
5,500
GE10 MS5001
Heat Rate (Btu/kWh) (kJ/kWh)
Pressure Ratio
Turbine Speed (rpm)
Exhaust Flow (lb/sec) (kg/sec) 19.6
Exhaust Temp. (ºF) (ºC)
11,130
11,740
14.8:1
16,630
43.1
11,250
10,884
11,481
15.5:1
11,000
104.7
47.5
900
482
26,830
12,028
12,687
10.5:1
5,094
276.1
125.2
901
483
Output (shp)
Heat Rate (Btu/shp-h)
Pressure Ratio
Turbine Speed (rpm)
Exhaust Flow (lb/sec) (kg/sec)
1,065
574
Exhaust Temp. (ºF) (ºC)
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
15
AERODERIVATIVE GAS TURBINES Turbine Speed (rpm)
Exhaust Flow (lb/sec) (kg/sec)
Exhaust Temp. (ºF) (ºC)
LMS100PA
98,894
7,563
7,979
40:1
3,000
458
208
782
416
LMS100PB LM6000PC Sprint*
98,359 50,041
7,569 8,461
7,873 8,925
40:1 31.5:1
3,000 3,627
456 302
207 137
783 813
417 434
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
41,711
8,374
8,833
29.3:1
3,627
279
127
838
448
LM6000PD (liquid fuel)
40,400
8,452
8,915
28.5:1
3,627
272
123
853
456 524
LM2500RC
32,916
8,880
9,369
23:1
3,600
202
92
976
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
GE Energy’s Oil & Gas products
LM2000PS
17,674
9,779
10,315
16.0:1
3,000
142
64
894
479
are installed in major upstream,
LM1600PE
13,748
9,749
10,283
20.2:1
7,900
104
47
915
491
midstream, downstream
LMS100PA
98,816
7,569
7,986
40:1
3,600
458
207.6
780
416
and distribution applications
LMS100PB
98,196
7,582
7,872
40:1
3,600
456
207
782
417
around the world.
LM6000PC Sprint*
50,080
8,434
8,896
31.3:1
3,600
299
136
819
437
LM6000PC
43,471
8,112
8,557
29.1:1
3,600
282
128
824
440
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
LM2500PH
27,763
8,391
8,850
19.4:1
3,600
167
76
922
494
LM2500PE
23,292
9,315
9,825
19.1:1
3,600
153
69
992
533
LM2000PS
17,606
9,587
10,112
15.6:1
3,600
139
63
886
474
LM1600PE
13,769
9,735
10,268
20.2:1
7,900
104
47
894
479
Output (hp)
Heat Rate (Btu/shp-h)
Pressure Ratio
Turbine Speed (rpm)
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
Exhaust Flow (lb/sec) (kg/sec)
GT06543
Pressure Ratio
Exhaust Temp. (ºF) (ºC) PSP30305
50 Hz Power Gen 60 Hz Power Gen Mechanical Drive
Heat Rate (Btu/kWh) (kJ/kWh)
S M A L L H E AV Y - D U T Y a n d A E R O D E R I VAT I V E G A S T U R B I N E S
Output (kW)
IGCC The Next Generation Power Plant
GE GAS TURBINES FOR IGCC APPLICATIONS
Making Environmental Compliance Affordable
Gas Turbines Model
Syngas Power Rating
Model
Syngas CC Output Power
Integrated Gasification Combined Cycle (IGCC) technology is increasingly important in the world energy
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 9E
90 MW (60 Hz) 150 MW (50 Hz)
107EA 109E
130 MW (60 Hz) 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)
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
IGCC
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
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
This 550 MW IGCC is located at the Saras oil
develop the most economical and reliable approaches to IGCC technology. Using the same combined cycle
refinery in Sardinia. The three GE 109E single-
technology for IGCC that we use for conventional systems, GE offers extensive experience and high levels
over 12,000 hours of syngas operation.
of reliability.
shaft combined cycle units have accumulated
Cover Photo: PSP30502-03, Inside Cover Photos: RDC27191-05-05, PSP30502-01. Designed by GE Energy — Creative Services.
requirements. Using knowledge gained from successfully operating many IGCC units, GE has optimized
PSP30120
I G CC
16
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17
GE Energy 4200 Wildwood Parkway Atlanta, GA 30339 gepower.com GEA 12985E (06/05)
GE Energy
GAS TURBINE AND COMBINED CYCLE PRODUCTS
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
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 utilization of available experience.
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-ofthe-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,
Table 1 SCALING RATIOS Scale Fat tor
0.5
1
2
Pressure Ratio Efficiency RPM Velocities Flow Power Weight Stresses Freq/ROM Tip Speed
1 1 2 1 0.25 0.25 0.125 1 1 1
1 1 1 1 1 1 1 1 1 1
1 1 0.5 1 4 4 8 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 fab1
GER-3434D
rication in many locales using foundry and forging 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 The Gas Turbine
DESCRIPTION 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 coordinates. The constant pressure lines diverge with increasing temperature and entropy. This divergence 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 compress 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 compress 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 avoidable 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
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 bottoming 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 Aerodynamic
cycle gas turbine 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 airflow of 37 kg/set (81.5 lb/set) . compressor 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-
COMPRESSOR Development
GE’s experience with compressor design spans several decades. The original heavy-duty 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.
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.
M-‘Fr-‘%
:$“r
I~~~~~------~ MS7001
MSfWlS
wed
I
m
R
-A L -(B a------I I ,Y, n n P “rrwss.kl,
____e_1 I,
s
I m
, s
12.29c
AREA
I BD(
MS7OOlE /
MS7001
E to MS7001
FA
GT01645N
Figure
3. Growth
in compressor
air flow
GTO4142E
Figure 5. Evolution
-
Percent Rated Power 122OF Day (50%)
GTOlllOH
4. Growth
in compressor
pressure
ratio
1 /
/I
c
P, the MS7001A and B, essentially the same aeroincreases in airflow and in Fig. 3 and 4. Figure 5
/
/
/ Old Compressor (Surge Limited)
I
I
I
57
56
59
Generator
The MS5001N and and the MS9001B are dynamic design, with pressure ratio shown
design
Production
75
50
Figure
of compressor
Line
Frequency
I
60 - Hz
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 17stage 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 unn
F,Ssp”n.,
Compressor Tip o&meter (mm)
Inchcw
Turbine th.Qut
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
63.5 118.9
MSBWlE
1114(340)
85.1 (2161 S)
3000
MS6WlFA
l~(ssl)
56.1 (1425.5)
5236
70.1
MS7001 FA
==(391)
81.8 po72.q
3600
166.4 226.5
MSBOOIFA
~282(38’)
97.9 (24B6.q
3000
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
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-
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
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 guides with low-pressure loss, and completely 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.
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.
GTO1412
Figure
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
TCZO178A
Figure
9. MS5001 compressor
10. Last-stage wheel with cooling-air extraction
rotor stacking
Each stage of the compressor is an individual bladed disk (Fig. 9). The use of this construction allows some weight reduction bv contour6
GER-3434D
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 longstanding 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 plastically yield the bore, producing a residual compressive 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).
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
I
Toughness
-40°F (4%)
,
150
KSlfi
loo
MPaLoO
r
#
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
oPER*TING STRESS WTHo”T
Design
PEAK TANGENTIAL
A typical reverse-flow multiple-combustion system, similar to those in most of the GE heavyduty 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 stabilize 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,
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-
7
GER-3434D
maintainable, and repairable. GE’s reverse-flow, multiple-combustion system is short, compact, lightweight, and is mounted within the flange-toflange 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.
l
l
l
l
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
l
allows
control
Combustor length residual fuels.
for
can be provided
The design is readily adaptable tions, such as water injection. The components are small adequately cooled.
to modifrcaenough
to be
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
Small diameter permitting careful control of the airflow patterns for smoke and NOx reduction. The design profile.
be of
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.
GT03619
Figure
Combustor diameter can readily increased to accommodate combustion the low heating value gas fuels.
of the gas path
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
0.5 k
Dynamic Pressure
15. Combustion
liner cap
I Standard
Single Nozzle System
0.3 psi 0.2 Multinozzle
System
Frequency
(Hz)
0.1
GT15267A
Figure
16. Multi-and single-fuel combustion noise
nozzle
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 positivedisplacement, 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 millimeters 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
GTI 5365
Figure
17. Transition
piece
temperatures and thermal gradients. Higher firing temperatures require combustors 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-frequencybanded noise. While this is generally “white flame to noise,” it is possible for the combustion 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
Figure
18. Combustor spectrum
200
300 Frequency
dynamic
400 - Hz
500
600
pressure
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.
Figure 20. Gas turbine development 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.
lffir 1.04 -
NO COMWJSTOR
FUEL NOZZLE GASPPRESSURE RATIO
COMBUSTOR OSCILLATIONS
.cm FUEL
.cm AIR
OOB
010
laboratory
012
RATIO
GT01425A
Figure
19. Combustor dynamic stability (gas fuel)
pressure
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.
GTOOS16
Figure After testing
2 1. Combustion laboratory
is completed
system scale model
development
of combustors,
on a production
turbine
at
full load conditions. This turbine is extensively instrumented to evaluate the combustor performance and to permit comparison with the results of the single-burner test. Measurements are made of the gas temperature entrance 11
to the first-stage
nozzle,
profile
at the
metal tempera-
GER3434D
tures and vibratory combustor
response
pressure
sures in combustors,
drop, fuel
of the hardware, and dynamic
lines,
GE’s design goal is to rapid swings in load). 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. combustor, shown in the The Dry Low NO, 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.
pres-
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 compare with laboratory tests and theoretical predictions.
Water and steam injection
ed to determine required
the amount
to meet emissions
systems are testof water or steam
standards.
Years of
gas turbine combustor development experience have shown that this combination of laboratory and machine testing is essential to the production of a reliable
combustion
Dry Low No,
Development
system.
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 operabilitythe 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
PRIMARY FUEL NOZZLES (6) LEAN *ND PREYWYG PWYAR” LON
DlL”TlcIH
ZONE
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 MS700lFA, and MSSOOIFA MS600lFA, machines. The base rated power of the MS7000 has increased since the first model was shipped in 1971, from the 46MW MS700lA to the 83.5MW MS700lEA. Seventy percent of this increase
12
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.
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.
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-
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-perstage 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
40 42 1 5% E36.* g Y 34. z E 32 f
TemD
P en8
:Lm40
mm 1900
loo
leoo
1700 16w ,500 OF ,400 13w 12w 1100 Iwo I
(1i4PC)‘ggy 2085’F * ‘;c$“,“,‘;l 0 m&l0 30 16‘6 IB (~ ‘I I. 12 121 2 10 10
44
200 SpeclflCovtpti - KwLbLsec I I I Km 400 iw Uwrn~seC GT01651A
1?igure 24. No compressor (ideal flow)
extraction
flow
40 suoc R
I 18
I 28
I 38
I 48
I
56
38
Turbine Bucket Stage
y&y
I I’&??
GT01649D
s I J E 2= g w 5 E St t-
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
36-
‘:g$’ 30
30
‘g&y J)30
16 18 76 ‘6 1 16 ‘4 14 14
18
3412
12
32-
10
30-
~~ 8
281 40 100
12
10
888
1 1 100 200 Specific Output - KWlLblSec ! 1 200
400
GT01652A
Figure 13
25. Compressor extraction needed (real flow)
flows as
GER-3434D
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 firststage nozzles were introduced into GE heavyduty 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
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 firststage 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
son,
17th Stage Compressor \ Extraction
L Compressor1 Discharge
~%fiJ 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
GT15360
Figure 14
27. First-stage
bucket
cooling
passages
GER-3434D
MS6001B bucket. The bucket shank, which joins the bucket airfoil 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 concentrations in the dovetail are minimized.
GT153S2
Figure
28. First-stage
first-stage components fer design assumptions.
Bucket
nozzle cooling
to validate
the heat trans-
Design
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 mating 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 remarkable innovations in vibration suppression. The development of turbine stages which are vibration free requires sophisticated interaction between the aerodynamic design and testing disciplines. 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
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*lwheel ‘-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 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,
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
30. Fourier analysis of bucket impulse excitation
and optimum strain gauge locations in preparation 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
MATERIAL PROPERTY
(+3fl)
50%
(MEAN)
TEMPERATURE
GTW843A
Figure 32. Statistical properties
nature of material
component life. This value is understood to be a reasonably close and conservative approximation. 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-
GTOI 403
Figure 3 1. Wheelbox
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
GTO3396
Figure
Stress and Material
facility 16
GER-3434D
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 possessed 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 considerable 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 partrelated 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 fatiguewill aid the operator in understanding the operating and repair options associated with the gas turbine, especially in nozzle, bucket, and combustion hardware.
STRAIN (c)
PRIMARY
A Tr
TIME (t-)
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 Maximum StreSS
KS1 ii
MPa
;\/-;;;;;
i:/
lo3
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 historically has utilized data such as those por-
Figure
* 1600°F (871%)
10’
10 5 10 6 Cycles to Failure
10’
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 nickeland 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 recognition 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
GTOS847C
Figure
36. Cooled nozzle vane showing isotherms (typical) I NLXlll.¶ Shutdown
TenSlIe (+I
Strain
0
Fatigue Compresswe
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 trajectory 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
(4 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 and severity of start/stop cycle. The duration 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 char18
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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
acteristics to explore their impact upon cyclic life. Fully instrumented hot section components were incorporated to provide experimental correlation. 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
Figure STRAIN
0
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 PtCr-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
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
PtAl Coated RDCZ6B82 Uncoated 39. First-stage turbine buckets (coated and uncoated IN-738 - 25,000 service hours)
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 19
GER-3434D
coatings does not lead easily to ductile compositions. Current and future work is aimed at overcoming this obstacle by identifying coating compositions which have high corrosion resistance while maintaining acceptable levels of ductility.
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 firststage alloy for all designs; in the MS6001FA, MS7001FA and MS9001FA it is used on all three stages.
Mechanical Substrate
Properties
of Coatings
PROTOTYPE
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 MontanaDakota 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:
and
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
Phase I - Fundamental studies and component tests Phase II - Factory prototype tests Phase III- Field prototype test
Coated
Total Strain Range %
’
Uncoated
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
Average
10'
10’
I 102
I 103
I 104
1 GTO72528
Figure 40. IN-738 low-cycle (871C)
TESTING
fatigue
at 1600F 20
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 steadystate 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 investigations with firing temperatures of 1288C (2350F), justifying the uprate of the MS7001F at 150 MW to the MS’7001FA at 166 MW. It also justified 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 11y 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 Clearly this experience similar performance. 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 Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure Figure
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) (first-stage turbine bucket) 38. Leading edge strain/ temperature 39. First-stage turbine buckets (coated and uncoated IN-738 - 25,000 service hours) 40. In-738 low-cycle fatigue at 1600 F (871 C)
1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. 2 1. 22. 23. 24. 25. 26. 27. 28. 29. 30. 31. 32. 33. 34. 35. 36. 37.
Figure Figure Figure
LIST OF TABLES Table 1 Table 2
GEK3434D
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)
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GE Aeroderivative Gas Turbines - Design and Operating Features G.H. Badeer GE IAD GE Power Systems Evendale, OH
GE Aeroderivative Gas Turbines - Design and Operating Features Contents Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Selection of Aeroderivative Engines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 LM1600 Gas Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 LM2500 Gas Turbine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 LM2500+ Gas Turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 LM6000 Gas Turbine. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 LM6000 Sprint™ System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 STIG™ Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Emissions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Design and Operation of GE Aeroderivative Gas Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Design Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Fuels. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Operating Conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Ratings Flexibility . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Performance Deterioration and Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16 Maintenance Features . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 Advances in Aircraft Engine Technology. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18 List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
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GE Aeroderivative Gas Turbines - Design and Operating Features Abstract Aeroderivative gas turbines possess certain technical features inherent in their design heritage which offer operational and economic advantages to the end user. This paper presents an overall description of GE's current LM series of aeroderivative gas turbines with power output ranging from 13 to 47 MW. It discusses operational and economic considerations resulting from GE’s aeroderivative gas turbine design philosophies, and the value of these considerations in a customer’s gas turbine selection process. GE's total research and development budget for aircraft engine technology is approximately one billion dollars a year. Today’s entire GE gas turbine product line continues to benefit from this constant infusion research and development funding. Advances are constantly being made which improve GE’s gas turbine benefits to the customer.
Introduction Headquartered in Cincinnati, OH, GE’s Industrial Aeroderivative Gas Turbine Division (GE-IAD) manufactures aeroderivative gas turbines for industrial and marine applications. GE Power Systems sells and services the current
gas turbine products, which include the LM1600, LM2500, LM2500+ and LM6000. In addition, the LM2000 is offered as an integrated packaged product including an LM2500 gas turbine at reduced rating. Figure 1 presents the performance characteristics for power generation applications, while Figure 2 presents the product line’s performance characteristics for mechanical drive applications. GE’s aeroderivative industrial products are produced in two configurations: ■ Gas turbine, made up of a GE-supplied gas generator and power turbine ■ Gas generator, which may be matched to an OEM-supplied power turbine. These turbines are utilized in simple cycle, STIG™ (Steam Injected Gas Turbine) applications for power enhancement, or integrated into cogeneration or combined-cycle arrangements. GE also produces a variety of enginemounted, emissions control technologies, described in Figure 3.
Selection of Aeroderivative Engines Prior to commencing production of a new aeroderivative gas turbine based on the current
GE INDUSTRIAL AERODERIVATIVE GAS TURBINE PERFORMANCE CHARACTERISTICS GENERATOR DRIVE GAS TURBINE RATINGS MODEL LM1600PA LM2000 LM2500PE LM2500PK LM2500PV LM6000PC
LM6000PD
OUTPUT HEAT RATE EXHAUST FLOW kWe Btu/kWhr kJ/kWhr lb/s kg/s 13750 9624 10153 103 46.7 13750 9692 10225 103 46.7 18000 9377 9892 139 63 22800 9273 9783 152 69 22800 9349 9863 152 69 30700 8815 9300 192 87.2 29600 8925 9415 189 85.8 30240 8598 9071 186 84.3 28850 8748 9229 182 82.5 43315 8198 8648 277 126 42111 8293 8748 276 125 42665 8323 8779 277 126 41479 8419 8881 276 125 42227 8246 8698 275 125 41505 8331 8787 273 124 41594 8372 8830 275 125 40882 8458 8921 273 124
FUEL G D G G D G D G D G D G D G D G D
EXHAUST TEMP. deg F deg C 910 488 928 498 886 474 974 523 994 534 959 515 965 518 931 499 941 505 845 451 851 455 845 451 851 455 841 449 854 457 841 449 854 457
FREQUENCY Hz 50/60 50/60 60 60 60 50/60 50/60 60 60 60 60 50 50 60 60 50 50
Figure 1. GE aeroderivative product line: generator drive gas turbine performance characteristics GE Power Systems GER-3695E (10/00) ■
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GE Aeroderivative Gas Turbines - Design and Operating Features
GE INDUSTRIAL AERODERIVATIVE GAS TURBINE PERFORMANCE CHARACTERISTICS MECHANICAL DRIVE GAS TURBINE RATINGS* OUTPUT HEAT RATE EXHAUST FLOW FUEL sHP kWs Btu/HPhr kJ/kWhr lb/s kg/s G 19200 14320 6892 9750 103 46.7 D 19200 14320 6941 9820 103 46.7 LM2500PE G 31200 23270 6777 9587 152 69 D 31200 23270 6832 9665 152 69 LM2500PK G 42000 31320 6442 9114 192 87.2 D 40500 30200 6522 9227 189 85.8 LM2500PV G 42000 31320 6189 8756 186 84.3 D 40100 29900 6297 8909 182 82.5 LM6000PC G 58932 43946 6002 8490 277 126 D 56937 42458 6095 8621 276 125 LM6000PD G 57783 43089 6026 8524 275 125 D 56795 42352 6088 8611 273 124 *ISO (15C, 60% RH, SEA LEVEL, NO LOSSES), BASE LOAD, AVERAGE NEW ENGINE MODEL LM1600PA
EXHAUST TEMP. deg F deg C 910 488 928 498 974 523 994 534 959 515 965 518 931 499 941 505 845 451 851 455 841 449 854 457
Figure 2. GE aeroderivative product line: mechanical drive gas turbine performance characteristics
GAS MODEL GENERATOR LM1600 X LM2000 X LM2500 X LM2500+ X LM6000 X
GAS TURBINE X X X X
SIMPLE CYCLE X X X X X
COMBINED CYCLE X X X X X
STIG X X X
ENGINE MOUNTED NOx ABATEMENT METHODS WATER STEAM DLE INJECTION INJECTION X X X X X X X X X X X X X X X
Figure 3. GE aeroderivative product line: available equipment arrangements line of aircraft engines, GE considers the following factors: ■ Market forecast for marine and industrial engines
cost as low as possible, the aircraft engine chosen as the basis for this line must be convertible from aircraft to marine and industrial usage: ■ With very few changes to its original design
■ Projected performance and price competitiveness of the new line of aeroderivative engines
■ Using parts which are mass-produced for the aircraft application.
■ Degree of difficulty involved in converting the aircraft engines design into the new, aeroderivative configuration. The last point is extremely important. In order to keep a new aeroderivative product’s overall
QUANTITY LM1600 (F404) LM2500 (TF39/CF6-6) LM6000 (CF6-80C2)
Figure 4 shows the operating hours accrued for each of the GE parent engines in flight applications and their derivative engines in industrial and marine service. For example, the LM2500 and its parent aircraft engine have over 63 million hours of operating experience and have
AIRCRAFT OPERATING HOURS
AERODERIVATIVE QUANTITY OPERATING HOURS
3400
7,000,000
146
3,500,000
1130
32,300,000
1767
31,200,000
2806
58,700,000
300
3,200,000
Data as of February, 2000
Figure 4. Aircraft and aeroderivative engine operating experience as of February 2000
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GE Aeroderivative Gas Turbines - Design and Operating Features demonstrated excellent reliability. All GE AeroDerivative engines benefit from this combined experience. The following sections will introduce and summarize the key characteristics of each of the individual LM model gas turbines. Configuration terminology and arrangement options are defined in Figure 5.
compressor. The low-pressure rotor consists of the low-pressure turbine (LPT), which drives the low-pressure compressor (LPC) via a concentric drive shaft through the high-pressure rotor. The high-pressure rotor is formed by the high-pressure turbine driving the high-pressure compressor (HPC). The LM2000, LM2500 and LM2500+ are single-rotor machines that have
Fuel
Combustor
Inlet LPC
Exhaust H P T
HPC
Load
L P T
PT Load
Variable Stators Variable Bleed Variable IGV
Core Engine
Figure 5. Gas turbine terminology and arrangement The following features are common to all LM model gas turbines: ■ A core engine (compressor, combustor, and turbine) ■ Variable-geometry for inlet guide and stator vanes ■ Coated combustor dome and liner ■ Air-cooled, coated, high-pressure turbine (HPT) blading ■ Uncooled power turbine blading ■ Fully tip-shrouded power turbine rotor blading ■ Engine-mounted accessory gearbox driven by a radial drive shaft. The LM1600 and LM6000 are dual-rotor units. A rotor consists of a turbine, drive shaft, and
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one axial-flow compressor, and an aerodynamically coupled power turbine. The LM1600, and LM6000 employ electronically operated, variable-bleed valves arranged in the flow passage between the low- and highpressure compressors to match the LPC discharge airflow to the HPC. These valves are fully open at idle and progressively close to zero bleed at approximately 50% power. The position of these variable-geometry controls is a function of the LP rotor speed, HP rotor speed and inlet air temperature. Aeroderivative engines incorporate variable geometry in the form of compressor inlet guide vanes that direct air at the optimum flow angle, and variable stator vanes to ensure ease of starting and smooth, efficient operation over the entire engine operating range.
3
GE Aeroderivative Gas Turbines - Design and Operating Features Aeroderivative turbines are available with two types of annular combustors. Similar to those used in flight applications, the single annular combustor features a through-flow, venturi swirler to provide a uniform exit temperature profile and distribution. This combustor configuration features individually replaceable fuel nozzles, a full-machined-ring liner for long life, and an yttrium-stabilized zirconium thermal barrier coating to improve hot corrosive resistance. In 1995, a dry, low emissions (DLE) combustor was introduced to achieve low emissions without the use of fuel diluents, such as water or steam. The LM1600, LM2000, LM2500, and LM2500+ all include an aerodynamically coupled, highefficiency power turbine. All power turbines are fully tip-shrouded. The LM1600 PT and LM2500+ High Speed Power Turbine (HSPT) feature a cantilever-supported rotor. The power turbine is attached to the gas generator by a transition duct that also serves to direct the exhaust gases from the gas generator into the stage one turbine nozzles. Output power is transmitted to the load by means of a coupling adapter on the aft end of the power turbine rotor shaft. Turbine rotation is clockwise when viewed from the coupling adapter looking forward. Power turbines are designed for frequent
thermal cycling and can operate at constant speed for generator drive applications, and over a cubic load curve for mechanical drive applications. The LM6000 power turbine drives both the LPC and the load device. This feature facilitates driving the load from either the front or aft end of the gas turbine shaft. All of the models have an engine-mounted, accessory drive gearbox for starting the unit and supplying power for critical accessories. Power is extracted through a radial drive shaft at the forward end of the compressor. Drive pads are provided for accessories, including the lube and scavenge pump, the starter, the variable-geometry control, and the liquid fuel pump.
LM1600 Gas Turbine The LM1600 gas turbine consists of a dual-rotor gas generator and an aerodynamically coupled power turbine. The LM1600 is shown in Figure 6, and consists of a three-stage, low-pressure compressor; a seven-stage, variable-geometry, high-pressure compressor; an annular combustor with 18 individually replaceable fuel nozzles; a single-stage, high-pressure turbine; and a single-stage, low-pressure turbine. The gas generator operates at a compression ratio of 22:1.
Figure 6. LM1600 gas turbine
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GE Aeroderivative Gas Turbines - Design and Operating Features The LM1600 incorporates variable-geometry in its LPC inlet guide vanes and HPC stator vanes. Four electronically operated, variable-geometry bleed valves match the discharge airflow between the LPC and HPC. In industrial applications, the nozzles and blades of both the HPT and LPT are air-cooled and coated with “CODEP,” a nickel-aluminide-based coating, to improve resistance to oxidation, erosion, and corrosion. For marine applications, HPT nozzles are coated with a thermal barrier coating, LPT nozzles are coated with CODEP and the blades of both the HPT and LPT are coated with PBC22. The two-stage power turbine operates at a constant speed of 7,000 rpm over the engine operating range for generator drive applications, and over a cubic load curve for mechanical drive applications.
high-pressure turbine, the nozzles and blades are air-cooled. For industrial applications, the nozzles are coated with CODEP and the blades are coated with platinum-aluminide to improve resistance to erosion, corrosion and oxidation.
LM2500 Gas Turbine
The first LM2500+, a design based on the very successful heritage of the LM2500 gas turbine, rolled off the production line in December 1996. The LM2500+ was originally rated at 27.6 MW, for a nominal 37.5% thermal efficiency at ISO, no losses and 60 Hz. Since that time, its rating has continually increased to reach its current level of 31.3 MW and 41% thermal efficiency. An isometric view of the LM2500+ gas turbine, including the single annular combustor (SAC), is shown in Figure 8.
The LM2500 gas turbine consists of a singlerotor gas turbine and an aerodynamically coupled power turbine. The LM2500 (Figure 7) consists of a six-stage, axial-flow design compressor, an annular combustor with 30 individually replaceable fuel nozzles, a two-stage, highpressure turbine, and a six-stage, high-efficiency power turbine. The gas generator operates at a compression ratio of 18:1. The inlet guide vanes and the first six-stages of stator vanes are variable. In both stages of the
The six-stage power turbine operates at a nominal speed of 3,600 rpm, making it ideal for 60 Hz generating service. Alternatively, it can be used in 50 Hz service without the need to add a speed reduction gear. The LM2500 can also operate efficiently over a cubic load curve for mechanical drive applications. The LM2500 gas turbine is also offered at an 18MW ISO rating as an integrated packaged product called the LM2000 with an extended hot-section life for the gas turbine.
LM2500+ Gas Turbine
The LM2500+ has a revised and upgraded com-
Figure 7. LM2500 gas turbine GE Power Systems GER-3695E (10/00) ■
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GE Aeroderivative Gas Turbines - Design and Operating Features
Figure 8. LM2500+ gas turbine pressor section with an added zero stage for increased flow and pressure ratio, and revised materials and design in the HP and power turbines. The gas generator operates at a compression ratio of 22:1. The inlet end of the LM2500+ design is approximately 13 inches/330 mm longer than the current LM2500, allowing for retrofit with only slight inlet plenum modifications. In addition to the hanging support found on the LM2500, the front frame of the LM2500+ has been modified to provide additional mount link pads on the side. This allows engine mounting on supports in the base skid. The LM2500+ is offered with two types of power turbines: a six-stage, low speed model, with a nominal speed of 3600 rpm; or a two-stage high speed power turbine (HSPT). The LM2500+ six-stage power turbine displays several subtle improvements over the L2500 model from which it was derived: ■ Flow function was increased by 9%, in order to match that of the HPC. ■ Stage 1, 5 and 6 blades as well as the stage 1 nozzle were redesigned. ■ Disc sizing was increased for all of the stages. ■ Spline/shaft torque capability was increased.
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■ Casing isolation from flow path gases by use of liners stages 1-3. The LM2500+ two-stage HSPT has a design speed of 6100 rpm, with an operating speed range of 3050 to 6400 rpm. It is sold for mechanical drive and other applications where continuous shaft output speeds of 6400 rpm are desirable. When the HSPT is used at 6,100 rpm to drive an electric generator through a speed reduction gear, it provides one of the best options available for power generation applications at 50 Hz. Both the six-stage and two-stage power turbine options can be operated over a cubic load curve for mechanical drive applications. In 1998, a version of LM2500+ was introduced to commercial marine application. The only differences between the marine and industrial versions to address the harsher environment are as follows: ■ Stage 1 HPT nozzle coating ■ Stage 1 HPT shroud material and coating.
LM6000 Gas Turbine The LM6000 turbine (Figure 9) consists of a fivestage LPC; a 14-stage HPC, which includes six variable-geometry stages; an annular combustor with 30 individually replaceable fuel nozzles; a
6
GE Aeroderivative Gas Turbines - Design and Operating Features
Figure 9. LM6000 gas turbine two-stage, air-cooled HPT; and a five-stage LPT. The overall compression ratio is 29:1. The LM6000 does not have an aerodynamically coupled power turbine.
ator only, and adds a unique power turbine. By maintaining high commonality, the LM6000 offers reduced parts cost and demonstrated reliability.
The LM6000 is a dual-rotor, “direct drive” gas turbine, derived from the CF6-80C2, highbypass, turbofan aircraft engine. The LM6000 takes advantage of its parent aircraft engine’s low-pressure rotor operating speed of approximately 3,600 rpm. The low-pressure rotor is the driven-equipment driver, providing for direct coupling of the gas turbine low-pressure system to the load, as well as the option of either cold end or hot end drive arrangements.
The status of the LM6000 program, as of February 2000, includes: ■ 300 units produced since introduction in 1991 ■ 208 units in commercial operation ■ First DLE combustor in commercial operation producing less than 25 ppm NOx - 1995 ■ High time engine =50,829 hours
The LM6000 maintains an extraordinarily high degree of commonality with its parent aircraft engine, as illustrated in Figure 10. This is unlike the conventional aeroderivative approach which maintains commonality in the gas gener-
■ 12 month rolling average engine availability = 96.8% ■ Engine reliability = 98.8% ■ Exceeded 3.1 million operating hours
Traditional Approach Common
HP Compressor
Unique
HP Turbine
LP Compressor
Generator or Compressor LP Turbine
Power Turbine
Common
LM6000 Approach
HP Compressor
Generator or Compressor LP Compressor
HP Turbine
Alternate Generator or Compressor LP Turbine
Figure 10. LM6000 concept
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GE Aeroderivative Gas Turbines - Design and Operating Features ■ Variable speed mechanical drive capability – 1998 ■ Dual fuel DLE in commercial operation – 1998 ■ LM6000 PC Sprint™ System in commercial operation - 1998 In mid-1995, GE committed to a major product improvement initiative for the LM6000. New models designated as LM6000 PC/PD were first produced in 1997, and included a significant increase in power output (to more than 43 MW) and thermal efficiency (to more than 42%); dual fuel DLE; and other improvements to further enhance product reliability.
LM6000 Sprint™ System Unlike most gas turbines, the LM6000 is primarily controlled by the compressor discharge temperature (T3) in lieu of the turbine inlet temperature. Some of the compressor discharge air is then used to cool HPT components. SPRINT™ (Spray Inter-cooled Turbine) reduces compressor discharge temperature, thereby allowing advancement of the throttle to significantly enhance power by 12% at ISO, and greater than 30% at 90°F (32°C) ambient temperatures. The LM6000 Sprint™ System is composed of
Air Manifold
Water Metering Valve Orifice
23 Spray Nozzles
atomized water injection at both LPC and HPC inlet plenums. This is accomplished by using a high-pressure compressor, eighth-stage bleed air to feed two air manifolds, water-injection manifolds, and sets of spray nozzles, where the water droplets are sufficiently atomized before injection at both LPC and HPC inlet plenums. Figure 11 displays a cross-section of the LM6000 Sprint™ System. Figure 12 provides the Sprint™ Gas Turbine expected performance enhancement, relative to the LM6000-PC. Since June 1998, when the first two Sprint™units began commercial operation, ten other installations have gone into service. As of February 2000, LM6000 Sprint™ Gas Turbine (Figure 13) operating experience exceeds 20,000 hours. Sprint™ System conversion kits for LM6000 PC models are now available for those considering a potential retrofit.
STIG™ Systems STIG™ (Steam Injected Gas Turbine) systems operate with an enhanced cycle, which uses large volumes of steam to increase power and improve efficiency. See Figure 14 for STIG™ system performance enhancements at ISO base load conditions. In the STIG™ cycle, steam is typically produced in a heat recovery steam generator (HRSG) and
Air Manifold
24 Spray Nozzles
Water Manifold 8th Stage Bleed Air Piping
Air atomized spray - Engine supplied air - Droplet diameter less than 20 microns
Figure 11. LM6000 Sprint™ flow cross section GE Power Systems GER-3695E (10/00) ■
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GE Aeroderivative Gas Turbines - Design and Operating Features
55000
Shaft Power kW
50000
12%
45000
SPRINT
TM
40000
30% 35000
Base LM6000-PC
30000
Sea level, 60% Rel Hum, 5" Inlet/10" Exhaust losses Natural Gas with Water Injection to 25 ppm
25000 40
50
60
70
80
90
100
Engine Inlet Temperature deg F
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)
LM1600 LM2000 LM2500
13.3 18 22.2
35 35 35
STIG Rating (MWe)
%Thermal Efficiency (LHV)
16 23.2 27.4
37 39 39
*3% margin on Eff. Included
Figure 14. STIG™ system performance enhancement – generator drive gas turbine performance is then injected into the gas turbine. The STIG™ system offers a fully flexible operating cycle, since the amount of steam injected can vary with load requirements and steam availability. Also, steam can be injected with the gas turbine operating from 50% power to full load. A typical STIG™ cycle is shown in Figure 15. The
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installation includes a steam-injected gas turbine, coupled with an HRSG which can be supplementally fired. The control system regulates the amount of steam sent to process and, typically, the excess steam is available for injection. Figure 16 shows the steam injection capability for the various models.
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GE Aeroderivative Gas Turbines - Design and Operating Features
Exhaust To process H 2O Steam
Fuel
Gas turbine
HRSG
~
Air
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
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GE Aeroderivative Gas Turbines - Design and Operating Features The site at which steam is injected into the gas turbine differs according to the design of the particular model. For instance, in both the LM1600, LM2000 and LM2500, steam is injected into the high-pressure section via the combustor fuel nozzles and compressor discharge plenum. See Figure 17 for the location of steam injection ports on an LM2500 gas turbine. A STIG™ system is not planned for the LM6000, beyond that steam injected through the fuel nozzles for NOx abatement.
Emissions NOx emissions from the LM1600, LM2000, LM2500, LM2500+ and LM6000 can be reduced using on-engine water or steam injection arrangements, or by the incorporation of DLE combustion system hardware. The introduction of steam or water into the combustion system: ■ Reduces NOx production rate ■ Impacts the gas turbine performance ■ Increases other emissions, such as CO and UHC ■ Increases combustion system dynamic activity which impacts flame stability ■ The last item results in a practical limitation on the amount of steam or water which can be used for NOx suppression. Figure 18 lists the unabated NOx emission levels for the GE Aeroderivative gas turbines when
ISO - Base Load - SAC Combustor Unabated NOx Emissions (ppmvd ref.15% O2) Model Natural Gas Distillate Oil LM1600 127 209 LM2000 129 240 LM2500 179 316 LM2500+ 229 346 LM6000 205 403
Figure 18. GE aeroderivative gas turbine unabated NOx emissions burning either natural gas or distillate oil. Depending on the applicable federal, state, country and local regulations, it may be necessary to reduce the unabated NOx emissions. Figure 19 shows GE’s current, guaranteed minimum NOx emission levels for various control options. With steam or water-injection and single fuel natural gas, the LM2500 can guarantee NOx emissions as low as 15 ppm. For applications requiring even lower NOx levels, other means, such as selective catalytic reduction (SCR), must be used. In 1990, GE launched a Dry Low Emissions Combustor Development program for its aeroderivative gas turbines. A premixed combustor configuration (Figure 20), was chosen to achieve uniform mixing of fuel and air. This premixing produces a reduced heating value gas, which will then burn at lower flame temperatures required to achieve low NOx levels. Increased combustor dome volume is used to increase combustor residence time for complete reaction of CO and UHC. DLE combustors feature replaceable premixer/nozzles and multiple burner modes to match low demand.
Figure 19. Minimum NOx emission guarantee levels – wet and dry emissions control options GE Power Systems GER-3695E (10/00) ■
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GE Aeroderivative Gas Turbines - Design and Operating Features
Combustion Liner Heat Shield Premixer
Figure 20. DLE combustor In order to achieve low emissions throughout the operating range, fuel is staged through the use of multiple annuli. The LM1600 uses a double annular configuration, while all other models use a triple annular construction. Factory testing of components and engine assembly on an LM6000 gas turbine was completed in 1994. These tests demonstrated less than 15 ppm NOx, 10 ppm CO and 2 ppm UHC at a firing temperature of 2350°F/1288°C at rated power of 41 MW. The Ghent power station in Belgium became the first commercial operator to use the LM6000 fitted with the new DLE combustor system. A milestone was reached in January 1995 when the station achieved full power at 43 MW with low emissions of 16 ppm NOx, 6 ppm CO and 1 ppm UHC. As of today, the high time LM6000 engine has accumulated over 34,000 hours. By the end of 1999, there were 3 LM1600, 58 LM2500, 27 LM2500+, and 30 LM6000 gas turbines equipped with the DLE combustion system in service worldwide. Today, GE continues its DLE technology develGE Power Systems GER-3695E (10/00) ■
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opment on the Dual Fuel DLE front. Completely dry operation has been achieved on gas and distillate fuels on two LM6000 engines in the United Kingdom. Operating on liquid fuel, NOx and CO emission levels have been less than 125 ppm and 25 ppm, respectively. GE continues to do research on reducing liquid fuel to NOx levels below 65 ppm , with the goal of achieving this by the end of the year 2000. By early 2001, GE plans to release a Dual Fuel DLE system on the LM2000, LM2500 and LM2500+ gas turbines.
Design and Operation of GE Aeroderivative Gas Turbines Design Features GE Aeroderivative gas turbines combine high temperature technology and high pressure ratios with the latest metallurgy to achieve simple-cycle efficiencies above 40%, the highest available in the industry. It is essential to GE’s aeroderivative design philosophy that an industrial or marine aeroderivative gas turbine retain the highest possible degree of commonality with the flight engine 12
GE Aeroderivative Gas Turbines - Design and Operating Features on which the aeroderivative is based. This results in a unique and highly successful approach to on-site preventive and corrective maintenance, including partial disassembly of the engine and replacement of components such as blades, vanes and bearings. On-site component removal and replacement can be accomplished in less than 100 manhours. Complete gas generators and gas turbines can be made available within 72 hours (guaranteed), with the complete unit replaced and back on-line within 48 hours. The hot-section repair interval for the aeroderivative meets the industrial demand of 25,000 hours on natural gas. The LM engines have been adapted to meet the important industrial standards of ASME, API, NEC, ISO9001, etc., consistent with their aircraft engine parentage. Other advantages related to the evolution from the flight application are the technical requirements of reduced size and low weight. The aeroderivatives’ rotor speeds (between 3,000 and 16,500 rpm) and casing pressure (20 to 30 atmospheres) may appear high when compared with other types of gas turbines. However, the high strength materials specified for the aircraft engine are capable of handling these pressures and rotor speeds with significant stress margins. For example, cast Inconel 718, commonly used for aircraft engine casing material, has a yield strength of 104 ksi (717 kN/m2) at 1200°F/649°C, while cast iron commonly used in other types of gas turbine casings has a yield strength of 40 ksi at 650°F (276 kN/m2 at 343°C). The aeroderivative design, with its low supported-weight rotors – for example, the LM2500 HP rotor weighs 971 lbs/441 kg – incorporates roller bearings throughout. These do not require the large lube oil reservoirs, coolers and pumps or the pre-and post-lube cycle associated GE Power Systems GER-3695E (10/00) ■
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with other bearing designs. Roller bearings have proven to be extremely rugged and have demonstrated excellent life in industrial service. Although bearings generally provide reliable service for over 100,000 hours, in practice, it is advisable to replace them when they are exposed during major repairs, or, at an estimated 50,000 hours for gas generators and 100,000 hours for power turbines. The high-efficiency aeroderivative is an excellent choice for simple-cycle power generation and cyclic applications such as peaking power, which parallels aircraft engine use. With start times in the one-minute range, the aeroderivative is ideal for emergency power applications of any sort. With its inherently low rotor inertias, and the variety of pneumatic and hydraulic starting options available, the GE Aeroderivative engine has excellent “black start capability,” meaning the ability to bring a “cold iron” machine online when a source of outside electrical power is unavailable. An additional benefit of having low rotor inertias is that starting torques and power requirements are relatively low, which in turn reduces the size and installed cost of either the pneumatic media storage system or the diesel or gasoline engine driven hydraulic systems. For example, the LM2500 starting torque is less than 750 ft-lbs (1,017 N-m), and its air consumption during a typical start cycle is between 2,000 and 2,600 SCFM (56,600 and 73,600 l/min).
Fuels Natural gas and distillate oil are the fuels most frequently utilized by aeroderivatives. These engines can burn gaseous fuels with heating values as low as 6,500 Btu/lb (15,120 kJ/kg). Recently, an LM6000 with a single, annular combustor was modified to operate on medium Btu (8,000-8,600 Btu/lb ~ 18,600-20,000 kJ/kg) 13
GE Aeroderivative Gas Turbines - Design and Operating Features fuel. It demonstrated that it could operate with lower NOx emissions without requiring flamequenching diluents such as water or steam. As part of GE’s Research and Development Program, an LM2500 combustor, modified to utilize low heating value biomass fuel, has been operated in a full annular configuration at atmospheric pressure. A sector of the annular combustor design was then tested at gas turbine operating pressures. Ignition, operability, gas temperature radial profiles, temperature variations and fuel switching were in acceptable ranges when operated on simulated biomass fuel. Low NOx is a by-product since low heating value fuel is essentially the same as operating in a lean premix mode like the DLE combustor.
Operating Conditions The climatological and environmental operating conditions for aeroderivatives are the same as for other types of gas turbines. Inlet filtration is necessary for gas turbines located in areas where sand, salt and other airborne contaminants may be present. At the extreme ends of the ambient temperature spectrum, the aeroderivative exhibits a less attractive lapse rate (power reduction at offambient temperatures) than other types of gas turbines. However, the LM aeroderivative does have a “constant power” performance option which can be applied in areas where the extremes are encountered for extended periods of time.
is an exception; at its base rating the hot-section repair interval is approximately 50,000 hours. Aeroderivatives utilize the same basic hardware as aircraft engines, which are designed to operate reliably at firing temperatures much higher than the corresponding aeroderivative base rating temperatures. By taking advantage of the extensively air cooled hot-gas-path components typically found in aircraft engines, aeroderivative models can operate at higher temperatures and power levels than their base rating. The LM2500 will be used as an example, with the other LM products having similar characteristics. Figure 21 illustrates the full capability of the LM2500 as a function of ambient temperature. In the ambient temperature region above 55°F/13°C, the LM2500’s maximum capability is limited by the maximum allowable temperature at the power turbine inlet. Figure 21 also shows the availability of additional power above the ISO base rating of the unit. In order to achieve this increased power, operation at increased cycle temperature is necessary. As with any gas turbine, the hot-gas-path section repair interval (HSRI) of the LM2500 is related to the cycle temperature. Figure 22 presents the relationship between output power, power tur-
Ratings Flexibility All turbines, including aeroderivatives, have “base ratings”. In the case of GE’s aeroderivatives, when natural gas is used as the fuel and the engine is operated at the base power turbine inlet temperature control setting, its base rating corresponds to a hot-section repair interval of approximately 25,000 hours. The LM2000
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Figure 21. LM2500 maximum power capability
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GE Aeroderivative Gas Turbines - Design and Operating Features where constant power, rather than variable power, is required over a specific ambient temperature range. This figure clearly shows that the LM2500 is capable of producing this power over the full ambient temperature range. However, the estimated hot-section repair interval for this type of operation is not apparent in Figure 23, since when operating during high ambient temperature conditions, the power turbine inlet temperature corresponds to shorter intervals than when operating at lower ambient temperatures. Figure 22. Effect of increased power rating on LM2500 hot-section repair interval bine inlet temperature and estimated time between hot-section repairs. The ISO rating temperature corresponds to the curve for an estimated 25,000 hours between hot-section repairs when burning natural gas fuel. Figure 22 also shows that power is available for applications requiring more power than is available when limiting the temperature to that associated with the 25,000 hours curve. However, those LM2500s utilizing this additional power will require more frequent hot-section repair intervals. The LM2500, like any gas turbine operating at a constant cycle temperature, has more power available at lower ambient temperatures than at higher ambient temperatures. This is shown in Figure 22 by the sloping lines of constant hotsection repair intervals (constant power turbine inlet temperature). There are, however, many applications in the industrial market that cannot use all of the power that is available at the lower ambient temperatures. In these cases, the operating characteristic of “constant power,” regardless of the ambient temperature, is more consistent with the actual requirements of the installation. Figure 23 shows an example of an application
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An ambient temperature profile for the partic-
Figure 23. LM2500 constant power rating ular site is needed to determine the duration of operation at the various power turbine inlet temperatures. Once this ambient temperature information is available, an estimate of the hotsection repair interval for this power level and particular site can be made. If the operator does not provide duty cycle estimates, it is generally assumed that a unit operates continuously for 8,600 hours per year for any given site. To carry this example further, assume the ambient temperature profile for this particular site results in an estimated hot-section repair interval of 25,000 hours for this power level. Comparison of operation at constant temperature and constant power level is shown in Figure 24. Since both curves result in an estimated hot-
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GE Aeroderivative Gas Turbines - Design and Operating Features section repair interval of 25,000 hours, potential power at low ambient temperatures has been traded for more potential power at higher ambient temperatures. Again, for an application where the required power is independent of the ambient temperature, a constant power rating results in trading off the higher power at low ambient temperatures for extended constant power at higher ambient temperatures.
severity of the local environment and operational profile of the site determine the frequency of washing.
Figure 24. LM2500 constant PT inlet temperature and constant power operation
Figure 25. LM2500 field trends – power and heat rate deterioration
Performance Deterioration and Recovery Deterioration of performance in GE Aeroderivative (LM) industrial gas turbines has proven to be consistent over various engine lines and applications. Total performance loss is attributable to a combination of “recoverable” (by washing) and “non-recoverable” (recoverable only by component replacement or repair) losses. Recoverable performance loss is caused by fouling of airfoil surfaces by airborne contaminants. The magnitude of recoverable performance loss is determined by site environment and character of operations. Generally, compressor fouling is the predominant cause of this type of loss. Periodic washing of the gas turbine, either by on-line wash or crank-soak wash procedures, will recover 98% to 100% of these losses. The
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Studies of representative engines in various applications show a predictable, nonrecoverable performance loss over long-term use. Deterioration experience is summarized in Figure 25 for power and heat rate for an LM aeroderivative gas turbine operating on natural gas fuel.
This figure illustrates long-term, non-recoverable deterioration, not losses recoverable by washing. Power deterioration at the 25,000hour operating point is on the order of 4%; heat rate is within 1% of “new and clean” guarantee. These deterioration patterns are referenced to the “new and clean” base rating guarantee, although actual as-shipped engine performance is generally better than the guarantee level. Generally, HPT components are replaced at 25,000 hour intervals for reasons of blade life and performance restoration. The result of replacement of the HPT components is 60% or more restoration of the non-recoverable performance loss, depending on the extent of work accomplished. Over 80% recovery can be achieved if limited high-pressure compressor
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GE Aeroderivative Gas Turbines - Design and Operating Features repairs are performed at the same time. General overhauls at about 50,000-hour intervals entail more comprehensive component restorations throughout the engine, and may result in nearly 100% restoration of the nonrecoverable performance. When using liquid fuel, which is more corrosive than natural gas, a similar but more rapid pattern of deterioration occurs, resulting in approximately the same 3% to 5% level at the typical 12,500-hour liquid-fuel HPT repair interval.
Maintenance Features In an operator’s life cycle cost equation, the most important factors are engine availability and maintenance cost. To enhance these considerations in regard to its aeroderivative engines, GE has invested considerable effort in developing features to optimize the result of this equation. GE’s aeroderivatives’ unique designs allow for maintenance plans with the following features: ■ Borescope inspection capability. This feature allows on-station, internal inspections to determine the condition of internal components, thereby increasing the interval between scheduled, periodic removals of engines. When the condition of the internal components of the affected module has deteriorated to such an extent that continued operation is not practical, the maintenance program calls for exchange of that module. ■ Modular design. Using their flight heritage to maximum advantage, aeroderivative engines are designed to allow for on-site, rapid exchange of major modules within the gas turbine. The elapsed time for a typical HPT
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and combustion module replacement is 72 hours. This exchange allows the gas turbine to operate for an additional 25,000 hours. ■ Compactness. The GE AeroDerivative engines have inherited modest dimensions and lightweight construction that generally allows for on-site replacement in less than 48 hours. ■ Monitoring and Diagnostics Services are made available by establishing direct phone connections from the control system at the customers' sites to computers in GE's LM monitoring center. These services link the expertise at the factory with the operations in the field to improve availability, reliability, operating performance, and maintenance effectiveness. Monitoring of key parameters by factory experts allows early diagnosis of equipment problems and avoidance of expensive secondary damage. The ability for service engineers to view real-time operations in many cases results in accelerated troubleshooting without requiring a site visit (Figure 26).
Figure 26. Monitoring and Diagnostic services: GE engineer remotely monitoring a unit 17
GE Aeroderivative Gas Turbines - Design and Operating Features The integration of all of the features noted above enables the operator to monitor the condition of the engine, maximize uptime, and conduct quick maintenance action. To learn in greater depth about the maintenance of the GE Aeroderivative gas turbines, refer to GER-3694, “Aeroderivative Gas Turbine Operating and Maintenance Considerations.”
Advances in Aircraft Engine Technology GE Aircraft Engines invests over $1 billion annually in research and development, much of which is directly applicable to all of GE’s aeroderivative gas turbines. In particular, consistent and significant improvement has been made in design methodologies, advanced materials and high-temperature technologies. Areas of current focus are presented in Figure 27. As these technological advances are applied to industrial uses, GE’s aeroderivative engines benefit from continual enhancement to attain greater power, efficiency, reliability, maintainability and reduced operating costs. In 1993, GE Aircraft Engines began testing the new, ultra-high thrust, GE90, high bypass fan engine (Figure 28). The thrust level demonstrated at initial certification was 87,400 pounds (376,764 N), and since then, has reached a thrust level of 110,000 pounds. •
Components – – – – – – – – – – – – –
•
– –
High temperature Alloys • N5. N6, R88DT, MX4 Intermetallic Alloys • NiAl, TiAl, Orthorhombic Ti Structural Ti Castings
Non-metals –
•
Advanced Materials
•
Advanced Processes
– – – – – – – – – – –
•
Metals –
•
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
Polymeric Composites • PMR 15 Case • Composite Fan Blade
– High Temperature Polymerics (700oF/371oC) – Thermal Barrier Coatings
Metal Matrix Composites (MMC) Ceramic Matrix Composites 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
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Figure 28. GE90 high-bypass fan engine on Boeing 777 The advanced technologies proven in the GE90 engine include wide-chord composite fan blades, short durable 10-stage HPC, composite compressor blades and nacelles, and a dualdome annular combustor. These attributes contribute to delivering economic advantages of low fuel consumption, low noise and emissions, reliability of a mature engine, and growth capability to over 100,000 pounds thrust. In 1995, the GE90 engine entered commercial service on a Boeing 777 aircraft operated by British Airways. One year later, a growth version of this engine, rated at 90,000 pounds of thrust, was certified and delivered. By 2000, GE90 engines had realized a major landmark, having accumulated more than one million flight hours since entry into service. After logging one million flight hours, and fueled by strong market interest and customer commitments, the Boeing Company and GE introduced two new, longer range models, powered by the newly introduced, growth derivative GE90-115B engine.
Summary GE’s continued investment in R&D aircraft engine technology enables the LM series of gas turbines to maintain their leadership position in technology, performance, operational flexibility, and value to the customer. Offered in power output from 13 to 47 MW, and having the
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GE Aeroderivative Gas Turbines - Design and Operating Features ability to operate with a variety of fuels and emission control technologies, GE’s aeroderivative gas turbines have gained the widest acceptance in the industry, with total operating experience in excess of 41million hours. These turbines have been selected for a multitude of
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applications, from power generation to mechanical drive, for the exploration, production and transmission of oil and gas, as well as marine propulsion systems including transport, ferryboat, and cruise ship installations.
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GE Aeroderivative Gas Turbines - Design and Operating Features List of Figures Figure 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 6.
LM1600 gas turbine
Figure 7.
LM2500 gas turbine
Figure 8.
LM2500+ gas turbine
Figure 9.
LM6000 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
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Technology for Gas Turbines
GE CONTROL SYSTEM EVOLUTION
GE Control System Evolution
3.0
Technology for Gas Turbines
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. 2. 3. 4. 5. 6.
Fuel Regulator 1948 to 1970 Mechanical Controls 1954 to 1960 SPEEDTRONIC Mark I 1968 to 197 SPEEDTRONIC Mark II 1975 to 1982 SPEEDTRONIC Mark II with ITS* 1980 to 1984 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.
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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. 2. 3. 4.
Control Protection Sequencing Power Supply
The control subsystem is the predominant, and it must perform six basic functions: 1. 2. 3. 4. 5. 6.
Set start-up and normal fuel limits Control turbine acceleration Control turbine speed Limit internal turbine temperatures Control variable inlet guide vanes 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 startup control from limiting fuel via the minimum value gate.
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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. 2. 3. 4. 5.
Overtemperature Overspeed Loss of Flame Vibration Combustion monitor (not part of early protective requirements, but now is a standard)
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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.
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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.
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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.
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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 , , and which provide basic control, and a fourth called which provides communications. 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 controllers sees only one third of the exhaust thermocouples. receives temperature information from each controller, and 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 and , 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. GE Control System Evolution
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SPEEDTRONIC CONTROL SYSTEM FEATURE EVOLUTION
COMPONENTS
Mark I
Mark II
Mark IV
Discrete Transistors (few ICs) Meters
Max use of integrated circuits Meters
Microprocessors -(four) CRT Display*
Indicator Lights
Indicator Lights
CRT Display*
Annunciator
Annunciator
CRT Display*
Relay Sequential
Solid State Seq.
Software Seq.
Relay Output Dual/(Single) LVDT
Relay Output Dual/(Single) LVDT
Relay Output Dual LVDT
2 Coil Servovalve Exh.Thermocouples 12 Iron-Constantan
2 Coil Servovalve Exh.Thermocouples 12 Chromel-Alumel (13-17 w/"ITS") (depends on Model Series)
3 Coil Servovalve Exh.Thermocouples 13-24 Chromel-Alumel
Panel: 36x36x90 in.
Panel: 36x36x90 in. "ITS": 54x36x90 in
Panel: 54x36x90 in
Signal: 0(4)-20 units
Signal: 0(4)-20 units
Signal: 0-100% units
Fuel (VCE)
Fuel (VCE)
Fuel (FSR)
Inlet Guide Vanes 2nd Stg. Nozzle
Inlet Guide Vanes 2nd Stg. Nozzle
Inlet Guide Vanes 2nd Stg. Nozzle
Steam/Water Inject.
Steam/Water Inject.
Steam/Water Inject.
Start-up Temp.Suppr Monitoring
Start-up Temp.Track
Start-up Accel.Cont
Vibration
Vibration Combustion monitor Turbine Wheelspaces Water/Steam Inject.
Vibration Combustion monitor Turbine Wheelspaces Water/Steam Inject.
Control Functions
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Adjustments-Controls and Sequential Potentiometers, etc logic rewiring
Availability/ Reliability Very good
Potentiometers, etc logic rewiring
Software Constants Software Ladder Diagrams
Very good 'Redundancy by Association'
Excellent '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 startup 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. GE Control System Evolution
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This is achieved by distributing control functions among four microcomputers; three are identical control sections, and the fourth 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 , , & are called , 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 for communicator. It is in communication with the sections over three independent communication channels (3 pairs). In this way, a Áfailure in one section of is much less likely to cause damage to another control section than if , , & were allowed to communicate directly with one another. The communicator also interfaces with the operator through the membrane switches and CRT monitor. In the case of remote control, communicates with the remote computers. GE Control System Evolution
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Critical sensors are distributed to the 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 , , & . Each of these sections sends its values to , which calculates the median value, and sends a correction bias back to . Under normal conditions, the turbine will be controlled by the median of all the exhaust thermocouples. If there is some failure, each section of 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 . This avoids extra I/O (input/ output) and processing in , 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 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 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 . 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 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 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 and . The promptly call for a decrease in fuel, and together the are able to override the false signal caused by . 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
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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
08AUG83
14:05:22.72
Status "1"
Description 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.
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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) b) c) d) e)
A User Password identification code is required for entering The rate of change of constants is limited, if turbine is running The adjustment ranges of critical parameters are limited Servo calibration is permitted only in 'OFF' or 'CRANK' 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. GE Control System Evolution
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* 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 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. 2. 3. 4.
Selection of highly reliable components Redundancy by association Redundancy by duplication of components 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.
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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 GE Control System Evolution
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Technology for Gas Turbines
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 , , and ", 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 " monitors and initiates an alarm when there is a discrepancy between the controllers. This alarm is audible and is displayed on the CRT. Each controller , , and makes its own assessment of turbine operation. This is accomplished by distributing critical sensors between them, while monitors the signals seen by ,, and 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 onand off-line diagnostics to enhance field troubleshooting.
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Technology for Gas Turbines
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.
GE Control System Evolution
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SPEEDTRONIC™ MARK V GAS TURBINE CONTROL SYSTEM D. Johnson and R.W. Miller GE Drive Systems Salem, VA
T. Ashley GE Power Systems Schenectady, NY
INTRODUCTION
Dry Low NOx techniques, fuel staging and combustion mode are controlled by the Mark V system, which also monitors the process. Sequencing of the auxiliaries to allow fully automated startup, shutdown and cooldown are also handled by the Mark V Control System. Turbine protection against adverse operating situations and annunciation of abnormal conditions are incorporated into the basic system. The operator interface consists of a color graphic monitor and keyboard to provide feedback regarding current operating conditions. Input commands from the operator are entered using a cursor positioning device. An arm/execute sequence is used to prevent inadvertent turbine operation. Communication between the operator interface and the turbine control is through the Common Data Processor, or , to the three control processors called , and . The operator interface also handles communication functions with remote and external devices. An optional arrangement, using a redundant operator interface, is available for those applications where integrity of the external data link is considered essential to continued plant operations. SIFT technology protects against module failure and propagation of data errors. A panel mounted back-up operator display, directly connected to the control processors, allows continued gas turbine operation in the unlikely event of a failure of the primary operator interface or the module. Built-in diagnostics for troubleshooting purposes are extensive and include “power-up,” background and manually initiated diagnostic routines capable of identifying both control panel and sensor faults. These faults are identified down to the board level for the panel and to the circuit level for the sensor or actuator components. The ability for on-line replacement of boards is built into the panel design and is available for those turbine sensors where physical access and system isolation are feasible. Set points, tuning parameters and control constants are adjustable during operation using a security password system to prevent unauthorized access. Minor modifications to sequencing and the addition of relatively simple algorithms can be
The SPEEDTRONIC Mark V Gas Turbine Control System is the latest derivative in the highly successful SPEEDTRONIC ™ series. Preceding systems were based on automated turbine control, protection and sequencing techniques dating back to the late 1940s, and have grown and developed with the available technology. Implementation of electronic turbine control, protection and sequencing originated with the Mark I system in 1968. The Mark V system is a digital implementation of the turbine automation techniques learned and refined in more than 40 years of successful experience, over 80% of which has been through the use of electronic control technology. The SPEEDTRONIC ™ Mark V Gas Turbine Control System employs current state-of-the-art technology, including triple-redundant 16-bit microprocessor controllers, two-out-of-three voting redundancy on critical control and protection parameters and Software-Implemented Fault Tolerance (SIFT). Critical control and protection sensors are triple redundant and voted by all three control processors. System output signals are voted at the contact level for critical solenoids, at the logic level for the remaining contact outputs and at three coil servo valves for analog control signals, thus maximizing both protective and running reliability. An independent protective module provides triple redundant hardwired detection and shutdown on overspeed along with detecting flame. This module also synchronizes the turbine generator to the power system. Synchronization is backed up by a check function in the three control processors. The Mark V Control System is designed to fulfill all gas turbine control requirements. These include control of liquid, gas or both fuels in accordance with the requirements of the speed, load control under part-load conditions, temperature control under maximum capability conditions or during startup conditions. In addition, inlet guide vanes and water or steam injection are controlled to meet emissions and operating requirements. If emissions control uses ™
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accomplished when the turbine is not operating. They are also protected by a security password. A printer is included in the control system and is connected via the operator interface. The printer is capable of copying any alpha-numeric display shown on the monitor. One of these displays is an operator configurable demand display that can be automatically printed at a selectable interval. It provides an easy means to obtain periodic and shift logs. The printer automatically logs time-tagged alarms, as well as the clearance of alarms. In addition, the printer will print the historical trip log that is frozen in memory in the unlikely event of a protective trip. The log assists in identifying the cause of a trip for trouble shooting purposes. The statistical measures of reliability and availability for SPEEDTRONIC™ Mark V systems have quickly established the effectiveness of the new control because it builds on the highly successful SPEEDTRONIC ™ Mark IV system. Improvements in the new design have been made in microprocessors, I/O capacity, SIFT technology, diagnostics, standardization and operator information, along with continued application flexibility and careful design for maintainability. SPEEDTRONIC™ Mark V control is achieving greater reliability, faster meantime-to repair and improved control system availability than the SPEEDTRONIC™ Mark IV applications. As of May 1994, almost 264 Mark V systems had entered commercial ser vice and system operation has exceeded 1.4 million hours. The established Mark V level of system reliability, including sensors and actuators, exceeds 99.9 percent, and the fleet mean-time-betweenforced-outages (MTBFO) stands at 28,000 hours. As of May 1994, there were 424 gas turbine Mark V systems and 106 steam turbine Mark V systems shipped or on order.
rapid growth in the field of control technology. The hydro-mechanical design culminated in the “fuel regulator” and automatic relay sequencing for automatic startup, shutdown and cooldown where appropriate for unattended installations. The automatic relay sequencing, in combination with rudimentary annunciator monitoring, also allowed interfacing with SCADA (Supervisory Control and Data Acquisition) systems for true continuous remote control operation. This was the basis for introduction of the first electronic gas turbine control in 1968. This system, ultimately known as the SPEEDTRONIC™ Mark I Control, replaced the fuel regulator, pneumatic temperature control and electromechanical starting fuel control with an electronic equivalent. The automatic relay sequencing was retained and the independent protective functions were upgraded with electronic equivalents where appropriate. Because of its electrically dependent nature, emphasis was placed on integrity of the power supply system, leading to a DC-based system with AC- and shaft-powered back-ups. These early electronic systems provided an order of magnitude increase in running reliability and maintainability. Once the changeover to electronics was achieved, the rapid advances in electronic system technology resulted in similar advances in gas turbine control technology (Table 1). Note that more than 40 years of gas turbine control experience has involved more than 5,400 units, while the 26 years of electronic control experience has been centered on more than 4,400 turbine installations. Throughout this time period, the control philosophy shown in Table 2 has developed and matured to match the capabilities of the existing technology. This philosophy emphasizes safety of operation, reliability, flexibility, maintainability and ease of use, in that order.
CONTROL SYSTEM HISTORY
CONTROL SYSTEM FUNCTIONS
The gas turbine was introduced as an industrial and utility prime mover in the late 1940s with initial applications in gas pipeline pumping and utility peaking. The early control systems were based on hydro-mechanical steam turbine governing practice, supplemented by a pneumatic temperature control, preset startup fuel limiting and manual sequencing. Independent devices provided protection against overspeed, overtemperature, fire, loss of flame, loss of lube oil and high vibration. Through the early years of the industry, gas turbine control designs benefited from the
The SPEEDTRONIC™ Gas Turbine Control System performs many functions including fuel, air and emissions control; sequencing of turbine fuel and auxiliaries for startup, shutdown and cooldown; synchronization and voltage matching of the generator and system; monitoring of all turbine, control and auxiliary functions; and protection against unsafe and adverse operating conditions. All of these functions are performed in an integrated manner that is tailored to achieve the previously described philosophy in 2
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Table 1 ADVANCES IN ELECTRONIC CONTROL CONCEPTS
the stated priority. The speed and load control function acts to control the fuel flow under part-load conditions to satisfy the needs of the gover nor. Temperature control limits fuel flow to a maximum consistent with achieving rated firing temperatures and controls air flow via the inlet guide vanes to optimize part-load heat rates on heat recovery applications. The operating limits of the fuel control are shown in Figure 1. A block diagram of the fuel, air and emissions control systems is shown in Figure 2. The input to the system is the operator command for speed
(when separated from the grid) or load (when connected). The outputs are the commands to the gas and liquid fuel control systems, the inlet guide vane positioning system and the emissions control system. A more detailed discussion of the control functionality required by the gas turbine may be found in Reference 1. The fuel command signal is passed to the gas and liquid fuel systems via the fuel signal divider in accordance with the operator’s fuel selection. Startup can be on either fuel and transfers
Table 2 GAS TURBINE CONTROL PHILOSOPHY • Single control failure alarms when running or during startup • 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 reliability while maintaining flexibility
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Figure 1.Gas turbine generator controls and limits 3
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Figure 2. Gas turbine fuel control under load are accomplished by transitioning warm-up conditions, as well as maximum flow from one system to the other after an approprifor peak output at minimum ambient temperaate fill time to minimize load excursions. System ture. The stop/speed ratio valve also acts as an characteristics during a transfer from gas to liqindependent stop valve. It is equipped with an uid fuel are illustrated in Figure 3. Purging of interposed, hydraulically-actuated trip relay that the idle fuel system is automatic and continuouscan trip the valve closed independent of control ly monitored to ensure proper operation. signals to the servo valve. Both the stop ratio Transfer can be automatically initiated on loss of and control valves are hydraulically actuated, supply of the r unning fuel, which will be single-acting valves that will fail to the closed alarmed, and will proceed to completion withposition on loss of either signal or hydraulic out operator intervention. Return to the origipressure. Fuel distribution to the gas fuel noznal fuel is manually initiated. zles in the multiple combustors is accomplished The gas fuel control system is shown schematby a ring manifold in conjunction with careful ically in Figure 4. It is a two-stage system, incorcontrol of fuel nozzle flow areas. porating a pressure control proportional to The liquid fuel control system is shown speed and a flow control proportional to fuel schematically in Figure 5. Since the fuel pump is command. Two stages provide a stable turna positive displacement pump, the system down ratio in excess of 100:1, which is more achieves flow control by recirculating excess fuel than adequate for control under starting and
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Figure 3. Dual fuel transfer characteristics gas to liquid
Figure 4. Gas fuel control system 4
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ulates the division of fuel among the multiplecombustion stages according to a schedule that is determined by a calculated value of the combustion reference temperature. The control system also monitors actual combustion system operation to ensure compliance with the required schedule. Special provisions are incorporated to accommodate off-normal situations such as load rejection. The gas turbine, like any internal combustion engine, is not self-starting and requires an outside source of cranking power for startup. This is usually a diesel engine or electric motor combined with a torque converter, but could also be a steam turbine or gas expander if external steam or gas supplies are available. Startup via the generator, using variable frequency power supplies, is used on some of the larger gas turbines. Sufficient cranking power is provided to crank the unfired gas turbine at 25% to 30% speed, depending on the ambient temperature, even though ignition speed is 10% to 15%. This extra cranking power is used for gas path purging prior to ignition, for compressor water washing, and for accelerated cooldown. A typical automatic starting sequence is shown in Figure 6. After automatic system checks have been successfully completed and lube oil pressure established, the cranking device is started and, for diesel engines, allowed to warm up. Simple-cycle gas turbines with conventional upward exhausts do not require purging prior to ignition and the ignition sequence can proceed as the rotor speed passes through firing speed. If ignition does not occur before the 60 second cross-firing timer times out, the controls will automatically enter a purge sequence, as described later, and then attempt to refire. However, if there is heat recovery equipment, or if the exhaust ducting has pockets where combustibles can collect, gas path purging ensures a safe light-off. When the turbine reaches purge speed, this speed is held for the necessary purge period, usually sufficient to ensure three to five volume changes in the gas path. Purge times will vary from one minute to as long as 10 minutes in some heat recovery applications. When purging is completed, the turbine rotor is allowed to decelerate to ignition speed. This speed has been found to be optimum from the standpoint of both thermal fatigue duty on the hot gas path components, as well as offering reliable ignition and cross firing of the combustors. The ignition sequence consists of turning on
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Figure 5. Liquid fuel control system from the discharge back to the pump suction. The required turndown ratio is achieved by multiplying the fuel command by a signal proportional to turbine speed. The resultant signal positions the pump recirculation, or bypass valve, as appropriate to make the actual fuel flow, as measured by the speed of the liquid fuel flow divider, equal the product of turbine speed and fuel command. This approach ensures a system in which both the liquid and gas fuel commands are essentially equal. Fuel distribution to the liquid fuel nozzles in the multiple combustors is achieved via the flow divider. This is a proven mechanical device that consists of carefully matched gear pumps for each combustor, all of which are mechanically connected to run at the same speed. Control of nitrogen oxide emissions may be accomplished by the injection of water or steam into the combustors. The amount of water required is a function of the fuel flow, the fuel type, the ambient humidity and nitrogen oxide emissions levels required by the regulations in force at the turbine site. Steam flow requirements are generally about 40% higher than the equivalent water flow, but have a more beneficial effect on turbine performance. Accuracy of the flow measurement, control system and system monitoring meets or exceeds both EPA and all local code requirements. An independent, fast-acting shutoff valve is provided to ensure against loss of flame from over-watering on sudden load rejection. Emissions control using Dry Low NOx combustion techniques relies on multiple-combustion staging to optimize fuel/air ratios and achieve thorough premixing in various combinations, depending on desired operating temperature. The emissions fuel control system reg5
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Figure 6. Typical gas turbine starting characteristics ignition power to the spark plugs and then setstep process that consists of matching turbine ting firing fuel flow. When flame is detected by generator speed, and sometimes voltage, to the the flame detectors, which are on the opposite bus, and then closing the breaker at the point side of the turbine from the spark plugs, igniwhere the two are in phase within predetertion and cross-firing are complete. Fuel is mined limits. reduced to the warm-up value for one minute Turbine speed is matched to the line frequenand the starting device power is brought to maxcy with a small positive differential to prevent imum. If successful ignition and cross firing are the generator breaker from tripping on reverse not achieved within an appropriate period of power at breaker closure. In the protective modtime, the control system automatically reverts ule, triple-redundant microprocessor-based synback to the purge sequence, and will attempt a chronizing methods are used to predict zerosecond firing sequence without operator interphase angle difference and compensate for vention. In the unlikely event of incomplete breaker closing time to provide true zero angle cross firing, it will be detected by the combusclosure. Acceptable synchronizing conditions tion monitor as a high exhaust temperature are independently verified by the triple-redunspread prior to loading the gas turbine. dant control processors as a check function. After completion of the warm-up period, fuel At the completion of synchronizing, the turflow is allowed to increase and the gas turbine bine will be at a spinning reserve load. The final begins to accelerate faster. At a speed of about step in the starting sequence consists of auto30% to 50%, the gas turbine enters a predetermatic loading of the gas turbine generator, at mined program of acceleration rates, slower inieither the normal or fast rate, to either a presetially, and faster just before reaching running lected intermediate load, base load or peak speed. The purpose of this is to reduce the therload. Typical starting times to base load are mal-fatigue duty associated with startup. shown in Table 3. Although the time to fullAt about 40% to 85% speed, turbine efficienspeed no-load applies to all simple cycle gas turcy has increased sufficiently so that the gas turbines, the loading rates shown are for standard bine becomes self sustaining and external crankcombustion and may var y for some Dr y Low ing power is no longer required. At about 80% NOx systems. to 90% speed, the compressor inlet guide vanes, Normal shutdown is initiated by the operator which were closed during startup to prevent and is reversible until the breaker is opened and compressor surge, are opened to the full-speed, the turbine operating speed falls below 95%. no-load position. The shutdown sequence begins with automatic As the turbine approaches running speed, unloading of the unit. The main generator synchronizing is initiated. This is a two or three breaker is opened by the reverse power relay at 6
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Table 3 SIMPLE CYCLE PACKAGE POWER PLANT STARTING TIMES
about 5% negative power, which drives the gas turbine fuel flow to a minimum value sufficient to maintain flame, but not turbine speed. The gas turbine then decelerates to about 40% to 25% speed, where fuel is completely shut off. As before, the purpose of this “fired shutdown” sequence is to reduce the thermal fatigue duty imposed on the hot gas path parts. After fuel is shut off, the gas turbine coasts down to a point where the rotor turning system can be effective. The rotor should be turned periodically to prevent bowing from uneven cooldown, which would cause vibration on subsequent startups. Turning of the rotor for cooldown or maintenance is accomplished by a ratcheting mechanism on the smaller gas turbines, or by operation of a conventional turning gear on some larger gas turbines. Normal cooldown periods vary from five hours on the smaller turbines to as much as 48 hours on some of the larger units. Cool down sequences may be interrupted at any point for a restart if desired. Gas turbines are capable of faster loading in the event of a system emergency. However, thermal fatigue duty for these fast load starts is substantially higher. Therefore, selection of a fast load start is by operator action with the normal start being the default case. Gas turbine generators that are equipped with diesel engine starting devices are optionally capable of starting in a blacked out condition without outside electrical power. Lubricating oil for starting is supplied by the DC emergency pump powered from the unit battery. This battery also provides power to the DC fuel forwarding pump for black starts on distillate. The turbine and generator control panels on all units are powered from the battery. An inverter sup-
plies the AC power required for ignition and the local operator interface. Power for the cooling system fans is obtained from the main generator through the power potential transformer after the generator field is flashed from the battery at about 50% speed. The black start option uses a DC batter y-powered turning device for rotor cooldown to ensure the integrity of the black start capability. As mentioned, the protective function acts to trip the gas turbine independently from the fuel control in the event of overspeed, overtemperature, high rotor vibration, fire, loss of flame or loss of lube oil pressure. With the advent of microprocessors, additional protective features have been added with minimum impact on running reliability due to the redundancy of the microprocessors, sensors and signal processing. The added functions include combustion and thermocouple monitoring, high lube oil header temperature, low hydraulic supply pressure, multiple control computer faults and compressor surge for the aircraft-derivative gas turbines. Because of their nature or criticality, some protective functions trip the stop valve through the hardwired, triple-redundant protective module. These functions are the hardwired overspeed detection system, which replaces the mechanical overspeed bolt on some units, the manual emergency trip buttons, and “customer process” trips. As previously mentioned, the protection model performs the synchronization function to close the breaker at the proper instant. It also receives signals from the flame detectors and determines if flame is on or off. A block diagram of the turbine protective system is shown in Figure 7. It shows how loss of lube oil, hydraulic supply, or manual hydraulic trip will 7
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Figure 7. Protective system block diagram; SPEEDTRONIC™ Mark V turbine control result in direct hydraulic actuation of the stop valves. Interfacing to other application-specific trip functions is provided through the three control processors, the hardwired protection module or the hydraulic trip system. These trip functions include turbine shutdown for generator protective purposes and combined-cycle coordination with heat recovery steam generators and singleshaft STAG ™ steam turbines. The latter is hydraulically integrated as shown in Figure 7. Other protective coordination is provided as required to meet the needs of specific applications.
SPEEDTRONIC™ MARK V CONTROL CONFIGURATION The SPEEDTRONIC™ Mark V control system makes increased use of modern microprocessors and has an enhanced system configuration. It uses SIFT technology for the control, a new triple-redundant protective module and a significant increase in hardware diagnostics. Standardized modular construction enhances quality, speed of installation, reliability and ease of on-line maintenance. The operator interface has been improved with color graphic displays and standardized links to remote operator sta-
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Figure 8. Standard control configuration 8
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tions and distributed control systems (DCS). Figure 8 shows the standard SPEEDTRONIC™ Mark V control system configuration. The top block in the diagram is the Inter face Data Processor called . It includes a monitor, keyboard, and printer. Its main functions are driving operator displays, managing the alarm process and handling operator commands. also does system configuration and download, offline diagnostics for maintenance, and implements interfaces to remote operator stations and plant distributed control systems. The Common Data Processor, or , collects data for display, maintains the alarm buffers, generates and keeps diagnostic data, and implements the common I/O for non-critical signals and control actions. Turbine supervisory sensors such as wheelspace thermocouples come directly to . The processor communicates with using a peer-to-peer communication link which permits one or more processors. gathers data from the control processors by participating on the voting link. At the core of SPEEDTRONIC™ Mark V control are the three identical control processors called and . All critical control algorithms, turbine sequencing and primary protective 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 turbine and generator sensors. Table 4 lists typical redundant sensor arrangements. By extending the fault tolerance to include sensors, as with the Mark IV system, the overall control system availability is significantly increased. Some sensors are brought in to all three control processors, but many, like exhaust thermocouples, are divided among the control processors. The individual exhaust temperature measurements are exchanged on the voter link so that each control processor knows all exhaust thermocouple values. Voted sensor values are computed by each of the control processors. These voted values are used in control and sequencing algorithms that produce the required control actions. One key output goes to the servo valves used in position loops as shown in Figure 9. These position loops are closed digitally. Redundant LVDTs (Linear Variable Dif ferential Transformers, a position sensor) produce a signal proportional to actuator position. Each control processor measures both LVDT signals and chooses the higher of the two signals. This value is chosen because the LVDT is designed to have a strong failure preference for low voltage output. The signal is compared with the position
Table 4 CRITICAL REDUNDANT SENSORS Parameter Speed Exhaust temperature Generator output Liquid fuel flow Gas fuel flow Water flow Actuator stroke Steam flow Vibration Flame Fire Control oil pressure L.O. pressure L.O. temperature Exh. frame blwr. Filter delta p.
Type Mag. Pickup T.C. Transducer Mag. pickup Transducer Mag. pickup LVDT Transducer Seismic probe Scanner Switch Switch Switch Switch Switch Switch
Function CTL & PROT CTL & PROT Control Control Control Control Control Control Protection Protection Protection Protection Protection Protection Protection Protection
Usage Dedicated Dedicated Dedicated Dedicated Dedicated Dedicated Shared Shared Shared Shared Shared Shared Shared Shared Shared Shared
Notes: 1. 2. 3. 4. 5. 6.
Dedicated sensors: one-third are connected to each processor Shared sensors are shared by processors Thee number of exhaust thermocouples is related to the number of combustors Vibration and fire detectors are related to the physical arrangement Generator output are redundant only for “constant settable droop” systems Dry Low NOx has four flame detectors in each of two zones
9
Number 3 to 6 13 to 27 3 3 3 3 2/Actuator 1 8 to 11 4 to 8 17 to 21 3 3 3 2 3
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Figure 9. Digital servo position loops command and the error signal passed through a transfer function and a D/A converter to a current amplifier. The current amplifier from each control processor drives one of the three coils. The servo valve acts on the sum of the ampere turns. If one of the three channels fails, the maximum current that one failed amplifier can deliver is overridden by the combined signals from the remaining two good amplifiers. The result is that the turbine continues running under control. The SIFT system ensures that the output fuel command signals to the digital ser vo stay in step. As a result, almost all single failures will not cause an appreciable bump in the controlled turbine parameter. Diagnostics of LVDT excitation voltage, LVDT outputs that disagree, and current not equalling the commanded value make it easy to find a system problem, so that on-line repair can be initiated quickly. An independent protective module is internally triple redundant. It accepts speed sensors, flame detectors and potential transformer inputs to perform emergency electronic overspeed, flame detection and synchronizing functions. Hardware voting for solenoid outputs
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is accomplished on a trip card associated with the module. The trip card merges trip contact signals from the emergency overspeed, the main control processors, manual trip push buttons and other hardwired customer trips. Overspeed and synchronization functions are independently performed in both the tripleredundant control and triple-redundant protective hardware, which reduces the probability of machine overspeed or out of phase synchronizing to the lowest achievable values. SPEEDTRONIC ™ Mark V control provides interfaces to DCS systems for plant control from the processor. The two interfaces available are Modbus Slave Station and a standard ethernet link, which complies with the IEEE-802.3 specification for the physical and medium access control (MAC) layers. A GE protocol is available for use over the ethernet link. A hardwired interface is also available. Table 5 lists signals and commands available on the interfacing links. The table includes an option for hard-wired contacts and 4-20 ma signals intended to interface with older systems such as SCADA remote dispatch terminal units. The wires are connected to the I/O module 10
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associated with . The “stage link” that interconnects the processor with the processor is an extendible Arcnet link that allows daisy chaining multiple gas turbines with multiple processors. Thus a single gas turbine can be controlled from multiple processors, or a single processor can control multiple gas and steam turbines. For multi-unit configurations, the processor can be equipped with plant load control capability that will allow plant level management of all units for both real and reactive power. The processor, or Operator Interface, is shown in Figure 10. In process plants where maintaining the link to the DCS is essential to keeping the plant online, two processors are used to obtain redundant links to the DCS system. For critical installations, a redundant processor option, referred to as the processor, is available that ensures that no single hardware failure can interrupt communications between the gas turbine and the DCS system. A specially configured PC is available to act as a “historian,” or processor, for the gas turbine installation. All data available in the Mark V data base can be captured and stored by the historian. Analog data is stored when the values change beyond a settable deadband, and events and alarms are captured when they occur. In addition, data can be requested periodically or on demand in user definable lists. The historian is sized so that about a month’s worth of data for a typical four unit plant can be stored on line, and provisions are included for both archiving and restoring older data. Display options include a full range of trending, cross-plotting and histogram screens. Compliance with recognized standards is an important aspect of SPEEDTRONIC™ Mark V controls. It is designed to comply with several standards including: • ETL — Approval has been obtained for labeling of the Mark V control panel, with ETL labeling of complete control cabs • CSA/UL — Approval has been obtained for the complete SPEEDTRONIC™ Mark V control panel • UBC — Seismic Code Section 2312 Zone 4 • ANSI — B133.4 Gas Turbine Control and Protection System • ANSI — C37.90A Surge Withstand
Table 5 INTERFACING 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 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
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RDC26449-2-8
Figure 12. Panel internal arrangement power supplies for the redundant processors through replaceable fuses. Each control module supplies its own regulated DC busses via AC/DC converters. These can accept an extremely wide range of incoming DC, which makes the control tolerant of significant battery voltage dips, such as those caused by starting a diesel cranking motor. All power sources and regulated busses are monitored. Individual power supplies can be replaced while the turbine is running. The Interface Data Processor, particularly a remote , can be powered by house power. This will normally be the case when the central control room has an Uninterruptible Power Supply (UPS) system. AC for the local processor will normally be supplied via a cable from the SPEEDTRONIC™ Mark V panel or alternatively from house power. The panel is constructed in a modular fashion and is quite standardized. A picture of the panel interior is shown in Figure 12, and the modules are identified by location in Figure 13. Each of these modules is also standardized, and a typical processor module is shown in Figure 14. They feature card racks that tilt out so cards can be individually accessed. Cards are connected by front-mounted ribbon cables which can be easily disconnected for service purposes. Tilting the card rack back in place and closing the front cover locks the cards in place. Considerable thought has been given to the routing of incoming wires to minimize noise and crosstalk. The wiring has been made more accessible for ease of installation. Each wire is easily identified and the resulting installation is neat. The panels are made in a highly standardized manufacturing process. Quality control is an integral part of the manufacturing; only thoroughly tested panels leave the factory. By having
RDC26449-2-5
Figure 11. Mark V turbine control panel
HARDWARE CONFIGURATION The SPEEDTRONIC ™ Mark V gas turbine control system is specifically designed for GE gas and steam turbines, and uses a considerable number of CMOS and VLSI chips selected to minimize power dissipation and maximize functionality. The new design dissipates less power than previous generations for equivalent panels. Ambient air at the panel inlet vents should be between 32 F and 72 F (0 C and 40 C) with a humidity between 5 and 95%, non-condensing. The standard panel is a NEMA 1A panel that is 90 inches high, 54 inches wide, 20 inches deep, and weighs approximately 1,200 pounds. Figure 11 shows the panel with doors closed. For gas turbines, the standard panel runs on 125 volt DC unit battery power, with AC auxiliary input at 120 volt, 50/60 Hz, used for the ignition transformer and the processor. The typical standard panel will require 900 watts of DC and 300 watts of auxiliar y AC power. Alternatively, the auxiliary power can be 240 volt AC 50 Hz, or it can be supplied from an optional black start inverter from the battery. The power distribution module conditions the power and distributes it to the individual 12
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median value for each sensor and integrator output, and uses these voted outputs in all subsequent calculations. and follow the same procedure. The basic SIFT concept brings one sensor of each kind into each of , and . If a sensor fails, the controller with the failed transducer initially has a bad value. But it exchanges data with the other processors and when the voting takes place, the bad value is rejected. Therefore, a SIFT-based system can tolerate one failed transducer of each kind. In previous systems, one failed transducer was likely to cause one processor to vote to trip. A failure of a different kind of transducer on another controller could cause a turbine trip. This does not happen with SIFT because the input data is exchanged and voted. is also connected to the voter link. It eavesdrops while all three sets of variables are transmitted by the control processors and calculates the voted values for itself. If there are any significant disagreements, reports them to for operator attention and maintenance action. If one of the transducers has failed, its output will not be correct and there will be a disagreement with the two correct values. will then diagnose that the transducer or parts immediately associated with it have failed and will post an alarm to . Voting is also performed on the outputs of all integrators and other state variables. By exchanging these variables, fewer bumps in output are caused when a failure or a repair takes place. For instance, if a turbine is set to run on isochronous speed control with an isolated load, an integrator compares the frequency of the generator with the nominal frequency reference (50 Hz or 60 Hz). Any error is integrated to produce the fuel command signal. If one computer calculates an erroneously high fuel command, nothing happens because the processors will exchange the fuel command and vote and all will use the correct value of fuel command. When the processor is repaired and put back in service, its fuel command will initially be set to zero. But as soon as the first data is exchanged on the voter link, the repaired control processor will output the voted value that will be from one of the running processors so no bump in fuel flow will occur. No special hardware or software is needed to keep integrated outputs in step. Since only one turbine is connected to each panel, the triple-redundant control information must be recombined. This recombination is done in software or, for more critical signals, in
GT20783A
Figure 13. Module map of panel interior
GT21533A
Figure14. Typical processor module a highly controlled process, the resulting modules and panels are very consistent and repeatable.
SOFTWARE CONFIGURATION Improved methods of implementing the triple-modular redundant system center on SIFT technology and result in a more robust control. SIFT involves exchanging information on the voter link directly between , , and controllers. Each control processor measures all of its input sensors so that each sensor signal is represented by a number in the controller. The sensor numbers to be voted are gathered in a table of values. The values of all state outputs, such as integrators, for example, the load setpoint, are added to the table. Each control processor sends its table out on the voter link and receives tables from the other processors. Consider the controller: it outputs its table to and receives the tables from the and controllers. Now all three controller tables will be in the processor, which selects the 13
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dedicated voting hardware. For critical outputs, such as the fuel command, the recombination of the signals is done by the servo valve on the turbine itself as previously explained. For example, up to four critical 4 ma to 20 ma outputs are voted in a dedicated electronic circuit. The circuit selects the median signal for output. It takes control power for the electronics and the actual output current from all three sections such that any two control sections will sustain the correct output. Non-critical outputs are software voted and output by the I/O associated with . Logic outputs are voted by dedicated hardware relay driver circuits that require two or three “on” signals to pick up the output relay. Control power for the circuit and output relay is taken from all three control sections. Protective functions are accomplished by the control processors and, for overspeed, independently by the Protective Module as well. Primary speed pickups are wired to the control processors and used for both speed control and primary overspeed protection. The trip commands, generated by the primary overspeed protective function in the control processors, each activate a relay driver. The driver signals are sent to the trip card in the protective model where independent relays are actuated. Contacts from each of these three primary protective trip relays are voted to cause the trip solenoid to drop out. Separate overspeed pickups are brought to the independent protective module. Their relay contacts are wired in a voting arrangement to the other side of the trip solenoid and independently cause the trip solenoid to drop out on detection of overspeed. The processor is equipped with a hard disk which keeps the records that define the site software configuration. It comes from GE with the site-specific software properly configured. For most upgrades, the basic software configuration on the disk is replaced with new software from the GE factory. The software is quite flexible and most required alterations can be made on site by qualified personnel. Security codes limit access to the programs used to change constants and sequencing, do logic forcing, manual control and so forth. These codes are under the control of the owner so that if there is a need to change access codes, new ones can be established 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 is stored in EEPROM
there. The information for the control processors is passed through and stored in EEPROM in , and . Once the download is complete, the processor can fail and the turbine will continue to run properly, accepting commands from the local backup display while is being repaired. Changes in control constants can be accomplished on-line in working memory. For example, a new set of tuning constants can be tried. If they are found to be satisfactory, they can be uploaded for storage in where they will be retained for use in any subsequent software download. also keeps a complete list of variables that can be displayed and printed. The most critical algorithms for protection, control and sequencing have evolved over many years of GE gas turbine experience. These basic algorithms are in EPROM. They are tuned and adapted with constants that are field adjustable. By protecting these critical algorithms from inadvertent change, the performance and safety of the complete fleet of GE gas turbines is made more secure.
OPERATION AND MAINTENANCE The operator interface is comprised of a VGA color graphics monitor, keyboard and printer. The functions available on the operator interface are shown in Table 6. Displays for normal operation center around the unit control display. It shows the status of major selections and presents key turbine parameters in a table that includes the variable name, value and engineering units. A list of the oldest three unacknowledged alarms appears on this screen. The operator interface also supports an operator-entered list of variables, called a user defined display, where the operator can type in any turbine-generator variable and it will be added to the variable list. Commands that change the state of the turbine require an arm activate sequence to avoid accidental operation. The exception is setpoint incrementing commands, which are processed immediately and do not require an arm-activate sequence. Alarm management screens list all the alarms in the chronological order of their time tags. The most recent alarm is added to the top of the display list. The line shows whether the alarm has been acknowledged or not, and whether the alarm is still active. When the alarm condition clears, the alarm can be reset. If reset is selected and the alarm has not cleared, the alarm does 14
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making a listing of the full text of all alarms or turbine variables. When the printer has been requested to make such an output, it will form feed, print the complete list and form feed again. Any alarms that happened during the time of printing were stored and are now printed. An optional alternative is to add a second printer, dedicating one to the alarm log. Administrative displays help with various tasks such as setting processor real time clocks and the date. These displays will include the selection of engineering units and allow changing between English and metric units. There are a number of diagnostic displays that provide information on the turbine and on the condition of the control system. A partial list of the diagnostics available is presented in Table 7. The trip diagnostic screen traps the actual signal condition that caused a turbine trip. This display gives detailed information about the actual logic signal path that caused any trip. It is accomplished by freezing information about the logic path when the trip occurs. This is particularly useful in identifying the original source of trouble if a spurious signal manages to cause one of the control processors to call for a trip and does not leave a normal diagnostic trail. In SPEEDTRONIC™ Mark V controls, all trips are annunciated and information about the actual logic path that caused the trip is captured. In addition to this information, contact inputs are resolved to one millisecond, which makes this sequence of events information more valuable. The previously mentioned comparison of voting values is another powerful diagnostic tool. Normally these values will agree and significant disagreement means that something is wrong. Diagnostic alarms are generated whenever there is such a disagreement. Examination of these records can reveal what has gone wrong with the system. Many of these combinations have specific diagnostics associated with them and the software has many algorithms that infer what has gone wrong from a pattern of incoming diagnostic signals. In this way the diagnostic alarm will identify as nearly as possible what is wrong, such as a failed power supply, blown fuse, failed card, or open sensor circuit. Some of the diagnostics are intended to enhance turbine-generator monitoring. For instance, reading and saving the actual closing time of the breaker is an excellent diagnostic on the health of the synchronizing system. An output from the flame detectors which shows the effective ultraviolet light level is another new diagnostic routine. It is an indicator of degrada-
Table 6 OPERATOR 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
not clear and the original time tag is retained. The alarm log prints alarms in their arrival sequence, showing the time tags which are sent from the control modules with each alarm. Software is provided to allow printing of other information, such as copying of text screens, or 15
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This upsets the operator much more than it disturbs the control processors or turbine. A backup display is provided to handle this situation. It happens ver y infrequently, and repair of the normal operator interface will usually be accomplished in less than three hours. Optional redundant processors make the use of the back-up display even more unlikely. The gas turbine control is completely automatic and needs little human intervention for starting, running, stopping or tripping once a sequence is initiated. The back-up display provides for a minimum set of control commands: start, stop, raise load and lower load. It reports all process alarms by number. Since the alarm text can be altered on site in , a provision is included to print the alarms with their internal alarm numbers. This list is used to look up the alarm name from the alarm number. The same is true for data points; however, a preselected list of key data points are programmed into the back-up panel that display the short symbol name, value and engineering units. The control ships from the factory with this limited list of key parameters established for the back-up display.
Table 7 MONITORING 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
tion in the ultraviolet flame detection system. In another example, the contact input circuits can be forced to either state and then be interrogated to ensure that the circuit functions correctly without disturbing their normal operation. The extent of this kind of diagnostics has been greatly increased in SPEEDTRONIC ™ Mark V control over previous generations. This level of monitoring and diagnostics makes maintenance easier and faster so that the control system stays in better repair. A properly maintained panel is highly fault-tolerant and makes systems starting and running reliability approach 100%. Once the diagnostic routines have located a failed part, it may be replaced while the turbine continues to run. The most critical function of the diagnostics is to identify the proper control section where the problem exists. Wrong identification could lead to powering down a good section and result in a vote to trip. If the failed section is also voting to trip, the turbine will trip. A great deal of effort has been put into identifying the correct section. To affect the repair, the correct section is powered down. The module is opened and tilted out, the offending card located, cables disconnected, card replaced and cables reconnected. The rack is closed and power is reapplied to the module. The module will then join in with the others to control the turbine and the fault tolerance is restored. Should the fault be in the or processor, it is likely that the operator display will stop or go blank and commands can no longer be sent by the operator to the turbine from .
CONTROL SYSTEM EXPERIENCE The SPEEDTRONIC ™ Mark V Turbine Control System was initially put into service in May 1992 on one of three industrial generator drive MS9001B gas turbines. The system was subsequently put into utility service on two peaking gas turbines to obtain experience in daily starting service in order to develop a starting reliability assessment in addition to the continuous duty running reliability assessment. General product line shipments of the Mark V System on new unit production commenced early in 1993, with new installations starting up throughout the second half of that year. Today, virtually all turbine shipments include Mark V Turbine Controls. This includes 424 new gas turbines and 106 new steam turbines either shipped or on order. In addition, almost 80 existing units have been committed to retrofitted SPEEDTRONIC™ Mark V Turbine Control Systems, however, the bulk of these are designed as Simplex rather than the tripleredundant systems associated with new units. This is due to the floor space available in retrofit applications. Reliability of the in service fleet, subsequent to commissioning and after accumulating more than 1.4 million powered opera16
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tional hours on 264 units, has been as expected. Indicated MTBFO (mean time between force outages) is in excess of 28,000 hours for the system, which includes control panel, sensors, actuators and all intervening wiring and connectors. This performance is shown relative to the rest of the electronic control history in Figure 15. Why is the Mark V system so much better than its predecessors? First, there are fewer components to fail and fewer types of components in the control panel. (This also means that there are fewer spares to stock.) Two-out-of-three redundancy on critical functions and components ensures that failures, which are less likely to begin with, are also less likely to cause a turbine trip. Extensive built-in diagnostics and the ability to replace almost any component while running further minimize exposure time, while running with a failed component when the potential to trip resulting from a double failure, is highest. Finally, the high degree of standardized, yet still flexible, software and hardware allowed a much greater degree of automated manufacturing and testing, substantially lowering the potential for human error, and increasing the repeatability of the process. The Mark V system is a further improvement over the Mark IV system. Although the two-outof-three voting philosophy is retained, its implementation is improved and made more robust through use of SIFT techniques. Components and types of components have been further reduced in number. Standardization of hard-
ware and software has been carried several steps further, but flexibility has also been increased. Greater degrees of automated manufacturing and testing have been complimented by greater use of computer-aided engineering to standardize the generation and testing of software and system configuration. Thus, it is fully expected the Mark V system will further advance the continuing growth of gas turbine control system starting and running reliability.
SUMMARY The SPEEDTRONIC ™ Mark V Gas Turbine Control System is based on a long history of successful gas turbine control experience, with a substantial portion using electronic and microprocessor techniques. Further advancements in the goals of starting and running reliability and system availability will be achieved by logical evolution of the unique architectural features developed and initially put into service with the Mark IV system. Flexibility of application and ease of operation will also grow to meet the needs of generator and mechanical drive systems, in process and utility operating environments, and in both peaking and base load service.
GT21537B
Figure 15. Control system reliability 17
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REFERENCES 1. Rowen, W.I., “Operating Characteristics of Heavy-Duty Gas Turbines in Utility Service,” ASME Paper No. 88-GT-150, presented at the Gas Turbine and Aeroengine Congress, Amsterdam, Netherlands, June 6-9, 1988.
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LIST OF FIGURES Figure 1. Gas turbine generator controls and limits Figure 2. Gas turbine fuel control Figure 3. Dual fuel transfer characteristics gas to liquid Figure 4. Gas fuel control system Figure 5. Liquid fuel control system Figure 6. Typical gas turbine starting characteristics Figure 7. Protective system block diagram; SPEEDTRONIC™ Mark V turbine control Figure 8. Standard control configuration Figure 9. Digital servo position loops Figure 10.Mark V operator interface Figure 11.Mark V turbine control panel Figure 12.Panel internal arrangement Figure 13.Module map of panel interior Figure 14.Typical processor module Figure 15.Control system reliability LIST OF TABLES Table 1. Table 2. Table 3. Table 4. Table 5. Table 6. Table 7.
Advances in electronic control concepts Gas turbine control philosophy Simple cycle package power plant starting times Critical redundant sensors Interfacing options Operator interface functions Monitoring and diagnostics
g SPEEDTRONIC™ Mark VI Turbine Control System Walter Barker Michael Cronin GE Power Systems Schenectady, NY
GER-4193A
GE Power Systems
SPEEDTRONIC™ Mark VI Turbine Control System Contents Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Architecture. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Triple Redundancy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 I/O Interface. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 General Purpose I/O . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 Application Specific I/O. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 Operator Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7 Software Maintenance Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Communications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 Communication Link Options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Time Synchronization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Diagnostics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10 Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11 Codes and Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Safety Standards . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Printed Wire Board Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 CE – Electromagnetic Compatibility (EMC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 CE – Low Voltage Directive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Temperature . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Humidity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12 Elevation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Gas Contaminants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Dust Contaminants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Seismic Universal Building Code (UBC). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Documentation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Manuals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 List of Figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 List of Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
GE Power Systems GER-4193A (10/00) ■
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SPEEDTRONIC™ Mark VI Turbine Control System
GE Power Systems GER-4193A (10/00) ■
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SPEEDTRONIC™ Mark VI Turbine Control System Introduction
Architecture
The SPEEDTRONIC™ Mark VI turbine control is the current state-of-the-art control for GE turbines that have a heritage of more than 30 years of successful operation. It is designed as a complete integrated control, protection, and monitoring system for generator and mechanical drive applications of gas and steam turbines. It is also an ideal platform for integrating all power island and balance-of-plant controls. Hardware and software are designed with close coordination between GE’s turbine design engineering and controls engineering to insure that your control system provides the optimum turbine performance and you receive a true “system” solution. With Mark VI, you receive the benefits of GE’s unmatched experience with an advanced turbine control platform. (See Figure 1.)
The heart of the control system is the Control Module, which is available in either a 13- or 21slot standard VME card rack. Inputs are received by the Control Module through termination boards with either barrier or box-type terminal blocks and passive signal conditioning. Each I/O card contains a TMS320C32 DSP processor to digitally filter the data before conversion to 32 bit IEEE-854 floating point format. The data is then placed in dual port memory that is accessible by the on-board C32 DSP on one side and the VME bus on the other. In addition to the I/O cards, the Control Module contains an “internal” communication card, a main processor card, and sometimes a flash disk card. Each card takes one slot except for the main processor that takes two slots. Cards are manufactured with surface-mounted technology and conformal coated per IPC-CC830. I/O data is transmitted on the VME backplane between the I/O cards and the VCMI card located in slot 1. The VCMI is used for “internal” communications between: ■ I/O cards that are contained within its card rack ■ I/O cards that may be contained in expansion I/O racks called Interface Modules
• Over 30 years experience • Complete control, protection, and monitoring • Can be used in variety of applications • Designed by GE turbine and controls engineering
Figure 1. Benefits of Speedtronic™ Mark VI GE Power Systems GER-4193A (10/00) ■
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■ I/O in backup Protection Modules ■ I/O in other Control Modules used in triple redundant control configurations ■ The main processor card The main processor card executes the bulk of the application software at 10, 20, or 40 ms depending on the requirements of the application. Since most applications require that spe1
SPEEDTRONIC™ Mark VI Turbine Control System cific parts of the control run at faster rates (i.e. servo loops, pyrometers, etc.), the distributed processor system between the main processor and the dedicated I/O processors is very important for optimum system performance. A QNX operating system is used for real-time applications with multi-tasking, priority-driven preemptive scheduling, and fast-context switching. Communication of data between the Control Module and other modules within the Mark VI control system is performed on IONet. The VCMI card in the Control Module is the IONet bus master communicating on an Ethernet 10Base2 network to slave stations. A unique poling type protocol (Asynchronous Drives Language) is used to make the IONet more deterministic than traditional Ethernet LANs. An optional Genius Bus™ interface can be provided on the main processor card in Mark VI Simplex controls for communication with the GE Fanuc family of remote I/O blocks. These blocks can be selected with the same software configuration tools that select Mark VI I/O cards, and the data is resident in the same database. The Control Module is used for control, protection, and monitoring functions, but some applications require backup protection. For example, backup emergency overspeed protection is always provided for turbines that do not have a mechanical overspeed bolt, and backup synch check protection is commonly provided for generator drives. In these applications, the IONet is extended to a Backup Protection Module that is available in Simplex and triple redundant forms. The triple redundant version contains three independent sections (power supply, processor, I/O) that can be replaced while the turbine is running. IONet is used to access diagnostic data or for cross-tripping between the Control Module and the
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Protection Module, but it is not required for tripping.
Triple Redundancy Mark VI control systems are available in Simplex and Triple Redundant forms for small applications and large integrated systems with control ranging from a single module to many distributed modules. The name Triple Module Redundant (TMR) is derived from the basic architecture with three completely separate and independent Control Modules, power supplies, and IONets. Mark VI is the third generation of triple redundant control systems that were pioneered by GE in 1983. System throughput enables operation of up to nine, 21-slot VME racks of I/O cards at 40 ms including voting the data. Inputs are voted in software in a scheme called Software Implemented Fault Tolerance (SIFT). The VCMI card in each Control Module receives inputs from the Control Module back-plane and other modules via “its own” IONet. Data from the VCMI cards in each of the three Control Modules is then exchanged and voted prior to transmitting the data to the main processor cards for execution of the application software. Output voting is extended to the turbine with three coil servos for control valves and 2 out of 3 relays for critical outputs such as hydraulic trip solenoids. Other forms of output voting are available, including a median select of 4-20ma outputs for process control and 0200ma outputs for positioners. Sensor interface for TMR controls can be either single, dual, triple redundant, or combinations of redundancy levels. The TMR architecture supports riding through a single point failure in the electronics and repair of the defective card or module while the process is running. Adding sensor redundancy increases the fault tolerance
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SPEEDTRONIC™ Mark VI Turbine Control System of the overall “system.” Another TMR feature is the ability to distinguish between field sensor faults and internal electronics faults. Diagnostics continuously monitor the 3 sets of input electronics and alarms any discrepancies between them as an internal fault versus a sensor fault. In addition, all three main processors continue to execute the correct “voted” input data. (See Figure 2.) Other GE ToTo Other GE Control Systems Control Systems
Operator Maintenance Operator /Maintenance Interface Interface Communications to DCS
Unit Data Highway Unit Data Highway Ethernet Ethernet
CIMPLICITY RDisplay System CIMPLICITY® Display System WindowsNT TM OperatingSystem Windows NT™ Operating System
CommunicationsToDCS 1.RS232 RS232 Modbus Modbus Slave/Master Slave/Master 1. Ethernet TCP-IP Slave 2.Ethernet TCP-IPModbus Modbus Slave 3. GSM 3.Ethernet Ethernet TCP-IP TCP-IPGSM
BackupProtection 1.Emergency Emergency Overspeed 1. Overspeed 2. Synch Synch Check Check Protection 2. Protection
Protection Module Protection Module
Control Module Control Module
P S
X
P.S. P.S. CPU CPU I/O I/O
Y
P.S. P.S. CPU CPU I/O I/O
Z
P.S. P.S. CPU CPU I/O I/O
Redundant Unit
RedundantUnit Data Highway Data Highway (Required) (ifrequired)
Ethernet Ethernet- IONet - IONet
Software SoftwareVoting Voting
Control Module Control Module
P S
Ethernet Ethernet --IONet IONet
Control Module Control Module
P S
Ethernet - IONet Ethernet - IONet
Figure 2. Mark VI TMR control configuration
I/O Interface There are two types of termination boards. One type has two 24-point, barrier-type terminal blocks that can be unplugged for field maintenance. These are available for Simplex and TMR controls. They can accept two 3.0 mm2 (#12AWG) wires with 300 volt insulation. Another type of termination board used on Simplex controls is mounted on a DIN rail and
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I/O devices on the equipment can be mounted up to 300 meters (984 feet) from the termination boards, and the termination boards must be within 15 m (49.2’) from their corresponding I/O cards. Normally, the termination boards are mounted in vertical columns in termination cabinets with pre-assigned cable lengths and routing to minimize exposure to emi-rfi for noise sensitive signals such as speed inputs and servo loops.
Backup Protection
Primary Controllers Primary Controllers 1. Control 1. Control 2.2.Protection Protection 3. 3.Monitoring Monitoring
Ethernet Ethernet
has one, fixed, box-type terminal block. It can accept one 3.0 mm2 (#12AWG) wire or two 2.0 mm2 (#14AWG) wires with 300 volt insulation.
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General Purpose I/O Discrete I/O. A VCRC card provides 48 digital inputs and 24 digital outputs. The I/O is divided between 2 Termination Boards for the contact inputs and another 2 for the relay outputs. (See Table 1.) Analog I/O. A VAIC card provides 20 analog inputs and 4 analog outputs. The I/O is divided between 2 Termination Boards. A VAOC is dedicated to 16 analog outputs and interfaces with 1 barrier-type Termination Board or 2 box-type Termination Boards. (See Table 2.) Temperature Monitoring. A VTCC card provides interface to 24 thermocouples, and a VRTD card provides interface for 16 RTDs. The input cards interface with 1 barrier-type TB
Type
I/O
TBCI
Barrier
24 CI
DTCI
Box
24 CI
TICI
Barrier
24 CI
TRLY
Barrier
12 CO
DRLY
Box
12 CO
Characteristics 70-145Vdc, optical isolation, 1ms SOE 2.5ma/point except last 3 input are 10ma / point 18-32Vdc, optical isolation, 1ms SOE 2.5ma/point except last 3 input are 10ma/point 70-145Vdc, 200-250Vdc, 90-132Vrms, 190-264Vrms (47-63Hz), optical isolation 1ms SOE, 3ma / point Plug-in, magnetic relays, dry, form “C” contacts 6 circuits with fused 3.2A, suppressed solenoid outputs Form H1B: diagnostics for coil current Form 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 Same as TRLY, but no solenoid circuits
Table 1. Discrete I/O 3
SPEEDTRONIC™ Mark VI Turbine Control System
Analog I/O TB TBAI
Type Barrier
TBAO
Barrier
16 AO
DTAI
Box
10 AI 2 AO
DTAO
Box
I/O 10 AI 2 AO
8 AO
Characteristics (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 (16) 4-20ma outputs (500 ohms) (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 (8) 4-20ma outputs (500 ohms)
Table 2. Analog I/O Termination Board or 2 box-type Termination Boards. Capacity for monitoring 9 additional thermocouples is provided in the Backup Protection Module. (See Table 3.) Temperature Monitoring TB TBTC
Type Barrier
I/O 24 TC
DTTC TRTD
Box Barrier
12 TC 16 RTD
DTAI
Box
8 RTD
Characteristics Types: E, J, K, T, grounded or ungrounded H1A fanned (paralleled) inputs, H1B dedicated inputs Types: E, J, K, T, grounded or ungrounded 3 points/RTD, grounded or ungrounded 10 ohm copper, 100/200 ohm platinum, 120 ohm nick H1A fanned (paralleled) inputs, H1B dedicated inputs RTDs, 3 points/RTD, grounded or ungrounded 10 ohm copper, 100/200 ohm platinum, 120 ohm nick
Table 3. Temperature Monitoring
Application Specific I/O In addition to general purpose I/O, the Mark VI has a large variety of cards that are designed for direct interface to unique sensors and actuators. This reduces or eliminates a substantial amount of interposing instrumentation in many applications. As a result, many potential single-point failures are eliminated in the most critical area for improved running reliability and reduced long-term maintenance. Direct interface to the sensors and actuators also enables the diagnostics to directly interrogate the devices on the equipment for maximum effectiveness. This data is used to analyze device and system performance. A subtle benefit of this design is that spare-parts inventories are
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reduced by eliminating peripheral instrumentation. The VTUR card is designed to integrate several of the unique sensor interfaces used in turbine control systems on a single card. In some applications, it works in conjunction with the I/O interface in the Backup Protection Module described below. Speed (Pulse Rate) Inputs. Four-speed inputs from passive magnetic sensors are monitored by the VTUR card. Another two-speed (pulse rate) inputs can be monitored by the servo card VSVO which can interface with either passive or active speed sensors. Pulse rate inputs on the VSVO are commonly used for flow-divider feedback in servo loops. The frequency range is 214k Hz with sufficient sensitivity at 2 Hz to detect zero speed from a 60-toothed wheel. Two additional passive speed sensors can be monitored by “each” of the three sections of the Backup Protection Module used for emergency overspeed protection on turbines that do not have a mechanical overspeed bolt. IONet is used to communicate diagnostic and process data between the Backup Protection Module and the Control Module(s) including cross-tripping capability; however, both modules will initiate system trips independent of the IONet. (See Table 4 and Table 5.) Synchronizing. The synchronizing system consists of automatic synchronizing, manual synchronizing, and backup synch check protection. Two single-phase PT inputs are provided VTUR I/O Terminations from Control Module TB TTUR
Type Barrier
TRPG* TRPS* TRPL* DTUR DRLY DTRT
Barrier
Box Box
I/O 4 Pulse rate 2 PTs Synch relays 2 SVM 3 Trip solenoids 8 Flame inputs
Characteristics Passive magnetic speed sensors (2-14k Hz) Single phase PTs for synchronizing Auto/Manual synchronizing interface Shaft voltage / current monitor (-) side of interface to hydraulic trip solenoids UV flame scanner inputs (Honeywell)
4 Pulse Rate 12 Relays
Passive magnetic speed sensors (2-14k Hz) Form “C” contacts – previously described Transition board between VTUR & DRLY
Table 4. VTUR I/O terminations from Control Module
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SPEEDTRONIC™ Mark VI Turbine Control System
VPRO I/O Terminations from Backup Protection Module TB TPRO
Type Barrier
TREG* TRES* TREL*
Barrier
I/O 9 Pulse rate 2 PTs 3 Analog inputs 9 TC inputs 3 Trip solenoids 8 Trip contact in
Characteristics 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 (+) side of interface to hydraulic trip solenoids 1 E-stop (24Vdc) & 7 Manual trips (125Vdc)
Table 5. VPRO I/O terminations from Backup Protection Module on the TTUR Termination Board to monitor the generator and line busses via the VTUR card. Turbine speed is matched to the line frequency, and the generator and line voltages are matched prior to giving a command to close the breaker via the TTUR. An external synch check relay is connected in series with the internal K25P synch permissive relay and the K25 auto synch relay via the TTUR. Feedback of the actual breaker closing time is provided by a 52G/a contact from the generator breaker (not an auxiliary relay) to update the database. An internal K25A synch check relay is provided on the TTUR; however, the backup phase / slip calculation for this relay is performed in the Backup Protection Module or via an external backup synch check relay. Manual synchronizing is available from an operator station on the network or from a synchroscope. Shaft Voltage and Current Monitor. Voltage can build up across the oil film of bearings until a discharge occurs. Repeated discharge and arcing can cause a pitted and roughened bearing surface that will eventually fail through accelerated mechanical wear. The VTUR / TTUR can continuously monitor the shaft-to- ground voltage and current, and alarm at excessive levels. Test circuits are provided to check the alarm functions and the continuity of wiring to the brush assembly that is mounted between the turbine and the generator.
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Flame Detection. The existence of flame either can be calculated from turbine parameters that are already being monitored or from a direct interface to Reuter Stokes or Honeywell-type flame detectors. These detectors monitor the flame in the combustion chamber by detecting UV radiation emitted by the flame. The Reuter Stokes detectors produce a 4-20ma input. For Honeywell flame scanners, the Mark VI supplies the 335Vdc excitation and the VTUR / TRPG monitors the pulses of current being generated. This determines if carbon buildup or other contaminates on the scanner window are causing reduced light detection. Trip System. On turbines that do not have a mechanical overspeed bolt, the control can issue a trip command either from the main processor card to the VTUR card in the Control Module(s) or from the Backup Protection Module. Hydraulic trip solenoids are wired with the negative side of the 24Vdc/125Vdc circuit connected to the TRPG, which is driven from the VTUR in the Control Module(s) and the positive side connected to the TREG which is driven from the VPRO in each section of the Backup Protection Module. A typical system trip initiated in the Control Module(s) will cause the analog control to drive the servo valve actuators closed, which stops fuel or steam flow and de-energizes (or energizes) the hydraulic trip solenoids from the VTUR and TRPG. If crosstripping is used or an overspeed condition is detected, then the VTUR/TRPG will trip one side of the solenoids and the VPTRO/TREG will trip the other side of the solenoid(s). Servo Valve Interface. A VSVO card provides 4 servo channels with selectable current drivers, feedback from LVDTs, LVDRs, or ratio metric LVDTs, and pulse-rate inputs from flow divider feedback used on some liquid fuel systems. In TMR applications, 3 coil servos are commonly
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SPEEDTRONIC™ Mark VI Turbine Control System used to extend the voting of analog outs to the servo coils. Two coil servos can also be used. One, two, or three LVDT/Rs feedback sensors can be used per servo channel with a high select, low select, or median select made in software. At least 2 LVDT/Rs are recommended for TMR applications because each sensor requires an AC excitation source. (See Table 6 and Table 7.) TB TSVO
Type Barrier
I/O 2 chnls.
DSVO
Box
2 chnls.
Characteristics (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 (2) Servo current sources (6) LVDT/LVDR feedback 0 to 7.0 Vrms (2) Excitation sources 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
mination board can be provided with active isolation amplifiers to buffer the sensor signals from BNC connectors. These connectors can be used to access real-time data by remote vibration analysis equipment. In addition, a direct plug connection is available from the termination board to a Bently Nevada 3500 monitor. The 16 vibration inputs, 8 DC position inputs, and 2 Keyphasor inputs on the VVIB are divided between 2 TVIB termination boards for 3,000 rpm and 3,600 rpm applications. Faster shaft speeds may require faster sampling rates on the VVIB processor, resulting in reduced vibration inputs from 16-to-8. (See Table 8.) VVIB I/O Terminations from Control Module TB TVIB
Type Barrier
I/O 8 Vibr.
4 Pos. 1 KP
Characteristics Seismic, Proximitor, Velomitor, accelerometer charge amplifier DC inputs Keyphasor Current limited –24Vdc provided per probe
Nominal Servo Valve Ratings Coil Type #1 #2 #3 #4 #5 #6 #7
Nominal Current +/- 10 ma +/- 20 ma +/- 40 ma +/- 40 ma +/- 80 ma +/- 120 ma +/- 120 ma
Coil Resistance 1,000 ohms 125 ohms 62 ohms 89 ohms 22 ohms 40 ohms 75 ohms
Mark VI Control Simplex & TMR Simplex Simplex TMR TMR Simplex TMR
Table 7. Nominal servo valve ratings Vibration / Proximitor® Inputs. The VVIB card provides a direct interface to seismic (velocity), Proximitor®, Velomitor®, and accelerometer (via charge amplifier) probes. In addition, DC position inputs are available for axial measurements and Keyphasor® inputs are provided. Displays show the 1X and unfiltered vibration levels and the 1X vibration phase angle. -24vdc is supplied from the control to each Proximitor with current limiting per point. An optional ter-
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Table 8. VVIB I/O terminations from Control Module Three phase PT and CT monitoring. The VGEN card serves a dual role as an interface for 3 phase PTs and 1 phase CTs as well as a specialized control for Power-Load Unbalance and Early-Valve Actuation on large reheat steam turbines. The I/O interface is split between the TGEN Termination Board for the PT and CT inputs and the TRLY Termination Board for relay outputs to the fast acting solenoids. 420ma inputs are also provided on the TGEN for monitoring pressure transducers. If an EX2000 Generator Excitation System is controlling the generator, then 3 phase PT and CT data is communicated to the Mark VI on the network rather than using the VGEN card. (See Table 9.) Optical Pyrometer Inputs. The VPYR card moni-
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SPEEDTRONIC™ Mark VI Turbine Control System
TB TGEN
Type Barrier
I/O 2 PTs 3 CTs 4 AI
TRLY
Barrier
12 CO
Characteristics 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 inputs Current limited +24Vdc/input Plug-in magnetic relays previously described
■ A backup operator interface to the plant DCS operator interface ■ A gateway for communication links to other control systems ■ A permanent or temporary maintenance station ■ An engineer’s workstation
Table 9. VGEN I/O terminations from Control Module tors two LAND infrared pyrometers to create a temperature profile of rotating turbine blades. Separate, current limited +24Vdc and –24Vdc sources are provided for each Pyrometer that returns four 4-20ma inputs. Two Keyphasors are used for the shaft reference. The VPYR and matching TPYR support 5,100 rpm shaft speeds and can be configured to monitor up to 92 buckets with 30 samples per bucket. (See Table 10.) TB TPYR
Type Barrier
I/O 2 Pyrometers
Characteristics (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
Operator Interface The operator interface is commonly referred to as the Human Machine Interface (HMI). It is a PC with a Microsoft® Windows NT® operating system supporting client/server capability, a CIMPLICITY® graphics display system, a Control System Toolbox for maintenance, and a software interface for the Mark VI and other control systems on the network. (See Figure 3.) It can be applied as: ■ The primary operator interface for one or multiple units GE Power Systems GER-4193A (10/00) ■
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Figure 3. Operator interface graphics: 7FA Mark VI All control and protection is resident in the Mark VI control, which allows the HMI to be a non-essential component of the control system. It can be reinitialized or replaced with the process running with no impact on the control system. The HMI communicates with the main processor card in the Control Module via the Ethernet based Unit Data Highway (UDH). All analog and digital data in the Mark VI is accessible for HMI screens including the high resolution time tags for alarms and events. System (process) alarms and diagnostics alarms for fault conditions are time tagged at frame rate (10/20/40 ms) in the Mark VI control and transmitted to the HMI alarm management system. System events are time tagged at frame rate, and Sequence of Events (SOE) for contact inputs are time tagged at 1ms on the contact input card in the Control Module. Alarms can 7
SPEEDTRONIC™ Mark VI Turbine Control System be sorted according to ID, Resource, Device, Time, and Priority. Operators can add comments to alarm messages or link specific alarm messages to supporting graphics. Data is displayed in either English or Metric engineering units with a one-second refresh rate and a maximum of one second to repaint a typical display graphic. Operator commands can be issued by either incrementing / decrementing a setpoint or entering a numerical value for the new setpoint. Responses to these commands can be observed on the screen one second from the time the command was issued. Security for HMI users is important to restrict access to certain maintenance functions such as editors and tuning capability, and to limit certain operations. A system called “User Accounts” is provided to limit access or use of particular HMI features. This is done through the Windows NT User Manager administration program that supports five user account levels.
Software Maintenance Tools The Mark VI is a fully programmable control system. Application software is created from inhouse software automation tools which select proven GE control and protection algorithms and integrate them with the I/O, sequencing, and displays for each application. A library of software is provided with general-purpose blocks, math blocks, macros, and application specific blocks. It uses 32-bit floating point data (IEEE-854) in a QNX operating system with real-time applications, multitasking, prioritydriven preemptive scheduling, and fast context switching. Software frame rates of 10, 20, and 40 ms are supported. This is the elapsed time that it takes to read inputs, condition the inputs, execute the application software, and send outputs. Changes to the application software can be
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made with password protection (5 levels) and downloaded to the Control Module while the process is running. All application software is stored in the Control Module in non-volatile flash memory. Application software is executed sequentially and represented in its dynamic state in a ladder diagram format. Maintenance personnel can add, delete, or change analog loops, sequencing logic, tuning constants, etc. Data points can be selected and “dragged” on the screen from one block to another to simplify editing. Other features include logic forcing, analog forcing, and trending at frame rate. Application software documentation is created directly from the source code and printed at the site. This includes the primary elementary diagram, I/O assignments, the settings of tuning constants, etc. The software maintenance tools (Control System Toolbox) are available in the HMI and as a separate software package for virtually any Windows 95 or NT based PC. The same tools are used for EX2000 Generator Excitation Systems, and Static Starters. (See Figure 4 and Figure 5.)
Communications Communications are provided for internal data transfer within a single Mark VI control; communications between Mark VI controls and peer GE control systems; and external communications to remote systems such as a plant distributed control system (DCS). The Unit Data Highway (UDH) is an Ethernetbased LAN with peer-to-peer communication between Mark VI controls, EX2000 Generator Excitation Controls, Static Starters, the GE Fanuc family of PLC based controls, HMIs, and Historians. The network uses Ethernet Global Data (EGD) which is a message-based protocol with support for sharing information with mul-
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SPEEDTRONIC™ Mark VI Turbine Control System control. All trips between units are hardwired even if the UDH is redundant.
Figure 4. Software maintenance tools – card configuration
Relay Ladder Diagram Editor for Boolean Functions
Figure 5. Software maintenance tools – editors 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 at 25Hz (40ms). A variety of other proprietary protocols are used with EGD to optimize communication performance on the UDH. 40 ms is fast enough to close control loops on the UDH; however, control loops are normally closed within each unit control. Variations of this exist, such as transmitting setpoints between turbine controls and generator controls for voltage matching and var/power-factor
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The UDH communication driver is located on the Main Processor Card in the Mark VI. This is the same card that executes the turbine application software; therefore, there are no potential communication failure points between the main turbine processor and other controls or monitoring systems on the UDH. In TMR systems, there are three separate processor cards executing identical application software from identical databases. Two of the UDH drivers are normally connected to one switch, and the other UDH driver is connected to the other switch in a star configuration. Network topologies conform to Ethernet IEEE 802.3 standards. The GE networks are a Class “C” Private Internet according to RFC 1918: Address Allocation for Private Internets – February 1996. Internet Assigned Numbers Authority (IANA) has reserved the following IP address space 192.168.1.1: 192.168.255.255 (192.168/ 16 prefix). Communication links from the Mark VI to remote computers can be implemented from either an optional RS232 Modbus port on the main processor card in Simplex systems, or from a variety of communication drivers from the HMI. When the HMI is used for the communication interface, an Ethernet card in the HMI provides an interface to the UDH, and a second Ethernet card provides an interface to the remote computer. All operator commands that can be issued from an HMI can be issued from a remote computer through the HMI(s) to the Mark VI(s), and the remote computer can monitor any application software data in the Mark VI(s). Approximately 500 data points per control are of interest to a plant control system; however, about 1,200
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SPEEDTRONIC™ Mark VI Turbine Control System points are commonly accessed through the communication links to support programming screen attributes such as changing the color of a valve when it opens.
Communication Link Options Communication link options include: ■ An RS-232 port with Modbus Slave RTU or ASCII communications from the Main Processor Card. (Simplex: full capability. TMR: monitor data only – no commands) ■ An RS-232 port with Modbus Master / Slave RTU protocol is available from the HMI. ■ An RS-232/485 converter (halfduplex) can be supplied to convert the RS-232 link for a multi-drop network. ■ Modbus protocol can be supplied on an Ethernet physical layer with TCP-IP for faster communication rates from the HMI. ■ Ethernet TCP-IP can be supplied with a GSM application layer to support the transmission of the local highresolution time tags in the control to a DCS from the HMI. This link offers spontaneous transmission of alarms and events, and common request messages that can be sent to the HMI including control commands and alarm queue commands. Typical commands include momentary logical commands and analog “setpoint target” commands. Alarm queue commands consist of silence (plant alarm horn) and reset commands as well as alarm dump requests that cause the entire alarm queue to be transmitted from the Mark VI to the DCS. GE Power Systems GER-4193A (10/00) ■
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■ Additional “master” communication drivers are available from the HMI.
Time Synchronization Time synchronization is available to synchronize all controls and HMIs on the UDH to a Global Time Source (GTS). Typical GTSs are Global Positioning Satellite (GPS) receivers such as the StarTime GPS Clock or other timeprocessing hardware. The preferred time sources are Universal Time Coordinated (UTC) or GPS; however, the time synchronization option also supports a GTS using local time as its base time reference. The GTS supplies a time-link network to one or more HMIs with a time/frequency processor board. When the HMI receives the time signal, it is sent to the Mark VI(s) using Network Time Protocol (NTP) which synchronizes the units to within +/-1ms time coherence. Time sources that are supported include IRIG-A, IRIG-B, 2137, NASA36, and local signals.
Diagnostics Each circuit card in the Control Module contains system (software) limit checking, high/low (hardware) limit checking, and comprehensive diagnostics for abnormal hardware conditions. System limit checking consists of 2 limits for every analog input signal, which can be set in engineering units for high/high, high/low, or low/low with the I/O Configurator. In addition, each input limit can be set for latching/nonlatching and enable/disable. Logic outputs from system limit checking are generated per frame and are available in the database (signal space) for use in control sequencing and alarm messages. High/low (hardware) limit checking is provided on each analog input with typically 2 occurrences required before initiating an alarm. These limits are not configurable, and they are 10
SPEEDTRONIC™ Mark VI Turbine Control System selected to be outside the normal control requirements range but inside the linear hardware operational range (before the hardware reaches saturation). Diagnostic messages for hardware limit checks and all other hardware diagnostics for the card can be accessed with the software maintenance tools (Control System Toolbox). A composite logic output is provided in the data base for each card, and another logic output is provided to indicate a high/low (hardware) limit fault of any analog input or the associated communications for that signal. The alarm management system collects and time stamps the diagnostic alarm messages at frame rate in the Control Module and displays the alarms on the HMI. Communication links to a plant DCS can contain both the software (system) diagnostics and composite hardware diagnostics with varying degrees of capability depending on the protocol’s ability to transmit the local time tags. Separate manual reset commands are required for hardware and system (software) diagnostic alarms assuming that the alarms were originally designated as latching alarms, and no alarms will reset if the original cause of the alarm is still present. Hardware diagnostic alarms are displayed on the yellow “status” LED on the card front. Each card front includes 3 LEDs and a reset at the top of the card along with serial and parallel ports. The LEDs include: RUN: Green; FAIL: Red; STATUS: Yellow. Each circuit card and termination board in the system contains a serial number, board type, and hardware revision that can be displayed; 37 pin “D” type connector cables are used to interface between the Termination Boards and the J3 and J4 connectors on the bottom of the Control Module. Each connector comes with latching fasteners and a unique label identify-
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ing the correct termination point. One wire in each connector is dedicated to transmitting an identification message with a bar-code serial number, board type, hardware revision, and a connection location to the corresponding I/O card in the Control Module.
Power In many applications, the control cabinet is powered from a 125Vdc battery system and short circuit protected external to the control. Both sides of the floating 125Vdc bus are continuously monitored with respect to ground, and a diagnostic alarm is initiated if a ground is detected on either side of the 125Vdc source. When a 120/240vac source is used, a power converter isolates the source with an isolation transformer and rectifies it to 125Vdc. A diode high select circuit chooses the highest of the 125Vdc busses to distribute to the Power Distribution Module. A second 120/240vac source can be provided for redundancy. Diagnostics produce an under-voltage alarm if either of the AC sources drop below the undervoltage setting. For gas turbine applications, a separate 120/240vac source is required for the ignition transformers with short circuit protection of 20A or less. The resultant “internal” 125Vdc is fuse-isolated in the Mark VI power distribution module and fed to the internal power supplies for the Control Modules, any expansion modules, and the termination boards for its field contact inputs and field solenoids. Additional 3.2A fuse protection is provided on the termination board TRLY for each solenoid. Separate 120Vac feeds are provided from the motor control center for any AC solenoids and ignition transformers on gas turbines. (See Table 11.)
11
SPEEDTRONIC™ Mark VI Turbine Control System
Steady State Voltage 125Vdc (100 to 144Vdc) 120vac (108 to 132vac) 240vac (200 to 264vac)
Freq.
Load
Comments
10.0 A dc
Ripple
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