RESEARCH REPORT 430 Offshore gas turbines (and major driven equipment) integrity and

HSE
Health & Safety
Executive
Offshore gas turbines (and major
driven equipment) integrity and
inspection guidance notes
Prepared by ESR Technology Ltd for the
Health and Safety Executive 2006
RESEARCH REPORT 430
HSE
Health & Safety
Executive
Offshore gas turbines (and major
driven equipment) integrity and
inspection guidance notes
Martin Wall, Richard Lee & Simon Frost
ESR Technology Ltd
551.11 Harwell International Business Centre
Harwell
Oxfordshire
OX11 0QJ
Gas turbines are widely used offshore for a variety of purposes including power generation,
compression, pumping and water injection. Relatively little information is included in safety cases, for
example only the manufacture, model, power rating (MW), fuel types, and installation drawings
showing the location of the turbines. Some descriptive text may be included on the power generation
package, back-up generators and arrangements for power transmission to satellite platforms.
Information on integrity management and maintenance is limited or at a high level.
This Inspection Guidance Note provides a more detailed assessment of gas turbines (GTs) and
major driven equipment installed on UK offshore installations, focussing on integrity and maintenance
issues. This complements the advice in HSE Guidance Note PM84, recently re-issued, covering
control of risks for gas turbines used in power generation and HSE Research Report RR076 which
provides general guidance on rotating equipment including turbines. The applications, systems and
components of offshore gas turbines are reviewed. Guidance is given on the integrity issues and
maintenance typical for different systems. Summaries are given of database information on the
turbines installed on UK installations together with recent incident and accident data. Recent
experience and anecdotal information from operators is also reviewed. The inspection guidance note
is principally designed to provide information for HSE inspectors in safety assessments, incident
investigations and prior to site visits. The note may also be of interest to manufacturers, suppliers
and operators of gas turbines (GTs) used offshore.
This report and the work it describes was co-funded by the Health and Safety Executive (HSE) and
the EU’s Fifth Framework Programme of Research. Its contents, including any opinions and/or
conclusions expressed, are those of the authors alone and do not necessarily reflect HSE policy.
HSE BOOKS
© Crown copyright 2006
First published 2006
All rights reserved. No part of this publication may be
reproduced, stored in a retrieval system, or transmitted in
any form or by any means (electronic, mechanical,
photocopying, recording or otherwise) without the prior
written permission of the copyright owner.
Applications for reproduction should be made in writing to:
Licensing Division, Her Majesty's Stationery Office, St Clements House, 2-16 Colegate, Norwich NR3 1BQ or by e-mail to [email protected]
ii
Acknowledgements
The authors would like to thank the HSE inspectors, turbine suppliers, operators and others who
have contributed to this report and allowed pictures and other information to be reproduced. In
particular we would like to thank the following HSE staff for their contribution: Prem Dua the
project technical officer, Jim MacFarlane for advice on rotating equipment issues, Tom Gudgin
for his valuable comments on electrical issues and control systems, Stan Cutts for advice in the
context of the KP3 initiative, Danny Shuter for handling project issues and HSE inspectors who
attended project seminars at Aberdeen, Bootle, Norwich and London for their comments. Rainer
Kurz from Solar is thanked specifically for allowing us to use some of the images and
introductory information from his IGTI 2004 paper. This project was initiated by the HSE
Research Strategy Unit. The authors of HSE Research Report RR076 on rotating equipment are
thanked for providing a starting point for present project.
iii
iv
Foreword
This report covers the inspection and integrity of gas turbines (GTs) and major driven
equipment (compressors, pumps, alternators). The focus is on offshore applications including
floating installations and FPSOs. The work is directly relevant to HSE’s Key Programme 3
(KP3) initiative.
The report is intended principally as an information source for HSE inspectors in safety
assessments, incident investigations and prior to site visits. The note may also be of interest to
manufacturers, suppliers and operators of gas turbines (GTs) used offshore.
The areas covered include: what can go wrong, typical inspection and maintenance, what is
done differently offshore, relevant, codes and standards, hazards and safety concerns, good and
best practice, summary of incident and accident data (RIDDOR, DO), a review of the main
systems and components and how they work. A summary is given of advice in other HSE
documents including PM84 and RR076.
Specific areas covered include: the basics of gas turbines, applications offshore, packaging
concepts, electrical and control systems, major driven equipment, GTs on UK installations,
safety codes and regulations (including environmental), hazards and failure modes, maintenance
and inspection, operational issues and recent trends.
Section 1 provides an introduction and advice on use of the information in the report
Section 2 gives an introduction to gas turbines, the types of gas turbines that are used offshore,
packaging concepts and their applications.
Section 3 summarises the main applications offshore
Section 4 describes offshore turbine packages in more detail
Section 5 summarises the integrity, safety and maintenance issues for major driven equipment
building on the information in RR076
Section 6 addresses the associated electrical systems.
Section 7 focuses on control systems a main safety consideration and recent developments
including synchronisation and corrected parameter control
Section 8 summarises the turbines installed in the UK sector.
Section 9 covers safety cases, codes and regulations.
Section 10 looks at degradation and failure modes including an analysis of incident, accident
dangerous occurrence and reliability data. Summary tables are given by system and component.
Section 11 looks at maintenance and inspection practice in-service and at overhaul.
Section 12 looks at operational issues including hazards, start-up and shutdown, surge
prevention, risk assessment and hazard management.
Section 13 reviews recent trends in gas turbines including dry low emissions (DLE), microturbines, waste heat recovery systems and combine cycle gas turbines.
Section 14 gives operational support guidance based on the principles developed in RR076.
Section 15 gives examples of good and best practice with applicable guidance and regulations
and references listed in Sections 16 and 17 respectively.
Supplementary information is included in a number of Appendices. Appendix 1 gives a current
list of UK installations and Appendix 2 describes what would be included in a typical
procurement package technical specification for gas turbines for a UK offshore installation.
Appendix 3 reproduces HSE guidance note PM84 on gas turbines, Appendix 4 summarises the
main turbine suppliers for UK installations derived from an analysis of DTI emissions data and
other sources. The specifications for gas turbines used in the UK sector are summarised in
Appendix 5. The key systems and components are described in more detail in Appendix 6.
v
vi
CONTENTS LIST
Foreword
1
2
Introduction to Inspection Guidance Notes
1
1.1
1.2
1.3
1
1
2
4
5
BACKGROUND
MAP OF GUIDANCE PROCESS
APPLICATION OF GUIDANCE NOTES
Basics of Gas turbines
2.1
2.2
2.3
2.4
2.5
2.6
2.7
2.8
2.9
2.10
2.11
2.12
2.13
2.14
2.15
2.16
3
iv
3
INTRODUCTION
SYSTEMS AND COMPONENTS
HOW A GAS TURBINE WORKS
WORKING CYCLE
PRESSURE, VOLUME AND TEMPERATURE
CHANGES IN VELOCITY AND PRESSURE
GAS TURBINES OFFSHORE
TYPES OF GAS TURBINE
PACKAGING CONCEPTS
TURBINE PACKAGES
DESIGN FACTORS
TURBINE CONFIGURATION
DRIVEN EQUIPMENT
OFFSHORE ENCLOSURES
GAS TURBINE GT CYCLES
FUELS
3
4
5
6
7
7
8
9
9
10
12
12
13
14
14
15
Applications Offshore
17
3.1
3.2
3.3
3.4
3.5
17
18
19
19
20
POWER GENERATION
GAS GATHERING
GAS LIFT
WATERFLOOD
EXPORT COMPRESSION
Offshore Packages
21
4.1
4.2
4.3
21
22
22
MODULAR TURBINE PACKAGES
DESIGN OPTIONS
FPSO TURBINE PACKAGES
Major Driven Equipment
25
5.1
5.2
ALTERNATORS
COMPRESSORS
26
27
Applications
Package Elements
Package Configuration
Hazards
PM84 Guidance
Components
29
29
30
30
31
32
PUMPS
34
5.3
vii
6
7
8
9
10
Electrical Systems
35
6.1
6.2
6.3
6.4
35
36
37
37
ELECTRICAL SYSTEMS
ELECTRICAL SYSTEMS GUIDANCE
ELECTROMAGNETIC RADIATION
MAINTENANCE OF ELECTRICAL SYSTEMS
Control Systems
41
7.1
7.2
PM84 GUIDANCE ON CONTROL SYSTEMS
RECENT DEVELOPMENTS IN CONTROL SYSTEMS
43
43
Corrected parameter control
Control Synchronisation
Triple Modular Redundant TMR Control Systems
Redundant Network Control
Standard Control System
Software Architecture for a Standard control system
43
44
45
46
46
47
Gas Turbines on UK Installations
49
8.1
8.2
50
50
PACKAGERS
SUPPLIERS
Safety Cases, Codes and Regulations
53
9.1
9.2
9.3
9.4
9.5
9.6
9.7
53
53
53
54
55
55
56
RELEVANT UK INSTALLATIONS
INFORMATION FROM SAFETY CASES
HSE GUIDANCE NOTE PM84
DESIGN CODES
EMISSION REGULATIONS
ELECTRICAL REGULATIONS
LEGAL REQUIREMENTS
Hazards and Failure Modes
59
10.1
10.2
59
59
WHAT CAN GO WRONG
FAILURE MECHANISMS AND ANALYSIS
Creep
Thermo-mechanical fatigue
High-cycle fatigue
Metallurgical embrittlement
Environmental attack
Foreign body damage
Manufacture or repair
Failure analysis
Materials
Air Compressors
Combustors
Turbines
10.3
10.4
10.5
59
60
60
60
60
60
60
60
61
62
62
63
PM84 ADVICE ON MECHANICAL FAILURES
ANECDOTAL INFORMATION
ACCIDENT, INCIDENT AND DANGEROUS OCCURRENCE DATA
Data extracted
Analysis of Data
10.6
63
64
65
65
65
IMIA INDUSTRIAL GAS TURBINE MEMBERS FAILURE STATISTICS
viii
69
10.7
10.8
10.9
11
RELIABILITY DATA FOR GAS TURBINES
SUMMARY TABLES BY SYSTEM AND COMPONENT
OTHER HAZARDS
Maintenance and Inspection
81
11.1
11.2
81
82
OVERVIEW
INSPECTION & REPAIR
Refurbishment of Gas Turbine Components
Evaluation of damage
Disassembly
Dimensional checking
Non-destructive testing (NDT)
Metallurgical Examination
Defining of workscope
Processes
Nozzle and Vanes
Buckets and Blades
Quality records
11.3
MAINTENANCE GUIDANCE
11.4
88
90
90
90
DISASSEMBLY INSPECTIONS
Combustion Inspection
Hot-Gas-Path Inspection
11.5
11.6
11.7
11.8
94
94
94
MAJOR INSPECTION
TURBINE BORE INSPECTIONS
CLEANING
SUMMARY BY SYSTEM AND COMPONENT
Operational Issues 12.1
12.2
12.3
12.4
12.5
12.6
12.7
12.8
12.9
12.10
12.11
12.12
12.13
12.14
12.15
12.16
12.17
12.18
12.19
82
83
84
84
84
85
85
85
85
85
86
86
Fuels
Water (or steam) Injection
Cyclic Effects
Rotor
12
70
70
80
96
97
97
99
105
HAZARDS
START-UP AND SHUT-DOWN
SURGE PREVENTION
RECYCLE FACILITY
CONTROL SYSTEMS
VIBRATION MONITORING
FIRE DETECTION REQUIREMENTS
PRECAUTIONS AGAINST FIRE
RISK ASSESSMENT FOR ROUTINE ACTIVITIES
ACCESS
HAZARD MANAGEMENT IN HOT-SPOTS
PRECAUTIONS AGAINST EXPLOSION
VENTILATION
FUEL SUPPLY SYSTEMS
GAS FUEL
ADDITIONAL EXPLOSION PRECAUTIONS FOR LIQUID FUELS AND OILS
EMERGENCY PROCEDURES
AIR AND GAS SEALS
CHANGEOVER IN DUEL FUEL SYSTEMS
ix
105
105
106
107
108
108
109
109
111
112
112
113
114
116
117
117
118
118
118
13
Recent Trends
13.1
13.2
13.3
13.4
13.5
119
MICROTURBINE DEVELOPMENT
DRY LOW EMISSIONS (DLE)
STEAM INJECTION FOR EMISSION REDUCTION AND POWER OUTPUT
WASTE HEAT RECOVERY UNITS
COMBINED CYCLE GAS TURBINES
119
119
120
120
120
14
Operational Support Guidance
123
15
Examples of good and Best practice
127
16
List of Applicable Guidance and Regulations
131
17
References
133
APPENDICES
Appendix 1 List of UK installations
A1
Appendix 2 Typical procurement package technical specification
A2
Appendix 3 HSE guidance note PM84 on gas turbines
A3
Appendix 4 Gas turbine suppliers and summary for UK installations
A4
Appendix 5 Specification of turbines used in UK sector
A5
Appendix 6 Key systems and components
A6
x
1
INTRODUCTION TO INSPECTION GUIDANCE NOTES
This Inspection Guidance Note provides a detailed assessment of gas turbines (GTs) and major
driven equipment installed on UK offshore installations, covering inspection, integrity and
maintenance issues. This complements the advice in HSE Guidance Note PM841, recently reissued, covering control of risks for gas turbines used in power generation. The report is also
complementary to HSE Research Report RR0762,which provides more general advice on
machinery and rotating equipment including GTs. The applications, systems and components of
offshore gas turbines are reviewed. Guidance is given on the integrity issues and maintenance
typical for different systems. Summaries are given of database information on the turbines
installed on UK installations together with recent incident and accident data. Recent experience
and anecdotal information from operators is also included. The guidance note is aimed at
manufacturers, suppliers and operators of gas turbines (GTs) used offshore as well as to provide
guidance to HSE inspectors in safety assessments, incident investigations and prior to site visits.
1.1
BACKGROUND
Gas turbines are widely used offshore for a variety of purposes including power generation,
compression, pumping and water injection, often in remote locations. GTS are commonly duel
fuelled, to run on fuel taken from the production process in normal operation or alternatively on
diesel. Electrical power can also be generated to run other systems on the offshore installation.
GTs offshore are typically from 1 to 50MW and may be modified aero-engines or industrial.
Aeroderivative designs are increasingly used, particularly for the gas-generator. Lightweight
industrial designs for offshore use are also available.
Relatively little information is included in safety cases, for example only the manufacture,
model, ISO power rating (MW), fuel types, and installation drawings showing the location of
the turbines. Some descriptive text may be included on the power generation package, back-up
generators and arrangements for power transmission to satellite platforms. Information on
integrity management and maintenance is limited or at a high level. This document is intended
to provide more detailed information.
1.2
MAP OF GUIDANCE PROCESS
The guidance note is broken down into a number of discrete sections. Section 1 provides an
introduction and advice on use of the information in the report. Section 2 gives an introduction
to gas turbines, the types of gas turbines that are used offshore, packaging concepts and their
applications. The main applications offshore and offshore turbine packages are covered
specifically in Sections 3 and 4. The integrity, safety and maintenance issues for major driven
equipment is summarised in section 5, building on the information in RR076.
Sections 6 and 7 address the associated electrical and control systems, a main safety
consideration. Recent developments including synchronisation and corrected parameter control
are included. Section 8 summarises the turbines installed in the UK sector, Section 9 covers
safety cases, codes and regulations and Section 10 looks at degradation and failure modes
including an analysis of incident, accident dangerous occurrence and reliability data. Summary
tables are given by system and component. Section 11 looks at maintenance and inspection
practice in-service and at overhaul. Operational issues including hazards, start-up and shutdown,
surge prevention, risk assessment and hazard management are covered in Section 12. Recent
trends in gas turbines including dry low emissions (DLE), micro-turbines, waste heat recovery
1
systems and combine cycle gas turbines are reviewed in Section 13. Section 14 gives
operational support guidance based on the principles developed in RR076 with examples of
good and best practice in Section 15. Applicable guidance and regulations and references listed
in Sections 16 and 17 respectively.
Supplementary information is included in a number of Appendices. Appendix 1 gives a current
list of UK installations and Appendix 2 describes what would be included in a typical
procurement package technical specification for gas turbines for a UK offshore installation.
Appendix 3 reproduces HSE guidance note PM84 on gas turbines, Appendix 4 summarises the
main turbine suppliers for UK installations derived from an analysis of DTI emissions data and
other sources. The specifications for gas turbines used in the UK sector are summarised in
Appendix 5. Appendix 6 describes the key systems and components.
1.3
APPLICATION OF GUIDANCE NOTES
The guidance notes are intended to provide advice to HSE inspectors prior to site visits, in
accident investigations and in evaluation of safety cases. The report may also be of interest to
other parties including dutyholders, users, manufacturers, suppliers and operators.
2
2
2.1
BASICS OF GAS TURBINES
INTRODUCTION
A gas turbine (GT) converts fuel into mechanical output power to drive equipment including
pumps, compressors, generators, blowers and fans. Gas turbines are widely used in the oil and
gas industry in production, midstream and downstream applications with around 300-400
installed on both fixed and mobile UK offshore installations. A typical gas turbine contains
three main systems: the compressor, the combustor – otherwise referred to as gas-generator or
core engine and the power turbine. These main systems are illustrated schematically in Figure
1. A cross section through an Alstom GTX100 industrial turbine is shown in Figure 2 and for an
Avon aeroderivative gas turbine in Figure 3. The gas generator itself for this latter turbine
design is shown in Figure 4.
Figure 1 The main systems in a gas turbine used for power generation:
compressor, gas generator or combustor and power turbine. Courtesy Solar 5
Figure 2 Alstom GTX100 turbine with cross section through GTX100 gas turbine
showing compressor, combustion system and power turbine and bearing
arrangements. Courtesy Alstom
A gas turbine is a complex component operating at high speeds and high temperatures. This
puts demanding conditions on the materials and components, which need to perform in these
environments and maintain tight dimensional tolerances. To function a turbine needs a number
of ancillary and support systems. Provision has to be made for air-intake, fuel input, starting and
ignition, dispersion of exhaust gases, as well as cooling, lubrication of bearings and sealing.
3
This total system forms the turbine package. Packaging concepts are described in more detail in
Section 2.10.
Figure 3 Rolls Royce Avon gas generator with RT48 Power Turbine
2.2
SYSTEMS AND COMPONENTS
The gas turbine itself contains three main components:
x Compressor (AC) Compresses the air before combustion and expansion through the
turbine
x Gas generator (GG) including combustor and gas turbine (GT). Ignition of air and fuel
mixture to give a smooth stream of uniformly heated gas into the power turbine
x Power turbine (PT) The power turbine has the task of providing the power to drive the
compressor and accessories and, in the case of driven equipment of providing shaft
power for power generation, or driving the compressor or pump. It does this by
extracting energy from the hot gases released from the combustion system and
expanding them to a lower pressure and temperature.
Other key systems within the package include the fuel system either natural gas or liquid
(pumped), the bearing lube oil system including tank and filters, pumps (main, pre/post,
backup), the starter (usually either pneumatic, hydraulic or a variable speed ac motor), cooling
systems, controls (on-skid, off-skid), driven equipment and the seal gas system (compressors).
There is other ancillary equipment external to the turbine package. This includes: the enclosure
and fire protection, the acoustic housing, the inlet system including air-filter (self-cleaning,
barrier, inertial) and silencer, the exhaust system including silencer and the exhaust stack, a lube
4
oil cooler (water, air), the motor control centre, switchgear, neutral ground resistor and inlet
fogger/cooler.
A detailed description of each of the main systems and individual components is given in
Reference 3 and Appendix 6.
.
Figure 4 Avon gas generator. Courtesy Rolls Royce
2.3
HOW A GAS TURBINE WORKS
The gas turbine is a heat engine using air as a working fluid to provide thrust (Figure 5). To
achieve this the air passing through the engine has to be accelerated. This means that the
velocity or kinetic energy of the air is increased. To obtain this increase the pressure energy is
first of all increased followed by the addition of heat energy before final conversion back to
kinetic energy in the form of a high velocity jet efflux. A good description of the principles,
design and detail of gas turbine engines can be found in References 4 and 5.
The working cycle of the gas turbine is similar to that of the four-stroke piston engine. In the
gas-turbine engine, combustion occurs at a constant pressure, whereas in the piston engine it
occurs at a constant volume. In each case there is air-intake, compression, combustion and
exhaust. These processes are intermittent in the case of a piston engine, whereas in a gas
turbine they occur continuously giving a much greater power output for the size of engine.
The pressure of the air does not rise during combustion due to the continuous action of the
turbine engine and the fact the combustion chamber is not an enclosed space. The volume does
increase. This process is known as heating at constant pressure. The lack of pressure
fluctuations allows the use of low octane fuels and light fabricated combustion chambers, in
contrast to the piston engine.
5
Air Intake
Æ
Compression
Æ
CombustionÆ
Exhaust
Figure 5 Cross section through a gas-turbine showing the continuous process of airintake, compression, combustion and exhaust in an aeroderivative design. Courtesy
Rolls Royce.
2.4
WORKING CYCLE
The working cycle upon which the gas turbine functions is represented by the cycle shown on
the pressure volume diagram in Figure 6 below. Point A represents air at atmospheric pressure
that is compressed in the air compressor stage along the line AB. From B to C heat is added to
the air in the gas generator by introducing and burning fuel at constant pressure, thereby
considerably increasing the volume of air. Pressure losses in the combustion chambers are
indicated by the drop between B and C. From C to D the gases resulting from combustion
expand through the power turbine and exhaust back to the flare. During this part of the cycle,
some of the energy in the expanding gases is turned into mechanical power by the turbine;
which can be used for power generation or to drive mechanical equipment such as compressors
or pumps.
Combustion
heat energy added
B
C
Expansion
Pressure
through turbine
and nozzle
Compression
pressure energy added
A
Ambient Air
D
Volume
Figure 6 The working cycle for a gas-turbine engine
6
2.5
PRESSURE, VOLUME AND TEMPERATURE
The higher the temperature of combustion the greater is the expansion of the gases, because the
gas turbine is essentially a heat engine. The gas entry temperature following combustion must
not exceed design limits or safe operating limits for materials in the turbine assembly.
The use of air-cooled blades and thermal barrier coatings in the turbine assembly permits a
higher gas temperature and consequently a higher thermal efficiency. During the working cycle
of the turbine engine, the airflow or working fluid receives and gives up heat, so producing
changes in its pressure, volume and temperature. These changes as they occur are closely related
through the relationships that apply in Boyle’s and Charles’ Laws.
Consequently, the product of the pressure and the volume of the air at the various stages in the
working cycle is proportional to the absolute temperature of the air at those stages. This
relationship applies for whatever means are used to change the state of the air. For example,
whether energy is added by combustion or by compression, or is extracted by the turbine, the
heat change is directly proportional to the work added or taken away. It is the change in the
momentum of the air that provides the thrust on the turbine. Local decelerations of airflow are
also required, as for instance, in the combustion chambers to provide a low velocity zone for the
flame to burn.
There are three stages in the turbine working cycle during which these changes occur. During
compression, work is done to increase the pressure and decrease the volume of the air. This
gives a corresponding rise in the temperature. During combustion, fuel is added to the air and
burnt to increase the temperature, there is a corresponding increase in volume whilst the
pressure remains almost constant. During expansion, work is taken from the gas stream by the
turbine assembly, there is a decrease in temperature and pressure with a corresponding increase
in volume.
2.6
CHANGES IN VELOCITY AND PRESSURE
The path of the air through a gas turbine varies according to the design. Changes in the velocity
and pressure of air are consequent from aerodynamic and energy requirements. For example,
during compression a rise in the pressure of the air is required and not an increase in its velocity.
After the air has been heated and its internal energy increased by combustion, an increase in the
velocity of the gases is necessary to force the turbine to rotate.
Changes in the temperature and pressure of the air can be traced through an turbine by using an
airflow diagram. With the airflow being continuous, volume changes are shown up as changes
in velocity. The efficiency with which these changes are made will determine to what extent the
desired relations between the pressure, volume and temperature are attained. In an efficient
compressor, higher pressure will be generated for a given work input and for a given
temperature rise of the air. Conversely, the more efficient the use of the expanding gas by the
turbine, the greater the output of work for a given drop of pressure in the gas.
When air is compressed or expanded at 100 per cent efficiency, the process is called adiabatic.
An adiabatic change means there are no energy losses in the process, for example by friction,
conduction or turbulence. It is obviously impossible to achieve this efficiency in practice. 90
per cent is a good adiabatic efficiency for the compressor and turbine.
7
Changes in velocity and pressure within the turbine stages are effected by means of the size and
shape of the ducts through which the air passes on its way through the turbine. Where a
conversion from velocity (kinetic) energy to pressure is required, the passages are divergent in
shape. Conversely, where it is required to convert the energy stored in the combustion gases to
velocity energy, a convergent passage or nozzle is used.
The design of the passages and nozzles is of great importance. Their good design will affect the
efficiency with which the energy changes are effected. Any interference with the smooth airflow
creates a loss in efficiency and could result in component failure due to vibration caused by
eddies or turbulence of the airflow.
Figure 7 A gas-turbine driving a generator: 1 Fresh air, 2 compressor, 3 combustion
chamber, 4 Burners, 5 frame cylinder, 6 turbine, 7 gas turbine exhaust gas, 8
Generator. Courtesy SWRI 3
2.7
GAS TURBINES OFFSHORE
Gas turbine packages offshore often differ to those used in other applications because of the
different drivers 3. Optimum size and high power to weight ratio are key factors offshore, as
well as availability, reliability and ruggedness. Efficiency has traditionally not been so critical
because of the availability of fuel. The increasing requirement for low emissions has made
combustion efficiency an important factor. A decision is needed on whether to go for large
turbines with appropriate back-up or a smaller number of lower power turbines for specific
applications. Most suppliers have different gas turbine products for the oil and gas market. A
recent trend has been towards low-emission turbines driven by recent environmental legislation
(SI 2005 No 925 The Greenhouse Gas Emission Trading Scheme Regulations, see Section 9.5).
Some of these issues are also relevant onshore.
8
Table 1 Main drivers for turbines used in the oil and gas sector. Compared to drivers for normal industrial applications Oil & Gas Requirements
Industrial Power Generation Requirements
Availability / Reliability –
Cost of Electricity
Ruggedness
Efficiency
High Power/Weight ratio
Cost of Operations and Maintenance
Efficiency not Critical
2.8
TYPES OF GAS TURBINE
There are two main types of gas turbine: industrial and aero-derivative. Aeroderivative GTs are
a development from aircraft engines and differ in a number of respects to industrial turbines:
they are usually lighter than industrial engines, often have power turbines (PTs) manufactured
by a different manufacturer and have all anti-friction bearings in the gas producer. There is an
increasing trend to use aeroderivative gas turbines offshore in the UK, at least in terms of the
gas generator (see Section 8).
This distinction is no longer so clear. It is common practice now to include an aeroderivative
gas generator (GG) with a conventional power turbine (PT) such as in the GE PGT series.
Industrial GTs for offshore use such as those produced by Solar have moved on in simplicity
and design and increasingly mirror aeroderivative designs in size and weight. It is common
practice for turbine suppliers to match their power turbine with a standard aero-derivative gas
generator, for example the LM2500 from GE utilises a Rolls Royce RB211. Industrial heavy
duty gas turbines are referred to as Type H by the American Petroleum Institute API. Modular
or aero-derivative gas turbines, are designated Type G.
Coincidentally aero-derivatives usually offer higher efficiency and faster start-up, particularly
for larger engines. Major maintenance of aero-derivatives and smaller industrial gas turbines is
usually off-site (sometimes with engine exchange). For larger industrial gas turbines major
maintenance is usually on-site. In the past industrial gas turbines were preferred to
aeroderivative gas turbines in process applications and in mechanical drive applications where a
wide range (70% to 100%) speed control was required.
Aeroderivative GTs offer advantages in offshore or oil field applications where allowable mass
and available space are limited. The reliability and availability of the specific gas turbine are
key criteria in selection. Aero-derivative gas turbines traditionally have required premium gas
and liquid fuels. If the gas turbine fuel available is a crude oil, residual fuel oil, very lean gas,
refinery mix gas or a gas that is subject to changes then an industrial gas turbines may have
advantages. Fuel control is an important factor in low emission or DLE turbines.
2.9
PACKAGING CONCEPTS
Gas turbines for offshore installations are normally provided as part of a turbine package
developing a rated power at a rated speed and mounted on a single skid (Figure 8) and are not
9
normally custom-built to meet the user's particular power requirements. API RP 11 PGT gives
general requirements and limitations in applying these standard turbine designs.
Packaging offers several advantages. It offers a fully integrated system that can be plugged in to
the installation. It facilitates a modular approach where the same modular systems can be used
in different applications; but configured to fit the fuel and exhaust requirements of the specific
installation. It combines systems that have been developed and shown to work together. It is
simpler to get safety case approval from regulatory bodies where similar packages have already
been used on other installations.
Figure 8 Typical gas turbine package offshore installation. Courtesy Solar
2.10
TURBINE PACKAGES
The systems that would usually be included as part of a gas turbine package are illustrated
below in
Figure 9. These include:
x Air compressor (AC),
x Gas generator (GG) including combustor and gas turbine (GT), x Power turbine (PT),
x Fuel system either natural gas or liquid (pumped), x
x
x
x
x
Bearing lube oil system including tank and filters, pumps (main, pre/post, backup), Starter (usually either pneumatic, hydraulic or variable speed ac motor), Controls (on-skid, off-skid), Driven equipment
Seal gas system (compressors). There are requirements for other ancillary equipment external to the turbine package. This
includes: the enclosure and fire protection, the inlet system including air-filter (self-cleaning,
barrier or inertial) and silencer, the exhaust system including the exhaust stack and silencer, a
10
lubricating oil cooler (water, air), the motor control center, switchgear, neutral ground resistor
and inlet fogger/cooler. The layout of these systems is illustrated in Figure 10 below.
x
Figure 9 Cross section showing the typical systems included as part of a turbine package. Courtesy Solar/SwRI Figure 10 Schematic showing the systems typically included outside the turbine
package. Courtesy SWRI3
11
2.11
DESIGN FACTORS
Factors that needed to be considered in designing turbines offshore include: low weight and
dimensions, minimising vibration, resistance to saltwater, resistance to pitch and roll
particularly in floating installations. The use of 3-point mounting is common to isolate the GT
from deck movements.
Issues in procurement are considered in Appendix 2. The main basis for procurement is
normally API 616. A range of other factors need to be considered dependent on the installation.
These may include:
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Operating requirements
Spares inventory
Type selection – aeroderivative or industrial, one or two shaft
Site environment and fuel considerations
Power requirements
Installation – cranes, safe access, lay down areas, mounting, enclosures, auxiliary
equipment
Noise levels- limits, support information, general requirements
Oil tank vents
Materials – specification,temperature, corrosion and environment resistance, coatings,
certification
Starting drives - gas expansion starters, hydraulic motors, diesel engines
Foundations, baseplates and mountings
Controls and instrumentation
Inlet system – intake location, new configurations, material, leak prevention, joints and
movement allowances
Air intake grids
Air compressor cleaning
Exhaust system – Exhaust emission, height, proximity to process equipment, rain
ingress, maintenance access, recirculation
Combustion air filtration – requirements, anti-icing, shutters
Fire protection – ventilation dampers, extinguishing systems, enclosure surveillance
Acoustic enclosures – accessibility, ventilation, area classification
Fuels and fuel systems – fuel selection, gas fuels and systems, liquid fuels and systems,
dual fuel systems, power augmentation Inspection and tests – general, combustion tests, complete unit or string tests Best practice in procurement is often included in the operators design and engineering practices.
These advise on the above issues and other factors such as: definitions of vital, non-essential
and non-essential services, how these impact on selection, gas turbine enclosure ventilation,
mounting and foundation requirements, exhaust stack rain-catcher requirements and key issues
for gas turbine washing systems. Diagrams of typical installation arrangements may be
included.
2.12
TURBINE CONFIGURATION
Gas turbines offshore are normally installed in an n+1 configuration with the additional unit
providing spare capacity in case of shutdown. The number of turbines is typically 3 or 5
offshore, depending on sparing requirements and the power needed. Using a number of smaller
turbines gives more flexibility if there is frequent need for turning on and off capacity. Whether
12
to go for large or smaller engines depends on the flexibility required. With smaller engines there
are more start-ups and shutdowns. There is a trade-off between size and maintainability where
requirements exist to reduce topside weight. Standards for gas turbines give limited flexibility,
for example A36 steel is defined for the baseplate. Increasingly turbine suppliers such as Solar,
Rolls Royce and MAN use a modular approach, with application selectors to assist in the
selection of modules, filters, and other ancillary components. In offshore applications there is a
trend to use increasingly lighter materials for the casings
2.13
DRIVEN EQUIPMENT
Gas turbines are used in a number of functions offshore including oil field power generation;
gas gathering; enhanced oil recovery including gas lift, gas injection and waterflood; export
compression; gas plants and gas transport in pipelines. This is an efficient use of gas or liquid
fuel which is naturally produced on most oil installations. Typically the GT would drive a
compressor or pump, normally with gas fuel. Turbines normally duel-fuel with natural gas as
primary. The secondary diesel is used in emergency situations e.g well shut down and in
bringing systems up. Then gas is used for fuel.
(a)
(b) (c)
Figure 11 Examples of equipment driven by a gas turbine and other methods: (a)
centrifugal compressor driven by 2-shaft gas turbine, (b) centrifugal compressor
driven by variable speed electric motor (c) reciprocating compressor driven by gas
motor. Courtesy Solar
13
In this guidance note the compressors, pumps and other equipment that supplies these functions
are referred to as driven equipment where they are mechanically driven by the turbine itself
either directly or indirectly. In more recent installations there is a trend to use gas turbines
primarily for power generation with other equipment driven electrically particularly for satellite
or remote installations. Equipment may also be driven by gas motors.
There can be considerable variation in the size and ratings for a gas turbine
x
x
x
x
x
2.14
Available Output Power Range: 20 kW- 250MW (25 hp – 350,000 hp)
Smaller units (60MW or below) are typically used offshore.
Typical Gas Turbine Simple Cycle Efficiency: 25- 35%
Output Speed Range: 3000 - 25000 rpm
Fuels: Natural Gas, Liquid Fuels or duel fuel
OFFSHORE ENCLOSURES
To mitigate the risk in case of turbine failure and to reduce noise it is common but not universal
to house offshore GTs in enclosures. Offshore gas turbines may be subject to salt spray. To
avoid corrosion damage stainless steel is normally used for the enclosures, bolts and hardware.
In smaller installations and FPSOs there can be advantages not to enclose the gas turbine. This
eliminates safety risks associated with access to enclosed spaces, reduces the risk of gas or
hydrocarbon build up and simplifies ventilation requirements. Gas turbines generally operate
smoothly provided a uniform supply of air, fuel and environmental conditions are maintained,
this may be more difficult to achieve if the GT is not enclosed.
Gas turbines emit a noise level which is higher than that normally permitted and acoustic
enclosures are invariably required. Particular precautions are required for the enclosure, in
which high temperatures may prevail and flammable vapour may be present.
The acoustic enclosure may include the gas turbine, its auxiliaries and driven equipment, or it
may have separate compartments for each of these individual units. The nature of the
installation, the type of driven equipment and the composition of any flammable vapour which
could be released within the enclosure will generally dictate whether the enclosure shall be
continuous or shall have separate compartments.
Noise control requirements and ergonomics require the use of off-base mounted turbine
enclosures to provide more space for maintenance and better control of noise emission instead
of the type of enclosures formerly used which were close-fitted and mounted on the turbine
baseplate). The enclosure is often fitted with strategically located lifting beams on which a chain
block can be fitted for minor maintenance activities.
2.15
GAS TURBINE GT CYCLES
The generation of electricity by a GT is implemented by several different systems. The simple
cycle only generates electricity. In combined heat and power (CHP) plants and with waste heat
revovery systems (WHRU) the residual heat in the engine exhaust is used for a variety of
purposes ranging from industrial process heating to domestic hot water. Combined cycle gas
turbine (CCGT) plant uses the residual heat to raise steam, which drives a steam turbine
14
producing further electricity. CHP, WHR and CCGT are increasingly used in offshore
applications. More information on these is included in Section 13.
2.16
FUELS
A variety of fuels can be used by a gas turbine. While natural gas is the preferred fuel for most
UK plants, liquefied petroleum gas (LPG), refinery gas, gas oil, diesel and naphtha may be used
as main, alternate, standby or startup fuels. Hydrogen and biogas derivatives are also
increasingly being used and fuel can include waste streams produced on-site. Aero-derivative
and low emission turbines have more precise fuel requirements. Fuels are covered in Paragraph
5 of HSE Guidance Notes PM 84 and also in Paragraphs 48 to 53.
The choice is dependent on commercial and environmental considerations. Each type of fuel has
its own particular hazards arising from its physical and chemical properties. Offshore the fuel
would come from the production process with diesel backup used for startup and production
shutdown.
The characteristics of the intended fuel(s) would be stated in the data/requisition sheets.
Manufacturers are required to confirm the suitability of the intended fuel(s) and to support this
with evidence of prior experience with fuels of similar quality and composition, see ASTM D
2880. The Manufacturer would also advise on any treatment needed for the intended fuel(s) to
render it suitable for the proposed application. It also needs to be verified that the smoke
emission of the intended fuel is within local regulations.
In marginal cases, it would be investigated whether identical fuels have been used by other
operators and any specific design requirements determined, especially in relation to trace
elements. Gas turbine hot parts are particularly sensitive to alkaline metals such as sodium and
potassium. Other elements may have additional restrictions due to environmental emission
limits and the general corrosion requirements of downstream systems. Fuels containing heavy
metals may require additional fuel treatment systems. Manufacturers have comprehensive
guides to suitable fuels including advice on the permissible level of contaminants and
concentration of corrosive agents which can be tolerated in a particular fuel. This advice would
be followed in reaching agreement with the gas turbine manufacturer on acceptable levels and
concentrations for the intended fuel(s). Fuel composition is usually normalised using the Wobbe
Index and evaluated for all operating conditions, including start up
15
3
APPLICATIONS OFFSHORE
Gas turbines are used in the gas and petroleum industries to provide pumping and gas
compression facilities, often in remote locations such as a pipeline. In this case the GT may run
on fuel taken from the pipeline. Electrical power can also be generated if required, for instance
on an oil production platform. GTdriven plant can be utilised for local or national powergeneration requirements. Turbines up to about 50 megawatts (MW) may be either industrial or
modified aero-engines, while larger industrial units up to about 330 MW are purpose-built.
Applications offshore include power generation, gas injection, gas lift, waterflood and export
compression 3. A distinction can be made between upstream, midstream and downstream
applications. In this context production facilities are upstream with pipelines and transportaion
being midstream. The specific applications where gas turbines are used offshore are summarised
below.
Upstream applications of gas turbines in the oil and gas industry include the following:
x
x
x
x
x
x
x
x
x
Self-Generation- Power generation to meet needs of oil field or platform
Enhanced Oil Recovery (EOR)- Advanced technologies to improve oil recovery
Gas Lift - Injecting gas into the production well to help lift the oil
Waterflood - Injection of water into the reservoir to increase reservoir pressure and
improve production
Gas Re-injection- Re-injection of natural gas into the reservoir to increase the
reservoir pressure
Export Compression- Initial boosting of natural gas pressure from field into pipeline
(a.k.a. header compression)
Gas Gathering- Collecting natural gas from multiple wells
Gas Plant and Gas Boost- Processing of gas to pipeline quality; i.e., removal of
sulphur, water and CO. components
Gas Storage/Withdrawal- Injecting of gas into underground structure for later use:
summer storage, winter withdrawal
In midstream applications gas turbines may be used for:
x Pipeline Compression - Compression stations on pipeline to "pump" natural gas;
typically 800-1200 psi compression
x Oil Pipeline Pumping - Pumping of crude or refined oil.
Gas turbines are also used in downstream applications including refineries. These are not
covered in the context of this inspection guidance note.
3.1
POWER GENERATION
The primary application of gas turbines offshore is in power generation. The turbine will
provide direct drive to an alternator to generate power for the installation. It is normal to have at
least two GTs on main platforms with an emergency generator as back-up. Satellite and remote
or unmanned platforms are commonly provided with power from the main installation via
umbilicals rather than having their own gas turbines.
There will be different power generation requirements for floaters/semi-submersibles, fixed leg
platforms and onshore. This will depend on electrical requirements and fuel gas availability
17
The typical gas turbine size in this application is 1 MW - 30MW. The number and configuration
of turbines depends on the flexibility and redundancy needed and to allow for future platform
upgrades.
Figure 12 Array of three gas turbines being used for power generation offshore
on an FPSO. Courtesy Solar
3.2
GAS GATHERING
Gas gathering is used to collect natural gas from several wells. Modern offshore installations
may produce from 50 or more wells. In gas gathering a turbine of typically 3MW - 20MW
would typically be used
18
Figure 13
3.3
3 Body Compressor Skid for Gas Gathering Application. Courtesy Solar
GAS LIFT
Gas-lift helps Increase crude oil production by injecting natural gas into the oil well. Reduction
in oil density and aeration helps oil flow. Gas is separated and re-injected. A typical gas turbine
size of 3MW-20MW would be used in this application.
3.4
WATERFLOOD
Waterflood is another method of enhanced Oil Recovery. A gas turbine drives a centrifugal
water pump (usually with gearbox). The pressure is usually up to 600bar. Pump cavitation must
be avoided. The typical gas turbine size in this application is: 1 MW-15MW
Figure 14 Schematic illustrating water flooding for enhanced oil recovery. Courtesy Solar.
19
3.5
EXPORT COMPRESSION
Export compression is used to boost the gas pressure to flow gas to plant or pipeline. The
typical gas turbine size in this application would be ~ 3MW-30MW with the larger turbines
being used in pipeline export.
Figure 15 Gas turbine being used in export compression. Courtesy Solar 20
4
4.1
OFFSHORE PACKAGES
MODULAR TURBINE PACKAGES
In oil and gas and other sectors, turbine suppliers are increasingly offering modular turbine
packages 6 for both aero-derivative and industrial gas turbines. These offer advantages in terms
of short installation time, smaller package size, ease of maintenance, achieving regulatory
approval and reduced cost. Such packages can be tailored with a wide range of options to fit the
requirements of an individual oil and gas installation. Such packages typically include three
modules; a turbine module, a compressor module and an air-intake module.
Figure 16 Example of modular approach for aero-derivative gas generator
maintenance. Courtesy Rolls Royce
Within these units smaller modules may be included to facilitate replacement, substitution or
maintenance (Figure 16). The following systems can vary:
x
x
x
Starter
Lube oil
Fuel
21
x
x
Air-Intake
Exhaust
For example, to fit single level or multi-level installations and routes to flare, the option of axial
or radial exhaust configurations offers flexibility.
The modules can be pre-installed and packages have a common frame size. The drivers for a
modular approach are short installation time and lower total cost. An additional benefit is the
short turbine change-out time. The sequence for a modular system would be as follows: shut
down, disconnect combustion system, disconnect air-intake module, turbine ready for transport.
The time required for installation could typically be as follows6 :
x
x
x
x
Installation of Foundation and Generator module 2h
Turbine module and air-intake module 4h
Total installation ½ day
14 days to start-up
Modular systems also allow a short turbine change-out time. The typical sequence of operations
may be as follows :
x
x
x
4.2
Step 1 Shutdown and disconnect combustion system Step 2 Disconnect air intake module Step 3 Remove turbine ready for transport DESIGN OPTIONS
An important option is provision for axial or radial exhaust. This gives flexibility in layout.
Radial exhausts are excellent for multilayered systems with the silencer above. Axial exhausts
allow direct link to a waste heat recovery units (WHRU) and heavier equipment to be installed
on the top deck. Approximately 50% of offshore installations have a WHRU, usually a glycol
cleaner. The axial v radial exhaust option in Solar Titan 130 and Taurus 170 gives layout
flexibility To aid installation the two exhaust options may be configured to have the same width
and external dimensions. For example in the Titan 130 turbine both exhaust modules are 3.12m
wide and 14.22m long. In the axial system there is an additional 4.22m to the silencer, with a
13.1m vertical rise to the silencer for the radial exhaust. More information on design options
and procurement is given in Appendix 2.
4.3
FPSO TURBINE PACKAGES
Deepwater installations are an area of growth in the oil and gas sector with over 150 new
Floating production Systems (FPSs) due to be installed Worldwide in the next 5 years. Floating
Production Storage and Offloading (FPSO) vessels are the most significant, followed by
Tension Leg Platforms (TLPs) and other options such as semi-submersibles. Worldwide
approximately 10-15% of gas turbine packages are on floating installations. For example, Solar
currently have nearly 300 turbine packages on FPSs of a total of 2375 turbine packages
offshore3. These are mainly Taurus 70 or Titan 130 turbines. For power generation an FPSO
will typically have one or more gas turbines, usually including waste heat recovery (WHRU)
sytems.
The key design drivers are low topside weight, limited space and resistance to changing weather
conditions. These impose specific requirements on the turbine package. A typical turbine
22
package can weigh 110 tons. A one ton reduction in topside weight on a floating installation can
produce savings of $10,000 in cost.
Location of turbines on FPSOs will depend on the installation. On the Trenergy FPSO3, Solar
turbines are installed in the middle of the vessel. Turbines used on FPSOs can be industrial or
aeroderivative. It is understood that Solar turbines installed on FPSOs up to Jun 2004 were all
industrial 3.
Special mounting procedures are needed on FPSOs to allow for pitch and roll. Baffles are used
to stop oil movement, scavenge pumps are used on the drains of engine bearings to ensure oil is
always flowing, a 3-point mounting is used verified by finite-element analysis. A single
mounting in front with two back mountings – gives the maximum flexibility on loading.
Multiple base plates are generally used as this is less costly and allows scavenging for spare
parts. On offshore platforms and floating production and FPSOs the design of the machinery
modules can be significantly simplified if the gas turbine driving train baseplate design is rigid
and supported on a three-point mount. Alignment of the driving train is then unaffected by
platform movements. Installation of the driving train on a steel structure allows tuning to avoid
vibration transmission.
Normally offshore the gas turbine train would allow for continuous operation under a tilt angle
of maximum 3 degrees. A structural analysis would be performed to achieve the required
stiffness of the baseplate, together with stress analysis of connecting pipe work and cables to
ensure that no distortion will occur.
For FPSOs the maximum tilt angle can be substantially larger than 3 degrees. The actual static
and dynamic displacement requirements for these applications would be specified separately. As
a guide, turbine-driven generator sets in essential services must be capable of normal operation
up to and including the maximum angles specified, while generator sets in non-essential
services and mechanical-drive packages and compressor sets in process services would be
capable of surviving, but not necessarily capable of operating, at these maximum angles.
23
5
MAJOR DRIVEN EQUIPMENT There are two options for equipment driven by gas turbines, either to provide power directly
from the turbine, known as single shaft, or to drive indirectly with the driven equipment on a
separate shaft, known as two-shaft. Mechanical Drive comprises a packaged gas turbine and
rotating equipment driven by it. The base frame will be a common single unit. For larger or on
shore units this is often of two or more segments bolted together. The gas turbine may be of two
distinct types as below:
Single shaft gas turbine
In a single-shaft gas turbine the Power Turbine (PT) and Gas Generator Turbine (GGT) are
combined mechanically on to a single shaft. A single shaft turbine has all internal parts rotating
at the same speed. This gives simplicity, but requires the driven equipment to be started and
operated at the same time as the turbine core. The main use is for electric power generation.
This configuration is used in fixed speed applications (in a range: 90%-100% full speed). For
example to produce generator drive via gearbox (1500 rpm - 50 hz, 1800 rpm - 60 hz).
Figure 17 Single shaft turbine with shaft coupling. Courtesy Solar/SwRI
Two-Shaft Gas Turbine (no Shaft Coupling)
A two-shaft gas turbine has no mechanical connection between the power turbine and the hot
gas generator, thus permitting the power turbine to rotate on its shaft independently of the hot
gas generator. In a two shaft gas turbine the Power Turbine (PT) is independently supported on
its own shaft and bearings. This allows variable speed applications (typically in range 25%100% full speed). This configuration is used for compressor, pump and blower applications.
Two Shaft turbines permit the core engine to be started without spinning the driven equipment,
This configuration is applicable to mechanical drive packages.
25
Figure 18 Two-Shaft Gas Turbine (no Shaft Coupling). Courtesy Solar.
Single and two-shaft gas turbines can be used across the full power range: from 0-100% full
load , however efficiency will be low and emissions high at loads below 60%.
5.1
ALTERNATORS
The term power generation package refers to a packaged gas turbine and alternator on a
common base. Power generation is the most common application of gas turbines offshore. The
turbine package is intended for fixed speed operation for electricity generation. The gas turbine
will have matched power turbine. A load gearbox is used to match turbine and alternator shaft
speeds. Detailed information on the safety and risk issues associated with alternators can be
found in HSE report RR0762 covering inspection guidance on rotating equipment. The
alternator is directly driven and mounted on the cold inlet end of the shaft before the
compressor.
26
Figure 19 Typhoon gas turbine power generation package. Courtesy EGT Figure 20 Cross section through Typhoon gas turbine power generation package 5.2
COMPRESSORS
The second most common application of gas turbines offshore is in gas compression. A compressor package is an enclosed gas turbine with one or two gas compressors co-axially on
27
the end of the output shaft. All turbine elements are mounted to a common baseframe. An
offshore compressor package will typically be provided as a single lift module to give
simplified installation and transportation to the platform. This module includes all systems,
exhaust and waste heat recovery unit (WHRU). In addition to the GT and the driven
compressor the package would include:
x
x
x
x
x
A sub-base providing added stiffness for gas turbine and compressor skids
3-point mounts to give isolation from twisting and vibration
An inclinometer to give alarm and shutdown at high list, trim, pitch, roll angles
Baffles to provide a continued supply of lube oil at inclined operation
A scavenging pump to give a forced supply of lube oil at inclined operation
Figure 21 Single lift gas turbine compression modules. Courtesy Solar, Rolls Royce Figure 22 Typical offshore gas-turbine compressor package
28
Applications
Gas Compressors are used to increase the pressure of a process gas, in order to drive it into a
pipeline system to an onshore process plant, to use on the producing well as gas lift, to re-inject
gas for reservoir pressure maintenance or for use as a fuel gas. Centrifugal compressors are
preferred for high mass flow systems because of their simplicity and reliability compared with
screw or reciprocating compressors. In order to achieve the required pressure ratio, several
compression stages may be required, in one or more casings. Each compression stage is carried
out by a rotor in a matching diffuser. Mechanically linked compressors, working together with
drive and support equipment, may be regarded as a single system for design and safety
purposes. More detailed information on compressors can be found in HSE Report RR076.
Package Elements
An offshore gas turbine compressor package used to compress hydrocarbon gas typically
comprises a twin shaft aero-derivative gas turbine driving a barrel casing centrifugal
compressor. The package would also include the control system & ancillary equipment. The
package is mounted on a 3-point mounting skid baseplate. It is normal to enclose the gas turbine
is enclosed in an acoustic enclosure with its own fire & gas system. Ancillary equipment and
systems will include:
x Inlet Air System & Filter
x
x
x
x
x
x
x
x
x
x
Fuel System
Exhaust Duct
Lubricating Oil System
Compressor Dry Gas Seals & Support System
Drive Gearbox ( if required )
Auxiliary Gearbox
Shaft Couplings
Cooling System
Piping Systems
Condition Monitoring
Figure 23 Offshore gas turbine driven compression package. Courtesy Solar. 29
Package Configuration
Figure 24 below shows the typical configuration for an offshore gas turbine compressor
package.
Figure 24 Process Schematic Diagram - Gas Turbine Driven Gas Compression
System. Courtesy RR0762
Hazards
The major hazards have been evaluated in RR076 2 and relate to the inventory of flammable gas
that can be released if there is an equipment failure. Hazard assessment must relate to the
complete package and not just the compressor body.
The injury risk from a mechanical failure is relatively low, as the robust casing will retain parts.
Hot / moving parts may still cause injury local to the machine. Most compressors have gas seals
on moving drive shafts or piston rods. These are safety critical items when handling hazardous
materials. The gas turbine is dependent on various ancillary systems for safe operation,
operating procedures and control system must ensure that these are operational prior to turbine
start, and at all times during operation. Hot surfaces will be fitted with heat shields or thermal
insulation. These must be in place for operator safety.
Multi-stage centrifugal gas compressors contain high speed moving parts within a robust casing.
Mechanical failure can result in severe internal damage but this is not likely to pose a direct
hazard to people who are not close to the equipment. The greatest potential threat is the
uncontrolled release of a flammable hydrocarbon gas, particularly if the gas is then able to form
an explosive mixture within a relatively enclosed space.
30
The risk is reduced by ensuring that compressors are competently operated and maintained, and
that protective systems are regularly tested and in good order. The overall system design should
provide suitable remote isolations, knockout pots and adequate vent routes. Control system
issues are covered in detail in Section 7.
A limited number of safety issues can arise from inclusion of a gearbox within a machine
package. The most serious are: the potential for accidental or failure engagement of auxiliary
drives, used to rotate the compressor at low speed, leading to massive overspeed and usual
disintegration of the drive; bursting of the gear wheels (design or manufacturing flaws); fires
due to leakage of lubricating oil.
Misalignment of the main drive coupling, even within its tolerance limits, puts increased loads
on adjacent shaft bearings. It also reduces the service life of the coupling, as flexible elements
are subjected to greater strains. Coupling lubrication (where required) and inspections must be
proactively maintained as the coupling has significant mass and has the potential to become a
dangerous missile if it fails. Loss of drive is not normally a safety-related incident; special
design requirements apply if drive continuity is critical. More information of flexible couplings
can be found in Reference 2.
PM84 Guidance
Paragraph 58 of HSE Guidance Note PM84 notes that those concerned with the supply and
operation of gas compressor stations used in UK should be aware that the foreword to BS EN
12583: 2000 Gas supply systems - compressor stations - functional requirements contains the
following proviso:
`In the UK the national safety body, the Health and Safety Executive (HSE) (see CR 13737), has
required additional precautions at gas turbine driven plant, eg compressors, combined heat and
power (CHP) and combined cycle gas turbine (CCGT), in order to comply with the general
provisions of the Health and Safety at Work etc Act (HSWA). These additional precautions are
contained in HSE Guidance (Control of safety risks at gas turbines used for power generation)'.
Surge in driven compressors
Surge, which is the flow reversal within the compressor, accompanied by high fluctuating load
on the compressor bearings, has to be avoided to protect the compressor. Surge avoidance in
centrifugal compressors driven by a two stage GT has been reviewed and modelled by Kurz7..
The possible operating points of a centrifugal gas compressor are limited by maximum and
minimum operating speed, maximum available power, choke flow, and stability (surge) limit.
The usual method for surge avoidance (“anti-surge-control”) consists of a recycle loop that can
be activated by a fast acting valve (“anti-surge valve”) when the control system detects that the
compressor approaches its surge limit. Typical control systems use suction and discharge
pressure
If the surge margin reaches a preset value (often 10%), the anti-surge valve starts to open,
thereby reducing the pressure ratio of the compressor and increasing the flow through the
compressor. The situation is complicated by the fact that the surge valve also has to be capable
of precisely controlling flow. Additionally, some manufacturers place limits on how far into
choke (or overload) they allow their compressors to operate. A safety critical situation can arise
upon emergency shutdown (ESD) if manufacturer’s surge prevention measures are not properly
adhered to.
31
Here, the fuel supply to the gas turbine driver is cut off instantly, thus letting the power turbine
and the driven compressor coast down on their own inertia . Because the head-making capability
of the compressor is reduced by the square of its running speed, while the pressure ratio across
the machine is imposed by the upstream and downstream piping sys-tem, the compressor would
surge if the surge valve cannot provide fast relief of the pressure. The deceleration of the
compressor as a result of inertia and dissipation are decisive factors. The speed at which the
pressure can be relieved of the pressure not only depends on the reaction time of the valve, but
also on the time constants imposed by the piping system. The transient behavior of the piping
system depends largely on the volumes of gas enclosed by the various components of the piping
system, which may include, besides the piping itself, various scrubbers, knockout drums, and
coolers. Models allow simulation of such upset situations and avoid their occurrence in service
model to simulate shutdown events and define simpler rules that help with proper sizing of
upstream and downstream piping systems, as well as the necessary control elements.
Normal practice is to a 5% margin control to the surge limit and protect against the possibility
of surge by use of a recycle valve and operating within turbine suppliers safe operating limits.
These precautions mitigate against the possibility of surge on emergency shutdown (ESD).
Components
Acoustic enclosure
The acoustic enclosure for an aero-derivative gas turbine is normally close fitting, and fitted out
with ventilation and Fire & Gas Detection Systems. The internal space is tightly packed, making
access to internal components quite difficult. A problem on one component has the potential to
affect adjacent components or systems, either by release of material, vibration or over-heating.
It may be necessary to remove a component to work on that component or to gain access to
adjacent components.
Figure 25 Typhoon mechanical drive package. Courtesy EGT Acoustic enclosure 32
Baseframe
The baseframe needs to be sufficiently rigid to maintain machine alignment, despite movement
of the supporting structure or vessel. The 3-point mounting system normally used eliminates the
transmission of twisting forces to and from the baseframe.
In order to save space, and the weight of additional bases, as many as possible of the ancillary
systems e.g. lubrication oil system, seal gas support system, are built into the main baseframe.
The control panel may be built on to the end of the baseframe (which is convenient for prewiring) or mounted separately (which permits control panels for separate machines to be
grouped together).
Gas Turbine
The configuration for a compression package is identical to turbines in other driven
applications. The turbine will have a fuel manifold wrapped around the middle of the machine,
with multiple combustor fuel feeds. Flexible connections will link to the inlet and exhaust ducts.
The gas turbine is typically centre-line mounted from the baseframe. This ensures internal
alignment while permitting thermal expansion of the machine. The main drive shaft will be at
the hot or exhaust end for a mechanical drive package and fitted with a flexible coupling. A
similar configuration is used for any auxiliary drive shafts.
Figure 26 Cross section through Typhoon gas turbine mechanical drive package. Courtesy EGT Any mechanical failure of the turbine, or an explosion within the acoustic enclosure, could
disrupt fuel pipework, with the potential for a significant release. Missiles, in the form of
ejected compressor blades or other high-speed components, may be thrown in a mainly radial
direction, with the potential to damage people or critical systems at some distance from the
turbine.
33
Gas Compressor
The gas compressor and drive gearbox (if fitted) are normally outside the acoustic enclosure,
they may still be very closely packed with service pipework & cable trunking. Good design
should permit ready access to compressor bearings, instruments and drive couplings. The air
inlet housing is located separate from the turbine next to the external cladding of the process
area. A multi-stage barrel type centrifugal gas compressor is centre-line mounted on an
extension of the common base-frame, ensuring shaft alignment. Where two compressors are
required to achieve the required pressure ratio, the second compressor is likely to be driven from
the first compressor shaft, by a mechanical gearbox. All shafts require alignment within the
tolerances of the shaft couplings.
Process Pipework
Process pipework is connected to the barrel casings, usually by flanged connections. Fully
welded assembly is also possible. Thermal expansion of process pipework must be allowed for
by good pipe support and flexibility design; bellows are not preferred. Dependent on operating
temperatures the compressor casing and pipework may be lagged. The centre-line support
system must not be lagged, as it has to remain at ambient temperatures, so far as is possible.
Gearbox and Auxiliary gearbox
The drive gearbox included within the machine package allows the manufacturer to optimise
operating speeds of the gas turbine driver and centrifugal compressor separately. The technical
disadvantages of additional skid length, equipment complexity, and weight are offset by the
benefits for the design of compressor and turbine. Gas turbine drive packages will include an
auxiliary gearbox, normally integral to the cold end of the machine. This provides the necessary
linkage for turbine starting, and mechanical drives where required for oil or fuel pumps.
Main Drive Coupling
The use of flexible couplings within a machine package is essential to provide the necessary
degrees of freedom to enable the machine elements to be aligned, and compensate for any
flexibility inherent in the installation skid.
5.3
PUMPS
Pump packages have a similar configuration to that shown for compressors. Normally these
will require a smaller turbine. Detailed guidance on the safety risks associated with turbine
driven pumps can be found in HSE inspection guidance document RR076 2. Pumps offer a
suitable application for use of micro-turbines.
34
6
6.1
ELECTRICAL SYSTEMS
ELECTRICAL SYSTEMS
Gas turbines contain a number of electrical systems associated with control, start-up, anciliary
systems and system monitoring.
These include ignition, governing, controls and
instrumentation systems, fuel pumps, inlet guide vane (IGV) controls for variable stators,
lubrication pumps and monitoring systems for speed, torque, thrust and pressure. There will be
associated electrical systems for driven equipment. Some of this equipment will be mounted as
part of the GT skid with separate systems for example in the control room. The major use of gas
turbines offshore is for power generation using an alternator driven by the turbine. The
alternator has it’s own electrical and electromagnetic concerns2.
The associated risks do not differ significantly to electrical systems on other large mechanical
equipment installed offshore. Specific risk factors for gas turbines are:
x the potential for gas leakage from the gas turbine and exhaust systems;
x the potential for leak of fuel, seal oil or hydraulic oil;
x the high temperatures, particularly in the combustor, transition and turbine.
In the presence of flammable substances, electrical equipment can be the source of ignition due
to sparking or high temperature surfaces integral to the electrical equipment. It is important that
electrical equipment is correctly selected, used and maintained in hazardous areas where there is
the potential for flammable substances to be present. Control of gas turbine operation and
emissions requires use of sensors and monitoring devices often exposed to high temperatures
and environmental attack; this places special requirements on the materials used in such sensors
and monitoring devices and the associated electrical systems.
PM84 provides specific guidance on gas turbines including electrical issues. Specific electrical
issues covered include:
x
x
x
x
x
x
x
x
x
Compliance of technical plant to UK and international standards.
Electrical protection systems to avoid overload
Enclosures and hazardous area classification
Site safety rules and operational procedures
Requirements for risk assessment
Identification and labelling systems and the positioning of labels and notices on
switchgear, transformers, control gear and plant
Legal requirements particularly commissioning and work on live electrical
systems
Electromagnetic radiation and protection measures for live conductors magnetic
field risk and corona discharge
Practices not covered by existing safety rules and operating procedures such as
live brush changing in relation to the exciter system of the alternator (not used
offshore).
Note that live brush changing is not carried out offshore due to the hazards this would incur.
There are few situations that can be envisaged where it is not possible to shut down the exciter
system and do in a safe manner. Regulation 16 of the Electricity at Work regulations would
apply
35
Electromagnetic radiation from close proximity to live conductors is covered by National
Radiological Protection Board guidance 32 and discussed in more detail in PM84.
6.2
ELECTRICAL SYSTEMS GUIDANCE
Electrical issues are covered in Paragraphs 69 to 78 of PM84. When the initial tenders for new
power generation are drawn up, care should be given to the consideration of the technical
specifications for the electrical plant, equipment, installations and systems to be provided. It is
essential to establish that what is to be provided and installed will comply with the relevant
health and safety legislation in the United Kingdom and relevant national or international
standards. The electrical protection system should minimise the risk of potentially damaging
overload situations (that may result in catastrophic drive-train failure). Note that no UK offshore
installations synchronise with the grid system.
Hazardous area classification should be carried out for all plant items and pipework containing
flammable substances such as fuel or oils, whether in an enclosure or otherwise. It should be
carried out in accordance with relevant regulations (The Dangerous Substances and Explosive
Atmospheres Regulations 2002), the associated Approved Codes of Practice L10121, L13422 and
L13823 and current recognised standards such as BS EN 60079-10 1996 Normally, enclosures
would be expected to be classified zone 2. In some cases it may be possible to justify the
reduction of zone sizes by making a conservative allowance for the effects of the ventilation in
accordance with relevant standards andguidance. This must take into account the extent of
flammable areas from CFD predictions as described at paragraphs 35-41 above. Zoned areas
may be safe when the plant has shut down, if the fuel and other flammables are adequately
isolated, as described in paragraph 50 of PM84, and sufficiently de-pressurised. Additional
guidance relating to area classification for natural gas is given in IGE/SR/25.20 All electrical
equipment should be checked to confirm it is suitable for the area classification.
HSE Offshore Division Operations Note ON58 issued in January 2003 provides a short guide
for the offshore industry on the Dangerous Substances and Explosive Atmospheres Regulations
2002 DSEAR. HSE Offshore Division Operations Notes 59 and 63 issued in January and
December 2003 respectively provide relevant guidance on the Equipment and Protective
Systems intended for use in Potentially Explosive Atmospheres Regulations 1996 EPS.
Before plant is taken into use, site safety rules and operational procedures should be carefully
matched to the original specifications for the electrical installation, to avoid misunderstandings
by the operators. Specific agreements between users/purchasers and manufacturers as required
by some relevant standards, need to be checked to ensure full compliance.
Risk assessment should be carried out on all the electrical systems for the plant. The assessment
should also include all the risks arising during system verification and commissioning tests. The
user will be responsible for ensuring that the suppliers of electrical systems provide sufficient
information to describe the safe use of their equipment.
Identification and labelling systems and the positioning of labels and notices on switchgear,
transformers, control gear and plant have been used in the UK which differ from those normally
used. It is essential that employees are fully conversant with alternative identification and
labelling systems and that labels, notices and instructions are clearly displayed. Where this is a
potential problem, systems will have to be replaced with more familiar ones or further training
will be needed.
36
People carrying out commissioning or live work must be familiar with the plant and systems to
be commissioned. They must be trained in using a permit-towork system as described in the
regulations referred to in paragraph 87 of PM84. They must also consider the effects the work
could have on other people and plant. Adequate documentation and drawings must be available
at handover and final documentation must be completed as soon as practicable following
completion of commissioning. For the purpose of commissioning activities, inhibits and
overrides may need to be temporarily installed in order to prove the system controls. If this is
the case, a log should be maintained to ensure that they are removed and the systems reinstated,
prior to the equipment being made fully operational.
Existing safety rules and operating procedures may not address the requirements of the plant. It
may be necessary to confirm before taking operational responsibility that the rules, procedures
and all equipment, including where necessary personal protective equipment, are in place. Staff
will also have to be familiar and practised in these matters.
If electrical apparatus is located outside, then some environmental protection will be needed for
the appropriate Ingress Protection (IP) code.
6.3
ELECTROMAGNETIC RADIATION
Electromagnetic radiation hazards are covered by Paragraphs 76 to 78 of PM84. Employers
should use the guidance published by the National Radiological Protection Board32 when
assessing whether there is a risk to health.
Current flows greater than a few hundred amps are capable of producing a significant magnetic
field risk at a distance of less than one metre. Bare HV conductors may lead to people being
exposed to electric fields which exceed the NRPB investigation levels of 12 kV/m. On GT plant
the HV conductors are normally phase segregated and insulated, which will prevent corona
discharge. The only exception is the conductors from the transformer bushing to the banking
compound where a visible corona may be present.
If the measured field strengths exceed the investigation level, more detailed investigation should
be carried out to determine the induced currents arising from potential exposures. These should
be compared with the published basic restrictions and, if necessary, preventative measures
taken. Such measures could include limiting the proximity at which people may approach live
conductors. Restricting the duration of exposure is not an acceptable control strategy. In this
case suitable barriers and signs shall be in place to warn of the potential for danger.
6.4
MAINTENANCE OF ELECTRICAL SYSTEMS
Maintenance of electrical systems in hazardous areas is a specialised area and covered by a
number of standards and regulations. These include:
BS EN 60079-17: 2003 Electrical apparatus for explosive gas atmospheres. Part 17: inspection
and maintenance of electrical installations in hazardous areas (other
than mines).
IEC 60079 –17
Recommendations for inspections and maintenance of electrical
installations in hazardous areas (other than mines).
IEC 60079-19
Repair and overhaul for apparatus used in explosive atmospheres
(other than mines or explosives)
37
BS 5345 Code of practice for the selection, installation and maintenance of
electrical apparatus for use in potentially explosive atmospheres (other
than mining applications or explosives processing and manufacture).
Other IEC guidance in regard to flameproof enclosures, increased safety, intrinsic safety,
protection is also relevant. Electrical apparatus and hazardous areas has been reviewed by
Garside13. Other relevant regulations are listed in Section 16.
Specific advice and information on relevant electrical codes and regulations is given in the HSE
guidance on Explosive Atmospheres – Classification of hazardous areas (Zoning) and selection
of Equipment www.hse.gov.uk/comah/sragtech/techmeasareaclas.htm.
Inspection schedules for different equipment type and locations are given in the Tables in BS
EN 60079-17: 2003.
Gas turbines present some specific concerns in regard to electrical equipment. There is the risk
of ignition in the event of a leak of gas, fuel or lubricating oil. Gas turbine components and
casings get extremely hot during operation, particularly in the hot-gas-path and combustion
system. Any on-skid electrical equipment must be suitably protected and enclosed. Particular
consideration is needed for sensors, wiring and other electrical equipment associated with
control and monitoring systems. HSE guidance note PM84 highlights specific concerns in
regard to electrical and control systems in gas turbines. See Section 12 and Appendix 3.
A typical summary of points to look for at routine or periodic inspection of electrical systems13
may include:
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Apparatus Tag number
Cable identifications correct to loop diagram/hook-up drawing
Apparatus has no unauthorised modifications
Any rectification work noted at previous inspections has been carried out suitably
Earth connections secure
No undue corrosion (especially on flanges for Ex d)
Cable entries tight
No degradation of required IP rating
No broken covers or fan cowls
No build up of dirt on cooling fins (especially on motors)
Electrical connections tight (especially Ex e and Ex n)
Correct lamp ratings
No changes to area classification. (If so, the type of protection or its apparatus group or
T-class may not be suitable.) No damage to associated cables No damage to apparatus Covers/lids correctly secured Apparatus mounting firm and acceptable Filters clean and free from dirt and debris Breathing and draining devices clean and free from dirt and debris Cable supports OK No external obstructions to flamepaths (Ex d) No excessive grease on flamepaths (Ex d) No hard setting compound on flamepaths (Ex d) No unauthorised gaskets (especially Ex d) 38
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Gaskets of correct type
No excessive grease on bearings
No signs of excessive temperatures (e.g. brittle or burnt insulation)
No cracks to ceramic feedthroughs or insulators (especially Ex d, Ex e, and Ex de)
No obvious changes to surrounding processes which could affect area classification
No signs of leakage of filling medium (especially Ex o and Ex q)
Filling medium at required level (especially Ex o and Ex q)
No signs of leakage from stopper boxes or stopper glands (especially Ex d)
Electrical aspects remain secure: especially earth loop tests, and especially for Ex ia/ib.
Compare value with that previously noted
No dirt or obstructions to fan covers
No signs of excessive vibration
Surveillance circuits functioning correctly (especially Ex p)
Correct associated apparatus installed (Ex ia/ib)
Conduit seals satisfactory at passage between non-hazardous area and hazardous area
Cable identifications correct, and no changes to wiring
39
7
CONTROL SYSTEMS
Gas turbines are sophisticated pieces of equipment and synchronisation of the key systems
(compressor, gas turbine, power turbine) is crucial to ensure smooth operation and avoid surge
and other operational issues. This is undertaken using the control system. The control system
will also control a range of other functions including start-up, monitoring, fuel flow and
ignition, lubrication, emergency shutdown ESD. The current trend is to use distributed control
systems, both on and off the skid, with separate modules, actuators and sensors to control
individual functions. Turbines are generally replaced after 6-7 years. The control system would
be updated more regularly, typically every 3 years.
The operation of all parts of the system may be affected by temperature, environment, air input
and other factors. The different systems must respond in a synchronised way to operational
changes, changes in loading, start-up and shutdown. This synchronisation is crucial in
emergency shutdowns.
(a)
(b)
(c)
Figure 27 Modern gas turbine control system components: 9a) GE control system
(Type IV). Images courtesy GE Power Systems, Woodward.
Machines within a package need to be integrated to function as a complete system. Control
systems are designed to provide this essential control and protection for the machine elements.
This requires key logical interlocks between the main control system, the turbine control and the
compressor control. These will provide for start / run permits and sequence control, e.g. Control
Room authorisation for turbine start. These logical signals must be of high integrity as they
cannot be bypassed or ignored. There will then be numerical (possibly a mixture of analogue
and digital) signals controlling e.g. compressor load, turbine set speed, and for data logging.
41
On some of these signals it may be permissible to operate with manual over-ride, for example
during load changes. Alternately, the system may be intended to operate purely in fully
automatic mode. This will require increased sophistication such as speed ramping, critical speed
avoidance, operating temperature bands, load and speed matching during duty changes. More
guidance on these is provided in HSE Research Report RR0762
(a)
(b)
Figure 28 Control system metering and actuating components.: (a) gas fuel meter, (b)
Water injection valve fuel system. Courtesy Woodward
It is normal to test as much as possible of the Package onshore before shipping. It is not possible
to fully test and tune the control system prior to commissioning. Computer models may be used
to test the interlocks, and to some degree the load control. The greater the degree of automation,
the greater the demands on the commissioning team, who must set up and prove the system,
knowing that in normal operation load changes will be done without close manual supervision.
Control software must be rigorously checked, subject to strict version and change recording and
control. Pre-programmed cards can be fitted to the wrong machine; they may be physically
identical ( to Model and Serial Number ) but carry different instructions.
The control system will manage the following systems necessary in normal operation and startup and shutdown. Most of the control will be managed remotely (off-skid) via a separate
control room. Some systems and actuators are necessarily mounted on-skid.
x
x
x
x
x
x
x
Dedicated PLC
Emergency shutdown system ESD
Temperature and vibration monitors
Overspeed\ monitors and trips
Fuel isolation and vent valves
Lubrication control systems
Ignition and flame control systems
Separation of safety related functions (e.g. ESD, safety interlocks) or plant protection functions
from the GT operational control functions is not always possible, but is recommended wherever
reasonably practicable. Such separation usually results in a smaller and less complex safety
system, which in turn minimises the chance of design, implementation or maintenance errors in
the critical safety related functions. In addition, separation enables design features that provide
security against misuse, independence against failures in the operational control system and
avoidance of common mode faults. Where safety related and operational control functions do
42
overlap, their design should be such as to ensure that any change made to the operational
controls does not reduce the integrity of the safety related functions.
General guidance on control systems and how control system failures can lead to accidents is
given in ‘Out of Control’, HSG238 2nd Edition, HSE, 2003. The booklet discusses the technical
causes of control system failure by describing actual case studies and highlights the importance
of adopting a systematic approach throughout the system lifecycle with particular emphasis on
the specification phase. The booklet summarises the lifecycle approach to
electrical/electronic/programmable electronic safety-related systems contained in BS EN 61508.
7.1
PM84 GUIDANCE ON CONTROL SYSTEMS
Control systems are covered in Paragraphs 46 and 47 of PM84.For those hazards identified by
risk assessment and which are addressed by precautions inherent within the GT control package,
safety-related systems should be identified, specified, implemented, tested and maintained in
accordance with the principles of BS EN 61508 or IEC 61511 as appropriate. Interfaces between
the GT and site control systems should be checked to avoid mismatch and subsequent failure.
Strict controls should be in place to prevent unauthorized access to safety related systems. Such
systems may include, for example, the GT purge cycle, flame detection, fuel isolation,
ventilation detection, fixed fire protection, engine trip, and gas detector alarm/trip settings.
A mechanism for control of software changes is recommended as part of the overall
management of the software. This should also include copies of the software being held at
secure locations and procedures being in place to audit and confirm that the copies are all to the
same revision. Any changes to the hardware/software of safety-related control systems should
be accompanied by an impact assessment to determine what effect such changes will have on
the safety integrity of the control system. Any adverse effects identified by the assessment will
require the design of the control system to be revisited, and possibly modified, to restore the
safety integrity to its original level. BS EN 61508 describes a mechanism for this process. Any
changes to the safety-related control system should be documented, including the reasons for
the change, relevant technical details, the impact assessment, the design review, and any
changes to the operating/maintenance regime. The asset owner or custodian should sign off all
relevant documentation.
7.2
RECENT DEVELOPMENTS IN CONTROL SYSTEMS
Corrected parameter control
The main current method of control for gas turbines is corrected parameter control based on an
analysis of the results from the monitoring system and sensors. In most cases the turbine is
controlled by monitoring the exhaust temperature and then varying fuel input. Control is more
complex for mechanical drive GTs, as they need to run at a variable power range (typically 15100% of full power).
The basis for turbine control is exhaust control curves. The control system pulls back fuel if the
monitored exhaust temperature is too high. Turbine performance will be influenced by other
factors such as inlet filter fouling and humidity. Inlet filter fouling also induces under-firing
reducing efficiency. The humidity effect correction is a function of the water in the system.
The controller uses a baseload calibration curve with additional terms:
T= F(PR comp) +'T (NLP) + '(Tin) +' (Pexp)….
43
The equation is additive allowing corrections to be removed if they are not relevant. Exhaust
Temperature
PT Speed
Speed
Time
Figure 29 schematic illustrating the effect of the control system on power turbine (PT)
speed as the monitored exhaust temperature goes up.
Recent developments in control systems have produced performance improvements8. For
example GE use a 9% correction to exhaust temperature (of 1000 ˚C) in their new control logic
compared to the old. This gave benefits in steady fuel flow and saved 0.5MW compared to the
old T48 controls. A number of measures are implemented to ensure the control system remains
failsafe: the lowest reading are taken, the turbine trips if a sensor is lost, and a limit is set on
exhaust temperature.
Refinements in the new GE CPC Virtual T48 Control system8 include a special control logic,
fewer sensors, and more accessible sensors in the exhaust outlet, which do not disturb the gas
path. A 0.5MW saving was reported with a constant firing temperature TFire , maximising power
and environmental benefit. Power turbine LPT speeds are obtained from a model. The control
system is independent of site tuning but it is necessary to measure humidity and include this in
the fault logic.
A current trend is the use of control synchronisation and triple modular redundant (TMR)
Control systems 10 9. The application of such control systems to LM2500 aeroderivative and
LM2X Marine gas turbines is discussed in Reference10. These refinements increase redundancy
but add complexity as there are more things to look at. This balance needs to be evaluated to
determine whether the use of TMR and control synchronisation is justified for a given gas
turbine.
Control Synchronisation
Control synchronisation is an improvement in control system particularly relevant to aeroderivative gas turbines. For aero-derivative GTs response time is critical. A 5-10ms response
time is sufficient to prevent overspeed and the consequent system damage that might occur to
the GT. Industrial GTs are more tolerant.
In a synchronous control system the clock controlling the monitoring of the turbine (exhaust
temperature etc.) is synchronised with the clock controlling the application of any changes to
44
turbine operation (fuel input etc.). By synchronising the time of measurement and feeding to the
control system this gives much better accuracy and timing in the response.
Application
Software
RAM
Input/Output
Synchronous
Figure 30 schematic showing the elements of a synchronous control system and
synchronization of the monitoring and application clocks
Most current controls and/or PCCS are asynchronous and have two separate clocks one
controlling the monitoring system and one the implementation. This results in jitter or variable
delays in response of the system to any changes that are monitored by the sensors. The sensor
goes to an analogue signal, is converted to a digital signal, gets processed and then is redirected
back to an analogue output. Resampling gives more performance improvements. However,
delays can build up with time, for example 30ms delay on the 4th sampling. Aero-derivative gas
turbines are affected by only 10ms delay.
In a synchronous system, the software is in line with hardware. There are two clocks, one the
master, and the two are in synchronisation. The delay of approximately 10ms is fixed and
known even with re-sampling and can be compensated for in the control software.
The synchronisation of monitoring and turbine system response can have important safety
applications. In one incident reported to HSE on an FPSO one PLC in an asynchronous system
went dead, the other did not know and shutdown all power to the FPSO. The FPSO required
ballasting and power for dynamic positioning to stay on station. The situation degraded and the
FPSO listed. It is important to be aware of such pitfalls and the potential for knock-on failures.
Triple Modular Redundant TMR Control Systems
The Triple Modular Redundant (TMR) control system is a new development with triplicate
processor units (CPUs) and triplicate input/output. To implement a change 2 out of 3 must
agree. In the event of a loss of a CPU the control system can still function.
45
CPU
CPU
CPU
Figure 31 Schematic illustrating a Triple Modular Redundant TMR control system.
Two out of three must agree. The control system can continue to operate if one CPU
fails.
TMR is adapted from aerospace technology. In aerospace it is necessary to keep systems
operational with multiple sensor loss. TMR also guards against software bugs. Today’s
processors are markedly superior.
Redundant Network Control
A simpler less costly alternative to TMR is Redundant Network Control. Examples are given of
for LM2000 and LM2500 GTs by Woodward in Reference 9. Redundant marine gas turbines are
used on cruise ships including the QE2 and the Princess for power generation for electric marine
propulsion. In redundant network control, Master/slave backup and a Synchronous interface
(I/O) improves performance, reduces delays and eliminates random timing. TMR costly and
complex Redundant CPU is more cost effective than TMR.
Standard Control System
The Operator has a lot of say how equipment is run10. The control system is typically optimised
with the Operator on their machines. Gas turbines typically have a 15-30 year lifespan
depending on the use, maintenance overhaul schemes, parts available, upgrades and
modifications.
There is a trend to develop standard control systems10. Digital control systems typically have a
5-10 year lifespan, typically one third of turbine life. Changes in performance, environmental
condition, upgrades and operational data acquisition can require an upgrade to the control
system. Control manufacturers have sought to develop a standard product that could work for
final two thirds of GT life. The need for flexibility makes it difficult to do this at the design
stage. The main advantages of a standard system would be:
x
x
x
Low cost and off-the shelf No re-engineering Quicker installation and commissioning (important for refits). 46
x
x
x
Allow to complete within 1 week outage
Improved product support
Built in high speed datalogging capability
This would require a high speed control interface (I/O) for core signal, hardware, software and
communications applicable to single-shaft or dual shaft GTs. A typical control system would
perform four main control functions:
x
x
x
x
Gas fuel actuator Liquid fuel actuator NOx actuator
Power augmentation actuator The performance requirements include fast synchronous behaviour and repeatability for
dynamic performance. There will always be some gas turbines that wont fit and require a
bespoke system. The intention would be have a standard control system applicable to the
majority of market.
Software Architecture for a Standard control system
Custom
details
Turbine
Fuel-Control
Core
Hardware Interface
Comm, ALM, SD
Figure 32 Schematic illustrating the software architecture for a standard control
system10
The intention from a software perspective would be to have a Core turbine control module, that
does not require modification each time each time, a hardware interface and some custom
details, as illustrated in Figure 32 above. There would be separate engineering control for the
three software sections.
Gas turbine control testing is typically carried out using simulators. This allows the user to test
out in advance that everything works OK, debug and test. The control system would then just
plug in. For example, Woodward10 have developed the NETSIM PC simulation that couples a
Gas Turbine Control Application Programme (GAP) software with turbine models. This is
illustrated in Figure 33 below. The runtime software allows system checkout. The following
features are included:
47
x
x
x
x
Trending and on-line capture
Datalogging for high speed events
Data event buffering (10ms resolution)
Simulation same or better than the requirements for an aeroderivative GT
GTC
Application
Programme
GAP
PC System
Emulation
NETSIM
Turbine
Simulator
Hardware
Emulation
Turbine
Emulation
Target
Hardware
Turbine
Figure 33 Schematic diagram of control simulation software modules. Courtesy
Woodward10
A standard control system of this type has been evaluated by Woodward10 on 2 units: a Rolls
Royce Avon GT in August 2003 and a GTC250 at Mykonos in Greece. The models were run to
test options on deceleration and load drop. The simulation showed The CPU was using less
than 15% capacity.
48
8
GAS TURBINES ON UK INSTALLATIONS
An analysis of DTI emissions data at April 2004 showed 273 gas turbines installed on
installations in the UK sector. The emission regulations are relatively new and there may be
additional turbines which have not yet been reported. A summary of the installations in the UK
sector and the number of gas turbines installed on each can be found in Appendix 1.
Increasingly new or satellite plants or remote unmanned plants are added to existing fields. In
many cases these will not have their own gas-turbines for power generation with power being
supplied by umbilical from adjacent platforms.
Aeroderivative gas-turbines are increasingly favoured offshore because of the requirements for
low weight, simple changeout and ease of maintenance. For example the aeroderivative GE LM
series are now favoured over GE’s older industrial Frame series. Industrial gas turbines have
also evolved for offshore use to give compact modular systems utilising modern aerospace rotor
technology and are very different to the earlier bulkier technology commonly used in onshore
power generation. The Solar range of gas turbines used offshore (Saturn, Centaur, Taurus, Mars
and Titan are all industrial gas turbines, but offer compact, light weight accessible designs
easily incorporated in offshore skids3.
Figure 34 Summary of gas turbine suppliers for UK installations. Source analysis of
DTI emissions data April 2004
It is common for modern turbines to include modules from another manufacturer. The
manufacturers own Power Turbine (PT) may be used with a gas generator from another
supplier. Examples are the GE LM Series which uses Rolls Royce RB211 and Avon gas
generators. Similarly, some Dresser Rand gas turbines now utilise GE LM Series gas
generators. Detailed performance specifications for gas turbines worldwide are compiled
annually by Gas Turbine World Journal38.
49
8.1
PACKAGERS
In most cases the complete turbine package will be supplied by the supplier of the turbine.
There are exceptions. In some cases the turbine supplier may included turbine equipment from
another supplier because of the particular design requirements for the installation.
There are a number of independent engineering contractors who may supply the package. There
have been increasing trends to modularisation and standardisation of packages. This is preferred
by operators because it simplifies the approval process if similar packages have been installed
previously. It also simplifies operation and maintenance if all turbines have a similar
configuration. Due to the package approach the customer has little direct influence over design,
although user groups have been set up to address common issues.
8.2
SUPPLIERS
There has been much consolidation of GT suppliers in recent years with smaller supplier being
acquired by the main players to give a portfolio of products covering different sectors. For
example Siemens Westinghouse aquired Alstom’s gas turbine interests including those for
offshore application. Alstom had previously aquired European gas turbines (EGT), formerly
Ruston.
There are four main players currently worldwide in the oil and gas sector as shown below
inTable 2. These comprise Rolls-Royce, Siemens Westinghouse, GE and Solar. As well as the
model type and power rating the model number usually includes additional numbers and letters
to indicate the version and upgrades that have been applied to the turbine. Turbine suppliers do
not upgrade without good reason. Upgrades are usually based on service experience with design
changes to eliminate degradation or operation problems encountered in service.
Figure 35 More detailed breakdown of gas turbine suppliers for UK installations.
Source analysis of DTI emissions data April 2004
50
It is worth noting that many current designs such as the Avon and RB211 turbines have evolved
over a lifetime of 20 years or more, though component and system technology has significantly
advanced.
Other suppliers will often use gas turbine systems from the main suppliers. For example
Dresser Rand match the RB211 gas turbines to their own power turbines (PT), John Brown and
Thomassen are European manufacturing partners for GE industrial turbines but may give their
own designation to the model. Hitachi-Toshiba similarly are Japanese manufacturing partners
for GE. GE match their power turbines (PT) to the Rolls Royce RB211 and Avon gas
generators to give the LM series of aeroderivative gas turbines. EGT (formerly Ruston) was a
licensee to GE for full manufacture of Frame series rotor assemblies for other GE associates.
A more detailed breakdown of gas turbines on offshore installations in the UK sector by
individual manufacturers is shown in Figure 35. The information in these tables has been
gathered from a number of sources including DTI emissions data at April 2004. Analysis of
emissions data shows there are currently more than 270 gas turbines on UK installations.
This list is dominated by the same suppliers and models as the Worldwide list with Rolls-Royce
and Siemens-Westinghause, the biggest players accounting for approximately a quarter each of
UK offshore turbines. A more detailed listing can be found in Appendix 2.
Table 2 Major Oil and Gas Market Players UK and Worldwide (Below 30 MW)
Company
% UK
Models UK
Models Worldwide
Siemens-Westinghouse
(Alstom, Ruston, EGT)
46%
Tornado G8000/8004
Alstom Ruston
TB3000/4500/5000
PGT10
8MW
14MW
10MW
Typhoon
Tornado
Cyclone
PGT10
5MW
8MW
13MW
14MW
Avon
RB211
15MW
30MW
Rolls-Royce (Avon, Coberra,
RB211)
27%
Avon 1534/1535
RB211
Coberra 2000/6000
Olympus GT SK30
15MW
30MW
20MW
35MW
General Electric Oil & Gas:
12%
GE Frame 5
5MW
GE-1201/1401A-C
LM2500+ 25MW
LM5000/6000
5MW
GE5
10-15MW GE 10
25MW LM 1600
40-50MW LM 2500
5 MW
10 MW
16 MW
25 MW
Solar Turbines
11%
Saturn 20
Centaur GSC 40/50
Mars 90/100
Taurus 60
1MW
3-4MW
8-10MW
6MW
1 MW
1MW
3-4 MW 3-4MW
5-7 MW 5-7MW
8-10 MW 8-10MW
13 MW 13MW
Other
12%
ABB GT35
Dresser KG2
MTU V16
Pratt & Witney ST18
1-2MW
12MW
2MW
51
Saturn 20
Centaur 40/50
Taurus 60/70
Mars 90/100
Titan 130
5MW
10MW
16MW
25MW
RB211
Avon
Coberra
Saturn
Centaur
Taurus
Mars
Titan
Solar
Type title here
Hitachi-Toshiba
Thomassen
John Brown
Manufacturing Partners
Nuovo Pigneone
GE Industrial Turbines
General Electric
European Gas Turbines EGT
(formerly Ruston)
Alstom Power Turbines
www.alstom.com
Demag Deleval
Siemens Westinghouse
www.industrial.turbines.siemens.com
52
Allison
ABB
Other
Pratt & Witney
MAN
Dresser
Rand, Kongsberg
Figure 36 Summary of main offshore gas turbine suppliers, subsidiary companies and manufacturing associates
Rolls Royce
www.rollsroyce.com
Offshore Gas Turbine
Suppliers
9
9.1
SAFETY CASES, CODES AND REGULATIONS
RELEVANT UK INSTALLATIONS
A summary of the installations in the UK sector and the number of gas turbines installed on
each can be found in Appendix 1. Increasingly new or satellite plants or remote unmanned
plants are added to existing fields. In many cases these will not have their own gas-turbines for
power generation with power being supplied by umbilical from adjacent platforms.
9.2
INFORMATION FROM SAFETY CASES
Relatively little information on gas turbines can be found in safety cases. In most cases this is
limited to the number of turbines, their function, power rating (MW) and their location
including plan drawings. In some cases the make of the turbines and Tag Numbers may also be
included. A number of safety cases were examined during the project to look at the differences
in the information supplied by different operators.
9.3
HSE GUIDANCE NOTE PM84
HSE guidance note PM841 on gas turbines has recently been updated. This is not industry
specific and provides succinct advice on key safety issues for gas turbines. The document was
drawn up by a working group which included HSE, offshore operators and turbine suppliers.
PM84 provides guidance but is not mandatory on offshore operators. PM84 is reproduced in
full in Appendix 3 of this report. The areas covered by PM84 include:
x Fuels
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Hazards Risk assessment Precautions against fire Precautions against explosion Requirements to satisfy ATEX directive Ventilation
Control systems Fuel supply systems Gas Fuel Additional explosion precautions for liquid fuels and oils Gas compressor stations Emergency procedures Mechanical failures Electrical issues Electromagnetic radiation Legal requirements PM84 provides a very useful port of call for inspectors for definitive guidance on these key
issues. A summary of the main guidance from PM84 on each of these issues is included in the
relevant section of this report.
53
9.4
DESIGN CODES
Procurement and design of gas turbines for operation in the UK sector is usually based on the
American API design codes. These are well developed and include standard forms that can
provide the basis for procurement. For gas turbine applications in the oil & gas sector, API 616
is the foundation for most purchase specifications. Operators are reluctant to vary from standard
package specifications because of the additional regulatory approval that may be required. For
similar reasons the turbines used on a given installation for a given function, such as power
generation, are usually likely to be of very similar specification.
The codes give some flexibility, for example; API 616 Foreword states: "Equipment
Manufacturers, in particular, are encouraged to suggest alternatives to those specified when such
approaches achieve improved energy effectiveness and reduce total life costs without sacrifice
of safety and reliability."
The following codes mostly affect the packaging:
x
x
x
x
API 616 - Gas Turbines API 617 - Compressors API 614 - Lube Oil System
API 670 - Machinery Protection x API 613 - Continuous Duty Gear x API 677 - Auxiliary Drive Gear
x API 671 - Flexible Couplings In addition there are codes governing testing and operation:
x ASME PTC-22 Gas Turbine Testing
x ASME PTC-10 Compressor Testing x ASME B133 - Gas Turbines API 616 and ASME PTC-22 are the only two principal gas turbine specific codes for oil & gas
applications. API 670, 614, 613, etc. are more generic codes. The codes cover most aspects of
the gas turbine package and often form the main basis for procurement. The information
includes:
x Definitions - ISO Rating, Normal Operating Point, Maximum Continuous Speed, Trip
Speed, etc; mechanical integrity - blade natural frequencies, vibration levels, balancing
requirements, alarms and shutdowns;
x Design requirements and features - materials, welding, accessories, controls,
instrumentation, inlet/exhaust systems, fuel systems; inspection, testing, and preparation
for shipment; and
x Minimum testing, inspection and certification documentation requirements.
API 616 does not cover government local codes & regulations
54
9.5
EMISSION REGULATIONS
Emission levels on offshore installations are controlled by the EU Emissions Trading Scheme
Regulations 2005. This is implemented in the UK through Statutory Instrument 2005 No. 925
The Greenhouse Gas Emissions Trading Scheme Regulations 2005. Permits for operations are
issued by the Licensing and Consents Unit in the DTI Offshore Environment and
Decommissioning, Environmental Management Team. The EMT also maintain a database on
emissions equipment installed offshore. Gas turbines are included within these current emission
regulations. Permit applications and guidance can be found at the DTI Oil and Gas,
environment home page http://www.og.dti.gov.uk/environment/euetsr.htm
9.6
ELECTRICAL REGULATIONS
Gas turbines contain electrical systems associated with operation, monitoring and control. The
hazards associated with electrical equipment on offshore installations are well recognised. To
minimise the risk of spark ignition, fire or explosion equipment must meet the regulations on
hazardous area classification and control of ignition sources 24, 22 This requires equipment to be
suitable for the zone in which it is installed. Guidance on the application of these regulations in
the context of gas turbines can be found in PM84.
An international standard BS EN 60079/10 explains the basic principles of area classification
for gases and vapours. From 1 July 2003 DSEAR requires that new equipment and protective
systems used in a hazardous area must be selected on the basis of the requirements set out in the
DTIs equipment and protective systems for use in potentially explosive atmospheres regulations
1996 (as amended) (EPS). A detailed listing of applicable standards can be found in Reference
18
. HSE Offshore Operations Note ON59 and ON63 give a guide to the EPS regulations for
Offshore application.
Note that FPSOs and jack-ups are excluded from the EPS regulations, see paragraph 5 of ON59.
This states that “EPS applies to fixed offshore installations but not to seagoing vessels and
mobile offshore units together with equipment on board such vessels or units”. EPS therefore
excludes FPSOs and floating production platforms (FPPs), as well as MODUs, flotels and other
mobile units.t
Electrical systems represent a safety hazard because of the risk of spark ignition, fire or
explosion. For this reason there are many regulations governing the use of electrical equipment
offshore. Specific precautions are required to prevent electrical equipment being a flame source
in hazardous areas, for example the use of flameproof electrical equipment and enclosures. This
may be supplemented by other risk-reduction measures including dilution ventilation, explosion
relief and explosion suppression.
It is exceptional for gas turbines and enclosures to be installed in a hazardous area. PM84
recommends their installation in Zone 1 areas (see definitions of zones in BS EN 60079-17
should be avoided. If installation is contemplated in Zone 2 areas, expert specialist advice
should be sought. HSE guidance document PM84 gives advice on precautions that should be
considered, including source of combustion air and ventilation air, fast-acting gas detectors,
engine exhaust forced ventilation, pressure detection and interlocks, access during operation, air
loss, BS EN standards for hazardous areas Relevant regulations are the Dangerous Substances
and Explosive Atmospheres Regulations 200222 and associated Approved Codes of Practice,21,22.
HSE Offshore Operations Note ON58 gives a short guide for operators to the DSEAR
regulations.
55
There are very specific requirements in BS EN 60079-17:2003 relating to use and maintenance
of electrical equipment for use in Zone 1 and 2 areas. More information on the selection,
installation, use and maintenance of electrical systems for potentially hazardous atmospheres
can be found in References 27 and 28.
9.7
LEGAL REQUIREMENTS
Legal requirements are covered in Paragraphs 79 to 91 of PM84.
The Health and Safety at Work etc Act 1974 requires that an employer ensure the health safety
and welfare at work of all employees and people affected by such work activities. Duties
include the provision and maintenance of plant and systems of work that are, so far as is
reasonably practicable, safe and without risk to health.
The Management of Health and Safety at Work Regulations 1999 (MHSWR) require a risk
assessment to be carried out to identify and implement any necessary preventative and
protective measures.
The Provision and Use of Work Equipment Regulations 1998 complement MHSWR. The risk
assessment will help identify all the protective and preventative measures that have to be taken
in order to select suitable work equipment and safeguard dangerous parts or features of that
equipment.
The Confined Spaces Regulations 1997, together with the associated Approved Code of
Practice,22 define a confined space. An acoustic enclosure around a GT is likely to form such a
confined space. The first consideration is to avoid entry when there is a reasonably foreseeable
risk of serious injury from any hazardous substance or condition. Based on a risk assessment,
measures can then be adopted to reduce the risk to an acceptable level.
The Noise at Work Regulations 1989 require an assessment of the exposure of employees to
noise to be carried out when the first action level of 85 dB (A) or the peak action level of 200
pascals is exceeded. Hearing protection is only acceptable after all reasonably practical
measures have been taken to reduce exposure at source.
The Supply of Machinery (Safety) Regulations 1992, which implement the Machinery Directive
89/392/EEC, places duties on the responsible person who supplies relevant machinery and/or
relevant safety components in the UK market. Relevant machinery and safety components are
defined within the Regulations. The Regulations require machinery etc to satisfy the essential
health and safety requirements (EHSRs), and to undergo the appropriate conformity assessment
procedures to demonstrate that the equipment has met the EHSRs and is safe.
The Gas Act 1995 authorises the Public Gas Transporter to require the fitting of supply
protection devices to protect against excess reverse pressures, low inlet pressures, large rates of
change of flow and undue pressure/flow perturbations.
The Dangerous Substances and Explosive Atmospheres Regulations DSEAR 2002, together
with the associated Approved Codes of Practice, 17,18219 implement Directive 1999/92/EC
(the ATEX "Workplace" Directive) and are concerned with area classification and the selection
and use of equipment for use in hazardous areas.
The Gas Safety (Installation and Use) Regulations 1998 mainly apply to domestic premises.
However, regulation 38 covering the use of antifluctuators and valves applies to all gas users.
56
This reaffirms the need to notify the Public Gas Transporter and carry out any requirements set
by the Transporter in order to protect other consumers from danger. This is not relevant
offshore.
The Electricity at Work Regulations 1989 set out the safety requirements for electrical
installations and the safety of people working with or near such systems. They impose duties
primarily on the occupier of the premises but also in certain cases on employees working on the
system, including contractors.
The Equipment and Protective Systems Intended for Use in Potentially Explosive Atmospheres
Regulations 1996, which implement Directive 94/9/EC (the ATEX `Equipment' Directive), are
concerned with the supply of equipment and protective systems for use in potentially explosive
atmospheres.
The Pressure Systems Safety Regulations 2000 set requirements for pressure systems containing
a relevant fluid. A relevant fluid is defined as steam, at any pressure, a gas or a liquid which
would have a vapour pressure greater than 0.5 bar above atmospheric. Gases dissolved under
pressure are also considered relevant fluids. The Regulations impose requirements on designers,
manufacturers, suppliers, owners and users of pressure systems, together with employers of
people who modify or repair such systems. The intention of the Regulations is to prevent the
risk of serious injury from stored energy as a result of a failure of the pressure system or part of
it. The design requirements of the Pressure Systems Safety Regulations (regulations 4 and 5(1)
and (4)) are specifically disapplied for equipment designed and supplied in accordance with the
Pressure Equipment Regulations 1999.
The Pressure Equipment Regulations 1999, which implement the Pressure Equipment Directive
97/23/EC, put duties on the responsible person who places pressure equipment on the UK
market or puts such equipment into service in the UK. The Regulations apply to the design,
manufacture and conformity assessment of pressure equipment and assemblies of pressure
equipment with a maximum allowable pressure greater than 0.5 bar. The Regulations require
equipment (as defined) to satisfy the essential safety requirements and to undergo the
appropriate conformity assessment procedures to demonstrate that the equipment has met the
essential safety requirements and is safe. The conformity assessment procedures are based on
the level of hazard, which is determined by classifying the equipment according to criteria laid
down in the Regulations.
The Dangerous Substances and Explosive Atmosphere Regulations 2002 together with the
associated Approved Codes of Practice 17,18,19 implement Directive 1999/92/EC (the ATEX
“Workplace” Directive) and are concerned with area classification and the use of equipment for
use in hazardous areas.
57
10
10.1
HAZARDS AND FAILURE MODES
WHAT CAN GO WRONG
Gas turbines are complex high speed components, with tight dimensional tolerances, operating
at very high temperatures. As such, components are subject to a variety of degradation
mechanisms in service. These are dominated by creep, fatigue, erosion and oxidation with
impact damage an issue if components fail or following maintenance. Creep may eventually
lead to failure but is of most concern because of the dimensional changes it produces in
components subject to load and temperature. A major part of maintenance is checking of
dimensions and tolerances. Fatigue is or particular concern at areas of stress concentration such
as the turbine blade roots.
Gas turbines are very reliable if run at a steady state, indeed if all the main factors such as fuel
flow, and air flow are constant. Usually problems are associated with a change in one of these
external inputs.
A mechanical failure of the turbine may cause substantial mechanical damage within the
acoustic enclosure, but is less likely to cause major injury / damage outside unless blades or
other missiles are thrown. The greater risk is the uncontrolled release of fuel (gas or liquid); this
may or may not be associated with a mechanical failure. There are well-understood risks to
maintenance personnel during overhaul work; the greater safety risk is that a major failure is
initiated by inadequate or incomplete maintenance work during subsequent operation.
Any mechanical failure of the turbine, or an explosion within the acoustic enclosure, could
disrupt fuel pipework, with the potential for a significant release. Missiles, in the form of
ejected compressor blades or other high-speed components, may be thrown in a mainly radial
direction, with the potential to damage people or critical systems at some distance from the
turbine.
10.2
FAILURE MECHANISMS AND ANALYSIS
Turbine components must withstand high temperatures, high speeds of operation and fluctuating
stresses. The major degradation mechanisms that arise from this combination are:
x
x
x
x
x
x
x
x
Creep
Thermo-mechanical fatigue
High cycle fatigue
Embrittlement
Corrosion, environmental attack
Erosion
Oxidation
Foreign object damage
Gas turbine components operate to high dimensional tolerances so any mechanism causing
changes in dimensions or shape is relevant to performance, not only mechanisms causing
cracking, overload or failure.
Creep
Creep refers to progressive deformation under load experienced increasingly at higher
temperatures. Components affected by creep include:
59
Blade shrouds, turbine blades (producing twisting) turbine vanes and combustion hardware.
Creep resistance is a major design consideration.
Thermo-mechanical fatigue
This refers to fatigue damage arising from the thermo-mechanical loads experienced during
start-up, operation and shut down of gas turbines. This may lead to crack initiation and growth
leading eventually to failure. Components affected include: turbine blades, vanes, combustion
hardware. Characteristic features are wedge-shaped cracks with oxidation.
High-cycle fatigue
High cycle fatigue refers to fatigue damage arising from the rapid stress cycling experienced by
turbine components during normal operation. Components affected include: turbine blades,
vanes, discs, compressor blades and vanes. Cracking is most likely at areas of stress
concentration such as the blade fir tree roots, pitting or surface damage.
Metallurgical embrittlement
This most commonly occurs in turbine components due to formation of brittle phases such as V,
P and Laves phase on high temperature ageing. Such phases which are topologically similar to
the base material reduce toughness. Temper embrittlement by P, Sn or Sb is also possible if
solute levels are high, for components operated in the embrittlement range (400-650 qC) or if
incorrectly heat treated during manufacture.
Environmental attack
Environmental attack is possible for all components. The environment in a gas turbine arising
from combustion processes is very corrosive. Erosion will occur due to the high velocity of air
movement within the turbine. All components are susceptible to progressive oxidation,
particularly the combustion system which sees the highest temperatures.
Foreign body damage
Damage from foreign bodies is not uncommon and could affect any rotating or stationary
component in the gas stream. The operating speeds of gas turbines are such that any foreign
body passing through the flow stream is likely to cause significant damage. Causes are debris
left in during maintenance or from failure of individual components. Domestic object damage
(DOD) arising from articles left on in maintenance such as bolts, spanners etc. is usually easily
identifiable.
Manufacture or repair
Casting and weld defects such as hot tears can be introduced on manufacture or during repair.
Failure analysis
Failure analysis follows similar principles to other rotating and static components to identify the
origin and cause of failure. This may be supported by metallurgical assessment, microscopy,
fracture mechanics analysis (FMA), stress analysis, operational analysis and fuel, air and water
analysis.
60
Table 3 Causes of degradation mechanisms, hot gas components
Duty
Degradation mechanism
Continuous duty application
Rupture
Creep deflection
High cycle fatigue
Corrosion
Oxidation
Erosion
Rubs/ wear
Foreign object damage
Cyclic duty application
Thermal mechanical fatigue
High cycle fatigue
Rubs/wear
Foreign object damage
Materials
Gas turbine components are prone to materials degradation12. They spin fast, are very hot in
some parts, operate in a corrosive, oxidising and erosive environment and exhibit hot and cool
thermal cycling. Mechanisms include diffusion, ageing, formation of grain-boundary phases and
changes in microstructure.
In gas turbines nimonic alloys are mainly used for the blades, Co-Ni based alloys for
compressor components, Hastelloys (Fe-based) in heater areas. Steel is no longer used much
and increasingly taken out of turbines. This is in contrast to steam turbines which mainly use
stainless steel. Gas turbines have much tighter tolerances. Ceramics have been used for turbine
blades in some Rolls Royce designs.
Co and Ni superalloys are widely used because of strength combined with good oxidation and
environment resistance. Superalloys typically have 10-12 alloying elements present for specific
reasons.
x
x
x
x
x
x
x
x
Ni or CO as matrix
Re, W, Mo, Nb and Ta for creep hardness. These elements have a higher
diameter than the Ni or Co matrix giving solid solution strengthening.
Precipitate hardening is provided by elements like Al. For example J' Ni3Al is a
main precipitate. The matrix is austenitic.
Higher strength alloys are cast (In738, ReneCo, GTD11), lower strength alloys
are forged
Precipitate hardening is provided by carbides at the grain boundaries. The
alloys are typically give a solution heat treatment followed by one or more
ageing cycles.
The grain size is controlled. Fine grains give a lower creep strength, but better
fatigue resistance. Discs are fine-grained and forged. Blades and rotors are
course grained and cast.
Oxidation resistance comes from formation of a thin protective oxide layer such
as Al2O3, NiAl2O4 or Cr2O3.
Thermal cycling, for example stressing on start-up or shut-down can cause
spalling of the oxide layers.
61
x
x
Cr203 is better than Al203 for hot corrosion resistance. Salt or oxide deposit on
the surface is accelerated at high temperature.
Cost is about $10,000 per directionally solidified turbine blade
Fine-grained components are typically produced by powder metallurgy or forging. Controlled
orientation by: directional solidification (DS), single crystals (SX) methods. These result in no
grain boundaries and optimum orientation control.
Table 4 Function of alloying additions in IN738 Nimonic turbine blade material
Alloy Element
Purpose
Cr
Oxidation and hot-corrosion resistance
Mo, W
Solid solution strengthening
Al, Ti
Precipitates
Co, Ni
Base material
Ni
Hardening
Cb
Precipitation J'
Ta
Beneficial in oxidation
Air Compressors
There is a much greater risk of air compressor failures in large GTs12. Factors that impact on
failure in new designs include: 3D aerofoils, controlled diffusion profile, reduced aerofoil count,
stages unique with longer chords, smaller clearances, higher pressure ratios, thinner leading
edges, wet operation. Safety margins are calculated by finite element methods FEM. New
designs have resulted in higher cost (typically 10x blade cost). There may be different or
additional stresses and more risk to the blades which in newer designs generally operate with
smaller operating margins
Combustors
The combustion chamber and transition zone must encounter very high temperatures, increased
pressure and buffeting from the air flow can occur, particularly for protruding sections.
Importantly the high pressure (HP) air flow goes directly from the combustor to the power
turbine (PT). The power turbine is the most expensive part of the gas turbine and costliest to
repair. For this reason it is very important to maintain the integrity of the combustor and
transition zone. Any cracks and debris cannot be tolerated because of the potential for knock-on
damage to the power turbine. Inspection of these regions forms an important part of
maintenance and acceptance criteria are necessarily tight.
Combustion systems are more complex than previously with multiple (often 9 or more)
combustor nozzles compared to the single combustor used in early GTs. Flashback is a major
problem in the turbine aggravated by any liquids. New factors including very low emission on
gas, premix, multiple injection points, staged operation with complex controls. Combustor
62
design and cooling designs are increasingly complex. It is not possible to guarantee there will
be no liquid. These factors have reduced life of Thermal Barrier Coatings (TBCs) used on
combustors and transition systems, and arguably cost and risk have also increased.
Turbines
Turbine components are subject to creep, fatigue, corrosion, erosion and oxidation. These may
affect clearances or initiate cracking. Most critical are areas of stress concentration such as the
fir tree roots used for blade attachment. Entrance temps in the power turbine are typically 1300
- 2600 ˚C and ensuring uniform cooling is an issue (cooling air typically at 1100 ˚C). Thermal
barrier coatings TBCs are used on the inside and outside of blades. Designers are now looking
at steam cooling for large turbines, but this requires an auxiliary boiler on start up. On large
turbines there may be 100 or more blades per rotor each costing around $20,000. In single
crystal blades repair is difficult. Aerofoils are ultra-high cost and the margin to avoid melting is
difficult.
10.3
PM84 ADVICE ON MECHANICAL FAILURES
Mechanical failures in gas turbine plant are covered in Paragraphs 60 to 68 of PM84. This notes
the following.
The frequency of mechanical failures on GT plant is low. However, if it occurs in close
proximity to other plant the consequences can be severe. This is a particular concern on offshore
installations where other highpressure pipework/plant containing flammable materials can be
damaged.
On some thin-walled machines, blade failure can result in blades being ejected at high speed
through the rotor housing. The casings of some machines are protected to withstand such
failures. The need for additional protection should be considered as part of the risk assessment.
Failures can occur for a variety of reasons such as overload, deterioration or damage incurred in
use. To further reduce the risk of turbine failure, appropriate measures should be implemented
to monitor blade condition for erosion, corrosion and damage. Air inlets may be screened to
prevent the entry of foreign bodies into the turbine intakes. In such cases precautions should be
taken to avoid hazards from ice formation where icing conditions can occur.
Turbines and their housings are precision components which run at high temperature. A
vibration footprint at first run up/run down and steady state can provide a valuable reference
point. To avoid damage, procedures need to be followed when starting and stopping the GT.
These procedures are intended to mitigate the rate of expansion or contraction of the blades and
housing. If they are not followed, the rates of expansion can differ and damage can occur.
While running, the rotational speed of GTs should be controlled within safe limits to prevent
blades from being overloaded and damaged due to centrifugal force. Any safety features
provided for this purpose, such as overspeed protection, need to be maintained in good working
order and tested both off-line and on-line. For instance, overspeed testing can be achieved by
causing a trip during recommissioning from an outage. On some machines a trip condition can
be simulated by control software, while other machines can only achieve this by actually
overspeeding the machine, when careful consideration needs to be given to any increased risks
from carrying out such a test.
Blades erode and shaft bearings may wear in use and this can upset the balance of the GT. If the
erosion and/or wear are allowed to progress beyond safe limits then mechanical failure can
occur due to the lack of balance. GTs should be inspected and maintained at set intervals to
63
protect against damage or wear which may lead to safety-critical failure. Periodic preventive
maintenance should be carried out to set schemes to determine the levels of deterioration or
damage on blades and shaft bearings. When formulating the inspection scheme or carrying out
maintenance, the manufacturer's recommendations on inspection intervals or replacement
criteria for parts should be taken into account.
Condition monitoring may be used to assess the condition of blades and bearings without
resorting to costly strip-downs. However, periodic inspection still needs to be carried out at
appropriate intervals and care needs to be taken over the correct interpretation of data obtained.
This often means that condition-monitoring data needs to be collected over a period of time and
compared with the results of periodic inspections before users can have sufficient confidence in
its interpretation. Also, a history of data is often needed to measure vibration trends, which can
indicate when blades or bearings need to be replaced. Only those who are competent to make
judgments on its significance should undertake the interpretation of such data.
Airborne contaminants can enter via the air inlet and become deposited on the compressor
blades. Compressor blade cleaning, as well as maintaining the efficiency of the GT, may also
lessen any possible risk of blade failure. Air inlet filters should be cleaned and maintained
regularly.
Gearboxes should be maintained, taking into account the manufacturer's instructions. The
correct grade of oil should be used and replaced at the correct intervals specified by the
manufacturer.
Major gearbox failures have been known to cause injury as the larger units transmit significant
shaft power. Vibration monitoring and oil debris analysis can give early warning of damage.
Continued contact with the supplier and participation in user networks can supply useful
information on problems encountered in use, what to look for during inspection and the
necessary frequency of inspection intervals.
10.4
ANECDOTAL INFORMATION
Cracks have been found even in younger turbines (5-10 years) in rotors and compressors. These
can be managed by blending out without needing to condemn the component. Given the
reliability of modern turbines there is a temptation to save on maintenance costs by not looking
for cracks in newer plant. Changes in duty cycle can result in unanticipated damage. Modes may
be unusual.
Offshore operators have reported incidences of cracking in newer gas turbines such as cracking
of the turbine casings in aeroderivative engines. Maintenance is usually subcontracted out to
the supplier or turbine specialist and a lot of reliance is placed on their expertise. In one example
the operator had been told that one of the turbine blades contained a defect but this was within
acceptable limits for operation. No specific information was supplied on the defect. There was
some concern by the operator that rejection criteria may be less stringent than commonly
applied in offshore operations.
64
10.5
ACCIDENT, INCIDENT AND DANGEROUS OCCURRENCE DATA
Data extracted
A review of HSE accident and RIDDOR databases was made in June 2004 to identify incidents
that related to turbines or driven equipment. Accident data was extracted from the ORION
database using the keywords: Turbines, Generator, Generation and Compressor. The data were
reviewed and incidents not directly relating to the criteria, such as ‘walking past the compressor
when IP slipped’ were excluded. Those suggesting, for example, issues of work on compressors
in confined space were retained. This generated three separate databases:
x Dangerous occurrences were extracted from ORION using the same search criteria
mentioned above but excluding any incidents which are captured instead in
hydrocarbon release (HCR) data. Again the incident reports were reviewed for
relevance and those considered inappropriate removed, e.g. ‘scaffolding board fell onto
roof of compressor house’. (do.xls)
x Hydrocarbon Release (HCR) data was extracted using the search criteria: Systems - Gas
compression, Utilities -gas and power generated turbines and fuel gas, oil - diesel and
power generated turbines, Equipment – Turbines, Compressors. Note this includes
different types of compressors e.g. air compressors and re-compressors, though no
incidents were found for the latter (HCR data.xls)
x Data on accidents was also extracted using the same search criteria as for dangerous
occurrences (accidents.xls)
Incidents classifying equipment type as pumps were available but not included. The data
extracted covered the 14 years from 1991 to 2004
Analysis of Data
A total of 278 dangerous occurrences meeting these criteria were reported in the Period from
January 1991 to March 2004. These were classified in terms of the type of equipment
mentioned and in terms of turbines and driven equipment. The total number of occurrences in
this period is not known. The dangerous occurrences (DO) database classifies the consequences
of incidents, with terms including: ‘explosion, fire offshore, fail vessel, and fail offshore’. The
term ‘fail fairground’ is used where data has not correctly copied across. It is not possible to be
precise from the DO data as it is not always mentioned if compressors were turbine driven and
the term generators is sometimes used, as it is in safety cases, for turbines. The causes of the
occurrences relating to turbines were also classified and reviewed.
The main cause of dangerous occurrence was leakage of gas, fuel or oil which subsequently
ignited. There were a number of cases of internal explosion due to excess fuel ingress into the
combustor on start up, problems with bearing seizure, in one case leading to shaft failure. The
exhaust lagging was prone to ignition following leaks and loss of lagging had occurred in one
case due to severe storm conditions. Taking only incidents where turbine was specifically
mentioned, approximately 45% of classified incidents were associated with the turbine (See
Figure 40 below). It is likely that a proportion of the generators are in fact turbines and that
some of the compressors were turbine driven. The fires were extinguished in almost all cases
by the fire and safety system. Note that Halon fire extinguishing systems have been withdrawn
offshore for environmental reasons.
65
Figure 37 below shows the number of dangerous occurrences reported by year for these
components from 1991 to 2004. The number of reported incidents has fallen in recent years
compared to 10-15 years ago. The highest number was recorded in 1992, falling progressively
until 2000. The year 2000 recorded a rise followed by a progressive decrease in the following
years. The rise in 1992 coincides with change in HSE reporting procedures for dangerous
occurrences. It is believed this reflects better reporting criteria rather than an actual increase in
the number of incidents. A similar change is considered to be the reason for the rise in 2000.
The subsequent decreases indicate improved reliability of gas turbines and indicate the value of
monitoring dangerous occurrences in reducing risk.
60
Count of Incident Id
50
Year
1991
1992
1993
40
1994
1995
1996
1997
30
1998
1999
2000
20
2001
2002
2003
2004
10
0
Total
Figure 37 Number of dangerous occurrences associated with turbines, generators and
compressors offshore by year. Analysis of data from ORION database 1991 to 2004
The ORION database normally categorises each incident in terms of the type of incident, for
example fire offshore or release offshore. Figure 38 summarises the consequences for the
incidents where a consequence was given. This comprised less than half of the 278 incidents
identified. For 170 of the incidents the type was not described and a default description of
failed fairground was given.
In order to better understand the actual incidences occurring on offshore gas turbines we
reviewed the comments in the database in those cases where no consequence had been given.
The type of incident in most cases could be inferred directly from the comments. Figure 39
below gives an analysis of all the incidents by consequences including those inferred. The most
common incidents were fire or smoke, with release of gas next common.
Common causes of fire and smoke involved leakage of lubricating oil or hydrocarbon onto the
exhaust lagging or hot parts of the combustion system, followed by smoke or ignition. Fuel
leakages could also lead to ignition. Gas releases were commonly associated with failure of
seals. Many parts of the turbine casing are hot so any leakage of gas, oil, fuel or hydrocarbon
poses a risk of ignition. Ignition can be a problem in newer low emission turbines. If the fuel
fails to ignite then there is a risk of subsequent ignition or explosion when the air/fuel mixture
reaches the hot exhaust system. There were relatively few incidents (around 20) associated with
the electrical systems.
66
Figure 38 Analysis of dangerous occurrences by reported consequence associated with turbines, generators and compressors offshore by year. Analysis of data from ORION database 1991 to 2004. Figure 39 Analysis of dangerous occurrences offshore by reported or inferred
consequence associated with turbines, generators and compressors. Consequence
inferred from comment in ORION database where not specifically given. Analysis of
data from ORION database 1991 to 2004.
67
A different analysis of the same data by equipment type is given in Figure 40 below. This
shows the proportion of failures associated with each equipment type. Turbines do feature
prominently accounting for approximately 45% of these reported incidents. Detailed
interpretation is difficult as we are dealing with only a small subset of the overall DO data
extracted with specific criteria.
Figure 40 Proportion of dangerous occurrences associated with turbines,
generators, compressors and driven equipment.
To understand better the causes of incidents an analysis was made by turbine system, taking
only the reported incidents where a gas turbine was specifically mentioned. This analysis is
shown in Figure 41 below. This illustrates clearly that the exhaust system, particularly the
lagging is a common location for fire. The gas generator (GG), in particular the hot combustion
parts, and the fuel system also feature significantly. The next most significant systems in terms
of dangerous occurrences are the Power Turbine (PT) and the lube oil system.
Figure 41 Proportion of dangerous occurrences associated with turbines, generators, compressors and driven equipment broken down by system 68
10.6
IMIA INDUSTRIAL GAS TURBINE MEMBERS FAILURE STATISTICS
The International Association of Industrial insurers IMIA carried out a survey in 1993 of the
causes of failure of industrial gas turbines37. This covered turbines from <10MW to very large
turbines (>100MW) in the period 1984 to 1992. The information received detailed
approximately 60 failure instances totalling some £44M in terms of claims.
The arising data is summarised in Figure 42 and Figure 43. It was found that failure was most
likely to occur in the first 3 years of operation. Design faults and maintenance induced faults
(MIFS) such as leaving a rag in the machine accounted for approximately half the number of
failures. Looking in terms of cost (Figure 43) design faults account for approximately 70% of
failures.
Information from individual insurance companies in the IMIA report 37 reveals some
interesting information: one failure database covering the period 1986 to 1991 concluded that
gas turbines were more reliable than most plant coming number 25 in their rankings.
Percentage of total loss frequency was 0.25% compared with 22.12% for boilers which came
top. However, when the losses were ranked by cost gas turbines came out on top with 22% of
total payout.
Other Causes
16%
Faulty Design
Lack of Maintenance
Other Causes
Lack of Maintenance
14%
Faulty Design
70%
Figure 42 Gas turbine failures by failure category (numbers of failures). Data from IMIA
Reference 37. www.imia.com
The average cost of failure in the time period of the survey (1984 to 1992) varied from
approximately £220k for turbines <10MW, £400k for 11-49MW turbines to £500 for 50-99MW
turbines. For gas turbines >100MW the average failure cost was very much greater at £5M.
69
Lack of Maintenance
11%
Maintenance Induced
Faults
15%
Misuse
7%
Miscellaneous
7%
Unknown
5%
Maintenance Induced Faults
Design Faults
Faulty Manufacture
Faulty Installation
Unknown
Miscellaneous
Misuse
Lack of Maintenance
Design Faults
35%
Faulty Installation
9%
Faulty Manufacture
11%
Figure 43 Gas turbine failures by failure category (costs of failures). Data from IMIA
Reference 37. www.imia.com
10.7
RELIABILITY DATA FOR GAS TURBINES
The Norwegian OREDA database provides useful information on reliability of mechanical
equipment offshore including gas turbines and turbine packages. OREDA was last updated in
2002 with previous issues in 1997, 1992 and 1984. The reliability data is grouped by years
between the different issues. This is so that the statistics for current more modern equipment
are not biased by poorer statistics for early developmental models.
The 1984 OREDA data for gas turbine driven compressor packages, showed that 85% of
failures were associated with the turbine drive unit. the critical failure rate per 106 hours varied
between 460 and 1700 and for all failure modes from 3300 to 4800. OREDA is very useful in
giving comparative reliability data, although It should be noted that the populations of given
components studied in OREDA are often quite low.
OREDA also gives information on typical testing and maintenance strategy.
10.8
SUMMARY TABLES BY SYSTEM AND COMPONENT
A summary of the main failure modes and associated hazards is given below in
Table 5
.
70
System
Air Intake
Air Compressor
ID
AI
AC
As for LP Compressor, plus (5) Bleed air valve failure (where fitted), causing debris to fall into aiurflow)
Primary failure very rare, fatigue most likely.
Failure due to impact of foreign objects most common: Projectile risk to personnel. Knock on damage.
overtemperature in turbine blades, especially HP Stage Accelerated creep damage and oxidation if
1 blades, also common.
overtemperature.
For compressors, most likely failure mode due to
Knock on damage. Vibration or poor perforamnce if
impact from ingested articles; For turbines, (1) impact airflow restricted.
damage due to upstream mechanical failure (2) erosion
due to temperature effects or (3) failure due to
overtemperature most likely failure causes.
HP compressor Rotor Discs Rotor blades Stators 71
(1) Stator or rotor blade damage due to foreign object Projectile damage to personnel. Debris in airflow.
ingestion (2) Disc fatigue failure (very rare) (3) Failure Non-uniform airflow. Knock-on damage to
due to build error or (4) Failure following surge.
compressor and turbine
LP compressor Knock-on damage to turbine. Variable airflow to
turbine
Hazards
See individual components below
Cracking, fracture - impact damage due to ingested
debris or during maintenance
Failure Mode
Rotor Assembly
Air inlet
Component
Table 5 Summary of main failure modes and associated hazards by system and component.
System
C
ompressor
(cont.)
ID
AC
72
Mechanical malfunction. Reduced timing and
efficiency.
Wear and corrosion or cracking of gearwheels,
Corrosion or cracking of shafts
Accessory drive
Mechanical failure. Projectile risk to personnel.
Extensive knock-on damage to other components
Hazards
Seals rely absolutely on correct handling procedures
Gas leakage with fire or explosion risk. Poor
during installation, and some also rely on correct
performance.
lubrication and rotor balance (ie, lack of vibration)
whilst running. A damaged seal must not be fitted; seal
failure soon after gas turbine repair or overhaul activity
usually (but not always) is due to incorrect maintenance
procedure(s).
Overtemperature, insufficient or incorrect lubrication
also are common causes of bearing distress leading to
failure. Gas Turbines rely on their bearings to function
correctly; a bearing failure invariably will lead to very
extensive and expensive damage to rotors, blades and
casings.
Bearings, if treated correctly, should not fail, but
bearing failure is perceived as common. Taking
insufficient care during installation, or incorrect
transportation of an uninstalled engine newly out of
overhaul or repair, can cause damage leading to
infantile failure.
Failure Mode
Seals
Bearings
Component
System
Compressor
(cont.)
Compressor
(cont.)
Gas Generator
ID
AC
AC
GG
Hazards
73
Failure due to vibration effects; also failure due to
incorrect or improperly filtered fuel or fuel additives.
High risk of knock-on damage to power turbine.
Incorrect fuel/ air mixing with risk of explosion.
Higher emissions.
Very rare, fatigue most likely
Couplings
Fuel nozzles Very rare; fatigue most likely
Shafts
Poor turbine operation. Risk of knock-on projectile
damage
High risk of knock-on damage to power turbine
Impact damage due to foreign objects, or surge.
Inlet guide vanes
Projectile damage to personnel or adjacent pipework.
Gas leak with risk of fire or explosion
Combustion chambers Fatigue due to weakening after formation of cracks in
combustion chamber liners; secondary failure
following surge, or foreign object ingestion, or
compressor blade failure, etc.
As for casings; most likely source is damage caused
during maintenance, leading to failure at a later date.
Failure unusual unless during catastrophic failure of
Projectile damage to personnel or adjacent pipework.
internal engine components (eg, blade(s) or a disc)
Gas leak with risk of fire or explosion
whilst running; however, vibration can cause cracking
due to fatigue; impact from external sources - tools
during maintenance or carelessness whilst accessing the
external surfaces during maintenance, for instance - can
cause damage which can deteriorate and cause casing
failure at a later date.
Failure Mode
Cowls
Casing
Component
System
Gas Generator
(cont)
Power Turbine
ID
GG
PT Impact or overtemperature.
Impact or overtemperature.
Impact, incorrectly adjusted fuel flow (overfuelling) or Gas leakage. High risk of damage to Power Turbine
vibration.
(PT) downstream
Liners
Transition piece
Bucket
Overtemperature; impact damage to blades; bearing
failure.
HP Turbine 74
Unusual as a primary cause, but fatigue most likely.
Shafts Projectile risk to personnel and adjacent pipework.
Knock-on failure of other PT components.
Accelerated degradation.
High energy mechanical failure
Carelessness during maintenance - impact of some sort, Gas leakage. Risk of fire or explosion.
or internal engine component failure causing the casing
to rupture, or prolonged exposure to excessive
vibration.
Casing
Gas leakage. High risk of damage to Power Turbine
(PT) downstream
Gas leakage. High risk of damage to Power
Turbine(PT) downstream
Accelerated degradation leading to failure of
component by creep, oxidation or erosion.
Normally coatings, especially those on the hottest
components or parts of gas turbines, fail due to
overtemperature effects.
Coatings
Non-uniform fuel mixing and ignition
Hazards
Impact damage or erosion.
Failure Mode
Swirl vanes
Component
EX
Power Turbine
PT
Exhaust
(cont.)
System
ID
Overtemperature; impact damage; bearing failure.
Overtemperature, impact damage.
Lubrication issues - lack of, incorrect type, or
overtemperature caused by same. See notes for
Compressor Bearings, which also apply here.
See also comments for Compressor seals above. PT
seals also can suffer from extended exposure to high
temperatures or high levels of vibration.
These rely on pressure differentials: if the difference
does not exist, then they fail.
Corrosion, erosion, cracking
Blades
Nozzle guide vanes
Bearings
Bearing seals
Air and gas seals
Support rings
75
Vibration, impact damage or damage due to overtemperature are most common causes of exhaust
failure.
Projectile risk to personnel and adjacent pipework.
Accelerated degradation.Knock-on failure of other PT
components
Unusual as a primary cause, but fatigue most likely.
Discs
Leakage of hot exhaust gases. Risk of personnel
injury. Ignition of fuel or lubricant leaked into
insulation.
Loss of function
Gas leakage with fire or explosion risk. Poor
performance.
Loss of lubrication leading to bearing seizure and
failure. Gas leakage with fire or explosion risk. Poor
performance.
Mechanical failure. Projectile risk to personnel.
Extensive knock-on damage to other components
Reduced turbine performance.
Projectile risk to personnel and adjacent pipework.
Accelerated degradation. Knock-on failure of other
PT components
Projectile risk to personnel and adjacent pipework.
Accelerated degradation. Knock-on failure of other
PT components
As above.
LP Turbine
Hazards
Failure Mode
Component
System
Fuel system
Starter Lube Oil System
Auxiliary Gearbox
Cooling system
ID
FS
ST
LO
AG
CL
Leakage
Seals 76
Overheating of blades and other components.
Accelerated creep, oxidation and erosion damage
Mechanical failure. Loss of function.
Leakage, pressure build up
Tanks All Failure of lubricant flow Pumps
Failure to start. Fuel build up in combustion chamber
Fuel injection system Contamination by foreign objects - usually dirt
introduced in the fuel - or failure of internal
components - shafts or seals. Occasionally, failure of
power supply or incorrect scheduling during setup at
manufacture can cause problems.
Overpressure; for solid pipes, inappropriate use (eg, as Fuel, water or lubricant leak. Risk of fire or explosion
handhold) whilst fitted - flexible pipes suffer n the
same way. Occasionally, but unusually, corrosion for
solid pipes; chafing by securing clips; accidental
damage to braiding for flexible pipes.
Piping Risk of component distortion, Oxidation or failure.
Seizure. Mechanical damage to components. Risk of
projectile damage
Loss of drive. Mechanical failure.
Lubricant leak. Risk of fire, explosion.
Lubricant leak. Risk of fire, explosion.
Seizing of components, overheating, failure
Failure to start. Risk of explosion if fuel build-up.
Restricted fuel flow, non-uniform combustion. Poor
turbine operation. Risk of damage to combustion
system
Loss of turbine ignition. Potential risk of explosion.
Fatigue failure of internal components; electrical
problems or, simply, old age.
Fuel pump Fuel leak. Risk of fire or explosion.
Hazards
Corrosion, impact damage to the exterior.
Failure Mode
Fuel tank
Component
ES
Electrical Systems
All
Sensor failure
Control system (on Skid) Operational controls
CS
Component
System
ID
77
Degradation of hazardous area protection principles
Inadequate maintenance Degradation of safeguards against electrocution due
to direct or indirect contact with hazardous electrical
charge
Ignition of hazardous area flammable substance from
internal sparks or hot surfaces
Hazardous plant condition unmitigated
Fail to operate on demand
Incorrect selection for hazardous area ESD condition not detected - plant operation beyond
safety limits
Operation to within unstable or hazardous region
Spurious output
ESD system failure
Automatic operation to within unstable or hazardous
region
Sensor failure
Unrevealed failure in redundant ESD configuration degradation of safety margins
Operator unable to exercise safe control
Operator controls fail
ESD condition not detected
Operator unaware of hazardous conditions
Hazards
Indications fail
Failure Mode
System
E
lectrical Systems
(cont)
ID
ES
Inadequate isolation for working on electrical
equipment
Inadequate labelling
Mechanical damage
Circuit trip/fuse - loss of function
Electrical fault
Mechanical damage
Electrical fault
Insulation damage
Enclosure
Insulation damage
Sheath damage
Mechanical damage Insulation damage
Mechanical damage
Damage to door seals - violation of hazardous area
protection principle
Ingress of hazardous area flammable substance violation of hazardous area protection principle
Ingress of hazardous area flammable substance violation of hazardous area protection principle
Cable damage
Sparks - ignition of hazardous area flammable
substance
Mechanical damage
Inadequate supports
78
Hazardous release of electrical energy leading to fire
or explosion
Hazards
Inadequate maintenance
Failure Mode
Conduit systems
Cables
All
Component
E
lectrical Systems
(cont)
ES
Mechanical Drive
System
ID
Mechanism malfunction
Mechanism malfunction
Isolators
Circuit breakers
79
Mechanical failure See RR076 Supply trip/fuse - loss of function
Electrical fault
Switchgear
Main drive coupling
Exposure of persons to electrocution by direct contact
with hazardous electrical charge
Inadequate shrouding of live parts
Mechanical failure See RR076 Violation of hazardous area protection principle (e.g.
bolts left out of flame proof enclosure door)
Inadequate cover or door seals
Gearbox
Exposure of persons to electrocution by direct contact
with hazardous electrical charge
Covers left off
Projectile risk to personnel. Loss of drive to driven
equipment. Risk of surge or damage to driven
equipment.
Projectile risk to personnel. Loss of drive to driven
equipment. Risk of surge or damage to driven
equipment.
Catastrophic failure on fault interruption - explosion
Unable to switch or isolate loads. Heating or arcing violation of hazardous area protection principle
Sparks - ignition of hazardous area flammable
substance
Ingress of hazardous area flammable substance violation of hazardous area protection principle
Inadequate cable glands
Hazards
Ingress of hazardous area flammable substance violation of hazardous area protection principle
Failure Mode
Conduit entry points not blanked
Enclosure
Component
10.9
OTHER HAZARDS
There are a number of hazards for gas turbines that are not associated with a particular system
or component. Many of these are generic issues offshore and not specific to gas turbines.
These include:
x
x
x
x
x
x
Access to enclosures
Risk of fire or explosion from gas or fuel leakage
Risk of projectile damage
Risk of fire from lubricant leakage
Risk of injury from touching hot components, particularly exhaust and
combustion systems
Build up of harmful gases or explosive mixtures in enclosures
80
11
MAINTENANCE AND INSPECTION Gas turbines have to withstand harsh conditions including high flow, temperature and pressure.
All materials are subject to degradation by mechanisms including fatigue, creep, erosion and
oxidation.
Some failure modes can be catastrophic with a risk of projectile damage to nearby personnel,
pipework or systems. Such damage is often extensive. There is documentary evidence of
projectile parts following turbine failures cutting the turbines in half. The packaging and the
enclosures seeks to contain any possible failure.
It is very important to comply with manufacturers inspection guidance. Inspection intervals are
typically based on elapsed time or number of starts or incursions, if the latter can be monitored.
The control system may monitor the number of starts or incursions using a cycle counter or just
the number of starts. A sequence Start > Operation > Stop up and down would count as one
cycle. Incursions may lead to shut down of turbine. Modern control systems include software to
monitor incursions and operation.
11.1
OVERVIEW
Maintenance costs and availability of plant are two of the most important concerns to equipment
owners. For maintenance programmes to be fully effective, equipment owners have developed a
general understanding of the relationship between their operating plans and priorities for the
plant, the skill level of operating and maintenance personnel, and the manufacturer's
recommendations regarding the number and types of inspections, spare parts planning, and
other major factors affecting component life and proper operation of the equipment.
The primary factors, which affect the maintenance planning process, are shown below in Figure
44.
Figure 44 key factors affecting maintenance planning. Courtesy GE. 81
Parts unique to the gas turbine requiring the most careful attention are those associated with the
combustion process together with those exposed to high temperatures from the hot gases
discharged from the combustion system. They are called the hot-gas-path parts and include:
x Combustion liners, x End caps,
x Fuel nozzle assemblies, x Crossfire tubes,
x Transition pieces, x Turbine nozzles,
x Turbine stationary shrouds x Turbine buckets. The basic design philosophy and recommended maintenance for heavy-duty gas turbines is to
ensure maximum periods of operation between overhauls and inspection, and perform in-place,
on-site inspection and maintenance using local trade skills to disassemble, inspect and reassemble.
In addition to maintenance of the basic gas turbine, the control devices, fuel metering
equipment, gas turbine auxiliaries, load package, and other station auxiliaries also require
periodic servicing. Analysis of scheduled outages and forced outages show that the primary
maintenance effort is attributed to five basic systems:
x Controls and accessories, x Combustion, x Turbine,
x Generator
x Balance of plant.
The unavailability of controls and accessories is generally composed of short-duration outages,
whereas conversely the other four systems are composed of fewer, but usually longer duration
outages.
11.2
INSPECTION & REPAIR
Refurbishment of Gas Turbine Components
Overhaul and refurbishment of gas turbine components is usually carried out in specialist
workshops. This will typically follow the following sequence:
x Receipt
x Evaluation of condition x Disassembly
x Cleaning and stripping 82
x Dimensional checking x Define workscope x Heat treatment x Welding, brazing, blending x Coating
x Final inspection x Verification
Verification is needed to provide own assessment that all necessary has been done. Evaluation
of incoming condition is of crucial importance. Good workshops usually have an in-house
repair shop. Serial numbers are usually on the edges of components or cast on.
Evaluation of damage
Damage can occur in shipping and handling. On receipt it should be confirmed that
components are in the expected condition; determine the cleaning and stripping required and
then define the inspection procedure. It is very important that this evaluation of components is
done up-front.
Figure 45 Changeout of RB211 Coberra gas generator. Courtesy Rolls Royce. 83
Disassembly
Disassembly can include rotating parts and parts subject to oxidation or heat damage. These
include the turbine discs, support rings, core plugs, cowl wraps and blades. It is often found that
vanes need re-welding if previously repaired to correct poor penetration. Components are
stripped and cleaned chemically or thermo-mechanically; usually with Aluminium Oxide and
NOT sand. Good repair shops will heat tint rotating parts, turbine blades and buckets at ~1100F
(590 ºC) to show up areas of oxidation damage.
Dimensional checking
Gas turbine components operate to high tolerances. Dimensional checking is crucial early in
maintenance to ensure correct fit. This is done by physical measurements, ultrasonics and by
use of a computer measurement machine (CMM). Fixtures are used that simulate actual fitting.
Non-destructive testing (NDT)
NDT methods applied in maintenance include visual, penetrant, magnetic particle, ultrasonic
and X-radiography. Penetrant is used for side-wall inspections. Blades out MPI is normal for
turbine blades. In-situ inspection is possible using specialised ultrasonic methods and MPI of
blade end faces.
MPI and penetrant methods are used to look for cracking of casings, cowls and components in
the combustion system and hot gas path. Transient thermography with thermal signal
reconstruction (TSR) signal processing has recently been applied for inspection of compressor
and turbine blades, transition pieces and vane inspection. This method can show up loss of wall
thickness (Figure 46 and Figure 47).
Figure 46 Thermography images of turbine blade component and vane showing wall
thinning, internal air channels, and misaligned or missed channels: (a) conventional
thermography or turbine blade (b) thermography of turbine blade with TSR processing,
(c) thermography of vane with TSR processing. . Images Courtesy Thermal Wave Inc.
www.thermalwave.com
84
Metallurgical Examination
Metallurgical examination is important, particularly for hot section equipment. It is very
important that the repair shop has a metallurgist in house.
Defining of workscope
This combines evaluation, customer requirements, repair facility, inspection and standards.
Quality assurance (QA) is mandatory. Good practice includes use of an in-house repair shop,
having a suitably experienced metallurgist on site, and taking time in gas turbine repair.
Processes
Heat treatment is an important part of repairs for Ni-based superalloys. This needs to be
undertaken in a controlled atmosphere, under vacuum or hot isostatic pressure (HIP).
Temperature is controlled using 3 thermocouples; one new, one slightly used and one older,
which are replaced in a cycle. These need to be physically on the part.
Nozzle and Vanes
Most repairs to nozzles and vanes are done with TIG welding. GSAW (stick), GMAW (MIG),
GTAW (TIG) and micro-plasma welding. It is detrimental if too much weld is left on as it needs
to be ground off leaving more scope for defects.
Figure 47 Thermography images of turbine vane using TSR processing showing
variations in local wall thickness. Courtesy Thermal Wave Inc. www.thermalwave.com
Buckets and Blades
Repair of these components involves brazing processes, blending, coating and final inspection.
Dirt and oxide is removed. By brazing and diffusing at high temperature it is possible to build
up a thin wall of material to restore dimensions and wall thickness. But, this will not restore lost
strength. The component is re-profiled by blending and recoated. Thermal barrier coating is
used on aero foils.
85
Final inspection is made to check metallurgical experience, dimensions, appearance, ensure
functionality. This is best done by someone who understands the tolerances. Water is used to
check there is no blockage of cooling holes.
Quality records
These include Heat treatment checks, other process records, direct material and documentation.
11.3
MAINTENANCE GUIDANCE
The inspection and repair requirements outlined in Maintenance and Instructions Manuals
provided to owners establishes a pattern of inspections. In addition, supplementary information
is provided through a system of Technical Information Letters. This updating of information,
contained in the maintenance and instructions manual, assures optimum installation, operation
and maintenance of the turbine.
Many of the Technical Information Letters contain advisory technical recommendations to
resolve issues and improve the operation, maintenance, safety, reliability or availability of the
turbine. The recommendations contained in Technical Information Letters should be reviewed
and factored into the overall maintenance planning program.
For a maintenance program to be effective, from both a cost and turbine availability standpoint,
owners must develop a general understanding of the relationship between their operating plans
and priorities for the plant and the manufacturer's recommendations regarding the number and
types of inspections, spare parts planning, and other major factors affecting the life and proper
operation of the equipment.
The heavy-duty gas turbine is designed to withstand severe duty and to be maintained on-site,
with off-site repair required only on certain combustion components, hot-gas-path parts and
rotor assemblies needing specialized shop service. The following features are designed into
heavy-duty gas turbines to facilitate on-site maintenance:
x Casings, shells and frames are generally split on the machine horizontal centreline.
Upper halves may be lifted individually for access to internal parts. With upper-half
compressor casings removed, all stator vanes can be slid circumferentially out of the
casings for inspection or replacement without rotor removal. On most designs, the
variable inlet guide vanes (VIGVs) can be removed radially with upper half of inlet
casing removed. With the upper-half of the turbine shell lifted, each half of the first
stage nozzle assembly can be removed for inspection, repair or replacement without
rotor removal. On some units, upper-half, later-stage nozzle assemblies are lifted with
the turbine shell, also allowing inspection and/or removal of the turbine buckets.
Turbine buckets are generally moment weighed and computer charted in sets for rotor
spool assembly so that they may be replaced without the need to remove or rebalance
the rotor assembly.
x Bearing housings and liners are generally split on the horizontal centreline so that they
may be inspected and replaced, when necessary. The lower half of the bearing liner can
be removed without removing the rotor. Seals and shaft packings are usually separate
from the main bearing housings and casing structures and may be readily removed and
replaced. On most designs, fuel nozzles, combustion liners and flow sleeves can be
removed for inspection, maintenance or replacement without lifting any casings. In
general, all major accessories, including filters and coolers, are separate assemblies that
86
are readily accessible for inspection or maintenance. They may also be individually
replaced as necessary.
Inspection aids can be built into heavy-duty gas turbines to assist with inspection procedures.
These provide for visual inspection and clearance measurement of some of the critical internal
turbine gas-path components without removal of the gas turbine outer casings and shells. These
procedures include gas-path borescope inspection and turbine nozzle axial clearance
measurements. An effective borescope inspection program can result in removing casings and
shells from a turbine unit only when it is necessary to repair or replace parts. Boroscope access
locations for a gas turbine are shown below in Figure 48.
Figure 48 Typical gas turbine boroscope access locations. Courtesy GE.
There are many factors that can influence equipment life and these must be understood and
accounted for in the owner's maintenance planning. Starting cycle, power setting, type of fuel
used and level of steam or water injection are key factors in determining the maintenance
interval requirements as these factors directly influence the life of critical gas turbine parts. In
the approach of one of the major equipment suppliers (GE) to maintenance planning, a gas fuel
unit operating continuous duty, with no water or steam injection, is established as the baseline
condition, which sets the maximum recommended maintenance intervals. For operation that
differs from the baseline, maintenance factors are established that determine the increased level
of maintenance that is required. For example, a maintenance factor of two would indicate a
maintenance interval that is half of the baseline interval.
Gas turbines are affected in different ways for different service-duties. Thermo-mechanical
fatigue is the dominant limiter of life for peaking machines, while creep, oxidation, and
87
corrosion are the dominant limiters of life for continuous duty machines. Interactions of these
mechanisms are considered in the design criteria, but to a great extent are second order effects.
For that reason, maintenance requirements are based on independent counts of starts and hours.
Whichever criterion limit is first reached determines the maintenance interval.
An alternative approach, converts each start cycle to an equivalent number of operating hours
(EOH) with inspection intervals based on the equivalent hours count. This logic can create the
impression of longer intervals; while in reality more frequent maintenance inspections are
required. Different approaches to setting maintenance time are summarised below in Figure 49.
Figure 49 Gas turbine maintenance requirements. Courtesy GE.
Fuels
Fuels burned in gas turbines range from clean natural gas to residual oils. Heavier hydrocarbon
fuels have a maintenance factor ranging from three to four for residual fuel and two to three for
crude oil fuels. These fuels generally release a higher amount of radiant thermal energy, which
results in a subsequent reduction in combustion hardware life, and frequently contain corrosive
elements such as sodium, potassium, vanadium and lead that can lead to accelerated hot
corrosion of turbine nozzles and buckets.
Some elements in these fuels can cause deposits either directly or through compounds formed
with inhibitors that are used to prevent corrosion. These deposits impact performance and can
lead to a need for more frequent maintenance. Distillates, as refined, do not generally contain
high levels of these corrosive elements, but harmful contaminants can be present in these fuels
when delivered to the site. Two common ways of contaminating number two distillate fuel oil
are: salt water ballast mixing with the cargo during sea transport, and contamination of the
distillate fuel when transported to site in tankers, tank trucks or pipelines that were previously
used to transport contaminated fuel, chemicals or leaded gasoline. Natural gas fuels are
generally considered to be the optimum fuel with regard to turbine maintenance.
88
Figure 50 Hot-gas-path maintenance intervals. Courtesy GE
Table 6 Maintenance Factors – hot-gas-path
Hot gas path inspectiona
24,000 hours or 1200 starts
Major inspectionb
48,000 hours or 2400 starts
Factors impacting maintenance
Hours factors
x Fuel
x
x
Gas
1
Distillate
Crude 2 to 3
Residual
Peak load
Water/steam injection
3 to 4
Dry control 1 (GTD-222)
Wet control 1.9 (5% H2O GTD-222)
Starts Factors
x Trip from full load
x Fast Load
x Emergency start
a,b
1.5
8
2
20
Criterion is hours or starts – whichever occurs first
The importance of proper fuel quality has been amplified with Dry Low NOx (DLN)
combustion systems. Proper adherence to equipment manufacturer’s fuel specifications is
required to allow proper combustion system operation, and to maintain applicable warranties.
Liquid hydrocarbon carryover can expose the hot-gas-path hardware to severe over temperature
89
conditions and can result in significant reductions in hot-gas-path parts lives or repair intervals.
Owners can control this potential issue by using effective gas scrubber systems and by
superheating the gaseous fuel prior to use to provide a nominal 50°F (28°C) of superheat at the
turbine gas control valve connection. The prevention of hot corrosion of the turbine buckets and
nozzles is mainly under the control of the owner. Undetected and untreated, a single shipment of
contaminated fuel can cause substantial damage to the gas turbine hot gas path components.
Potentially high maintenance costs and loss of availability can be minimised or eliminated by:
x Placing a proper fuel specification on the fuel supplier. For liquid fuels, each shipment
should include a report that identifies specific gravity, flash point, viscosity, sulphur
content, pour point and ash content of the fuel.
x Providing a regular fuel quality sampling and analysis program. As part of this program,
an online water in fuel oil monitor is recommended, as is a portable fuel analyser that,
as a minimum, reads vanadium, lead, sodium, potassium, calcium and magnesium.
Water (or steam) Injection
Water (or steam) injection for emissions control or power augmentation can impact on the lives
of turbine parts and maintenance intervals. This relates to the effect of the added water on the
hot-gas transport properties. Higher gas conductivity, in particular, increases the heat transfer to
the buckets and nozzles and can lead to higher metal temperature and reduced parts lifetime.
The impact on part life from steam or water injection is related to the way the turbine is
controlled. The control system on most base load applications reduces firing temperature as
water or steam is injected.
Cyclic Effects
For the starts-based maintenance criteria (as opposed to the hours-based maintenance criteria
described earlier), operating factors associated with the cyclic effects produced during start-up,
operation and shutdown of the turbine must be considered. Operating conditions other than the
standard start-up and shutdown sequence can potentially reduce the cyclic life of the hot gas
path components and rotors, and, if present, will require more frequent maintenance and parts
refurbishment and/or replacement. A typical gas turbine start-stop cycle is illustrated in Figure
51.
Thermal mechanical fatigue testing has found that the number of cycles that a part can
withstand before cracking occurs is strongly influenced by the total strain range and the
maximum metal temperature experienced. Any operating condition that significantly increases
the strain range and/or the maximum metal temperature over the normal cycle conditions will
act to reduce the fatigue life and increase the starts-based maintenance factor.
Rotor
In addition to the hot gas path components, the rotor structure maintenance and refurbishment
requirements are affected by the cyclic effects associated with start-up, operation and shutdown.
Maintenance factors specific to an application's operating profile and rotor design must be
determined and incorporated into the operators maintenance planning. Disassembly and
inspection of all rotor components is required when the accumulated rotor starts reach the
inspection limit.
90
Figure 51 Turbine start-stop cycle – firing temperature changes
Combustion System
A typical combustion system contains transition pieces, combustion liners, flow sleeves, headend assemblies containing fuel nozzles and cartridges, end caps and end covers, and assorted
other hardware including cross-fire tubes, spark plugs and flame detectors. In addition, there can
be various fuel and air delivery components such as purge or check valves and flex hoses.
GE, for example, provides several types of combustion systems including standard combustors,
Multi-Nozzle Quiet Combustors (MNQC), IGCC combustors and Dry Low NOx (DLN)
combustors. Each of these combustion systems have unique operating characteristics and modes
of operation with differing responses to operational variables affecting maintenance and
refurbishment requirements. The maintenance and refurbishment requirements of combustion
parts are impacted by many of the same factors as hot gas path parts including start cycle, trips,
fuel type and quality, firing temperature and use of steam or water injection for either emissions
control or power augmentation.
Combustion maintenance is performed, if required, following each combustion inspection (or
repair) interval. It is expected and recommended that intervals be modified based on specific
experience. Replacement intervals are usually defined by a recommended number of
combustion (or repair) intervals and are usually combustion component specific. In general, the
replacement interval as a function of the number of combustion inspection intervals is reduced if
the combustion inspection interval is extended. For example, a component having an 8,000 hour
combustion inspection (CI) interval and a 6(CI) or 48,000 hour replacement interval would have
a replacement interval of 4(CI) if the inspection interval was increased to 12,000 hours to
maintain a 48,000 hour replacement interval.
Off Frequency Operation
Heavy-duty single shaft gas turbines are generally designed to operate over a 95% to 105%
speed range. However, operation at other than rated speed has the potential to impact
maintenance requirements. Depending on the industry code requirements, the specifics of the
91
turbine design and the turbine control philosophy employed, operating conditions can result that
will accelerate life consumption of hot gas path components. Where this is true, the maintenance
factor associated with this operation must be understood and these speed events analysed and
recorded so as to include in the maintenance plan for this gas turbine installation. Generator
drive turbines operating in a power system grid are sometimes required to meet operational
requirements that are aimed at maintaining grid stability under conditions of sudden load or
capacity changes. Most codes require turbines to remain on line in the event of a frequency
disturbance. For under-frequency operation, the turbine output decrease that will normally occur
with a speed decrease is allowed and the net impact on the turbine as measured by a
maintenance factor is minimal. In some grid systems, there are more stringent codes that require
remaining on line while maintaining load on a defined schedule of load versus grid frequency.
Air Quality
Maintenance and operating costs are also influenced by the quality of the air that the turbine
consumes. In addition to the deleterious effects of airborne contaminants on hot-gas-path
components, contaminants such as dust, salt and oil can also cause compressor blade erosion,
corrosion and fouling. Twenty-micron particles entering the compressor can cause significant
blade erosion. Fouling can be caused by sub micron dirt particles entering the compressor as
well as from ingestion of oil vapours, smoke, sea salt and industrial vapours. Corrosion of
compressor blading causes pitting of the blade surface, which, in addition to increasing the
surface roughness, also serves as potential sites for fatigue crack initiation. These surface
roughness and blade contour changes will decrease compressor airflow and efficiency, which in
turn reduces the gas turbine output and overall thermal efficiency.
Inlet Fogging
One of the ways some users increase turbine output is through the use of inlet foggers. Foggers
inject a large amount of moisture in the inlet ducting, exposing the forward stages of the
compressor to a continuously moist environment. Operation of a compressor in such an
environment may lead to long-term degradation of the compressor due to fouling, material
property degradation, corrosion and erosion. Experience has shown that depending on the
quality of water used, the inlet silencer and ducting material, and the condition of the inlet
silencer, fouling of the compressor can be severe with inlet foggers.
As an example, for turbines with Type 403 stainless steel compressor blades, the presence of
moisture will reduce blade fatigue strength by as much as 30% as well as subject the blades to
corrosion. Further reductions in fatigue strength will result if the environment is acidic and if
pitting is present on the blade. Pitting is corrosion-induced and blades with pitting can see
material strength reduced to 40% of its virgin value. The presence of moisture also increases the
crack propagation rate in a blade if a flaw is present. Water droplets, in excess of 25 microns in
diameter, will cause leading edge erosion on the first few stages of the compressor. This
erosion, if sufficiently developed, may lead to blade failure. Additionally, the roughened leading
edge surface lowers the compressor efficiency and unit performance.
92
Maintenance Inspections
Maintenance inspection types may be broadly classified as:
x Standby,
x Running
x Disassembly inspections
The standby inspection is performed during off-peak periods when the unit is not operating and
includes routine servicing of accessory systems and device calibration. The running inspection
is performed by observing key operating parameters while the turbine is running. The
disassembly inspection requires opening the turbine for inspection of internal components and is
performed in varying degrees. Disassembly inspections progress from the combustion
inspection to the hot-gas-path inspection to the major inspection as shown in the figure below.
Standby Inspections
Standby inspections are performed on all gas turbines but are applicable particularly to gas
turbines used in peaking and intermittent-duty service where starting reliability is of primary
concern. This inspection includes routinely servicing the battery system, changing filters,
checking oil and water levels, cleaning relays and checking device calibrations. Servicing can
be performed in off-peak periods without interrupting the availability of the turbine. A periodic
start-up test run is an essential part of the standby inspection.
The turbine suppliers Maintenance and Instructions Manual, as well as the Service Manual
Instruction Books, contain information and drawings necessary to perform these periodic
checks. Among the most useful drawings in the Service Manual Instruction Books for standby
maintenance are the control specifications, piping schematic and electrical configuration. These
drawings provide the calibrations, operating limits, operating characteristics and sequencing of
all control devices. This information should be used regularly by operating and maintenance
93
personnel. Careful adherence to minor standby inspection maintenance can have a significant
effect on reducing overall maintenance costs and maintaining high turbine reliability. It is
essential that a good record be kept of all inspections made and of the maintenance work
performed in order to ensure establishing a sound maintenance program.
Running Inspections
Running inspections consist of the general and continued observations made while a unit is
operating. This starts by establishing baseline operating data during initial start-up of a new unit
and after any major disassembly work. This baseline then serves as a reference from which
subsequent unit deterioration can be measured. Data should be taken to establish normal
equipment start-up parameters as well as key steady state operating parameters. Steady state is
defined as conditions at which no more than a 5°F/3°C change in wheel space temperature
occurs over a 15-minute time period. Data must be taken at regular intervals and should be
recorded to permit an evaluation of the turbine performance and maintenance requirements as a
function of operating time.
This operating inspection data, includes: load versus exhaust temperature, vibration, fuel flow
and pressure, bearing metal temperature, lube oil pressure, exhaust gas temperatures, exhaust
temperature spread variation and start-up time. This list is only a minimum and other parameters
should be used as necessary. A graph of these parameters will help provide a basis for judging
the conditions of the system. Deviations from the norm help pinpoint impending trouble,
changes in calibration or damaged components.
11.4
DISASSEMBLY INSPECTIONS
Combustion Inspection
The combustion inspection is a relatively short disassembly shutdown inspection of fuel
nozzles, liners, transition pieces, crossfire tubes and retainers, spark plug assemblies, flame
detectors and combustor flow sleeves. This inspection concentrates on the combustion liners,
transition pieces, fuel nozzles and end caps which are recognized as being the first to require
replacement and repair in a good maintenance program. Proper inspection, maintenance and
repair of these items will contribute to a longer life of the downstream parts, such as turbine
nozzles and buckets.
Hot-Gas-Path Inspection
The purpose of a hot-gas-path inspection is to examine those parts exposed to high temperatures
from the hot gases discharged from the combustion process. The hot-gas-path inspection
includes the full scope of the combustion inspection and, in addition, a detailed inspection of the
turbine nozzles, stationary stator shrouds and turbine buckets. To perform this inspection, the
top half of the turbine shell must be removed. Prior to shell removal, proper machine centreline
support using mechanical jacks is necessary to assure proper alignment of rotor to stator, obtain
accurate half-shell clearances and prevent twisting of the stator casings.
The first-stage turbine nozzle assembly is exposed to the direct hot-gas discharge from the
combustion process and is subjected to the highest gas temperatures in the turbine section. Such
conditions frequently cause nozzle cracking and oxidation and, in fact, this is expected. The
second- and third-stage nozzles are exposed to high gas bending loads, which, in combination
with the operating temperatures, can lead to downstream deflection and closure of critical axial
clearances. To a degree, nozzle distress can be tolerated and criteria have been established for
94
determining when repair is required. These limits are contained in the Maintenance and
Instruction Books previously described. As a general rule, first stage nozzles will require repair
at the hot-gas path inspection. The second- and third-stage nozzles may require refurbishment to
re-establish the proper axial clearances. Normally, turbine nozzles can be repaired several times
to extend life and it is generally repair cost versus replacement cost that dictates the replacement
decision.
Coatings play a critical role in protecting the combustion buckets operating at high metal
temperatures to ensure that the full capability of the high strength superalloy is maintained and
that the bucket rupture life meets design expectations. This is particularly true of cooled bucket
designs that operate above 1985°F (1085°C) firing temperature. Significant exposure of the base
metal to the environment will accelerate the creep rate and can lead to premature replacement
through a combination of increased temperature and stress and a reduction in material strength.
This degradation process is driven by oxidation of the unprotected base alloy. In the past, on
early generation uncooled designs, surface degradation due to corrosion or oxidation was
considered to be a performance issue and not a factor in bucket life. This is no longer the case at
the higher firing temperatures of current generation designs. These factors are illustrated in
Figure 52.
Given the importance of coatings, it must be recognized that even the best coatings available
will have a finite life and the condition of the coating will play a major role in determining
bucket replacement life. Refurbishment through stripping and recoating is an option for
extending bucket life, but if recoating is selected, it should be done before the coating has
breached to expose base metal.
Figure 52 Stage 1 bucket oxidation and bucket life. Courtesy GE 95
11.5
MAJOR INSPECTION
The purpose of the major inspection is to examine all of the internal rotating and stationary
components from the inlet of the machine through the exhaust section of the machine. A major
inspection should be scheduled in accordance with the recommendations in the owner's
Maintenance and Instructions Manual or as modified by the results of previous borescope and
hot-gas-path inspection. The work scope involves inspection of all of the major flange-to-flange
components of the gas turbine which are subject to deterioration during normal turbine
operation. This inspection includes previous elements of the combustion and hot-gas-path
inspections, in addition to laying open the complete flange-to-flange gas turbine to the
horizontal joints, as shown in Figure ##, with inspections being performed on individual items.
Prior to removing casings, shells and frames, the unit must be properly supported. Proper
centreline support using mechanical jacks and jacking sequence procedures are necessary to
assure proper alignment of rotor to stator, obtain accurate half shell clearances and to prevent
twisting of the casings while on the half shell.
Typical major inspection requirements for all machines are:
x All radial and axial clearances are checked against their original values (opening and
closing).
x Casings, shells and frames/ diffusers are inspected for cracks and erosion.
x Compressor inlet and compressor flowpath are inspected for fouling, erosion, corrosion
and leakage. The IGVs are inspected, looking for corrosion, bushing wear and vane
cracking.
x Rotor and stator compressor blades are checked for tip clearance, rubs, impact damage,
corrosion pitting, bowing and cracking.
x Turbine stationary shrouds are checked for clearance, erosion, rubbing, cracking, and
build-up.
x Seals and hook fits of turbine nozzles and diaphragms are inspected for rubs, erosion,
fretting or thermal deterioration.
x Turbine buckets are removed and a non-destructive check of buckets and wheel
dovetails is performed (first stage bucket protective coating should be evaluated for
remaining coating life). Buckets that were not recoated at the hot-gas-path inspection
should be replaced.
x Rotor inspections recommended in the maintenance and inspection manual or by
Technical Information Letters should be performed.
x Bearing liners and seals are inspected for clearance and wear.
x Inlet systems are inspected for corrosion, cracked silencers and loose parts.
x Exhaust systems are inspected for cracks, broken silencer panels or insulation panels.
x Check alignment - gas turbine to generator/gas turbine to accessory gear.
96
11.6
TURBINE BORE INSPECTIONS
Inspection of the bore and inside of rotors in gas and steam turbines has been difficult due to the
poor access and illumination. Commercial ultrasonic systems are now available that deploy
arrays of ultrasonic probes inside the bore to look for signs of cracking. A new commercial
system is shown below in Figure 53.
Figure 53 Ultrasonic turbine bore inspection system. Deploys arrays of ultrasonic
probes. Courtesy Phoenix
11.7
CLEANING
Gas turbine operation produces deposits and fouling which can affect smooth operation. It is
normal practice to clean the turbine at regular intervals. This is commonly done by the injection
of water droplets. It is very individual how this is done, different methods may be required for
on-line washing for 2-stage and one-stage turbines. Cleaning is characterised by flow rate and
pressure. To assist cleaning and optimise the process models have been developed for washing
systems17. Such models may typically plot air flow rate versus power output. Smaller droplets
are desirable to avoid erosion. Injection may be into crossflow or parallel. Higher momentum
(size, velocity) gives better air flow penetration.
Washing frequency depends on the installation profile. Economic analysis is commonly used to
balance cleaning with operational requirements. For cleaning and other monitoring and
maintenance the following definitions are used:
x off-line not firing fuel,
x on-line firing fuel.
At high pressures small droplets are preferred, at low pressures 100-200Pm particles are typical.
In off-line cleaning the gas turbine is run at crank speed for cleaning; on-line the GT is run at
up-speed. There is a risk of running in flutter mode if too much water.
97
Key points to note for gas turbine washing include: x On-line washing may not restore full power since dirt may be moved down the
compressor section settling at the high pressure sections.
x On-line washing needs to be supplemented with off-line washing to restore near-full
power conditions. To be effective, on-line washing needs to be carried out frequently
(once every 72 hours is typical)
x After each detergent on-line wash, a rinse wash should be applied to remove residue
from the injection nozzles.
x Effectiveness of washing techniques depends on the type of fouling experienced, the
selected washing liquid and the location of the injection nozzles.
x Solvent-based detergents are the most effective cleaning detergents. Water-based
detergents are less effective.
x Logging of performance records before and after washing are crucial to the washing
operation.
x Demineralised water with purity in accordance with Manufacturer's recommendations is
best used for washing. The critical issue is corrosion of the hot gas path due to
impurities.
x Selection of washing detergent needs to be based on the lowest possible ash content to
minimise hot gas path corrosion.
x For off-line washing, waste water handling shall be considered.
The cleaning of gas turbines has been modelled at Cranfield University and reported at
Turbo200417. Particles deposit during operation; reduce inlet size and affect blade performance.
To clean it is normal to inject water droplets upstream of the compressor. There are a variety of
intake ducts on a given GT and a variety of operating conditions. Experiments are costly and
difficult; therefore it is preferable to do numerical analysis. Filter loss is included as a
correction, not explicitly included in the model domain. Outlet power and inlet mass flow
depend on installation, altitude (m), high ambient temperatures.
The Cranfield study modelled two scenarios: design point (DP) and a High Desert extreme
heavy duty installation (HD). At 870m in the HD environment power is down 23% and inlet
mass flow significantly reduced.
Droplet trajectories were modelled for a for 40˚ solid cone pattern. Flow was disrupted by the
bearing support struts. In gas turbine cleaning a complete wetting of first blade row from hub to
tip is essential. The spray centre line at the IGV was modelled. Better penetration was observed
as the velocity goes up. In HD conditions lower flow occured, better penetration above shaft
cone, adverse below. Shading occurred from the support struts. Jets impinged on the casing and
hit the support strut. The effect of particle size 300um and 50-500um was modelled.
It was concluded that operating condition has an effect on spray injection, Droplet trajectories
modelled based on momentum balance showed droplet diameter, injection velocity and
injection angle to be key factors. Small GTs have lower mass flow but similar operating
velocities to large GTs. The injection angle provides a simple method of compensation. It is a
common configuration to have vertical inlet ducts; in this situation the shaft cone is an obstacle.
98
11.8
SUMMARY BY SYSTEM AND COMPONENT
A summary of inspection practice by system and component is given below in Table 7. It should
be noted this is a general summary and actual inspection practice will vary between
manufacturer and turbine type; industrial or aero-derivative. Manufacturers may choose to
concentrate on specific areas dependent on the service experience with specific models and past
inspection and service experience on a given installation. There are areas such as the
combustion, hot gas path, exhaust and fuel systems that are common locations for degradation
in service and reported incidents (see Section 10.5).
99
Inspection
Standby Inspections
Running Inspections
ID
SI
RI
Establishing baseline operating
data during initial start-up of a new
unit and after any major
disassembly work. This baseline
serves as a reference from which
subsequent unit deterioration can
be measured.
Running inspections consist of
general and continued
observations made while a unit is
operating.
Standby inspections are
performed on all gas turbines but
are applicable particularly to gas
turbines used in peaking and
intermittent-duty service where
starting reliability is of primary
concern.
Purpose of Inspection
Gas Turbine
100
Start-up, lubrication,
cooling, cleaning and
fuel systems
System
On-line sensors
Various
Components
This list is only a minimum and other parameters should be
used as necessary. A graph of these parameters will help
provide a basis for judging the conditions of the system.
Deviations from the norm help pinpoint impending trouble,
changes in calibration or damaged components.
This operating inspection data includes: load versus
exhaust temperature, vibration, fuel flow and pressure,
bearing metal temperature, lube oil pressure, exhaust gas
temperatures, exhaust temperature spread variation and
start-up time.
Data must be taken at regular intervals and should be
recorded to permit an evaluation of the turbine performance
and maintenance requirements as a function of operating
time.
Operating inspection data to establish normal equipment
start-up parameters as well as key steady state operating
parameters. Steady state is defined as conditions at which
no more than a 5°F/3°C change in wheel space
temperature occurs over a 15-minute time period.
This inspection includes routinely servicing the battery
system, changing filters, checking oil and water levels,
cleaning relays and checking device calibrations. Servicing
can be performed in off-peak periods without interrupting
the availability of the turbine. A periodic start-up test run is
an essential part of the standby inspection.
Inspection
Table 7 Summary of inspection practice for gas turbine systems and components
Disassembly - Hot gas path The purpose of a hot-gas-path
inspection
inspection is to examine those
parts exposed to high
temperatures from the hot gases
discharged from the combustion
process.
Major Inspection
HCP
MI
All significant
components
Hot gas path
Combustion
System
A major inspection should be
Air Intake
scheduled in accordance with the
recommendations in the owner's
Maintenance and Instructions
Manual or as modified by the
results of previous borescope and
hot-gas-path inspection.
The purpose of the major
inspection is to examine all of the
internal rotating and stationary
components from the inlet of the
machine through the exhaust
section of the machine.
Disassembly - Combustion Relatively short disassembly
Inspection
shutdown inspection.
Concentrates on the combustion
liners, transition pieces, fuel
nozzles and end caps which are
recognized as being the first to
require replacement and repair in
a good maintenance program.
DCI
Purpose of Inspection
Inspection
ID
101
Air inlet
Various
As combustion
inspection. Also
turbine nozzles,
stationary stator
shrouds and turbine
buckets
Liners, transition
pieces, fuel nozzles,
end-caps
Components
This inspection includes previous elements of the
combustion and hot-gas-path inspections. The complete
flange-to-flange gas turbine is layed open to the horizontal
joints to allow inspections to be performed on individual
items.
Inspection for corrosion, cracked silencers and loose parts
To perform this inspection, the top half of the turbine shell
must be removed.
The work scope involves inspection of all of the major
flange-to-flange components of the gas turbine which are
subject to deterioration during normal turbine operation.
This inspection concentrates on the combustion liners,
transition pieces, fuel nozzles and end caps which are
recognized as being the first to require replacement and
repair in a good maintenance program. Proper inspection,
maintenance and repair of these items will contribute to a
longer life of the downstream parts, such as turbine nozzles
and buckets.
The hot-gas-path inspection includes the full scope of the
combustion inspection and, in addition, a detailed
inspection of the turbine nozzles, stationary stator shrouds
and turbine buckets.
Relatively short disassembly shutdown inspection of fuel
nozzles, liners, transition pieces, crossfire tubes and
retainers, spark plug assemblies, flame detectors and
combustor flow sleeves.
Inspection
Inspection
Major Inspection
ID
MI
See above
Purpose of Inspection
102
Gas Generator (GG)
Compressor
System
Inspection
Turbine Nozzles
Transition Piece
Bucket
Fuel system
Combustion system
Bearings and Seals
Inlet guide vanes
Buckets that were not recoated at the hot-gas-path
inspection should be replaced.
Visual examination for oxidation, cracking, erosion and loss
of wall thickness.Internal visual inspection using
boroscopes.
Non- intrusive NDE examination by thermography and
other methods. Penetrant and MPI inspections in major
overhauls.
Seals and hook fits of turbine nozzles and diaphragms are
inspected for rubs, erosion, fretting or thermal deterioration.
Turbine buckets are removed and a non-destructive check
of buckets and wheel dovetails is performed (first stage
bucket protective coating should be evaluated for remaining
coating life).
The inlet guide vanes (IGVs) are inspected, looking for
corrosion, bushing wear and vane cracking.
Bearing liners and seals are inspected for clearance and
wear. Bearing housings will be examined for corrosion,
wear and cracking
Combustion and hot gas path inspection as above. Check
fuel nozzles for erosion and blockage. Remote visual
inspection internally by boroscope.
Inspect for leaks, integrity of pipe sytems, blockage of
filters, condition and blockage of fuel nozzles.
Compressor inlet and compressor flowpath are inspected
for fouling, erosion, corrosion and leakage.
Rotor Assembly
Rotor and stator blades are checked for tip clearance, rubs,
impact damage, corrosion pitting, bowing and cracking. All
radial and axial clearances are checked against their
original values (opening and closing).
Generator, Accessory Check alignment - gas turbine to generator/gas turbine to
Drives, Driven
accessory gear. Driven equipment will be subject to it's own
equipment
maintenance requirements
Casing, Cowls and
Casings, shells and frames/ diffusers are inspected for
frames/ diffusers
cracks and erosion.
Inlet and flow path
Components
Inspection
Major Inspection
ID
MI
See above
Purpose of Inspection
Various
Cleaning Systems
103
Various
Operational controls
Exhaust baffles,
silencer, insulation
Various
Bearings and Seals
Nozzle guide vanes
and shrouds
Rotors
Electrical systems
Generator, Accessory
Drives, Driven
equipment
Control system (on
Skid)
Exhaust
Power Turbine (PT)
(Continued)
Casing
Power Turbine (PT)
Shafts
Components
System
Gas turbines are subject to periodic in-situ cleaning by
injection of water dropletstand other methods to clear the
flow path and remove any accumulated fouling or debris.
Maintenance in line with BS EN 60079-17 and other IEC
regulations concerning electrical equipment in hazardous
environments. Note specific guidance in PM84
Bearing liners and seals are inspected for clearance and
wear. Bearing housings will be examined for corrosion,
wear and cracking
Exhaust systems are inspected for cracks, broken silencer
panels or insulation panels.
Check alignment - gas turbine to generator/gas turbine to
accessory gear. Driven equipment will be subject to it's own
maintenance requirements
Check functionality and sensor condition. Check integrity of
electrical systems. Note specific guidance in PM84.
Casings, shells and frames/ diffusers are inspected for
cracks and erosion.
NDE and visual examination for cracking. NDE methods
may include specialised ultrasonics (UT) MPI, and
penetrant methods
Rotor inspections recommended in the maintenance and
inspection manual or by Technical Information Letters
should be performed. This may include dismantling, visual
examination, dimensional checking, assessmant of coating
conditions and NDE examination by magnetic particle
inspection (MPI), radiography, thermography, ultrasonics
and other methods for cracking erosion or corrosion
damage, loss of wall thickness and blocking of cooling
holes.
Turbine stationary shrouds are checked for clearance,
erosion, rubbing, cracking, and build-up.
Inspection
12
12.1
OPERATIONAL ISSUES
HAZARDS
Hazards associated with operation of GTS are covered in PM84 Paragraphs 6 to 11. HSE
Guidance Note PM84 is reproduced in full in Appendix 3. The fuel supply to a GT has to be at
high pressure. Typically, industrial units require natural gas up to 30 barg and some machines
require fuel up to 50 barg. The pipework supplying the fuel to the turbine combustion chambers
is often highly complex since the fuel is supplied to one or more annular distribution manifolds
connected to numerous individual burners. A combination of flanges, flexible pipes, valves and
bellows may be used, each being a potential leak site. Leaks are therefore foreseeable. Leaks
may be ignited immediately producing a flame, or may lead to the accumulation of a flammable
fuel air mixture. The delayed ignition of such a mixture within a confined space, such as an
acoustic enclosure, can lead to an explosion with potential for injury and major plant damage. A
leak of liquid at high pressure can produce a mist, which is flammable at a temperature below
the flashpoint of the liquid, so that leaks of liquid fuels, lubricating oils and hydraulic fluids
may also result in fires or explosions.
The burning of fuel in the GT may produce high surface temperatures capable of igniting a leak.
In the case of aero-engines the casings may glow dull red due to the heat produced. On larger
plant, hot surfaces in excess of 520°C have been found during normal operation. In certain
circumstances such temperatures are sufficient to ignite leaks of mist or vapor from liquid fuels,
lubricating or hydraulic oils, as well as gaseous fuels.
GTs are a significant noise source capable of causing noise-induced hearing loss as well as
producing environmentally unacceptable noise. For these reasons they are often installed within
an acoustic enclosure.
Other explosion hazards may be present within the GT. An excess of flammable fuel/air mixture
may accumulate within the turbine inlet or exhaust system, which can be ignited (especially at
start-up).
Due to the high operating speeds mechanical failure can occur, in particular with turbine and
compressor blades and discs. Such failures can lead to a loss of containment, risk of injury or
damage from projectiles, mechanical damage, and fire and explosion risks from plant
disruption.
Electric shock and electromagnetic field hazards may also exist on generators and turbine
auxiliary systems.
12.2
START-UP AND SHUT-DOWN
Explosions within fired plant at start-up, due to the ignition of accumulated fuel, are a wellrecognized hazard, and measures should be adopted to control this hazard. Such measures
identified in PM84 should include adequate gas path purging (at least three volume changes)
before startup, a high standard of isolation to prevent leakage during shutdown and a controlled
duration for attempted ignition based on flame or combustion detection. Arrangements should
be provided to drain any accumulation of liquid fuel from the GT casing. These precautions are
normally inherent within the GT control package provided by the manufacturer. Care should
also be taken with the design of drain lines, to minimise risks when changing from a liquid fuel
to gas, by preventing gas from entering sump tanks. Consideration should also be given to
fitting gas detectors in such tanks.
105
12.3
SURGE PREVENTION
Surge is a backflow in pressure giving a momentary change in the direction of airflow. This is
different to overspeed. This flow reversal is accompanied by high fluctuating load on the
compressor bearings Surge must be avoided at all costs as it can cause damage to the turbine,
combustion chamber or back-end of the compressor; damage may be severe. There are a variety
of causes. Causes could include blockage of air supply, blockage of fuel or other transient
changes. In some circumstances it is possible to get a locked-in surge with pressure waves
bouncing back and forth.
Normally the gas turbine may carry on with little affect. In other circumstances surge can cause
severe damage, depending how deep the extent of the pressure variation. If surge conditions are
met, there is little an operator can do physically to stop or avoid a surge. Surge is best avoided
by keeping operation within strictly controlled boundaries which have been previously defined
and modelled by the turbine supplier. Some protection is afforded by surge-protection systems
and recycle valves which open to control pressure differentials if pressure variations potentially
leading to surge are monitored. Because of the potential consequences it is important to be
assured of the operator's competence in this area.
Surge is relevant to the air compressor in the turbine and to driven compressors. In the context
of gas turbines surge is possible in the Compressor (GC) of the GT. Where the GT drives a gas
compressor, surge must also be avoided in the driven equipment. Surge has the potential to
cause significant damage to a GT or compressor. If the discharge volume of trapped gas goes
past the stability limit a lot of load can be transferred to the thrust bearings. The GT usually
survives but the high stress conditions can lead to overheating of the machine.
Surge is avoided primarily by careful control of operating conditions so that the GT stays within
stability limits ( Figure 54). This is an important part of gas turbine design. Turbine suppliers
will run simulation models to ensure that the conditions that could give rise to surge in a given
design are well understood. A gas turbine will include a recycle loop with control valves
between the power turbine (PT) and gas compressor (GC) for surge prevention. Other ways of
minimising the likelihood of surge include: active and passive methods to increase the stability,
simulation to improve the accuracy of determining the stability (surge) limit, and simulation to
better understand the interaction between the compressor, the anti-surge devices (control
system, valves) and the station piping layout (coolers, scrubbers, check valves). A detailed study
of surge avoidance in centrifugal compressors driven by two-shaft gas turbines was given at
IGTI2004 by Kurz and White7 The possible operating points of a centrifugal gas compressor
are limited by maximum and minimum operating speed, maximum available power, choke flow,
and stability (surge) limit
Surge is most likely during rapid or emergency shutdown. When the power supply is cut, the
rotating system slows down in inertia, gas is trapped with less head than normal operation.
Pressure is reduced, the ESD works against the emergency shutdown. Whether surge occurs
will depend on a number of factors including mass and energy balance, momentum, valve
characteristics, compressor characteristics and system inertia. Shutdown is rapid; as a rule of
thumb ~30% of speed is lost in the first second.
106
Figure 54 Limits of stable airflow
Each stage of a multi-stage air compressor possesses certain airflow characteristics that are
dissimilar from those of its neighbour; thus to design a workable and efficient compressor, the
characteristics of each stage must be carefully matched. This is a relatively simple process to
implement for one set of conditions (design mass flow, pressure ratio and rotational speed), but
is much more difficult when reasonable matching is to be retained with the compressor
operating over a wide range of conditions such as a gas turbine encounters.
If the engine demands a pressure rise from the compressor which is higher than the blading can
sustain, surge occurs. In this case there is an instantaneous breakdown of flow through the
machine and the high pressure air in the combustion system is expelled forward through the
compressor with a loud 'bang' and a resultant loss of engine thrust. Compressors are designed
with adequate margin to ensure that this area of instability is avoided
Models can give an understanding of the conditions leading to surge and aid prevention7. Recent
experience of using models by Statoil in the Troll field [Bjorge IGTI 2004] showed that models
can give insight to the factors causing surge and what protects the system, for example high
inertia, slow power decay and power-loss delay. Modern control systems with real time
monitoring of exhaust temperature and feedback can adjust performance of all parts of the
turbine (air compression, fuel input etc.) to prevent surge
A key factor in surge prevention is the downstream volume. Proper sizing of the system and
pressure side volume is essential. The volume downside of the check valve should be reduced as
much as possible. The size of the downstream volume is very important to get stability in the
compression system. The pressure coupling between the compressor and gas turbine is also an
important factor in determining the size of discharge volume.
Simplified models are available from suppliers to look at surge issues. These have been
validated against test data. The turbine supplier will normally determine what ESD valve to
use. In operation stepping to idle is preferred to ESD. Supplier experience is that ~90% of ESDs
are preventable. Surge in driven compressors may also impact on gas turbine integrity. Surge
avoidance in compressors is covered in Reference 7
12.4
RECYCLE FACILITY
The usual method for surge avoidance, anti-surge control, consists of operation and control of a
recycle loop. This can be activated by a fast acting valve, the anti-surge valve, when the control
system detects that the compressor is approaching its surge limit. Typical control systems use
107
suction and discharge pressure and temperature, together with the inlet flow into the compressor
as input to calculate the relative distance, the surge margin, of the present operating point to the
predicted or measured surge line of the air compressor or driven compressor.
If the surge margin reaches a preset value (often 10%), the anti-surge valve starts to open,
thereby reducing the pressure ratio of the compressor and increasing the flow through the
compressor. The situation is complicated by the fact that the surge valve also has to be capable
of precisely controlling low. Additionally, some manufacturers place limits on how far into
choke (or overload) they allow their compressors to operate. The surge prevention system may
cause associated noise and vibration problems.
12.5
CONTROL SYSTEMS
Control systems have been covered in detail in Section 0 and are also covered in PM84. Gas
turbines are complex machines and synchronisation and controlled operation of the different
systems is essential to ensure smooth operation and avoid surge or instability. It is important
that operators are fully familiar with the operation of the control system and any warning
indicators that may be indicative of a deviation from normal operating conditions. Gas turbines
are tolerant and reliable in normal operation provided fuel flow and input of air remain uniform.
Control is often undertaken through monitoring of exhaust temperature. In turbine packages,
the turbine control must respond to the operating requirements for the driven equipment such as
alternators, pumps or compressors.
A major recent North Sea incident occurred where a maintenance engineer had shut off part of
the control system during routine maintenance. The logic controlling the purging system for the
combustion chamber had been bypassed. There was a flame-out problem on restart. A
significant explosion occurred due to build up of fuel within the chamber damaging the power
turbine and exhaust and taking out the waste heat recovery systems. HSE inspectors
investigating were surprised that no controls were in place to prevent the maintenance engineer
switching off this safety control system.
Maintenance of gas turbines is usually subcontracted with the maintenance companies following
their own procedures. Gas turbines operate within clearly defined margins. Normal practice
before carrying out a new procedure or bypassing control systems in this way would be to
contact the turbine manufacturer who would simulate on their computer models and assure the
planned intervention would be OK
The key issue is that before overriding or modifying any part of the control system, the
maintenance engineer should check with the manufacturer that this is safe. Such changes need
to be undertaken by personnel with appropriate training and authorisation. Shortcuts are to be
avoided.
12.6
VIBRATION MONITORING
Vibration monitoring is used primarily to monitor conditions of bearings, blade tip rub, blade
integrity. Any imbalance in these causes vibration. Vibration monitoring gives an early
warning of any issues before they have time to cause major damage.
If the operating conditions imposed upon the compressor blade departs too far from the design
intention, breakdown of airflow and/or aerodynamically induced vibration will occur. These
phenomena may take one of two forms; the blades may stall because the angle of incidence of
108
the air relative to the blade is too high (positive incidence stall) or too low (negative incidence
stall). The former is a front stage problem at low speeds and the latter usually affects the rear
stages at high speed, either can lead to blade vibration which can induce rapid destruction.
12.7
FIRE DETECTION REQUIREMENTS
Fire and gas detection is essential in and around the acoustic enclosures. Advice on gas
detection can be found in PM84. At least one gas detector should always be installed if the GT
has a gaseous fuel supply. The best location for gas detection is in the ventilation outlet because
a leak will always reach it. The detector should be located sufficiently downstream to ensure
adequate mixing within the outlet duct. Additional detectors can also be used within the
enclosure to increase the probability of detecting small leaks. As well as considering the best
location for such additional detectors, care needs to be taken that they are not exposed to
temperatures above their operating range. Some large units have successfully used piped
sampling systems to monitor for gas from potential leaks. The sampling regime of these systems
means they are slow to respond but may be valuable as an additional source of warning of small
leaks. In the case of a turbine hall, CFD modelling work suggests it is useful to model likely
fuel dispersions around the GTs to identify the best location for gas detectors30. The
effectiveness of such detectors may also be improved by providing baffles, which will direct
predicted flows towards them.
The settings for gas detectors placed around a GT should be dictated by their purpose. Gas
detectors in the ventilation outlet from the enclosure should be set to alarm at the lowest
reasonably practicable level, preferably below 5% of the lower explosive limit (LEL) but not
exceeding 10%. Ventilation inlets should be located in a safe area, but if there is a possibility of
a flammable mixture being drawn into the enclosure via the air inlets, then further fast-acting
gas detectors will be required. In the event of a gas alarm safe plant rundown should be
initiated. During this period, the ventilation should run at its maximum rate. The increase in
ventilation may reduce the gas concentration, but this should not cancel the alarm or delay the
rundown. It should only be possible to cancel alarms manually and preferably only after the
plant has shut down. High-level trips should also be set as low as reasonably practicable, but no
higher than 25% of the LEL and should initiate automatic GT trip with gas supply valves being
fully closed. Intermediate detector settings, between the alarm and trip settings, may be valuable
as a means of initiating automatic controlled shutdown of larger turbines. Very sensitive
detectors may be valuable as a means of early warning of a gas leak, which may enable safe
access to investigate the leak source.
Gas detectors should be selected in accordance with BS EN 50073 and installed and calibrated
regularly in accordance with manufacturers' recommendations. In-situ calibration facilities are
recommended if plant is expected to run continuously for long periods. The use of additional
detectors or recalibration may be required for different fuels. However, recalibration must be
strictly controlled to prevent the incorrect setting of detectors. Where spurious trips must be
minimised, such as at larger plant or critical supply installations, a voting system based on a
number of detectors in the ventilation outlet may be used. For example, activation of any one
out of three detectors would initiate an alarm. However, any two out of three detectors above the
trip level would be required to automatically shut down the fuel supply. Displays of gas levels,
recording and trending facilities can also add to reliability and aid the diagnosis of faults.
12.8
PRECAUTIONS AGAINST FIRE
Guidance on precautions against fire is given in PM84 paragraphs14-22. Minimizing the risk of
fuel and oil leakage and controlling the presence of sources of ignition will reduce the risk of
109
fire. The presence of exposed hot surfaces during normal operation precludes complete control
over sources of ignition.
The fuel supply should be interlocked in a fail-safe manner with the fire and gas detection
systems. It should also be possible to manually isolate the fuel supply from a safe position
outside any enclosure around a GT.
Many oil fires, in particular oil-soaked insulation fires, have occurred. Insulation materials in
areas susceptible to oil leaks or likely to be exposed to such fluids during general maintenance
can include a protective film or metal skin. This should be carefully installed to avoid
puncturing, and seams should be taped or folded in such a way as not to collect fluids. Further
protection of high risk pipes can be achieved by the use of double-walled pipe systems to
contain any leak. To minimise risk, lubrication and hydraulic oil systems should be designed
and constructed to recognised engineering standards.
Once a GT is in service, a regular scheme of inspection for leaks of both fuel and oil should be
developed and implemented. This should be carried out in accordance with a safe system of
work to minimise the risk to those carrying out the inspection. Guidance on access to enclosures
is given in paragraphs 54-57. Such an inspection scheme should be regularly reviewed and
modified according to user experience. Results of inspections should be recorded. While visual
inspections can help identify liquid leaks they will not detect gas fuel leaks.
A fixed fire protection system should be installed to mitigate the consequences of a fire on the
GT. This should be to an appropriate standard, such as NFPA 750, BS ISO 14520PM or BS
5306 and, as a minimum, designed to be capable of at least suppressing a fire on the GT or
within the GT enclosure. The design and installation of fixed fire protection systems is a
specialist field and it is recommended that companies experienced in fire protection engineering
are consulted.
In considering the design of a fire protection system, careful attention also needs to be given to
its interactions with other parts of the installation and personnel. These may include:
a) The ventilation system;
b) The isolation of the fuel supply to reduce fire loading and the risk of explosion once the
fire has been extinguished;
c) The isolation of the electrical supply;
d) The choice of extinguishant to minimise the risk of electrocution or asphyxiation;
e) The environment in which the GT is installed; and
f) The means of access to the enclosure and the location of emergency shutdown
pushbuttons and fuel isolation devices.
g) The openings into the enclosure should be fitted with an automatic closing damper.
The early and reliable detection of fire is critical to the successful performance of the fire
protection system. Key to this is the careful choice and siting of fire detectors in the GT
enclosure. No single type of fire detector is the best in all situations and typically a combination
of thermal, flame and smoke detectors will be appropriate. The choice should be based on an
analysis of the characteristics of the potential fires that might occur in the GT enclosure and
their particular causes. Fire detectors should comply with the relevant part of BS EN 54 and
should be installed in accordance with the recommendations of BS 5839 and BS 7273. A
110
manual release facility for the fire protection system should also be provided in accordance with
the recommendations of BS 7273.
Where a fixed fire protection system is installed it should be regularly inspected and properly
maintained in accordance with BS 5839 and BS 7273. The fire protection system should be
periodically inspected and serviced by a competent person with the necessary skills and
specialist knowledge of such systems. A suitable record should be kept of the inspection checks,
servicing and maintenance work carried out. The user should carry out a daily check that the
system is operational and other regular checks and tests detailed in the user instructions
provided by the fire protection system installer. The user should ensure that those with
responsibility for carrying out these tasks are adequately trained.
Exposure to extinguishants that are potentially hazardous should be prevented. This may be
achieved by selecting a non-hazardous extinguishant, eg water mist. Alternatively, potentially
hazardous extinguishants, such as gaseous fire extinguishants, can be used under carefully
controlled conditions to prevent inadvertent exposure to the extinguishant. The control
requirements depend on the particular extinguishant and its maximum concentration in the
enclosure. Details and recommendations on this are contained in BS ISO 14520. Extinguishing
systems that may create an asphyxiation or toxic hazard should be isolated before entry into an
enclosure. The isolation procedure should comply with BS ISO 14520 and BS 7273. However,
systems based on extinguishants such as water mist do not have to be isolated so the risk of
inadvertent isolation is eliminated. Inadvertent exposure to extinguishants should be avoided,
even with fire protection systems using concentrations at which there are no observed adverse
toxicological or physiological effects, in accordance with BS 5839. PM84-5 A suitable alarm
should be incorporated into the fire protection control system to provide sufficient warning to
people within the enclosure to make their escape before discharge of the extinguishant. Where
there is a potential visibility hazard, the exits from the enclosure should be adequately
illuminated. Any air exhausts or air inlet.
12.9
RISK ASSESSMENT FOR ROUTINE ACTIVITIES
Risk assessment should be in place for routine activities such as cab entry, water wash, isolation
schemes and start-up checks. Guidance on Risk Assessment for GTs is given in PM84
paragraphs 12-13. Risk assessment should be undertaken by competent people at all stages of
the design, manufacture, packaging and commissioning of the GT. This should also include the
consequences of foreseeable abnormal operation impacting on nearby plant, for example on an
offshore platform. Manufacturers and suppliers should not only use existing knowledge of
hazards associated with GTs but should also maintain contact with the users of such plant to
gain information on plant failures. The commissioning stage is particularly important as it
necessarily includes the first admission of fuel to the equipment and also because the
responsibility for managing the plant is being progressively transferred to the user.
Before handover the user should carry out a suitable and sufficient risk assessment on the
operation of the GT. This should include the requirements of the Management of Health and
Safety at Work Regulations 1999 (see paragraph 80) and of the Dangerous Substances and
Explosive Atmospheres Regulations (see PM84 paragraph 91). For larger plants, which
generally present a greater risk, a more detailed risk assessment may be required, including the
use of qualitative or quantitative risk analysis techniques. As well as confirming that the safety
features of the plant meet the agreed specification, the risk assessment should also pay particular
attention to operational procedures. Third-party design appraisal may be used to demonstrate
reduced risk by providing verification that relevant design standards have been met. The
adequacy of the training and experience of those involved with the operation, maintenance,
111
inspection and monitoring of the GT plant should also be confirmed. Consideration should be
given to the site conditions in which the equipment is installed, in order to reduce the risk of
environmental or third-party impact; for example weather related motion would affect
performance and lifecycle of components and equipment installed on floating platforms. The
risk assessment should be reviewed at appropriate intervals as operational experience develops.
12.10
ACCESS
Safety issues concerned with access to GT enclosures and confined spaces are covered in PM84
Paragaphs 54 to 57.The acoustic enclosure around a GT is likely to be a confined space (see
PM84 paragraph 82) as there is a foreseeable risk of serious injury due to the leakage and
subsequent ignition of a flammable fuel. Entry for maintenance when the GT has been shut
down should be under the control of a suitable safe system of work, which may include a permit
to work. Such a safe system of work should include the manual isolation of the fuel supply and
the testing of the atmosphere within the enclosure to confirm the absence of flammable or toxic
gases.
Strong justification will be required for entry to an enclosure during turbine operation. All other
potential options for carrying out the work from outside the enclosure should be considered
before allowing entry. Instrumentation with remote indication should be used to avoid routine
entry. CCTV and/or viewing windows can be used where practicable to provide visual checks
on machinery conditions. On new plant, both manufacturers and users should try to eliminate
the need for entry. If there is no alternative then it should be restricted to a minimum duration
and limited to authorised personnel carrying out specific tasks. The risk assessment should
identify why such an entry is required, what the inherent hazards are, and the measures to be
taken to reduce them. Thermal and noise hazards should also be considered in setting entry
duration. A written safe system of work will be required which may include a permit to enter
and to carry out specified work. Appropriate precautions should be taken to prevent the trapping
of personnel inside the enclosure under any foreseeable circumstances.
Due to the increased risk while load and fuel changes are taking place, entry should be
prohibited at these times. Such changes can occur automatically. However, entry should not be
permitted to the enclosure when there is an imminent planned change. Load changes may
increase the risk of a leak by an increase in fuel pressure when an idling GT is brought on load.
The small variations that occur during normal running are not considered to increase risk.
Changing from one fuel to another may increase the possibility of a leak occurring due to the
increase in fuel system pressures or use of different pipework. Similarly, entry at start-up and
under any ongoing uncontrolled emergency condition should not be permitted.
For GTs in a turbine hall, close approach to a running machine and access to hazardous areas in
the vicinity of the GT should be kept to the minimum necessary for safe operation in accordance
with risk assessment.
12.11
HAZARD MANAGEMENT IN HOT-SPOTS
Gas turbines operate at extremely high temperatures, sometimes exceeding 2000ºC in the
combustor and gas generator (Figure 1), the hottest parts of the gas turbine. The exhaust
manifold in particularly can achieve high temperatures and is covered with lagging for safety
reasons. Despite the use of air cooling the turbine casing may also be extremely hot.
These high temperatures pose a risk in terms of injury and burns to personnel and fire ignition
following oil, gas or fuel leak. Rigorous safety measures should be in place to avoid injury to
112
personnel from contact with hot surfaces.
particularly after storm conditions.
The integrity of lagging should be checked,
Analysis of the incidents, dangerous occurrences and accidents on UK installations (Section
10.5 ) indicates ignition from oil and fuel leaks to be responsible for a high proportion of the
total incidents. Good maintenance and preventative measures against leakage or subsequent
ignition is important
12.12
PRECAUTIONS AGAINST EXPLOSION
Precautions against explosion are covered in guidance PM84 paragraphs 23 to 30. This includes
ventilation, dilution ventilation and explosion suppression. If an enclosure is provided, then
precautions should also be taken against explosion hazards. These precautions should be based
on risk assessment. The use of certain fuels having low auto-ignition temperatures (AIT) or
ignition energies, such as naphtha or hydrogen enriched fuel, requires specialist advice because
of their particular hazards. The risk assessment should identify the additional risks posed by
such fuels and any measures necessary to reduce the risk to an acceptable level.
Ventilation was initially installed in acoustic enclosures to assist cooling of the GTs.
Subsequently it has been shown that it can also be used as a basis of safety, if designed as
dilution ventilation. In practice this means that the ventilation should ensure that there are no
stagnant or poorly ventilated spaces and that any leak is effectively mixed with air. Recirculation and re-entrainment should be minimised, further reducing any accumulation of
flammable mixture. This may require a large number of air inlet positions to obtain adequate
distribution and, in extreme cases, supplementary fans or air distributors. Dilution ventilation is
only acceptable as a basis of safety when associated with the use of suitable gas detection. See
PM84 paragraphs 43-45.
In most cases a GT cannot directly comply with the regulations made to implement the ATEX
Directive (paragraph 88), because of the requirement to exclude hot surfaces from hazardous
areas. The European Commission have published guidance on their website29, which confirms
that the provision of dilution ventilation will, by preventing an explosion, enable GTs operating
in an enclosure to be regarded as ATEX compliant. Conformity assessment of the ventilation
design, in the UK, will be required to ATEX Equipment-Group II, Category 3 equivalence, and
will therefore be the responsibility of the final supplier.
While dilution ventilation has now been accepted as the preferred basis of safety, explosion
relief and explosion suppression may be used as additional risk reduction measures. However if
either of these techniques were to be used as an alternative basis of safety, then appropriate
justification would be required.
Explosion relief is easier and less costly to fit to new plant than to retrofit. It has the advantage
of proven reliability as a basis of safety in many process industries. Strengthening of the
enclosure can be used to reduce the vent area required. Modification of existing roof panels may
provide sufficient explosion relief. All such relief panels should be restrained and should
discharge to a safe place, preferably in the open air, in order to prevent injury to personnel and
damage to adjacent plant. Any ductwork associated with the relief panels should be designed to
contain the expected pressures.
Explosion suppression is a well established technique in other industries. A suitable suppressant
is distributed within an enclosure at the onset of an explosion with such speed that the explosion
is quenched and the pressure rise is limited to a small acceptable value. It can be linked to a fire
extinguishing system and will similarly preclude access to the plant during normal operation
113
unless isolated. Ventilation, fuel controls and fire extinguishing systems may need to be linked
to the suppression system to maintain safety following its operation.
Turbines within spacious halls are unlikely to present an explosion hazard, since foreseeable
flammable mixtures are not sufficiently enclosed. Such an arrangement has significant
advantages of accessibility for maintenance, although employees in the building are likely to
need protection against exposure to noise. In turbine halls the use of dilution ventilation as a
basis for safety and ATEX compliance is less applicable, and the focus shifts towards gas
detection. However, the ventilation of such large halls should be designed, and checked, to
ensure that large accumulations of flammable mixture would not arise from foreseeable leaks,
and that such leaks can be detected 8 Screens or baffles may assist the detection of leaks by
restricting the spread of fuel/air mixtures. Access to hazardous areas in the vicinity of the GT
should be restricted to mitigate the residual risk, as noted at PM84 paragraph 57.
GT enclosures may, in exceptional circumstances, be installed in a hazardous area. Their
installation in zone 1 areas (see definitions of zones in BS EN 60079109) should be avoided. If
installation is contemplated in zone 2 areas, expert specialist advice should be sought. Such
advice should include consideration of the following precautions:
a) Combustion air and ventilation air should be drawn from a safe area, i.e. un-zoned,
taking wind effects into account;
b) Fast-acting gas detectors should be placed in combustion air and ventilation air intakes
to provide alarm and trip functions. These detectors should be set to the lowest levels
compatible with a minimum of spurious operations;
c) Engine exhaust should discharge to a safe place outside any zoned areas, taking wind
effects into account;
d) Ventilation should be forced, so as to maintain a positive pressure within the enclosure;
e) A pressure detector should be used to interlock the enclosure pressure with the GT fuel
trip;
f) Access to the enclosure should be prevented during GT operation and after engine
shutdown until hot surfaces have cooled to a safe level. An assessment of the time
required to achieve adequate cooling will be required;
g) The enclosure should be constructed to minimise air loss to the outside;
h) In general, the enclosure and associated equipment should comply with BS EN
standards for equipment intended for use in hazardous atmospheres; and
i) Depending upon the regulations applicable to the installation site, certification of
conformity and appropriate marking may also be required.
12.13
VENTILATION
Ventilation requirements andeffectiveness are covered in PM84 paragraphs 31 to 41.
If practicable for new plant, ventilation should be designed so that it passes from potential
hydrocarbon leak sources away from surfaces which are at a high temperature, and not towards
them. However, in doing so care should be taken not to expose other sensitive components, such
as instrumentation and cable trays, to excessive temperatures. Also any modified ventilation
flow should not generate component stresses in the GT casing that could lead to failure. It
should be noted that the appropriate distribution of ventilation air is more important than its
quantity, and that high ventilation rates may inhibit the detection of small leaks.
114
Dilution ventilation air movement should be monitored and interlocked to GT start and trip
sequences so that the unit cannot start without sufficient ventilation and GT pre-purging. The
gas shut-off valves should not open and any gas-line vent valves should not close until after the
GT purge cycle is complete. Failure of the ventilation system during running should initiate a
fuel trip, unless the ventilation is automatically restored from an alternate or emergency power
supply. This should also supply the air movement detection instruments, gas detection
instruments and associated engine trip systems. In the case of battery back-up systems a
controlled shutdown should be initiated within the expected safe period of operation of the
batteries. Reliance must not be placed on battery back-up systems to continue normal running.
All types of electrical back-up systems involved in safe operation of the plant will require
regular maintenance and testing to ensure their continued availability.
At turbine start-up, thermally induced flows that are present during normal operation may be
absent. The possibility of gas leaks is also likely to be greater at start-up, for example following
maintenance operations. The effectiveness of the ventilation under normal operating conditions
and at turbine start-up should therefore be confirmed.
In smaller enclosures the effectiveness of the ventilation may be studied with the use of smoke
combined with closed circuit television (CCTV). In larger enclosures (above about 50 m3) tracer
gas techniques have been used effectively. However, it has been found that in most cases
ventilation and gas leakage in these larger enclosures are best predicted by modelling with
computational fluid dynamics (CFD). Currently other available techniques may fail to take full
account of the momentum of the leak. An additional benefit is that CFD permits a quantitative
assessment against the criterion noted below. A CFD approach also has the advantage. that
ventilation modifications, if shown to be necessary, can be modelled without actual plant
change, or even before the plant is built.
A quantitative criterion against which to assess dilution ventilation efficiency in enclosures has
been proposed [10] and shown to be both conservative [PM84-8] and attainable. It is based on the
principle of limiting any foreseeable accumulation of flammable mixture, so that its ignition
would not present a hazard to the strength of the enclosure or to people. The criterion proposes
that the size of the flammable cloud, as defined by the iso-surface at 50% of the lower explosive
limit (LEL), should be no larger than 0.1 % of the net enclosure volume. This criterion has been
developed to allow a common basis for assessment of ventilation effectiveness in enclosures. It
is primarily applicable to a CFD-based approach. The results of any research into this field
should be taken into account as they become available.
In adopting a CFD approach, the model should be representative of the plant. The geometry of
the enclosure, turbine and associated equipment should be adequately resolved by the CFD grid.
It may not prove possible to explicitly resolve small obstacles, such as pipework, fittings etc, in
which case these should be taken into account by adopting a porosity-based approach. The
number and location of ventilation inlets and outlets should be correctly represented, as should
the flow rates. Consideration should be given to thermal boundary conditions, and the need to
satisfy an overall heat balance for the turbine enclosure system. Where possible, the CFD model
should be demonstrated as being representative of actual conditions, by comparison of
simulated velocity and temperature fields with in-situ measurements.
The effects of buoyancy in a CFD model should be addressed, since thermally induced natural
convection flows can be significant. While the main fuel, natural gas, is inherently buoyant, a
high-pressure release will normally cause a substantial amount of mixing, and the resulting gas
cloud may then be at relatively low concentration. In these circumstances the gas cloud could be
more affected by the background ventilation, including any thermally induced flows, or flows
115
induced by the momentum of the release. The modelling of the gas leak in a CFD approach can
be undertaken in one of two ways: either the leak source is resolved explicitly by the CFD grid,
or the effects of the leak are introduced as sub-grid scale sources of mass, momentum, energy,
and turbulence. In practice, it is usually not feasible to resolve the leak directly at its source, due
to its small dimensions. In such cases it is acceptable to use correlations or a simple jet model to
provide a larger pseudo-source a small distance downstream from the leak location, which can
be resolved by the CFD grid. In general, this approach is more reliable than use of a sub-grid
scale source.
The leak rate to be modelled in CFD simulations should be the largest leak that would just pass
undetected. This can be calculated as that gas release rate which, when fully mixed in the
ventilating air passing through the enclosure, just initiates the alarm for a detector located in the
ventilation outlet. Larger leaks than this should be readily detected and appropriate action taken.
Smaller leaks could pass undetected, but present no hazard if the ventilation design has been
validated.
A CFD approach should aim to demonstrate that the ventilation is effective for a credible `worst
case'. The leak rate should be calculated using the above approach, and the leak location and
orientation chosen to produce the largest flammable cloud predicted by CFD modelling. This
can be best achieved by an approach which identifies poorly ventilated regions, ie re-circulating
or stagnant flow. Identification of poorly ventilated regions can be achieved by analysing
simulations or measurements. Since it is not possible to know, in advance, which combination
of factors will lead to the largest flammable cloud, a small number of alternative leak locations
and orientations should be simulated. These leak scenarios should be investigated separately to
avoid interactions, rather than all modelled within a single simulation.
CFD results should be subject to sensitivity analysis regarding areas of modelling uncertainty.
In particular, the sensitivity of the flammable cloud volume to the mesh resolution should be
addressed. This can, for example, be achieved by local grid refinement. The numerical schemes
that are used to estimate fluid flow across the boundaries of grid cells can also have a significant
influence on the accuracy of the results. Simple schemes may result in over-rapid mixing,
purely as a consequence of numerical errors. This effect is commonly referred to as false, or
numerical, diffusion. More advanced numerical schemes should ideally be used to avoid
excessive numerical diffusion.
12.14
FUEL SUPPLY SYSTEMS
Fuel supply systems are covered in paragraphs 48 and 49 of PM84. Fuel pipework should be
designed, constructed, tested and installed to an appropriate recognised standard. Relevant
references are given in Institution of Gas Engineers and Managers publication UP/9.14
Replacement pipework should be subject to the same standards. Vulnerable pipework should be
routed so as to avoid the likely disintegration plane of ejected turbine disks and blades. Fuel
pipework should also be designed with the minimum of non-welded joints compatible with
maintenance requirements. Assembly and maintenance requirements should be considered at the
design stage.
All fuel pipelines should be assembled, and reassembled following maintenance, under a quality
assurance scheme. They should also be pressure tested, so far as practicable. All flanges and
fittings upstream of any final flanges or connections at combustion chambers should be pressure
and leak tested after assembly. Final flanges or connections should be tightened under recorded
and controlled quality assured conditions, and leak tested so far as practicable. Adequate access
to all such fuel pipework flanges is thus essential. Where it is possible to produce a small
116
backpressure by spinning the gas turbine, techniques such as the use of proprietary leak
detection spray or a tracer gas can be used to aid leak detection33.
12.15
GAS FUEL
Paragraphs 50 and 51 of PM84 give special precautions for gas fuel
A high standard of automatic isolation, based on two safety shut-off valves meeting class A
performance standards, should be fitted to the gas supply to prevent gas from passing into
downstream equipment while the GT is stationary. For systems where the fuel thermal energy
input flow rate exceeds 1.2 MW, the valves should be fitted with a system to prove their
effective closure, for example by the fitting of proving switches to detect mechanical overtravel,
or by sequential pressure proving, which may use an intermediate vent valve. The latter system
has the advantage that it effectively tests the valves for leakage at each start-up and shutdown.
Further guidance on isolation is given in IGE/UP/9.
For applications where gas supplied by a national gas transporter is further compressed by the
end user, safety features will be required to prevent the back feed of high-pressure gas into the
distribution system.
Appropriate measures to prevent this situation during upset conditions may be required by the
gas transporter. Such measures could include:
a) a plant inlet `emergency shutdown valve' acting on rising pressure in addition to other
plant safety requirements; and
b) a 'non-return valve' at the suction side of the gas compressor package to prevent reverse
flow.
Further details are given in IGE /UP/6.
12.16
ADDITIONAL EXPLOSION PRECAUTIONS FOR LIQUID FUELS AND OILS
Additional precautions to avoid explosion with liquid fuels and oils are given in Paragraphs 52
and 53 of PM84.
Liquid fuel leaks from high-pressure sources can produce a mist, which can be flammable at a
temperature below the flashpoint of the liquid. Ignition of such a mist can have explosive effects
similar to gas explosions. Effective ventilation should be provided but, because ventilation is
less effective in diluting and removing liquid droplets, their formation should be avoided as far
as possible. Vulnerable joints and fittings should be minimised. Consideration should be given
to the use of welded joints or the use of double containment pipework, as well as to the use of
proprietary mist eliminators (spray shields) or encapsulation to protect remaining vulnerable
joints and fittings. Mist detection should be considered as a further risk reduction measure if
practicable. So far as possible, joints should be positioned so that leaks do not drip or spray onto
hot surfaces. In particular, for liquid fuels of very low AIT such as naphtha, segregation of risk
areas, explosion relief or explosion suppression should be considered. This is because of the
increased risk of ignition and the uncertainties of CFD modelling of such releases. Further
guidance on liquid fuel installations is given in IGE/UP/9.
High pressure leaks of lubricating oils and hydraulic oils may also produce a flammable mist
with risks similar to those noted above for fuels. The properties of any such flammable fluids
should be obtained from suppliers and taken into account in a risk assessment. Where necessary,
additional precautions as described above should be considered to reduce the risk. Where other
117
risk reduction measures against flammable oil mists do not provide an adequate level of safety,
it will be necessary to use fire-resistant or non-flammable fluids.
12.17
EMERGENCY PROCEDURES
Emergency procedures are covered in Paragraph 59 of PM84. Actions to be taken in the event
of fire or gas alarms should be written into emergency plans and regularly reviewed. Guidance
from suppliers should be sought and applied. Training in emergency procedures should be given
to operators. Instructions should be given on when to shut down under controlled conditions or
to trip fuel
supplies immediately, when to summon the emergency services, control of the ventilation
system, access limitation, and emergency communications. Emergency shutdown controls
should be located within the control room and at other appropriate locations based on a risk
assessment.
12.18
AIR AND GAS SEALS
There are many air and gas seals in gas turbines to separate different regions and pressures of air
and gas flow and to facilitate cooling of high temperature components. Air may build up in the
lubricant oil used for bearing and seals in the gas turbine. This is separated off in separation
tank. Air inlet to the tank is controlled to avoid the risk of explosion, with breather valves to
avoid pressure build-up. There have been quite a few incidents associated with blockage of
breather valves, leading to pressure release. This can pose a safety hazard particularly if sour
gas is present and in enclosed environments.
12.19
CHANGEOVER IN DUEL FUEL SYSTEMS
Many offshore gas turbines are duel fuel, that is they can also operate on diesel as well as
produced gas. There have been a number of incidents associated with fuel changeover. It is
important to ensure that necessary control sequences are carried out. This includes shutting off
the fuel system for conventional gas operation and purging the combustion chambers to clear
these of existing fuel build up.
118
13
13.1
RECENT TRENDS
MICROTURBINE DEVELOPMENT
A recent trend is the development of small microturbines for simple power generation or driven
equipment applications. The positive features of microturbines are large power for small size.
The negatives are fuel requirements and running cost. Applications foreseen include use in the
home to cover grid unreliability, refrigeration, and military use for remote vehicles and sensors.
There are potential offshore applications include use on remote installations or where a small
local power or drive requirement such as pumping exists.
Compact radial and centrifugal designs have been developed by Hitachi http://www.powerhitachi.com and SWRI GE have been developing microturbines in the CHP project15. Goal is
33-40% electrical efficiency. Applications seen include power refrigeration and heating.
x NOx <7ppm x 10,000h between major overhauls x Cost $500/kW In refrigeration an evaporator, condensor and power module are required. Microturbines tend to
use integral single-piece component turbines rather than individual turbine blades.
13.2
DRY LOW EMISSIONS (DLE)
Increasingly stringent emission controls have produced a trend to gas turbines giving low NOx
and CO emissions (<25vppm). This is achieved using a dry low emissions (DLE) combustion
systems and requires careful control of air and fuel input and other operating parameters. DLE
versions are available now from most major suppliers.
As an example, design innovations to achieve DLE and give significantly lower NOx emissions
in RB211gas generators in Rolls Royce Trent and Coberra 6000 gas turbines included:
x pre-mix, lean burn combustion in original lean burn designs. Successful initially but
developed a noise problem.
x Solution to make fueling asymmetric and moving the location of heat release. Similar
problems were found in the secondary zone and removed.
x less cooling air and lower flame temperature to give lower Nox emissions and improved
fuel mixing
x new shorter combustors. These gave more uniform and lower NOx emissions.
x new mixing ducts – fuel in, air gradually goes in
x damping technologies to remove noise.
x pressure wave dumping, resonant cavities take out noise. New combustor gives much
lower noise.
x Closed loop emission control
The temperature is critical to the level of emissions. Too low a temperature leads to CO, too
high a temperature results in higher NOx emissions as illustrated below in Figure 55.
119
100
65
NOx Level
NOx
CO Level
CO
0
0
Temperature (qC)
2000
Figure 55 Schematic illustrating the effect of temperature on NOx and CO emissions
13.3
STEAM INJECTION FOR EMISSION REDUCTION AND POWER OUTPUT
An alternative way of reducing NOx and CO emissions to below 3ppm has been reported 35
involving premixing steam with the fuel prior to it’s combustion. The steam is intimately mixed
with the fuel in such away as to suppress the size of the flame and promote combustion
efficiency. This combustion consumes much of the excess oxygen and thereby inhibits NOx and
CO formation. Very low emission levels have been demonstrated in preliminary laboratory and
engine testing.
The use of steam injection to increase power output of gas turbines is already established. It has
been reported that steam mass flow typically boosts power output by up to 30%. Without
consuming more fuel with a 15% reduction in plant heat rate 35..
13.4
WASTE HEAT RECOVERY UNITS
Waste heat recovery units (WHRU) are increasingly used offshore. These convert waste heat
generated in the exhaust gases of the gas turbine for hot water, heating, process and other
services. This is achieved by integrating a WHRU heat exchanger unit within the exhaust
system of the gas turbine.
13.5
COMBINED CYCLE GAS TURBINES
Combined cycle gas turbines CCGTs combine a gas turbine with a steam turbine used for
secondary power generation14. The heat generated from the gas turbine is used to produce steam
for the steam turbine. CCGTs therefore have greater efficiency than conventional gas turbines.
CCCGTs are more commonly found in power stations than offshore installations. Daily cycling
and weekend shutdowns can reduce component life.
120
Figure 56 Advanced combined cycle gas turbine system configuration. Courtesy GE36.
The use of combined cycle is usually associated with larger turbines such as the GE Frame 5 1518MW to very large gas turbines (>100MW) in conventional utilities. Smaller CCGTs are
available, for example in the 5-50MW range. The additional topside weight and space necessary
to incorporate an additional steam turbine could limit application offshore.
Combined cycle gas turbines are more complex than conventional GTs. This change in regime
and complexity causes:
x Lower life in nozzles and blades (average 25,000h compared with 40-45,000h
previously)
x Higher degradation rate, typically 5-7% in first 10,000h
x High thermal efficiency 45-60%
x Lower availability, typically 10% less –10% ~80%)
Sources of downtime have been summarised as:
x <200MW Turbine 53%, Compressors 30%, Rotor, Auxiliary, Combustors 30% x >200MW Turbine 28%, Compressor 28% 121
Figure 57 Cycle diagram for a combined cycle gas turbine (CCGT) showing steam
turbine in axial line with the gas turbine. Courtesy GE power36
In the conventional power industry manufacturers pay penalties ($Ms) on not meeting power
and heating rates. This is aggravated by the instability of low NOX combustors. For CGGTs the
use of Long Term Service Agreements (LTSA) are a future trend. LTSA may be necessary to
get financing and insurance cover. The driving forces are: gas turbines pushing design
envelopes, limited operational history, limited parts availability, high degradation rate.
122
14
OPERATIONAL SUPPORT GUIDANCE Guidance on operational activities which will have an effect on the safety and reliable operation
of rotating equipment is given in HSE research report RR076 including gas turbine packages.
This includes delineation of factors which may indicate that the equipment is being well
maintained or there are deficiencies. Summary tables are included for major packages to be
used on site visits in reviewing the installation.
To avoid confusion this guidance note does not propose a separate system for review of gas
turbines and the inspectors and readers are referred to RR076 for the details of the review
process. Some indicators from RR076 that are relevant to gas turbines are reproduced below.
Additional indicators that may be indicative of good practice in operation and maintenance of
gas turbines are given in Section 15.
123
OPERATION
MAINTENANCE
ITEM
EQUIPMENT
Viewing windows dirty /
obscured / no internal
lighting
Enclosure access without
permit
Acoustic enclosure
Access
Oil leakage
Oil leakage
Ventilation
Oil absorbent pads around
enclosure base
Oil absorbent pads around
enclosure base
Acoustic enclosure
ventilation louvers very
dirty flammable mixture.
Gas or obscured
Enclosure doors left open.
Panels removed
Ventilation
Fuel
KEY OBSERVATION
Vibration monitors not
functioning, or alarms in
Significant vibration can
be felt
High fuel pressures ( if
visible on local gauges)
TOPIC
Vibration
124
Cannot see inside
enclosure to check.
Unnecessary entries.
Increased personnel risk
Increased personnel risk.
Search problems if there is
an incident.
Wrong ventilation pattern,
overheating, gas detection
ineffective. Noise
emissions
Fuel or lubricant leakage?
Pool fires? Fuel mist?
Slippery floor – personnel
injury
Increased risk of pipe or
joint failures ( particularly
flexible )
Over-heating, risk of
flammable mixture
detection ineffective
IMPACT
Machine damage, damage
to fuel lines, fuel releases.
Blade failures.
Additional hazard of enclosure
entry is not recognised
Checks, if made, require entry to
enclosure
Operators unable to contain fuel
leak
Operators have not considered
risk of injury
Operators are unaware of the
potential hazard
Effectiveness of ventilation is not
checked
INFERENCE
Operators not paying attention to
Review vibration monitoring
vibration levels, not aware of
potential damage
Fuel nozzle restrictions or excess
fuel flow
Review operating
instructions & PTW control
Identify fluid and source.
Plan remedial action.
Identify fluid and source.
Plan remedial action.
Monitor condition of floor,
warning signs, barriers
Review operating
instructions - plan
improvements
Review operating/
maintenance philosophy
Check fuel pressure vs.
vendor fuel flow. Check
operating logs
Carry out air flow test
ACTION
Review vibration monitoring
policy / practice
Table 8 The table gives examples of observations which would indicate not best practice in the operation / maintenance of a gas turbine. Source HSE Research Report RR076 ITEM
OPERATION
Exhaust
Instruments
Personnel safety
TOPIC
KEY OBSERVATION
Acoustic enclosure door
can be padlocked
Control panel or local
instrument displays
inaccessible / dirty /
damaged
High discharge
temperature( alarms in or
scorched ducting )
125
IMPACT
Potential to trap personnel
inside
Operators do not manage
equipment, faults develop
un-checked. Alarms might
be missed.
Creep failure of blades.
Missiles. Exhaust ducting /
flexible failure
Internal problems with turbine,
fuel control problems
INFERENCE
Trapping risk has not been
recognised
Operators do not routinely check
these instruments
ACTION
Assess hazard, identify if
alternative escape exists.
Review operating
instructions - are instruments
necessary or redundant.
Reinstate or remove.
Review recent operating
temperature and condition
monitoring data
15
EXAMPLES OF GOOD AND BEST PRACTICE In this context good practice is defined as practice or action that would be expected by any
reasonably trained inspector to be done on an installation. Best practice covers procedures and
operation practice that goes beyond this.
HSE guidance document PM84 [1] covers the main safety factors that need to be considered in
the operation of gas turbines. This includes ventilation, access, fire prevention systems, surge
prevention, and electrical and control systems. PM84 notes that the guidance is not obligatory
to operators. Adherence to the advice in PM84, developed in working groups including users,
operators, suppliers and HSE is seen as good practice. Conversely not following the guidance
may be indicative or poor practice or require justification.
There are many basic things that would be considered normal and part of good practice. These
include access arrangements, use of monitoring systems, appropriate ventilation, checking for
leaks of gas, fuel or lubricant. These are necessary from a safety perspective and do not
constitute best practice. Specific indicators of lack of good practice for turbine packages taken
from RR076 are summarised above in Table 8.
Gas turbines are specialist equipment and maintenance is usually managed by the supplier or
specialist contractor under a maintenance agreement. Simple adherence to the recommendations
of such contractors is not in itself indicative of good practice. Best practice would be where the
operator takes and active interest in what has been done at maintenance and any failures or
degradation found that may impact on future integrity. For example:
x
x
x
x
What is the basis for any components which have been found defective being
left in service and not replaced.
Are the rejection criteria for defective components in accordance with offshore
practice, where tighter definitions may be used than on onshore applications.
What is the reason for upgrades or chances to design
Where cracking has been found or failures have occurred; are these known
limitations with a given turbine model or new. Are these a result of changes in
design, for example to blade profile or casing material.
From operation experience it is good practice to have technicians that know both disciplines:
mechanical (propulsion) and electronic (control). It is highly beneficial to know both to
properly diagnose faults. Electromechanical and digital system experience is important. Dual
trade is beneficial
Maintenance manuals are the first port of call in any maintenance and inspection process.
Things that an inspector would need to check for include:
x What is the kit
x
x
x
x
x
x
x
x
Who provided it What documentation is available Amendment status Is the manufacturer aware any issues in this particular installation Are Manuals available and being used Updates
Right air, fuel Are reasonable precautions being observed 127
A lack of familiarity of relevant platform personnel with these factors would be indicative of
poor practice.
There are certain fundamentals in safe turbine operation. These include:
x Not blocking air intakes
x
x
x
x
x
Fuel supply protected, inviolate No water (unless intended). water injection used in some GTs to enhance performance). Don't block exhausts If the GT needs lube oil it is stored in the right containers, recorded, right stuff. People operating know what to do A lack of familiarity of relevant platform personnel with these factors would similarly be
indicative of poor practice.
An example of best practice is where the dutyholder has procurement and design specification
documents that bring together best practice from their historical operating experience with gas
turbines; see procurement example in Appendix 2. Such documents may also suggest
amendments to API procurement standards based on the operators experience. Examples of
relevant advice from such procurement and design documents reviewed in Appendix 2 include:
x Identify all changes which are not proven in similar machines produced over the last 5
years or where less than 100 000 fired hours have been accumulated in all machines.
x Give attention to off-design conditions which may occur during start-up and shutdown
procedures associated with the particular applications of the gas turbine.
x Consider spares availability. A spares inventory comprising either a recommended
range of individual components or a complete gas generator and/or rotors, or a
combination of both, will be dictated by the required plant availability. In some cases,
holding a complete spare gas generator may be more economical in the longer term than
holding individual components.
x Consider gas and liquid fuel variability on the installation. Aero-derivative gas turbines
require premium gas and liquid fuels. If the gas turbine fuel may be a crude oil, residual
fuel oil, very lean gas, refinery mix gas or a gas that is subject to changes of Wobbe
Index of more than 10%, then industrial gas turbines may be preferable.
x The site conditions of elevation, humidity and ambient temperature should be taken into
consideration together with the type of fuel (gas/liquid) and combustors and the power
requirements of the driven equipment in order to arrive at a realistic site-rated power
(rating) of the gas turbine.
x Copper and its alloys shall not be used in the presence of hydrogen sulphides, acetylene,
ammonia, ammonium chloride or mercury. Materials for components in contact with
gas shall conform to NACE MR0175 if the level of H2S exceeds the levels specified
therein.
x The location of the combustion air intake shall be carefully selected so as not to shorten
the life of the gas turbine. Satisfactory access shall be provided and no undue hazard
shall be created. If flammable gasses are detected in the combustion air inlet, the
safeguarding system shall shut down the gas turbine.
128
x The combustion air intakes should be as close to the gas turbine as possible, to
minimise cost and any power reduction due to pressure loss. The intake shall be located
in a non-hazardous area or a zone 2 area;
x Air intakes should not be located in a zone 0 or a zone 1 area. The intake should not be
placed beneath a roof of any building within which flammable vapours may
accumulate.
x Process equipment, pipe flanges and open drains should not be placed within 5 metres
of the air intake. Careful consideration shall be given to the area classification
surrounding the gas turbine installation.
x In marginal cases, it should be investigated whether identical fuels have been used by
other operators and any specific design requirements determined, especially in relation
to trace elements.
x Gas turbine hot parts are particularly sensitive to alkaline metals such as sodium and
potassium. Other elements may have additional restrictions due to environmental
emission limits and the general corrosion requirements of downstream systems.
x Fuel condition. The possibility of liquid entrainment or condensate formation in the fuel
gas supply should be avoided by system design. The system should be designed to
prevent this occurring under all conditions, in particular the formation of condensates in
fuel gas lines under idle conditions.
x Gas Turbine Washing. Advice on key points regarding turbine cleaning practice as
identified in Section 11.7.
Whilst the actual advice may vary between dutyholder and installation, the availability of such
prior service information and inclusion in Dutyholder specifications is a sign of best practice.
129
16
LIST OF APPLICABLE GUIDANCE AND REGULATIONS
API 613 - Continuous Duty Gear
API 614 - Lube Oil System
API 616 - Gas Turbines
API 617 Centrifugal compressors for petroleum, chemical and gas service industries
API 617 - Compressors
API 670 - Machinery Protection
API 671 - Flexible Couplings
API 677 - Auxiliary Drive Gear
API RP 11 PGT Packaged combustion gas turbines
ASME B133 - Gas Turbines
ASME PTC 22 Gas turbine power plants
ASME PTC-10 Compressor Testing
ASME PTC-22 Gas Turbine Testing
ASTM D 2880 Specification for gas turbine fuel oils
ATEX Directives 94/9/EC Equipment in Hazardous Environments European Union (EU)
BS 5839: Part 1: 2002 Fire detection and alarm systems for buildings. Code of Practice for
system design, installation, commissioning and maintenance PM84-5
BS 7273: Parts 1-3 Code of Practice for the operation of fire protection measures PM84-6
BS 7273: Parts 1-3 Code of Practice for the operation of fire protection measures PM84-6
BS EN 50073: 1999 Guide for selection, installation, use and maintenance of apparatus for
the detection and measurement of combustible gases or oxygen PM84-11
BS EN 54: Parts 1-11 Fire detection and fire alarm systems PM84-4
BS EN 60079-10: 1996 Electrical apparatus for explosive gas atmospheres. Classification
of hazardous areas PM84-9
BS EN 61508: 2002 Parts 1-7 Functional safety of electrical/electronic programmable
electronic safety related systems PM84-12
BS EN60079-17:2003 British and European standard on electrical apparatus for explosive
gas atmospheres; Part 17: Inspection and maintenance of electrical installations in hazardous areas (other than mines) BS ISO 14520: Parts 1-15, 2000 Gaseous fire extinguishing systems. PM84-2
BS5306-4: 2001 Fire extinguishing installations and equipment on premises - Part 4 Specification for carbon dioxide systems PM84-3
EEMUA 140 Noise procedure specification. British Standard. EU Emissions Trading Scheme Regulations 2005 HSE L101 Control and mitigation measures. Dangerous Substances and Explosive Atmospheres Regulations 2002. Approved Code of Practice and guidance L101 HSE Books
1997 ISBN 0 7176 1405 0 PM84-19
131
HSE L134 Design of plant, equipment and workplaces. Dangerous Substances and
Explosive Atmospheres Regulations 2002. Approved Code of Practice and guidance L134
HSE Books 2003 ISBN 0 7176 2199 5 PM84-18
HSE L138 Dangerous Substances and Explosive Atmospheres Regulations 2002. Approved
Code of Practice L138 HSE Books 2003 ISBN 0 7176 2203 7 (available from autumn 2003)
PM84-17
IEC 61511: 2003 Functional safety -Safety instrumented systems for the process industry
sector - Part 1: Framework, definitions, system, hardware and software requirements
PM84-13
IGE SR/25 Hazardous area classification of natural gas installations Institution of Gas
Engineers and Managers PM84-20
IGE/UP/6 Application of positive displacement compressors to natural gas systems
Institution of Gas Engineers and Managers PM84-16
ISO 2324 Gas turbines - acceptance tests
L101 Safe work in confined spaces. Confined Spaces Regulations 1997. Approved Code of
Practice, Regulations and guidance Ll01 HSE Books 1997 ISBN 0 7176 1405 0 PM84-22
NACE MR0175 Sulphide stress cracking resistant metallic material for oil field equipment
NFPA 750:2000. 1 Water mist fire protection systems National Fire Protection Association
(NFPA) National Fire Codes 750:2000. 1 Water mist fire protection systems National
Fire Protection Association (NFPA) National Fire Codes 750:2000. PM84-1
ON58 HSE Offshore Division Operations Note 58 Dangerous Substances and Explosive
Atmospheres Regulations 2002 DSEAR - A short guide for the offshore industry Issue Date
Jan 2003
ON59 HSE Offshore Division operations Note 59 The Equipment and Protective Systems
Intended for use in Potentially Explosive Atmospheres Regulations 1996 EPS - A short
guide for the offshore industry Issue Date Jan 2003
ON63 HSE Offshore Division Operations Notice 63 A Guide to the Equipment and
Protective Systems Intended for Use in Potentially Explosive Atmospheres Regulations 1996
Issue Date Dec 2003
PM84 Guidance Note PM84 Control of safety risks at gas turbines used for power
generation
SI 2005 No 925 The Greenhouse Gas Emissions Trading Scheme Regulations 2005, ISBN
0110727150 The Stationary Office Limited, EU Emissions Trading Scheme Regulations
2005 http://www.og.dti.gov.uk/environment/euetsr.htm
132
17
REFERENCES
1.
P
M84 Control of safety risks at gas turbines used for power generation, UK Health and
Safety Executive HSE, ISBN 0-7176-2193-6, second edition 2003
2.
R
R076 Machinery and rotating equipment guidance notes, HSE Research Report 076
http://www.hse.gov.uk/research/rrhtm/rr076.htm
3. Brun K and Kurz R Gas turbines in oil and gas applications ASME IGTI Turbo 2004
Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
4.
Gas Turbine Theory, second edition, Cohen H, Rogers GFC and Saravanamuttoo,
Longman Group Limited , ISBN 0 58244926 x cased, 11927 8 Paper, 4th impression 1977
5.
The Jet Engine, Rolls Royce plc, ISBN 0 902121 04 9 (1986).
6. Fruchtal MAN Turbo, Modular approach to Gas Turbines paper M16 ASME IGTI
Turbo 2004 Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
7. Kurz R and White R C Surge avoidance in gas compression systems, GT2004-53066,
Proceedings ASME IGTI Turbo 2004 Conference, Power for land, sea and air, Vienna
Austria, 14-17 June 2004
8. Elliot J GE Test and Instrumentation, Proceedings ASME IGTI Turbo 2004 Conference,
Power for land, sea and air, Vienna Austria, 14-17 June 2004
9.
Woodward Redundant Network Controls for Industrial Turbines 14.30 GT2004 53946
Proceedings ASME IGTI Turbo 2004 Conference, Power for land, sea and air, Vienna
Austria, 14-17 June 2004
10.
Woodward Controls, development, design and testing of a standard gas turbine control
15:00h Proceedings ASME IGTI Turbo 2004 Conference, Power for land, sea and air,
Vienna Austria, 14-17 June 2004
11.
Failure analysis of Turbines Session G T56 Tutorial session, ASME IGTI Turbo 2004
Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
12.
Ludwig M Materials in gas turbines IGTI Session T56 Room G 14:00, ASME IGTI
Turbo 2004 Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
13.
G
arside R Electrical apparatus and hazardous areas 4th Edition, Published Hexagon
Technology Limited, Aylesbury, K ISBN 0 9516848 3 3, 2002
14.
Combined Cycle Gas turbines, Paper W56, ASME IGTI Turbo 2004 Conference, Power
for land, sea and air, Vienna Austria, 14-17 June 2004
15.
Microturbines for Power Generation, Turbo2004 Session K Monday 15.30, ASME IGTI
Turbo 2004 Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
16.
Brun K A Novel Centrifugal Flow Gas Turbine Design Paper GT2004-53063 ASME
IGTI Turbo 2004 Conference, Power for land, sea and air, Vienna Austria, 14-17 June
2004
17.
Gas turbine cleaning IGTI Paper TH33 Cranfield University ASME IGTI Turbo 2004
Conference, Power for land, sea and air, Vienna Austria, 14-17 June 2004
18.
Standards and codes of practice for hazardous areas, Simplex
19.
Water mist fire protection systems National Fire Protection Association (NFPA) National
Fire Codes 750:2000. 1 Water mist fire protection systems National Fire Protection
Association (NFPA) National Fire Codes 750:2000. PM84-1
133
20.
Application of positive displacement compressors to natural gas systems IGE/UP/6
Institution of Gas Engineers and Managers PM84-16
21.
Control and mitigation measures. Dangerous Substances and Explosive Atmospheres
Regulations 2002. Approved Code of Practice and guidance L101 HSE Books 1997
ISBN 0 7176 1405 0 PM84-19
22.
Design of plant, equipment and workplaces. Dangerous Substances and Explosive
Atmospheres Regulations 2002. Approved Code of Practice and guidance L134 HSE
Books 2003 ISBN 0 7176 2199 5 PM84-18
23.
Dangerous Substances and Explosive Atmospheres Regulations 2002. Approved Code of
Practice L138 HSE Books 2003 ISBN 0 7176 2203 7 (available from autumn 2003)
PM84-17
24.
Hazardous area classification of natural gas installations IGE SR/25 Institution of Gas
Engineers and Managers PM84-20
25.
Safe work in confined spaces. Confined Spaces Regulations 1997. Approved Code of
Practice, Regulations and guidance Ll01 HSE Books 1997 ISBN 0 7176 1405 0 PM84-22
26.
Explosive Atmospheres – Classification of Hazardous Areas (Zoning) and selection of
Equipment HSE www.hse.gov.uk/comah/sragtech/techmeasareaclas.htm
27.
G
arside R Electrical apparatus in hazardous areas, ISBN 0 9516848 3 3, 4th Edition,
2002, Pub Hexagon Technology Limited, Aylesbury, UK.
28.
Simplex - An introduction and basic guidance for the selection, installation and
utilisation of apparatus in potentially hazardous atmospheres, Allenwest electrical, AEL
406 Nov (1993)
29.
ATEX Directives and their application to gas turbines European Commission
http://europa.eu.int/comm/enterprise/atex/gasturbines.htm PM84-7
30. Santon R C, CJ Lea, Lewis M J, Pritchard D K, Thyer A M and Sinai Y Studies into the
role of ventilation and the consequences of leaks in gas turbine power plant acoustic
enclosures and turbine halls Trans IChemE Vol 78 Part B May 2000 175-183 PM84-8
31.
Santon R C Explosion hazards at gas turbine driven power plants ASME 98-GT-215
PM84-10
32.
Board statement on restrictions on human exposure to static and time varying
electromagnetic fields and radiation Documents of the NRPB1993 4 (5) PM84-21
33. DA Farthing, L Marley and JA Lees Operational safety and post-maintenance gas leak
detection in GE frame 9001FA gas turbines Proc Instn Mech Engnrs Vol 213 Part A 465474 PM8-15
34.
The application of natural gas fuel systems to gas turbines and supplementary and
auxiliary burners IGE/UP/9 Institution of Gas Engineers and Managers (first revision
published July 2003) PM84-14
35. De Biasi V Steam-fuel mix limits Nox and CO below 3 ppm without DLN or SCR Gas
Turbine World, October-November 2004, pp24-28
36. Smith, R et al, Advanced Technology Combined Cycles, GE Power Systems, Report GER
3936A http://www.gepower.com
37. Sinfield K D Industrial gas turbine development and operating experience IMIA 161993
59(93)E
IMIA
Conference,
September
http://www.imia.com/documents/development_and_operating_experience.htm
134
38. Gas Turbine World 2005 Performance Specs, Gas Turbine Power Plant Ratings for
Project planning, Engineering Design and Procurement, 2005 GTW Specifications 23rd
Edition, January 2005 Vol 34 No 6 135
APPENDICES
Appendix 1 List of UK installations
A1
Appendix 2 Typical procurement package technical specification
A2
Appendix 3 HSE guidance note PM84 on gas turbines
A3
Appendix 4 Gas turbine suppliers and summary for UK installations
A4
Appendix 5 Specification of turbines used in UK sector
A5
Appendix 6 Key systems and components
A6
A-1
APPENDIX 1 LIST OF UK INSTALLATIONS
The installations in UK waters can change particularly for mobile and floating installations (FPS,
FPSO). This list summarises the position at April 2004.
Installation
AH001
ALBA FSU
ALBA NORTHERN
ALWYN NORTH
AMETHYST
ANASURIA
ANDREW
ANGLIA A
ANGLIA B
ARBROATH
Dutyholder
AMERADA HESS
CHEVRON
CHEVRON
TOTAL E&P UK PLC
BP SNS (N)
SHELL U.K. (CENTRAL)
BP MBU
GAZ DE FRANCE
GAZ DE FRANCE
PETROFAC
PRODUCTION
SERVICES
ARCH ROWAN
ROWAN DRILLING (UK)
LTD
ARDMORE
ROWAN DRILLING (UK)
(ROWAN GORILLA LTD
VII)
ARMADA
BG INTERNATIONAL
AUDREY PWD
CONOCO PHILLIPS
49/11A
AUK A
SHELL U.K. (CENTRAL)
BAE 6 TOWERS
BAE
AIR
BALMORAL
ENI
BAR 331
SAIPEM
BAR PROTECTOR SAIPEM
BARQUE PB 48/13A SHELL U.K. SOUTHERN
OPS
BARQUE PL 48/14P SHELL U.K. SOUTHERN
OPS
BEATRICE A
TALISMAN ENERGY
(UK) LIMITED
BEATRICE B
TALISMAN ENERGY
(UK) LIMITED
BEATRICE C
TALISMAN ENERGY
(UK) LIMITED
BELLWELL
CONOCO PHILLIPS
BERYL A
MOBIL NORTH SEA
LIMITED
BERYL B
MOBIL NORTH SEA
LIMITED
BESSEMER
PERENCO UK LIMITED
BLEO HOLM
BLUEWATER
ENGINEERING
BORGHOLM
DOLPHIN DRILLING
DOLPHIN
COMPANY
BORGILA
DOLPHIN DRILLING
DOLPHIN
COMPANY
BORGNY DOLPHIN DOLPHIN DRILLING
COMPANY
BORGSTEN
DOLPHIN DRILLING
Fixed/
Mobile
F
F
F
F
F
F
F
F
F
F
Type of
Fixed
FP
FSU
F
F
NUI
FPSO
F
F
SUBSEA
F
Type of
Mobile
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Reg
No.
246
425
409
290
372
500
483
408
0
354
Location
M
N/A
JU
188
USA
F
F
N/A
603
UK
F
F
F
NUI
N/A
N/A
478
334
UK
UK
F
F
F
F
N/A
N/A
88
0
UK
UK
F
M
M
F
FP
N/A
N/A
NUI
N/A
MH
MH
N/A
301
0
578
364
UK
NL
UK
UK
F
F
N/A
470
UK
F
F
N/A
160
UK
F
F
N/A
161
UK
F
F
N/A
271
UK
F
F
SUBSEA
F
N/A
N/A
0
95
UK
UK
F
F
N/A
174
UK
F
F
NUI
FPSO
N/A
N/A
490
520
UK
UK
M
N/A
SS
341
UK
M
N/A
SS
582
UK
M
N/A
SS
157
UK
M
N/A
SS
170
UK
A1-1
UK
UK
UK
UK
UK
UK
UK
UK
UK
UK
Installation
Dutyholder
DOLPHIN
BOULTON
BRAE A
COMPANY
CONOCO PHILLIPS
MARATHON OIL (UK)
LIMITED
BRAE B
MARATHON OIL (UK)
LIMITED
BRENT A
SHELL U.K. NORTHERN
OPS
BRENT B
SHELL U.K. NORTHERN
OPS
BRENT C
SHELL U.K. NORTHERN
OPS
BRENT D
SHELL U.K. NORTHERN
OPS
BRIGANTINE BG SHELL U.K. SOUTHERN
OPS
BRIGANTINE BR SHELL U.K. SOUTHERN
OPS
BRITANNIA
BOL (BRITANNIA
OPERATOR LIMITED)
BRUCE
BP (DBU)
BUCHAN A
TALISMAN ENERGY
(UK) LIMITED
BULFORD
DOLPHIN DRILLING
DOLPHIN
COMPANY
BUZZARD FIELD ENCANA (U.K) LIMITED
BYFORD DOLPHIN DOLPHIN DRILLING
COMPANY
CAISTER 44/23A
CONOCO PHILLIPS
CM (MURDOCH
FIELD)
CAMELOT CA
MOBIL NORTH SEA
CAMELOT CB
MOBIL NORTH SEA
CAPTAIN
TEXACO
CARRACK A
SHELL U.K. SOUTHERN
OPS
CASTORO 10
SAIPEM
CASTORO SEI
SAIPEM
CECIL PROVINE
ROWAN DRILLING (UK)
LTD
CENTRAL BRAE
MARATHON OIL (UK)
LIMITED
CHARLES ROWAN ROWAN DRILLING (UK)
LTD
CLAIR
BP (DBU)
CLAYMORE
TALISMAN ENERGY
(UK) LIMITED
CLEETON P/Q
BP SNS (N)
CLYDE
TALISMAN ENERGY
(UK) LIMITED
CORMORANT A
SHELL U.K. NORTHERN
OPS
CORVETTE A
SHELL U.K. SOUTHERN
OPS
CRYSTAL OCEAN BROVIG
CRYSTAL SEA
BROVIG
CSO ALLIANCE
TECHNIP OFFSHORE
CSO APACHE
TECHNIP OFFSHORE
Fixed/
Mobile
Type of
Fixed
Type of
Mobile
Reg
No.
Location
F
F
NUI
F
N/A
N/A
511
192
UK
UK
F
F
N/A
332
UK
F
F
N/A
122
UK
F
F
N/A
107
UK
F
F
N/A
137
UK
F
F
N/A
124
UK
F
NUI
N/A
548
UK
F
NUI
N/A
554
UK
F
F
N/A
489
UK
F
F
F
FP
N/A
N/A
430
89
UK
UK
M
N/A
SS
304
UK
F
M
F
N/A
N/A
SS
6067
171
UK
NOR
F
NUI
N/A
431
UK
F
F
F
NUI
F
FPSO
N/A
N/A
N/A
362
435
495
UK
UK
UK
F
F
N/A
576
UK
M
M
M
N/A
N/A
N/A
MH
SS
JU
900034
9188
200
UK
UK
USA
F
F
N/A
377
UK
M
N/A
JU
182
USA
F
F
F
F
N/A
N/A
6020
120
UK
UK
F
F
F
F
N/A
N/A
319
286
UK
UK
F
F
N/A
138
UK
F
NUI
N/A
522
UK
M
M
M
M
N/A
N/A
N/A
N/A
MH
MH
MH
MH
542
552
579
0
UNKNOWN
UNKNOWN
VARIOUS
VARIOUS
A1-2
Installation
CSO
CONSTRUCTOR
CSO INSTALLER
DAVY
DEEPSEA BERGEN
DEEPSEA DELTA
DEEPSEA TRYM
DOUGLAS (LBA)
DSND MAYO
DSND PELICAN
DUNBAR
DUNLIN A
Dutyholder
TECHNIP OFFSHORE
TECHNIP OFFSHORE
PERENCO UK LIMITED
ODFJELL
ODFJELL
ODFJELL
BHP BILLITON
SUBSEA 7 (UK)
SUBSEA 7 (UK)
TOTAL E&P UK PLC
SHELL U.K. NORTHERN
OPS
EAST BRAE
MARATHON OIL (UK)
LIMITED
EIDER
SHELL U.K. NORTHERN
OPS
ELGIN FRANKLIN TOTAL E&P UK PLC
ENSCO 100
ENSCO
ENSCO 101
ENSCO
ENSCO 102
ENSCO
ENSCO 70
ENSCO
ENSCO 71
ENSCO
ENSCO 72
ENSCO
ENSCO 80
ENSCO
ENSCO 85
ENSCO
ENSCO 92
ENSCO
ERSKINE
TEXACO
ETAP
BP MBU
F G McCLINTOCK TRANSOCEAN SEDCO
FOREX
FORTIES A
APACHE NORTH SEA
LIMITED
FORTIES B
APACHE NORTH SEA
LIMITED
FORTIES C
APACHE NORTH SEA
LIMITED
FORTIES D
APACHE NORTH SEA
LIMITED
FORTIES E
APACHE NORTH SEA
LIMITED
FRIGG CDPI
TOTAL E&P NORGE AS
FULMAR A
SHELL U.K. (CENTRAL)
GALAXY I
GLOBAL SANTA FE
DRILLING
GALAXY II
GLOBAL SANTA FE
DRILLING
GALAXY III
GLOBAL SANTA FE
DRILLING
GALLEON 48/20PN SHELL U.K. SOUTHERN
OPS
GALLEON PG
SHELL U.K. SOUTHERN
OPS
GANNET A
SHELL U.K. (CENTRAL)
GLAS DOWR
BLUEWATER
ENGINEERING
GLOBAL
KERR MCGEE
PRODUCER III
Fixed/
Mobile
M
Type of
Fixed
N/A
Type of
Mobile
SS
Reg
No.
507
VARIOUS
M
F
M
M
M
F
M
M
F
F
N/A
NUI
N/A
N/A
N/A
F
N/A
N/A
F
F
SS
N/A
SS
SS
SS
N/A
MH
MH
N/A
N/A
0
491
462
580
562
465
0
900054
447
136
VARIOUS
UK
UK
UK
UK
UK
VARIOUS
VARIOUS
UK
UK
F
F
N/A
454
UK
F
F
N/A
350
UK
F
M
M
M
M
M
M
M
M
M
F
F
M
F
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
F
F
N/A
N/A
JU
JU
JU
JU
JU
JU
JU
JU
JU
N/A
N/A
JU
540
331
543
568
363
309
289
176
194
202
504
512
317
UK
NL
NL
UK
NL
NL
UK
UK
UK
UK
UK
UK
WHE
F
F
N/A
76
UK
F
F
N/A
103
UK
F
F
N/A
82
UK
F
F
N/A
104
UK
F
F
N/A
314
UK
F
F
M
F
F
N/A
N/A
N/A
JU
108
152
420
UK
UK
UK
M
N/A
JU
518
CAN
M
N/A
JU
538
UK
F
F
N/A
455
UK
F
F
N/A
477
UK
F
F
F
FPSO
N/A
N/A
384
503
UK
AFR
F
FPSO
N/A
555
UK
A1-3
Location
Installation
(LEADON)
GLOMAR
ADRIATIC IV
GLOMAR
ADRIATIC VI
GLOMAR
ADRIATIC VII
GLOMAR
ADRIATIC XI
GLOMAR ARCTIC I
GLOMAR ARCTIC
II
GLOMAR ARCTIC
III
GLOMAR ARCTIC
IV
GLOMAR BALTIC I
GLOMAR GRAND
BANKS
GLOMAR
LABRADOR I
GLOMAR NORTH
SEA
GOLDENEYE
GRYPHON A
HAEWENE BRIM
HAMILTON (LBA)
HAMILTON
NORTH (LBA)
HARDING FIELD
HEATHER ALPHA
HENRY
GOODRICH
HEWETT FIELD
HOTON
HYDE 48/6
INDE 49/18A
INDE 49/18B
INDE 49/23A
INDE 49/23C
INDE 49/23D
INDE 49/24J
INDE 49/24K
INDE 49/24L
INDE 49/24M
INDE 49/24N
IOLAIR
Dutyholder
Fixed/
Mobile
Type of
Fixed
Type of
Mobile
Reg
No.
Location
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
SHELL U.K. (CENTRAL)
KERR MCGEE
BLUEWATER
ENGINEERING
BHP BILLITON
BHP BILLITON
M
N/A
JU
524
USA
M
N/A
JU
257
UK
M
N/A
JU
308
USA
M
N/A
JU
214
UK
M
N/A
SS
256
USA
M
N/A
SS
0
UK
M
N/A
SS
281
UK
M
N/A
SS
244
UK
M
N/A
JU
380
USA
M
N/A
SS
299
CAN
M
N/A
JU
300
WHE
M
N/A
SS
204
CAN
F
F
F
F
FPSO
FPSO
N/A
N/A
N/A
4022
448
519
UK
UK
UK
F
F
NUI
NUI
N/A
N/A
468
467
UK
UK
BP MBU
DNO HEATHER LTD
TRANSOCEAN SEDCO
FOREX
PETROFAC
PRODUCTION
SERVICES
BP SNS (N)
BP SNS (N)
PERENCO UK LIMITED
PERENCO UK LIMITED
PERENCO UK LIMITED
PERENCO UK LIMITED
PERENCO UK LIMITED
SHELL U.K. SOUTHERN
OPS
SHELL U.K. SOUTHERN
OPS
SHELL U.K. SOUTHERN
OPS
SHELL U.K. SOUTHERN
OPS
SHELL U.K. SOUTHERN
OPS
TRANSOCEAN SEDCO
FOREX
F
F
M
F
F
N/A
N/A
N/A
SS
476
144
333
UK
UK
CAN
F
F
N/A
11
UK
F
F
F
F
F
F
F
F
F
NUI
NUI
NUI
F
F
NUI
F
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
560
446
2
59
3
123
368
17
UK
UK
UK
UK
UK
UK
UK
UK
F
F
N/A
18
UK
F
F
N/A
145
UK
F
F
N/A
528
UK
F
F
N/A
529
UK
M
N/A
SS
241
NOR
A1-4
Installation
IRISH SEA
PIONEER
J W MCLEAN
JACK BATES
JADE
JANICE
JOHN SHAW
JUDY-JOANNE
JUNO MINERVA
KAN TAN IV
KETCH A
KITTIWAKE
KOMMANDOR
SUBSEA
LAPS FIELD
LEIV EIRIKSSON
LEMAN 49/26A
Dutyholder
HALLIBURTON
MANUFACTURING &
SERVICES LTD
TRANSOCEAN SEDCO
FOREX
TRANSOCEAN SEDCO
FOREX
PHILLIPS NORTHERN
OPS
KERR MCGEE
TRANSOCEAN SEDCO
FOREX
PHILLIPS NORTHERN
OPS
BP SNS (N)
MAERSK COMPANY
LIMITED
SHELL U.K. SOUTHERN
OPS
SHELL U.K. (CENTRAL)
SUBSEA 7 (UK)
MOBIL NORTH SEA
OCEAN RIG LIMITED
SHELL U.K. SOUTHERN
OPS
LEMAN 49/27A
PERENCO UK LIMITED
LEMAN 49/27B
PERENCO UK LIMITED
LEMAN 49/27C
PERENCO UK LIMITED
LEMAN 49/27D
PERENCO UK LIMITED
LEMAN 49/27E
PERENCO UK LIMITED
LEMAN 49/27F
PERENCO UK LIMITED
LEMAN 49/27G
PERENCO UK LIMITED
LEMAN 49/27H
PERENCO UK LIMITED
LEMAN 49/27J
PERENCO UK LIMITED
LEMAN B 49/26B
SHELL U.K. SOUTHERN
OPS
LEMAN BT 49/26B SHELL U.K. SOUTHERN
OPS
LEMAN C 49/26C
SHELL U.K. SOUTHERN
OPS
LEMAN D 49/26D SHELL U.K. SOUTHERN
OPS
LEMAN E 49/26E
SHELL U.K. SOUTHERN
OPS
LEMAN F 49/26F
SHELL U.K. SOUTHERN
OPS
LEMAN G 49/26G SHELL U.K. SOUTHERN
OPS
LENNOX (LBA)
BHP BILLITON
LOGGS CENTRAL CONOCO PHILLIPS
LOGGS
CONOCO PHILLIPS
SATELLITES
LOMOND
BP MBU
LORELAY
ALLSEAS
LYELL
KERR MCGEE
MAERSK CURLEW MAERSK COMPANY
LIMITED
Fixed/
Mobile
M
Type of
Fixed
N/A
Type of
Mobile
JU
Reg
No.
494
Location
M
N/A
SS
70
UK
M
N/A
SS
508
UK
F
F
N/A
558
UK
F
M
FPSO
N/A
N/A
SS
523
388
UK
UK
F
F
N/A
449
UK
F
M
F
N/A
N/A
SS
566
248
UK
WHE
F
F
N/A
531
UK
F
M
F
MH
N/A
MH
378
0
UK
VARIOUS
F
M
F
F
N/A
F
N/A
SS
N/A
8
549
12
UK
NOR
UK
F
F
F
F
F
F
F
F
F
F
F
F
NUI
NUI
NUI
NUI
NUI
NUI
NUI
F
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
4
5
6
7
22
58
287
253
254
13
UK
UK
UK
UK
UK
UK
UK
UK
UK
UK
F
NUI
N/A
16
UK
F
F
N/A
14
UK
F
F
N/A
15
UK
F
F
N/A
189
UK
F
F
N/A
284
UK
F
F
N/A
285
UK
F
F
F
NUI
NUI
NUI
N/A
N/A
N/A
466
326
348
UK
UK
UK
F
M
F
F
F
N/A
SUBSEA
FPSO
N/A
MH
N/A
N/A
418
0
422
510
UK
VARIOUS
UK
UK
A1-5
UK
Installation
MAERSK
ENDEAVOUR
MAERSK
ENDURER
MAERSK
ENHANCER
MAERSK
EXERTER
MAERSK
GALLANT
MAERSK GIANT
Dutyholder
MAERSK COMPANY
LIMITED
MAERSK COMPANY
LIMITED
MAERSK COMPANY
LIMITED
MAERSK COMPANY
LIMITED
MAERSK COMPANY
LIMITED
MAERSK COMPANY
LIMITED
MAERSK
MAERSK COMPANY
GUARDIAN
LIMITED
MAERSK
MAERSK COMPANY
INNOVATOR
LIMITED
MAERSK
MAERSK COMPANY
JUTLANDER
LIMITED
MAGELLAN
GLOBAL SANTA FE
DRILLING
MAGNUS 211/12
BP (DBU)
MARIANOS
TECHNIP OFFSHORE
MARKHAM ST1
LASMO NETHERLANDS
BV
MCP 01
TOTAL E&P UK PLC
MILLER
BP MBU
MONARCH
GLOBAL SANTA FE
DRILLING
MONITOR
GLOBAL SANTA FE
DRILLING
MONTROSE
PETROFAC
PRODUCTION
SERVICES
MORECAMBE BAY BRITISH GAS
HYDROCARBON
RESOURCES LIMITED
MPSV
SHELL U.K. SOUTHERN
OPS
MSV REGALIA
PROSAFE OFFSHORE
LTD
MURCHISON
CNR (CANADIAN
211/19
NATIONAL RESOURCE)
MURDOCH
CONOCO PHILLIPS
COMPLEX
NAVIS EXPLORER DOLPHIN DRILLING
COMPANY
NELSON
SHELL U.K. (CENTRAL)
NEPTUNE
BP SNS (N)
NINIAN CENTRAL CNR (CANADIAN
NATIONAL RESOURCE)
NINIAN
CNR (CANADIAN
NORTHERN
NATIONAL RESOURCE)
NINIAN
CNR (CANADIAN
SOUTHERN
NATIONAL RESOURCE)
NOBLE AL WHITE NOBLE DRILLING
NOBLE GEORGE
NOBLE DRILLING
SAUVAGEAU
NOBLE JULIE
NOBLE DRILLING
Fixed/
Mobile
M
Type of
Fixed
N/A
Type of
Mobile
JU
Reg
No.
211
Location
M
N/A
JU
506
UK
M
N/A
JU
247
UK
M
N/A
JU
539
DK
M
N/A
JU
439
UK
M
N/A
JU
292
NOR
M
N/A
JU
293
DK
M
N/A
JU
581
UK
M
N/A
SS
371
NOR
M
N/A
JU
438
UK
F
M
F
F
N/A
F
N/A
SS
N/A
203
575
456
UK
VARIOUS
UK
F
F
M
F
F
N/A
N/A
N/A
JU
119
369
346
UK
UK
UK
M
N/A
JU
406
UK
F
F
N/A
111
UK
F
F
N/A
340
UK
M
N/A
JU
5023
UK
M
N/A
SS
288
NOR
F
F
N/A
158
UK
F
F
N/A
565
UK
M
N/A
DS
567
UK
F
F
F
F
NUI
F
N/A
N/A
N/A
407
537
153
UK
UK
UK
F
F
N/A
151
UK
F
F
N/A
141
UK
M
M
N/A
N/A
SS
JU
252
458
UK
UK
M
N/A
JU
533
NL
A1-6
DK
Installation
Fixed/
Mobile
Type of
Fixed
Type of
Mobile
Reg
No.
Location
NOBLE DRILLING
M
N/A
JU
249
UK
NOBLE DRILLING
M
N/A
JU
342
UNKNOWN
NOBLE DRILLING
M
N/A
JU
236
UK
NOBLE DRILLING
M
N/A
SS
414
UK
UGLAND STENA
STORAGE
PHILLIPS NORWAY
SHELL U.K. NORTHERN
OPS
BP MBU
NORTH SEA
PRODUCTION
BP (DBU)
F
FPSO
N/A
547
UK
F
F
F
F
N/A
N/A
226
183
UK
UK
F
F
F
FPSO
N/A
N/A
417
499
UK
UK
F
F
N/A
187
UK
PETROFAC
PRODUCTION
SERVICES
OCEAN ALLIANCE DIAMOND OFFSHORE
DRILLING
OCEAN AMERICA DIAMOND OFFSHORE
DRILLING
OCEAN
DIAMOND OFFSHORE
GUARDIAN
DRILLING
OCEAN NOMAD
DIAMOND OFFSHORE
DRILLING
OCEAN PRINCESS DIAMOND OFFSHORE
DRILLING
OCEAN RIG 2
OCEAN RIG LIMITED
OCEAN VALIANT DIAMOND OFFSHORE
DRILLING
OCEAN
DIAMOND OFFSHORE
VANGUARD
DRILLING
OCEAN VICTORY DIAMOND OFFSHORE
DRILLING
ORELIA
TECHNIP OFFSHORE
OSI (LBA)
BHP BILLITON
PAUL B LOYD
TRANSOCEAN SEDCO
JUNIOR
FOREX
PETROJARL
PGS PRODUCTION AS
FOINAVEN
PETROJARL I
PGS PRODUCTION AS
PETROLIA
PETROLIA DRILLING
LTD
PICKERILL
PERENCO UK LIMITED
PIPER B
TALISMAN ENERGY
(UK) LIMITED
POLYCONCORD
RASMUSSEN A/S
POLYCONFIDENC RASMUSSEN A/S
E
PORT REGENCY
RASMUSSEN A/S
PORT RIGMAR
PORT RIGMAR AS
PRIDE NORTH
PRIDE NORTH SEA LTD
ATLANTIC
F
FPSO
N/A
167
UK
M
N/A
SS
359
NOR
M
N/A
SS
45
USA
M
N/A
SS
282
UK
M
N/A
SS
264
UK
M
N/A
SS
218
UK
M
M
N/A
N/A
SS
SS
550
385
WHE
AFR
M
N/A
SS
452
UK
M
N/A
SS
42
USA
M
F
M
N/A
FSU
N/A
DSV
N/A
SS
266
480
398
VARIOUS
UK
UK
F
FPSO
N/A
486
UK
F
M
FPSO
N/A
N/A
SS
352
242
NOR
UK
F
F
F
F
N/A
N/A
401
391
UK
UK
M
M
N/A
N/A
SS
SS
219
374
UK
USA
M
M
M
N/A
N/A
N/A
SS
JU
SS
215
492
208
UNKNOWN
NOR
UK
ROBERTSON
NOBLE LYNDA
BOSSLER
NOBLE PIET VAN
EDE
NOBLE RONALD
HOOPE
NOBLE TON VAN
LANGEVELD
NORDIC APOLLO
NORPIPE
NORTH
CORMORANT
NORTH EVEREST
NORTH SEA
PRODUCER
NORTH WEST
HUTTON
NORTHERN
PRODUCER
Dutyholder
A1-7
Installation
Dutyholder
PRIDE NORTH SEA
PUFFIN
RAMFORM BANFF
RAVENSPURN
NORTH
RAVENSPURN
NORTH ST2 & ST3
RAVENSPURN
SOUTH
ROCKWATER 1
ROUGH FIELD
PRIDE NORTH SEA LTD
SHELL U.K. (CENTRAL)
PGS PRODUCTION AS
BP SNS (N)
ROWAN
CALIFORNIA
ROWAN GORILLA
II
ROWAN GORILLA
III
ROWAN GORILLA
IV
ROWAN GORILLA
V
ROWAN GORILLA
VI
ROWAN GORILLA
VII
ROWAN HALIFAX
S7000
SAFE BRITANNIA
SAFE CALEDONIA
SAFE LANCIA
SAFE
SCANDINAVIA
SALTIRE A
SANTA FE 135
SANTA FE 140
SANTA FE
BRITANNIA
SCARABEO 6
SCHIEHALLION
SCHOONER A
SCOTT FIELD
SEAFOX 2
SEAFOX 3
SEAFOX 4
SEAN P 49/25A
SEAN RD
SEAWAY
Fixed/
Mobile
M
F
F
F
Type of
Fixed
N/A
F
FPSO
F
Type of
Mobile
SS
N/A
N/A
N/A
Reg
No.
112
6026
525
356
Location
BP SNS (N)
F
NUI
N/A
357
UK
BP SNS (N)
F
NUI
N/A
320
UK
SUBSEA 7 (UK)
CENTRICA STORAGE
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
ROWAN DRILLING (UK)
LTD
SAIPEM
PROSAFE OFFSHORE
LTD
PROSAFE OFFSHORE
LTD
PROSAFE OFFSHORE
LTD
PROSAFE OFFSHORE
LTD
TALISMAN ENERGY
(UK) LIMITED
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
GLOBAL SANTA FE
DRILLING
SAIPEM
BP (DBU)
SHELL U.K. SOUTHERN
OPS
ENCANA (U.K) LIMITED
WORKFOX UK LTD
WORKFOX UK LTD
WORKFOX UK LTD
SHELL U.K. SOUTHERN
OPS
SHELL U.K. SOUTHERN
OPS
STOLT OFFSHORE
M
F
MH
F
MH
N/A
0
79
VARIOUS
UK
M
N/A
JU
272
USA
M
N/A
JU
283
USA
M
N/A
JU
559
USA
M
N/A
JU
358
USA
M
N/A
JU
526
CAN
M
N/A
JU
544
USA
M
N/A
JU
545
UK
M
N/A
JU
237
USA
M
M
N/A
N/A
SS
SS
347
217
VARIOUS
NOR
M
N/A
SS
213
NOR
M
N/A
SS
255
UK
M
N/A
SS
553
NOR
F
F
N/A
405
UK
M
N/A
SS
245
UK
M
N/A
SS
250
UK
M
N/A
JU
35
UK
M
F
F
N/A
FPSO
F
SS
N/A
N/A
280
509
469
UK
UK
UK
F
M
M
M
F
F
N/A
N/A
N/A
F
N/A
JU
JU
JU
N/A
434
268
259
482
279
UK
NL
NL
NL
UK
F
F
N/A
278
UK
M
N/A
MH
0
VARIOUS
A1-8
UK
UK
UK
UK
Installation
COMMANDER
SEAWAY CONDOR
SEAWAY
DISCOVERY
SEAWAY EAGLE
SEAWAY FALCON
SEAWAY
KINGFISHER
SEAWELL
Dutyholder
Fixed/
Mobile
Type of
Fixed
Type of
Mobile
Reg
No.
Location
STOLT OFFSHORE
STOLT OFFSHORE
M
M
N/A
N/A
MH
MH
900010
574
UNKNOWN
VARIOUS
STOLT OFFSHORE
STOLT OFFSHORE
STOLT OFFSHORE
M
M
M
N/A
N/A
N/A
MH
MH
MH
0
573
0
VARIOUS
VARIOUS
VARIOUS
M
N/A
MH
311
UK
M
N/A
SS
83
UK
M
N/A
SS
394
UK
M
N/A
SS
220
UK
M
N/A
SS
276
UK
M
N/A
SS
258
UK
F
FPSO
N/A
383
WHE
M
F
M
N/A
F
N/A
SS
N/A
JU
9002
541
201
UK
UK
EUR
M
F
N/A
NUI
MH
N/A
0
546
VARIOUS
UK
F
F
N/A
365
UK
M
M
N/A
N/A
MH
SS
0
261
VARIOUS
UK
M
N/A
MH
428
VARIOUS
M
M
F
N/A
N/A
F
SS
SS
N/A
318
221
159
UK
UK
UK
F
F
N/A
353
UK
F
M
F
F
M
M
M
F
N/A
F
F
N/A
N/A
N/A
N/A
SS
N/A
N/A
MH
MH
SS
306
349
125
400
20
0
463
UK
VARIOUS
UK
UK
VARIOUS
VARIOUS
EUR
M
N/A
SS
118
UK
M
N/A
SS
481
UK
M
N/A
JU
294
UK
M
N/A
SS
572
UK
WELL OPERATORS UK
LTD
SEDCO 704
TRANSOCEAN SEDCO
FOREX
SEDCO 706
TRANSOCEAN SEDCO
FOREX
SEDCO 711
TRANSOCEAN SEDCO
FOREX
SEDCO 712
TRANSOCEAN SEDCO
FOREX
SEDCO 714
TRANSOCEAN SEDCO
FOREX
SEILLEAN
TRANSOCEAN SEDCO
FOREX
SEMAC I
SAIPEM
SHEARWATER
SHELL U.K. (CENTRAL)
SHELF EXPLORER TRANSOCEAN SEDCO
FOREX
SKANDI NAVICA SUBSEA 7 (UK)
SKIFF PS
SHELL U.K. SOUTHERN
OPS
SOLE PIT CLIPPER SHELL U.K. SOUTHERN
48/19A
OPS
SOLITAIRE
ALLSEAS
SOVEREIGN
TRANSOCEAN SEDCO
EXPLORER
FOREX
STANISLAV
SEAWAY HEAVY LIFT
YUDIN
STENA DEE
STENA DRILLING LTD
STENA SPEY
STENA DRILLING LTD
TARTAN A
TALISMAN ENERGY
(UK) LIMITED
TERN A
SHELL U.K. NORTHERN
OPS
THAMES A 49/28
MOBIL NORTH SEA
THIALF
HEEREMA
THISTLE A
DNO THISTLE LTD
TIFFANY
ENI
TOG MOR
ALLSEAS
TOISA POLARIS
SUBSEA 7 (UK)
TRANSOCEAN
TRANSOCEAN SEDCO
ARCTIC
FOREX
TRANSOCEAN
TRANSOCEAN SEDCO
EXPLORER
FOREX
TRANSOCEAN
TRANSOCEAN SEDCO
LEADER
FOREX
TRANSOCEAN
TRANSOCEAN SEDCO
NORDIC
FOREX
TRANSOCEAN
TRANSOCEAN SEDCO
PROSPECT
FOREX
A1-9
Installation
TRANSOCEAN
SEARCHER
TRANSOCEAN
WILDKAT
TRENCH SETTER
TRENT 43/24
TRITON
TYNE
UISGE GORM
UNITY
VIKING 49/17B
VIKING
SATELLITES
WAVENEY
WELL SERVICER
WELLAND 53/4A
WEST ALPHA
WEST NAVION
WEST SOLE A
WEST SOLE B
WEST SOLE C
WEST SOLE
NEWSHAM
WINDERMERE
Key
F
M
FPSO
FSU
MH
SS
JU
DSV
NUI
Dutyholder
Fixed/
Mobile
M
Type of
Fixed
N/A
Type of
Mobile
SS
Reg
No.
475
Location
M
N/A
SS
166
EUR
M
F
F
F
F
N/A
NUI
FPSO
NUI
FPSO
MH
N/A
N/A
N/A
N/A
21
497
536
498
493
VARIOUS
UK
UK
UK
UK
F
F
N/A
427
UK
F
F
F
NUI
N/A
N/A
10
19
UK
UK
BP SNS (N)
TECHNIP OFFSHORE
MOBIL NORTH SEA
SMEDVIG LTD
SMEDVIG LTD
BP SNS (N)
BP SNS (N)
BP SNS (N)
BP SNS (N)
F
M
F
M
M
F
F
F
F
F
N/A
NUI
N/A
N/A
F
NUI
NUI
F
N/A
SS
N/A
SS
MH
N/A
N/A
N/A
N/A
521
312
393
450
557
27
28
29
0
UK
VARIOUS
UK
UNKNOWN
UNKNOWN
UK
UK
UK
UK
RWE / DEA
F
F
N/A
502
UK
TRANSOCEAN SEDCO
FOREX
TRANSOCEAN SEDCO
FOREX
ALLSEAS
PERENCO UK LIMITED
AMERADA HESS
PERENCO UK LIMITED
BLUEWATER
ENGINEERING
APACHE NORTH SEA
LIMITED
CONOCO PHILLIPS
CONOCO PHILLIPS
Fixed
Mobile
Floating, Production, Storage and Offloading Vessel
Floating Storage Unit
Mono Hull
Semi- Submersible
Jack-Up
Drilling Service Vessel
Normally Unmanned Installation
A1-10
EUR
APPENDIX 2 TYPICAL PROCUREMENT PACKAGE
TECHNICAL SPECIFICATION
1.1
INTRODUCTION
This Appendix is intended to help inspectors be aware of the factors that may be considered
in procurement of a gas turbine for offshore use. The technical procurement specifications
for gas turbines offshore are difficult to obtain for commercial and practical reasons. Such
information is very detailed and confidential in nature. More importantly the engineers
involved in production and maintenance of the installation usually different to those in the
original design team.
The design team would normally be brought together specifically for purpose of
procurement and then disbanded once the installation is complete. Whilst Information
relevant to operation and safety would be retained, detailed technical information relating to
procurement is normally archived and not easily accessible at a later date. Procurement of
specific process or equipment packages may be undertaken in-house or sub-contracted out to
a packager or design house. For these reasons it did not prove straightforward to access
technical procurement information during the project.
Procurement and design of gas turbines for operation in the UK sector is usually based on
the American API design codes. These are well developed and include standard data forms
that provide the basis for procurement. For gas turbine applications in the oil & gas sector,
API 616 is the foundation for most purchase specifications. Operators are reluctant to vary
from standard package specifications because of the additional regulatory approval that may
be required. For similar reasons the turbines used on a given installation for a given function,
such as power generation, are usually likely to be of very similar specification.
Dutyholders have experience over many years in the procurement of gas turbines. API 616
is generic and may not in all cases contain sufficient information regarding offshore
requirements. It is normal for the operator to encompass their own best practice and specific
information into a Design and Engineering Practice. For example:
x Combustion Gas Turbines – Design and Engineering practice on selection, testing
and installation
x Combustion Gas Turbines – Amendments and supplements to API 616
These design documents bring together best practice form the basis for the technical
procurement specifications issued by the requisitioning oil company.
In this Section an example is given of the information that might typically be included in a
technical purchase specification. The information included in practice will depend on the
operator, their normal practices and the turbine requirement. Experienced operators may
seek to incorporate good practice and consistency across their installations. The reliance
placed on the turbine supplier for advice in selection of an appropriate gas turbine will vary.
Gas turbines are specialised items of equipment and significant advice and interaction with
the gas turbine supplier in meeting the installation requirements is both advisable and
necessary.
1.2
API CODES
A2-1
The codes give some flexibility, for example; API 616 Foreword states: "Equipment
Manufacturers, in particular, are encouraged to suggest alternatives to those specified when
such approaches achieve improved energy effectiveness and reduce total life costs without
sacrifice of safety and reliability."
The following codes mostly affect the packaging:
x
x
x
x
x
x
x
API 616 - Gas Turbines API 617 - Compressors API 614 - Lube Oil System
API 670 - Machinery Protection API 613 - Continuous Duty Gear API 677 - Auxiliary Drive Gear
API 671 - Flexible Couplings In addition there are codes governing testing and operation:
x ASME PTC-22 Gas Turbine Testing
x ASME PTC-10 Compressor Testing x ASME B133 - Gas Turbines API 616 and ASME PTC-22 are the only two principal gas turbine specific codes for oil &
gas applications. API 670, 614, 613, etc. are more generic codes.
The codes and associated data sheets cover most aspects of the gas turbine package and often
form the main basis for procurement. The information includes: definitions, for example:
x
x
x
x
ISO Rating,
Normal Operating Point, Maximum Continuous Speed, Trip Speed, etc; mechanical integrity - blade natural frequencies, vibration levels, balancing requirements, alarms and shutdowns;
x Design requirements and features - materials, welding, accessories, controls,
instrumentation, inlet/exhaust systems, fuel systems; inspection, testing, and
preparation for shipment; and
x Minimum testing, inspection and certification documentation requirements. API 616
does not cover government local codes & regulations
1.3
SUPPLIER PROCUREMENT ADVICE
The main suppliers of gas turbine normally provide standard forms to assist in the selection
of the most appropriate turbine or turbines for a specific application. The information
requested is very similar to that included in the API 616 forms.
The supplier needs to take account of the installation layout and hence any zoning
requirements and the optimum configuration for the exhaust, the intended fuel composition
and whether larger turbines or several smaller turbines are preferable. This will depend if
the turbine(s) are required for power generation or driven equipment. For safety critical
applications it is necessary to ensure sufficient redundancy is in place.
The operator will normally have standard data sheets available as part of their procurement
sytem.
A2-2
1.4
TYPICAL TECHNICAL PROCUREMENT SPECIFICATION
The main technical basis for procurement is the operators design and engineering practices
and these define what is included in the technical procurement specification. The
information that may be included in a typical technical procurement specification is
summarized below.
Information included
The design specification specifies gives requirements and recommendations for the type,
selection, testing and installation of combustion gas turbine for mechanical and generator
drives and for hot gas generation. As an example, the following issues may be addressed.
Introduction
x
x
x
x
x
Definitions
Selection and evaluation Range and variety of gas turbines Prototype gas turbines Complete unit responsibility
Technical information
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
x
Operating requirements
Spares inventory
Type selection – aeroderivative or industrial, one or two shaft
Site environment and fuel considerations
Power requirements
Use of standard packages
Installation – cranes, safe access, lay down areas, mounting, enclosures, auxiliary
equipment
Noise levels- limits, support information, general requirements
Oil tank vents
Materials – specification,temperature, corrosion and environment resistance,
coatings, certification
Starting drives - gas expansion starters, hydraulic motors, diesel engines
Foundations, baseplates and mountings
Controls and instrumentation
Inlet system – intake location, new configurations, material, leak prevention, joints
and movement allowances
Air compressor cleaning
Exhaust system – Exhaust emission, height, proximity to process equipment, rain
ingress, maintenance access, recirculation
Combustion air filtration – requirements, anti-icing, shutters
Fire protection – ventilation dampers, extinguishing systems, enclosure surveillance
Acoustic enclosures – accessibility, ventilation, area classification
Fuels and fuel systems – fuel selection, gas fuels and systems, liquid fuels and
systems, dual fuel systems, power augmentation Inspection and tests – general, combustion tests, complete unit or string tests
Appendices in the design and engineering practice advise on issues such as definitions of
vital, non-essential and non-essential services and how that impacts on selection, gas turbine
A2-3
enclosure ventilation, mounting and foundation requirements, exhaust stack rain-catcher
requirements, key points for gas turbine washing systems. Diagrams of typical installation
arrangements may be included.
References
Reference is made to the Operators other design standards, covering for example:
x
x
x
x
x
x
x
x
x
x
Requisitioning binder containing data sheets Metallic materials - selected standards Metallic materials - prevention of brittle fracture Noise control Installation of rotating equipment combustion gas turbines (amendments/ supplements to API 616) field inspection prior to commissioning of mechanical equipment fire-fighting systems data/requisition sheet for equipment noise limitation data/requisition sheet for gas turbines Oil Industry Standards
Reference is normally included to relevant oil industry standards, for example:
x API RP 11 PGT Packaged combustion gas turbines
x API 617
Centrifugal compressors for petroleum, chemical and gas service
industries
x ASME PTC 22
Gas turbine power plants
x ASTM D 2880
Specification for gas turbine fuel oils
x NACE MR0175
Sulphide stress cracking resistant metallic material for oil field
equipment
x EEMUA 140
Noise procedure specification. British Standard.
x ISO 2324
Gas turbines - acceptance tests
1.5
VARIATIONS TO API 616 IN OFFSHORE APPLICATIONS
API 616 is generic and offshore operators may specify variations based on their service
experience, to ensure good practice, and to meet the particular requirements of an offshore
environment. The items that may be covered in such amendments include:
x
x
x
x
x
x
x
x
x
x
x
x
Definitions
Basic design Referenced standards Pressure casings Combustors and fuel nozzles Casing connections Rotating elements Seals
Dynamics Bearings and bearing housings Lubrication
Materials
A2-4
x
x
x
x
x
x
x
x
x
x
x
Name plates and rotational arrows
Accessories - starting and helper driver gears, couplings and guards mounting plates
Controls and instrumentation
Insulation, weatherproofing, fire protection
Acoustic enclosure
Piping and appurtenances
Inlet coolers
Fuel system treatment
Inspection and tests
Preparation for shipment
Dynamic analysis for use with modified rotor bearing designs or prototype gas
turbines
A2-5
A2-6
APPENDIX 3 HSE GUIDANCE NOTE PM84 ON GAS TURBINES
A3-1
A3-2
APPENDIX 4 GAS TURBINE SUPPLIERS AND SUMMARY
FOR UK INSTALLATIONS
INTRODUCTION
There has been significant consolidation in the gas turbine market in recent years. The
majority of gas turbines in the North Sea are now provided by Rolls Royce, Solar , General
Electric (GE) and Siemens-Westinghouse.
SOLAR
Solar based in Houston USA is one the largest suppliers of gas turbines for the offshore
market accounting for around 11% of those currently on UK installations. Solar is owned by
Caterpillar Group.
Website:
http://esolar.cat.com
The Solar turbines commonly used offshore in UK installations and Worldwide are as
follows:
Company
Solar Turbines
% UK Models UK
11%
Saturn 20
Centaur GSC 40/50
Taurus 60/70
Mars 90/100
1MW
3-4MW
5-7MW
8- 10MW
Models Worldwide
Saturn 20
Centaur 40/50
Taurus 60/70
Mars 90/100
Titan 130
1MW
3-4MW
5-7MW
8-10MW
15MW
ROLLS ROYCE GAS TURBINES 1
Rolls Royce is the market leader in the UK sector accounting for about 21% of the gas
turbines, including the 501, RB211, Avon and Coberra brands. These are all aero-derivatives
and adaptations of Rolls-Royce’s aero-engines. Coberra gas turbines use the Avon 1535
aeroderivative gas generators
Website:
http://www.rolls-royce.com/energy/products/oilgas/gasturb.jsp
The main Rolls Royce gas turbines used offshore in the UK and Worldwide include the
following:
Company
Rolls-Royce (Avon,
Coberra, RB211)
1
% UK Models UK
27%
501
Avon 1534/1535
Coberra 2000/6000
RB211
Olympus GT SK30
Paul Fletcher (stand-in for Tomas, Mon PM) Turbine Designer
A4-3
5MW
15MW
15MW
30MW
35MW
Models Worldwide
501
Avon
RB211
Trent
5MW
15MW
30MW
50MW
SIEMENS-WESTINGHOUSE2
Siemens aquired Alstom’s industrial gas turbine business www.power.alstom.com in 2003 to
fill in their portfolio for intermediate gas turbines up to 15MW. There are a number of new
turbine products: Cyclone, GT10C and GTX100 and an alternative fuels programme.
Siemens also took over the Alstom medium industrial gas turbine business with its
headquarters in Finspong, Sweden, supplying gas turbines from 15MW to 50MW. At the
same time, Siemens acquired the Alstom industrial steam turbine business, supplying
turbines up to 130MW, its main execution centers being in Finspong, (Sweden), Brno
(Czech Republic) and Nuremberg (Germany). The combined businesses are now registered
under the name of Demag Delaval Industrial Turbomachinery, and are fully owned by
Siemens.
Website: www.industrial.turbines.siemens.com
The main Siemens turbines used offshore on UK installations and Worldwide include the
following.
Company
Siemens-Westinghouse
(Alstom, Ruston, EGT)
% UK Models UK
46%
Tornado G8000/8004
Alstom Ruston
TB3000/4500/5000
PGT10
Models Worldwide
8MW Typhoon
14MW Tornado
Cyclone
14MW PGT10
Alstom had previously absorbed the turbine businesses of EGT and Ruston.
2
Siemens Frank Carchedi (Simens (UK) compressor aerodynamics Oil & Gas Mon 14.30
A4-4
5MW
8MW
13MW
14MW
The different gas turbine offerings arising historically from the Alstom, EGT, Ruston and
Siemens businesses have now been configured into a sequence of Siemens SGT models from
the SGT-100 formerly the Typhoon, the SGT-200 formerly the Tornado, up to the 100MW
plus SGT1000.
The Siemens gas turbine models used offshore are typically in the 5-30MW range.
GENERAL ELECTRIC OIL AND GAS
GE accounts for around 8% of the gas turbines on UK installations including the industrial
Frame5 gas turbine and the LM1600, LM2500, LM5000 and LM6000 series of
aeroderivative gas turbines.
LM2500 series aero-derivative gas turbines are used in a number of other manufacturers
turbine packages.The PGT series of gas turbines combines an aeroderivative gas turbine with
a more rugged industrial power turbine.
Website: www.gepower.com
GE turbines used on UK offshore installations and Worldwide include the following:
Company
General Electric Oil &
Gas:
% UK Models UK
12%
GE Frame 5
GE-1201/1401A-C
LM2500+
LM5000/6000
5MW
10-15MW
25MW
40-50MW
Models Worldwide
GE5
5MW
GE 10
10MW
LM 1600
16MW
LM 2500
25MW
Links:
Gas Turbines- Aero-Derivative:
http://www.gepower.com/prod_serv/products/aero_turbines/en/index.htm
Gas Turbines Heavy Duty
http://www.gepower.com/prod_serv/products/gas_turbines_cc/en/index.htm
Turbine Generators
http://www.gepower.com/prod_serv/products/generators/en/index.htm
Turbine Control Systems:
http://www.gepower.com/prod_serv/products/turbine_ctrl_sys/en/index.htm
OTHER
Gas turbines currently used offshore in UK waters from other independent turbine suppliers
include the following:
Company
ABB
Dresser Rand
Pratt and Witney
% UK Models UK
12%
ABB GT35
Dresser KG2, KG3
MTU V16
Pratt & Witney ST18
A4-5
1-2MW
12MW
2MW
A4-6
APPENDIX 5 SPECIFICATION OF TURBINES USED IN UK SECTOR Example ISO rated performance specifications for gas turbines installed offshore in the UK
sector, and manufacturers current models for oil and gas use, are given in the following
Table. These are taken from a variety of sources including supplier’s literature and the Gas
Turbine World 2005 Performance Specifications3.
The values are for information and cannot be guaranteed to be correct. The performance
specification will vary as improvements are made to a given gas turbine and vary for simple
cycle and combined cycle applications. The specification will also vary depending on
whether the turbine is being used in power generation, to drive a compressor or mechanical
drive. For current specifications for gas turbines in these applications, images and cross
sections for specific turbines and a wider range of turbine specifications, readers are referred
to the Suppliers web sites and the Gas Turbine World performance specifications. These
sources provide general background and detail on ISO rating as well as describing the basis
for the turbine performance measures.
3
Gas Turbine World 2005 performance Specifications gas Turbine power ratings for Project Planning, Engineering, Design and
procurement, gas Turbine wold Vol 34 No. 6 2005 GTW Specifications
A5-1
A5-2
PGT10
PGT16
PGT20
PGT20
PGT25
PGT25+
PGT5
501-KB5S
501-KB7S
501-KH5
501-KC5
501-KC7
Avon-1535
Avon2648
Avon 2656
GE
GE
GE
GE
GE
GE
GE
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
GE
GE
GE5
GE10
LM1600PE
LM2500+
6Stg
LM2500PE
LM6000
GE
GE
GE
GE
Manufacturer Model
1,988
1,988
1,988
1992
1990
1982
1992
1990
1981
1996
1989
2001
2001
1981
1992
1st year
unit
available
1999
2000
1989
1997
Year
16 MW
15 MW
15 MW
6 MW
4 MW
6 MW
5 MW
22 MW
30 MW
5 MW
4 MW
10 MW
14 MW
17 MW
17 MW
22 MW
43 MW
6 MW
11 MW
15 MW
30 MW
ISO
Base
Rating
MW
15,660
15,180
15,180
5518
4100
6447
5245
22,417
30,226
5,220
3897
10,220
13,720
17,464
17,469
22,346
43,076
8,405
8,660
8,660
7902
8495
8 509
10 848
9403
8612
12724
11 747
10940
9764
9706
9,721
9,630
8,255
A5-3
30.3%
29.4%
29.4%
31.7%
29.6%
40.1%
31.5%
36.3%
39.6%
26.8%
29.1%
31.2%
34.9%
35.2%
35.1%
35.4%
41.3%
6000h per Lower Heating Value
year or
(LHV)
more
5,500
11,130
30.7%
11,250
10884
31.4%
14,898
10094
33.8%
30,463
8,854
38.5%
%
93.3
104.3
137.7
137.8
153.6
288.8
43.1
104.7
109.7
191.3
At base
load
(lb/sec)
8.8
8.8
8.8
13.5
9.4
12.5
170
170
170
46.2
34.2
40.6
13.9 46.6 Ib
153
92
89
159
159
159
113
115
127
145
149
136
159
Per lb of
air per
second
128
kW/lb
Flow Specific
Power
17.9 151.9
21.5 185.9
9.1
54.2
10.3 33.9 Ib
13.8
20.2
15.7
18.0
18.0
30.0
14.8
15.5
21.3
22.6
Heat Efficiency Pressure
Rate
Ratio
kW Btu/kWh
ISO Base
Rating
4950
5500
5500
13600
13600
14600
14600
6,500
6,100
10,290
14200
7,900
7,900
6,500
6,500
3000
3,600
16,630
11,000
7,900
3600
Output
shaft
rpm
818
827
827
968
1060
986
928
976
931
973
1040
910
919
887
887
1001
840
1,065
900
894
960
°F
Turbine Exhaust
Speed
Temp
19 8
30 8
50 12
57 9
27 8
27 8
30
30 11
52,000
50,000
50,000
26000
25000
25000
25000
8
8
8
83018 30 11
67804 21
61740 28 8
25000
59535
41895
83018
83,003
250,000 57 9
68,342 31 14
116,160
74970
190000
260,000
10
Ratings at sea
level, 15 deg C
No external
pressure losses
Case steam
injected 2.73
kg/sec
501-KC5 Gas
generator
501-KC7 Gas
generator
Avon 1535 Gas
Generator
Avon 1535 Gas
Generator
Avon 1535 Gas
Generator
11 size w/o GT
enclosure
11
10 dry
14 Size w/o GT
enclosure
13
12
10 IDLE
20
15 Water
10 DLE
Approx Approximate Comments
Weight Dimensions
(ft)
lb
L W
H
RB211 6562
RB211-6562
DLE
RB211-6762
DLE
RB211-6761
DLE
Trent 60
IDLE
Trent 60
WLE
Rolls Royce
Rolls Royce
Rolls Royce
Tornado
Typhoon
SGT-100
SGT-100
SGT-100
SGT-100
SGT-200
Siemens
Siemens
Siemens
Siemens
Siemens
Siemens
Siemens
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Rolls Royce
Coberra
2648
Coberra
2656
Coberra
6556
Coberra
6562
RB211 6556
Rolls Royce
Manufacturer Model
1981
1998
1997
1989
1989
1981
2001
1996
2000
1999
1993
1993
1992
1993
1992
1,990
1st year
unit
available
1,989
Year
7 MW
5 MW
5 MW
5 MW
5 MW
4 MW
7 MW
58 MW
52 MW
32 MW
30 MW
28 MW
29 MW
26 MW
26 MW
26 MW
16 MW
15 MW
ISO
Base
Rating
MW
6750
5250
5050
4700
4850
4350
6640
58000
51685
32120
29500
27520
28,500
26,020
25,930
26,025
15,660
10824
11203
11294
11309
10273
11370
10760
8 346
8 138
6290
6565
6705
6705
7100
9 415
8,660
8,405
A5-4
31.5%
30.5%
30.2%
30.2%
31.0%
30.0%
31.0%
40.9%
41.9%
39.3%
37.7%
36.3%
36.7%
34.6%
29.4%
29.4%
29.4%
6000h per Lower Heating Value
year or
(LHV)
more
15,180
8,660
29.4%
%
12.3
14.8
14.3
14.1
14
13.0
11.3
36
34
21.5
21.5
20.8
20.8
20.1
20.8
20.1
8.8
8.8
Heat Efficiency Pressure
Rate
Ratio
kW Btu/kWh
ISO Base
Rating
65.0
46.0
43.0
42.0
43.2
39.0
60.6
365
341
208
211
202
209
203
208.7
203.3
169.4
170.1
At base
load
(lb/sec)
104
114
117
112
112
112
110
159
152
154
140
136
136
136
136
136
154
Per lb of
air per
second
92
kW/lb
Flow Specific
Power
11053
17384
17384
17384
17384
16500
11053
3000
3600
4850
4800
4800
4,800
4,950
4,800
4,950
4,950
5,500
Output
shaft
rpm
871
986
1015
975
954
981
860
794
825
938
920
932
917
910
1,404
1,350
1,145
1,141
°F
Turbine Exhaust
Speed
Temp
124000 41
78175 33
78175 33
78175 33
74515 27
78175 33
8
8
8
8
8
8
121253 37 11
286598
286598
57000
57000
50,000 29. 13
8
50,000 30. 13
1
58000
58,000
58,000
52,000
50,000
11 Tornado
11 Typhoon 5.25
11 Typhoon 5.05
11 Typhoon 4.70
11 Alstom - EGT
11 Typhoon 4.35
Avon 1535 Gas
Generator
Avon 1535 Gas
Generator
RB11 -24GT
Gas Generator
RB11 -24GT
Gas Generator
14 RB11 -24GT
Gas Generator
14 RB11 -24GT
Gas Generator
RB11 -24GT
Gas Generator Steam injection
RB11 -24GT
Gas Generator
RB11 -24GT
Gas Generator
RB11 -24GT
Gas Generator
RB11 -24GT
Gas Generator Water injected
8 Alstom - EGT
Approx Approximate Comments
Weight Dimensions
(ft)
lb
L W
H
Saturn 20
GS
Centaur 40
GS
Centaur 50
GS
Taurus 60
GS
Taurus 65
Taurus 70
Mars 90 GS
Solar
Solar
Solar
Mars 100 GS
Titan 130 GS
KG2-3C
KG2-3E
DR60G
DR61
DR61 G
Solar
Solar
Other
Other
Other
Other
Other
Solar
Solar
Solar
Solar
Saturn 20
Solar
SGT-700
Siemens
SGT-800
SGT-600
Siemens
SGT-900
SGT-500
Siemens
Siemens
SGT-400
Siemens
Siemens
SGT-300
Siemens
Manufacturer Model
1973
1986
1990
1989
1968
1998
1994
1994
1994
2005
1992
1993
1992
1984
1985
1982
1998
1999
1981
1968
1997
1st year
unit
available
1995
Year
24 MW
22 MW
14 MW
2 MW
1 MW
15 MW
11 MW
9 MW
8 MW
6 MW
6 MW
5 MW
4 MW
1 MW
1 MW
50 MW
45 MW
29 MW
25 MW
17 MW
13 MW
8 MW
ISO
Base
Rating
MW
23873
22302
13775
1895
1499
15000
10695
9450
7520
6000
5500
4600
3515
1210
1200
49500
45000
29060
24770
17000
12900
989
9422
9752
20421
21202
9695
10515
10710
10100
10375
11220
12270
12240
14025
14025
10450
9215
9480
9985
10600
9817
A5-5
37.6%
36.2%
35.0%
16.7%
16.1%
35.2%
33.0%
31.9%
33.8%
32.9%
31.5%
29.3%
27.9%
24.3%
24.3%
32.7%
37.0%
36.0%
34.2%
32.2%
34.8%
6000h per Lower Heating Value
year or
(LHV)
more
7900
10937
31.2%
%
18.4
18.1
21.5
4.7
3.9
15.0
17.4
16.1
16.1
15.0
11.5
10.6
9.8
6.8
6.8
15.3
19.3
18.0
14.0
12.0
16.9
13.8
Heat Efficiency Pressure
Rate
Ratio
kW Btu/kWh
ISO Base
Rating
153.0
150.0
104.0
33.0
28.2
109.8
91.7
88.5
59.4
43.2
48.3
41.6
41.0
14.4
14.4
386.0
287.0
201.0
177.3
203.5
87.0
66.0
At base
load
(lb/sec)
11170
11168
15200
14950
14951
14950
14950
22516
22516
5425
6600
6500
3000/
3600
7700
9500
14010
Output
shaft
rpm
149 5500 rpm
156 3600 rpm
992
986
1020
1020
1058
925
905
870
905
1017
950
510
820
940
940
957
1001
964
1009
707
1031
999
°F
Turbine Exhaust
Speed
Temp
18000
rpm
57
18800
rpm
132 7000 rpm
53
137
116
107
127
139
118
109
84
83
83
128
157
145
140
84
148
Per lb of
air per
second
120
kW/lb
Flow Specific
Power
9
8
9
9
8
8
8
8
6
6
7
7
308645 48 12
352735 49 13
227075 42 12
38580 21
36375 21
147599 46 10
137750 48 10
149000 48
110923 34
72700 32
67140 29
27080 18
52370 29
22000 18
19800 20
276000 50 12
379000 56 15
353000 68 15 18
335000 168 15
331000 68 16
165000 61
126000 40
18
18
11
9
9
11
12
12
11
10
7
9
7
7
7
14
13 GTX100
GT10 C
17 GT10 B
13 GT35 C
13 Cyclone
12 Tempest
Approx Approximate Comments
Weight Dimensions
(ft)
lb
L W
H
DR63G
ST18
Other
Other
Source Supplier information and 2005 GTW Turbine Specifications
Btu/lb x 2.326 = kJ/kg
kJ/kg x 0.430 = Btu/lb
1 kWh =859.8 kcal = 3413 Btu
1hp-hr = o.746 kWh = 2545 Btu
11237
8245
8416
Btu x 1.055 = kJ
kJ x 0.948 = Btu
1961
42984
31380
A5-6
3.0.4%
41.4%
40.6%
6000h per Lower Heating Value
year or
(LHV)
more
31380
8638
39.5%
%
17.6
282.0
186.0
192.0
At base
load
(lb/sec)
111
18900
152 3600 rpm
J x 0.239 = calorie
calorie x 0.239 = J
hph x 2.685 = MJ
MJ x 0.373 = hph
990
824
955
959
169 6200 rpm
°F
rpm
kW/lb
Turbine Exhaust
Speed
Temp
Output
Per lb of
air per
shaft
second
163 3600 rpm
Flow Specific
Power
lb/hph x 0.608 = kg/kWh
kg/kWh x 1.644 = lb/hph
14
29.6
22.8
22.8
Heat Efficiency Pressure
Rate
Ratio
kW Btu/kWh
ISO Base
Rating
kW x 1.341 = hp
hp x 0.746 = kW
2 MW
43 MW
31 MW
31 MW
ISO
Base
Rating
MW
lb x 0.454 = kg
kg x 2.205 = lb
1995
1992
1998
1st year
unit
available
1998
Year
ºC = (ºF-32) /1.8
ºF = (ºC x 1.8) +32
Conversion Factors
Other
DR61 GP
(SAC)
Vectra-40G
Other
Manufacturer Model
772
5
2
485010 60 14
352735 48 14
352735 48 12
3
23
18
18
Approx Approximate Comments
Weight Dimensions
(ft)
lb
L W
H
Appendix 6 Key Systems and Components
Introduction
The gas turbine itself contains three main components:
x Compressor,
x Gas generator (GG) including combustor and gas turbine (GT)
x Power turbine (PT),
Other key systems within the package include the fuel system either natural gas or liquid
(pumped), the bearing lube oil system including tank and filters, pumps (main, pre/post,
backup), the starter (usually either pneumatic, hydraulic or variable speed ac motor), cooling
systems, controls (on-skid, off-skid), driven equipment and the seal gas system (compressors).
There is other ancillary equipment external to the turbine package. This includes: the enclosure
and fire protection, the acoustic housing, the inlet system including air-filter (self-cleaning,
barrier, inertial) and silencer, the exhaust system including silencer and the exhaust stack, a lube
oil cooler (water, air), the motor control center, switchgear, neutral ground resistor and inlet
fogger/cooler. A basic description of each of the main systems is included here.
Package Mounting
The gas turbine within an Offshore Package is normally centre-line mounted from the
baseframe, ensuring internal alignment while permitting thermal expansion of the machine. The
main drive shaft, which will be at the hot or exhaust end for a mechanical drive package,
includes a flexible coupling, as will any auxiliary drive shafts. Flexible connections link to the
inlet and exhaust ducts. The fuel manifold is wrapped around the middle of the machine, with
multiple combustor fuel feeds. Hot surfaces will be fitted with heat shields or thermal insulation
for operator safety.
For turbine packages all machine elements are mounted to a common baseframe that is
sufficiently rigid to maintain machine alignment, despite movement of the supporting structure
or vessel. The normal 3-point mounting system eliminates the transmission of twisting forces to
and from the baseframe. As many as possible of the ancillary systems e.g. lubrication oil
system, seal gas support system, are built into the main baseframe in order to save space, and
the weight of additional bases. The control panel may be mounted separately or built on to the
end of the baseframe. The former permits control panels for separate machines to be grouped
together; the latter is convenient for pre-wiring.
Acoustic enclosure
The gas turbine is normally enclosed in a acoustic enclosure. The enclosure reduces the risk
from the noise hazard but introduces hazards of an enclosure possibly containing flammable
gas. The Acoustic Enclosure for an Aero-derivative Gas Turbine is normally close fitting, and
fitted out with ventilation and Fire & Gas Detection Systems. The internal space can be tightly
packed, making access to internal components quite difficult. Modern practice is to use a
modular approach with units simply replaced for maintenance. A problem on one component
has the potential to affect adjacent components or systems, whether by release of material,
vibration or over-heating. It may be necessary to remove a component to gain access to adjacent
components.
A6-1
The gas compressor and drive gearbox (if fitted) will be outside the acoustic enclosure, but still
very closely packed with service pipework & cable trunking. Good design should permit ready
access to compressor bearings, instruments and drive couplings.
The air inlet housing will be located separate from the turbine next to the external cladding of
the process area.
Ventilation
Ventilation requirements within the turbine enclosure are important to minimise the risk of fire
and explosion following any leak of fuel, gas or oil as well as ensure safety during maintenance
intervention and monitoring. Guidance on ventilation requirements for turbines in offshore
installations can be found in the main report and in PM84 (Appendix 3) and HSE Research
Report RR076.
Fire and gas explosion prevention system
Gas turbines operate at very high temperature particularly in the gas generator, combustor and
early stages of the power turbine. Temperatures are very high also in the exhaust and associated
lagging. There are large amounts of pipework external to the turbine for lubrication of bearings
and seals and fuel supply to the combustor. Gas leaks also can occur if seals become
ineffective. The high temperatures ensure that any leak is likely to lead to ignition and fire.
Most dangerous occurrences noted in the HSE RIDDOR and ORION databases are of this type.
A robust fire prevention system is required. This is usually based on extinguishing the fire
using an appropriate inert but breathable gas. Halon systems were formerly used but has been
phased out offshore. Guidance on fire prevention systems is given in Section PM84 and RR076.
Extinguishing systems
Water deluge systems shall not be fitted on gas turbine installations (a deluge of water on to a
hot gas turbine casing will cause extensive damage). Inergen or C02 gaseous fire extinguishing
systems are often used. Inergen is an agent composed of nitrogen, argon and carbon dioxide,
which after a release sufficiently reduces the concentration of oxygen to stop a fire but is safe
enough for humans to survive and function in a normal matter. The mixture of nitrogen, argon
and carbon dioxide stimulates respiration systems so that survival in a low oxygen environment
is possible. Inergen is therefore safer than C02 and may be the preferred choice for new
applications provided appropriate refills are locally available. Release of the agents can be
automatically and/or manually initiated. For offshore applications, fine water mist systems may
be considered if space is at premium. These systems require a large quantity of nozzles and
tubing to be an effective extinguishing system at the source of the fire.
Enclosure surveillance
For remote unattended locations, the use may be considered of closed circuit television (CCTV)
to monitor equipment within an acoustic enclosure. Zoom, pan and tilt controls shall be
provided from the control room. With low light image intensification, CCTV is a useful tool for
operators to survey remote equipment.
AIR INTAKE
Air intake to the turbine is through large bore ducting. The air is filtered using a self cleaning
inertial barrier filter. De-icing systems are also used to optimise the air condition before entry
A6-2
into the air compressor. Turbines are capable of working across a wide range of inlet
temperatures and environmental conditions. Control of air condition and temperature is
particularly critical for turbine performance and efficiency in low emission (DLE) turbines. A
silencer is also fitted to the air intake to minimise noise and vibration.
Air Intake Filter
Air feed to the gas turbine is filtered through a series of filtration elements to ensure cleanliness
of combustion air.
COMBUSTION AIR COMPRESSOR
The air compressor is the first major part of the gas turbine. It’s function is to compress the air
before combustion and expansion through the turbine. There are two basic types of compressor,
one giving axial flow and the other centrifugal flow. Axial compressors are by far the most used
in modern offshore gas turbines giving higher air flow, pressure ratios, fuel effiviancy and
thrust. Centrifugal compressors may be found in older or smaller turbines where its simplicity
and ruggedness outweigh any other disadvantages. Both types are driven by the engine
turbine and are usually coupled direct to the turbine shaft.
The axial flow compressor is a multi-stage unit employing alternate rows of rotating (rotor)
blades and stationary (stator) vanes, to accelerate and diffuse the air until the required pressure
rise is obtained. A centrifugal flow compressor is a single or two-stage unit employing an
impeller to accelerate the air and a diffuser to produce the required pressure rise.
Figure A6.1 Axial compressor and high pressure turbine rotor in PGT5 gas turbine.
Courtesy Nuovo Pigneone
Axial Flow Compressor
An axial flow compressor consists of one or more rotor assemblies that carry blades of airfoil
section. These assemblies are mounted between bearings in the casings which incorporate the
stator vanes. The compressor is a multi-stage unit as the amount of pressure increase by each
stage is small; a stage consists of a row of rotating blades followed by a row of stator vanes.
A6-3
Design of blades and stator vanes is highly specialized. The casing and rotor are tapered from
the front (low-pressure) end to rear (high pressure) to maintain constant axial flow velocity.
The construction of the compressor centres around the rotor assembly and casings. The rotor
shaft is supported in ball and roller bearings and coupled to the turbine shaft in a manner that
allows for any slight variation of alignment. The cylindrical casing assembly may consist of a
number of cylindrical casings with a bolted axial joint between each stage or the casing may be
in two halves with a bolted centre line joint. One or other of these construction methods is
required in order that the casing can be assembled around the rotor.
Principles
The rotor is turned at high speed by the turbine so that air is continuously induced into the
compressor, which is then accelerated by the rotating blades and swept rearwards onto the
adjacent row of stator vanes. The pressure rise results from the energy imparted to the air in the
rotor which increases the air velocity. The air is then decelerated (diffused) in the following
stator passage and the kinetic energy translated into pressure.
Stator vanes serve to correct the deflection given to the air by the rotor blades and to present the
air at the correct angle to the next stage of rotor blades. The last row of stator vanes usually act
as air straighteners to remove swirl from the air prior to entry into the combustion system at a
reasonably uniform axial velocity. Pressure changes are accompanied by a progressive increase
in air temperature as the pressure increases.
The pressure change across each stage can be quite small, typically 1:1 and 1:2. The compressor
itself can increase pressure by factors of 30:1 or more. The ability to design multi-stage axial
compressors with controlled air velocities and straight through flow minimizes losses and
results in a high efficiency and hence low fuel consumption. This gives it a further advantage
over the centrifugal compressor where these conditions are fundamentally not so easily
achieved. For high pressure ratios variable-angle stator vanes or interstage blades are used to
ensure uniform flow and compression across the full speed range.
Figure A6-2 RB211 gas generator showing axial compressor with stator vanes at left hand side, combustion chamber and initial turbine stages. Courtesy Rolls Royce A6-4
A single-spool compressor consists of one rotor assembly and stators with as many stages as
necessary to achieve the desired pressure ratio and all the airflow from the intake passes through
the compressor. The multi-spool compressor consists of two or more rotor assemblies, each
driven by their own turbine at an optimum speed to achieve higher pressure ratios and to give
greater operating flexibility.
Although a twin-spool compressor can be used for a pure jet engine, it is most suitable for the
by-pass type of engine where the front or low pressure compressor is designed to handle a larger
airflow than the high pressure compressor. Only a percentage of the air from the low pressure
compressor passes into the high pressure compressor; the remainder of the air, the by-pass flow,
is ducted around the high pressure compressor.
Components
The construction of the compressor centres around the rotor assembly and casings. The main
components of an axial air compressor comprise:
x
x
x
x
x
x
x
Rotors
Blades
Stator vanes
Discs
Casing
Rotor shaft
Bearings and seals Rotors
The rotational speed of an axial compressor is such that a disc is required to support the
centrifugal blade load. Where a number of discs are fitted onto one shaft they may be coupled
and secured together by a mechanical fixing. Generally, the discs are assembled and welded
together, close to their periphery, thus forming an integral drum.
Figure A6-3 Detail of Rotor on aeroderivative gas turbine. Courtesy Sulzer. A6-5
Rotor blades
The rotor blades are of airfoil section (Figure A6-4) and usually designed to give a pressure
gradient along their length to ensure that the air maintains a reasonably uniform axial velocity.
The higher pressure towards the tip balances out the centrifugal action of the rotor on the
airstream. The blade is twisted from root to tip to give the correct angle of incidence at each
point, defined by a stagger angle. Air flowing through a compressor creates two boundary
layers of slow to stagnant air on the inner and outer walls. In order to compensate for the slew
air in the boundary layer a localized increase in blade camber both at the blade tip and root has
been introduced. The blade extremities appear as if formed by bending over each corner, hence
the term end-bend.
Figure A6-4 Gas turbine compressor and stator parts including variable angle stators.
.Courtesy Nuovo Pigneone, EGT
Rotor Disc
Individual rotor blades are attached to the rotor disc. A variety of fixing methods may be used.
Fixing may be circumferential or axial to suit special requirements of the stage. In general the
aim is to design a securing feature that imparts the lightest possible load on the supporting disc
thus minimizing disc weight. Rotor discs are then stacked on the rotor shaft (Figure A6-5)
Figure A6-5 Installation of rotor blades. Courtesy Sulzer A6-6
Stator vanes
The stator vanes are of airfoil section and are secured into the compressor casing or into stator
vane retaining rings, which are themselves secured to the casing (Figure A6-6). The vanes are
often assembled in segments in the front stages and may be shrouded at their inner ends to
minimize the vibrational effect of flow variations on the longer vanes. The stator vanes are
locked in such a manner that they will not rotate around the casing.
Figure A6-6 Axial compressor half casing and stator blades
Casings
The construction of the compressor centres around the rotor assembly and casings. The
cylindrical casing assembly may consist of a number of cylindrical casings with a bolted axial
joint between each stage or the casing may be in two halves with a bolted centre line joint. One
or other of these construction methods is required in order that the casing can be assembled
around the rotor.
Rotor Shaft
The rotor shaft is supported in ball and roller bearings and coupled to the turbine shaft in a
manner that allows for any slight variation of alignment.
Airflow Control
Where high pressure ratios on a single shaft are required it becomes necessary to introduce
airflow control into the compressor design. This may take the form of variable inlet guide vanes
for the first stage plus a number of stages incorporating variable stator vanes for the succeeding
stages as the shaft pressure ratio is increased (fig. 3-15). As the compressor speed is reduced
from its design value these static vanes are progressively closed in order to maintain an
A6-7
acceptable air angle value onto the following rotor blades. Additionally interstage bleed may be
provided but its use in design is now usually limited to the provision of extra margin while the
engine is being accelerated, because use at steady operating conditions is inefficient and
wasteful of fuel. Three types of air bleed systems are used: hydraulic, pneumatic and electronic.
Figure A6-7 Typical variable stator vanes. Courtesy Rolls Royce.
For casing designs the need is for a light but rigid construction enabling blade tip clearances to
be accurately maintained ensuring the highest possible efficiency. These needs are achieved by
using aluminium at the front of the compression system followed by alloy steel as compression
temperature increases. Whilst for the final stages of the compression system, where temperature
requirements possibly exceed the capability of the best steel, nickel based alloys may be
required. The use of titanium in preference to aluminium and steel is now more common;
particularly in military engines where its high rigidity to density ratio can result in significant
weight reduction. With the development of new manufacturing methods component costs can
now be maintained at a more acceptable level in spite of high initial material costs.
Stator vanes are normally produced from steel or nickel based alloys, a prime requirement being
a high fatigue strength when notched by ingestion damage. Earlier designs specified aluminium
alloys but because of its inferior ability to withstand damage its use has declined. Titanium may
be used for stator vanes in the low pressure area but is unsuitable for the smaller stator vanes
further rearwards in the compression system because of the higher pressures and temperatures
encountered. Any excessive rub which may occur between rotating and static components as a
result of other mechanical failures, can generate sufficient heat from friction to ignite the
titanium. This in turn can lead to expensive repair costs and a possible hazard.
A6-8
Figure A6-8 A hydraulically operated bleed valve and inlet guide vane
airflow control system.
In the design of rotor discs, drums and blades, centrifugal forces dominate and the requirement
is for metal with the highest ratio of strength to density. This results in the lightest possible rotor
assembly which in turn reduces the forces on the engine structure enabling a further reduction in
weight to be obtained. For this reason, titanium even with its high initial cost is the preferred
material and has replaced the steel alloys that were favoured in earlier designs. As higher
temperature titanium alloys are developed and produced they are progressively displacing the
nickel alloys for the disc and blades at the rear of the system.
Materials
Materials are chosen to achieve the most cost effective design for the components in question,
in practice for aero engine design this need is usually best satisfied by the lightest design that
technology allows for the given loads and temperatures prevailing.
A6-9
Figure A6-9 Typical types of fan blades.
Centrifugal impeller material requirements are similar to those for the axial compressor rotors.
Titanium is thus normally specified though aluminium may still be employed on the largest
lowpressure ratio designs where robust sections give adequate ingestion capability and
temperatures are acceptably low.
Balancing
The balancing of a compressor rotor or impeller is an extremely important operation in its
manufacture. In view of the high rotational speeds and the mass of materials any unbalance
would affect the rotating assembly bearings and engine operation. Balancing on these parts is
effected on a special balancing machine.
Centrifugal Flow Compressor
Centrifugal flow compressors have a single or double-sided impeller and occasionally a twostage, single sided impeller is used. The impeller is supported in a casing that also contains a
ring of diffuser vanes. If a double-entry impeller is used, the airflow to the rear side is reversed
in direction and a plenum chamber is required. The impeller shaft rotates in ball and roller
bearings and is either common to the turbine shaft or split in the centre. The impellor shaft is
connected by a coupling, which is usually designed for ease of detachment.
A6-10
Figure A6-10 Two stage cylindrical compressor and two stage turbine. PGT2 gas
turbine. Courtesy Nuovo Pigneone.
Impellers
The impeller is rotated at high speed by the turbine and air is continuously induced into the
centre of the impeller. Centrifugal action causes it to flow radially outwards along the vanes to
the impeller tip, thus accelerating the air and also causing a rise in pressure to occur. The engine
intake duct may contain vanes that provide an initial swirl to the air entering the compressor.
The impeller consists of a forged disc with integral, radially disposed vanes on one or both side
forming convergent passages in conjunction with the compressor casing. For ease of
manufacture straight radial vanes are usually employed. To ease the air from axial flow in the
entry duct on to the rotating impeller, the vanes in the centre of the impeller are curved in the
direction of rotation.
Diffusers
The air, on leaving the impeller, passes into the diffuser section where the passages form
divergent nozzles that convert most of the kinetic energy into pressure. To maximize the airflow
and pressure rise through the compressor requires the impeller to be rotated at high speed,
therefore impellers are designed to operate at tip speeds of up to 1,600 ft. per sec. To maintain
the efficiency of the compressor, it is necessary to prevent excessive air leakage between the
impeller and the casing; this is achieved by keeping their clearances as small as possible. The
diffuser assembly may be an integral part of the compressor casing or a separately attached
assembly. In each instance it consists of a number of vanes formed tangential to the impeller.
The vane passages are divergent to convert the kinetic energy into pressure energy and the inner
edges of the vanes are in line with the direction of the resultant airflow from the impeller. The
clearance between the impeller and the diffuser is an important factor
A6-11
GAS GENERATOR (CORE ENGINE)
Combustion System
The combustion chamber (has the difficult task of burning large quantities of fuel, supplied
through the fuel spray nozzles, with extensive volumes of air, supplied by the compressor, and
releasing the heat in such a manner that the air is expanded and accelerated to give a smooth
stream of uniformly heated gas at all conditions required by the turbine. This task must be
accomplished with the minimum loss in pressure and with the maximum heat release for the
limited space available. The amount of fuel added to the air will depend upon the temperature
rise required. However, the maximum temperature is limited to within the range of 850 to 1700
qC, determined by the temperature limitations for the materials from which the turbine blades
and nozzles are made.
The air has already been heated to between 200 and 550qC the work done during compression,
giving a temperature rise requirement of 650 to 1150 ºC from the combustion process. Since the
gas temperature required at the turbine varies with engine thrust, the combustion chamber must
also be capable of maintaining stable and efficient combustion over a wide range of engine
operating conditions. Efficient combustion has become increasingly important because of the
need to carbon emissions and atmospheric pollution.
Figure A6-11 Avon gas generator with combustion chamber and surrounding fuel
nozzles visible to right.
Combustion Process
Air from the engine compressor enters the combustion chamber at a velocity up to 200 m s-1 sec,
Because at this velocity the air speed is far too high for combustion, the first thing that the
chamber must do is to diffuse it, i.e. decelerate it and raise its static pressure. The speed of
burning fuel at normal mixture ratios is only a few feet per second, any fuel lit even in the
diffused air stream, which now has a velocity of about 80 feet per second, would be blown
away. A region of low axial velocity has therefore to be created in the chamber, so that the
flame will remain alight throughout the range of engine operating conditions. Designs of
combustor and fuel nozzle are shown in Figure A6-12 below.
A6-12
Figure A6-12 Multiple combustor in EGT typhoon gas turbine. Right, combustion
chamber liner. Courtesy EGT, Nuovo Pigneone
In normal operation, the overall air/fuel ratio of a combustion chamber can vary between 45:1
and 130:1. However, fuel will only burn efficiently at, or close to, a ratio of 15:1, so the fuel
must normally be burned with only part of the air entering the chamber, in what is called a
primary combustion zone. This is achieved by means of a flame tube (combustion liner).
Approximately 20 per cent of the air mass flow is taken in by the snout or entry section.
Immediately downstream of the snout are swirl vanes and a perforated flare, through which air
passes into the primary combustion zone. The swirling air induces a flow upstream of the centre
of the flame tube and promotes the desired recirculation. The air not picked up by the snout
flows into the annular space between the flame tube and the air casing.
Through the wall of the flame tube body, adjacent to the combustion zone, are a selected
number of secondary holes through which a further 20 per cent of the main flow of air passes
into the primary zone. The air from the swirl vanes and that from the secondary air holes
interacts and creates a region of low velocity recirculation. This takes the form of a toroidal
vortex,similar to a smoke ring, which has the effect of stabilizing and anchoring the flame . The
recirculating gases hasten the burning of freshly. It is arranged that the conical fuel spray from
the nozzle intersects the recirculation vortex at its centre. This action, together with the general
turbulence in the primary zone, greatly assists in breaking up the fuel and mixing it with the
incoming air.
The temperature of the gases released by combustion is about 1,800 to 2,000 qC which is far
too hot for entry to the nozzle guide vanes of the turbine. The air not used for combustion,
which amounts to about 60 per cent of the total airflow, is therefore introduced progressively
into the flame tube. Approximately a third of this is used to lower the gas temperature in the
dilution zone before it enters the turbine and the remainder is used for cooling the walls of the
flame tube. This is achieved by a film of cooling air flowing along the inside surface of the
flame tube wall, insulating it from the hot combustion gases. A recent development allows
cooling air to enter a network of passages within the flame tube wall before exiting to form an
insulating film of air, this can reduce the required wall cooling airflow by up to 50 per cent.
Combustion should be completed before the dilution air, enters the flame tube, otherwise the
A6-13
incoming air will cool the flame and incomplete combustion will result. An electric spark from
an igniter plug initiates combustion and the flame is then self sustained.
Figure A6-13 Flame stabilizing and general airflow pattern through a combustion
chamber. Courtesy Rolls Royce
Fuel Supply
Fuel is supplied to the airstream by one of two distinct methods. The most common is the
injection of a fine atomized spray into the recirculating airstream through spray nozzles. The
second method is based on the pre-vaporization of the fuel before it enters the combustion zone.
In the vaporizing method the fuel is sprayed from feed tubes into vaporizing tubes which are
positioned inside the flame tube. These tubes turn the fuel through 180 degrees and, as they are
heated by combustion, the fuel vaporizes before passing into the flame tube. The primary
airflow passes down the vaporizing tubes with the fuel and also through holes in the flame tube
entry section which provide fans of air to sweep the flame rearwards.
Types Of Combustion Chamber
The design of a combustion chamber and the method of adding the fuel may vary considerably,
but the airflow distribution used to effect and maintain combustion is always very similar to that
described. Dilution air is metered into the flame tube in a manner similar to the atomizer flame
tube. There are three main types of combustion chamber in use for gas turbine engines. These
are the multiple chamber, the tubo-annular chamber and the annular chamber.
Multiple combustion chamber
This type of combustion chamber is used on centrifugal compressor engines and the earlier
types of axial flow compressor engines. It is a direct development of the early type of Whittle
combustion chamber. The major difference is that the Whittle chamber had a reverse flow but,
as this created a considerable pressure loss, the straight-through multiple chamber was
developed by Joseph Lucas Limited. The chambers are disposed around the engine and
compressor delivery air is directed by ducts to pass into the individual chambers. Each chamber
has an inner flame tube around which there is an air casing. The air passes through the flame
tube snout and also between the tube and the outer casing as already described .The separate
A6-14
flame tubes are all interconnected. This allows each tube to operate at the same pressure and
also allows combustion to propagate around the flame tubes during engine starting.
Tubo-annular combustion chamber
The tubo-annular combustion chamber bridges the evolutionary gap between the multiple and
annular types. A number of flame tubes are fitted inside a common air casing. The airflow is
similar to that already described. This arrangement combines the ease of overhaul and testing of
the multiple system with the compactness of the annular system.
Annular combustion chamber
The annular combustion chamber is the design most favoured in modern aero-derivative gas
turbines, such as those used offshore. This type of combustion chamber consists of a single
flame tube, completely annular in form, which is contained in an inner and outer casing . The
airflow through the flame tube is similar to that already described, the chamber being open at
the front to the compressor and at the rear to the turbine nozzles.The main advantage of the
annular chamber is that, for the same power output, the length of the chamber is only 75 per
cent of that of a tubo-annular system of the same diameter, resulting in considerable saving of
weight and production cost.
Another advantage is the elimination of combustion propagation problems from chamber to
chamber. In comparison with a tubo-annular combustion system, the wall area of a comparable
annular chamber is much less; consequently the amount of cooling air required to prevent the
burning of the flame tube wall is less, by approximately 15 per cent. This reduction in cooling
air raises the combustion efficiency to virtually eliminate unburnt fuel, and oxidizes the carbon
monoxide to non-toxic carbon dioxide, thus reducing air pollution.The introduction of the air
spray type fuel spray nozzle to this type of combustion chamber also greatly improves the
preparation of fuel for
Fuel manifold
The fuel manifold supplies fuel to the combustion nozzles via a series of pipes. Fuel flow and
ignition is controlled by the control system. The start up process for turbines is controlled to
provide adequate air flow through the compressor before fuel is injected. Excessive build up of
fuel due to failed starts has in a number of cases lead to internal explosion within the
combustion chamber and damage to the turbine.
Combustion Nozzles
Fuel is injected into the turbine through a series of injection nozzles. Design is such as to inject
the fuel into reverse flow to ensure uniform dispersion and mixing with the air prior to ignition.
Ignition is usually by inductive discharge.
A6-15
TRANSITION PIECE
The transition piece leading from the combustion chamber to the power turbine encounters
some of the highest temperatures in the gas turbine. Oxidation, erosion and cracking of the
transition piece are key concerns. There has been significant development of specialised NDE
methods including thermography for inspection and wall thickness wall loss measurement in
transition pieces.
Figure A6-14 Transition piece leading into power-turbine. Courtesy Sulzer
POWER TURBINE (PT)
The power turbine has the task of providing the power to drive the compressor and accessories
and, in the case of driven equipment of providing shaft power for power generation, the
compressor or pump. It does this by extracting energy from the hot gases released from the
combustion system and expanding them to a lower pressure and temperature. High stresses are
involved in this process, and for efficient operation, the turbine blade tips may rotate at speeds
over 1,500 feet per second. The continuous flow of gas to which the turbine is exposed may
have an entry temperature between 850 and 1,700 deg C and may reach a velocity of over 2,500
feet per second in parts of the turbine.
To produce the driving torque, the turbine may consist of several stages each employing one
row of stationary nozzle guide vanes and one row of moving blades. The number of stages
depends upon the relationship between the power required from the gas flow, the rotational
speed at which it must be produced and the diameter of turbine permitted.
The number of shafts, and therefore turbines, varies with the type of engine. High compression
ratio turbines usually have two shafts, driving high and low pressure compressors. On some
turbines, driving torque is derived from a free-power turbine This method allows the turbine to
run at its optimum speed because it is mechanically independent of other turbine and
compressor shafts.
A6-16
Figure A6-15 Power turbine rotor. Courtesy Rolls Royce
The mean blade speed of a turbine has considerable effect on the maximum efficiency possible
for a given stage output. For a given output the gas velocities, deflections, and hence losses, are
reduced in proportion to the square of higher mean blade speeds. Stress in the turbine disc
increases as the square of the speed, therefore to maintain the same stress level at higher speed
the sectional thickness, hence the weight, must be increased disproportionately. For this reason,
the final design is a compromise between efficiency and weight. Turbines operating at higher
turbine inlet temperatures are thermally more efficient and have an improved power to weight
ratio. The design of the nozzle guide vane and turbine blade passages is based on aerodynamic
considerations The turbine depends for it’s operation on the transfer of energy between the
combustion gases and the turbine. This transfer is never 100 per cent because of thermodynamic
and mechanical losses.
Figure A6-16 Turbine blades PGT2 gas turbine. Courtesy Nuovo Pigneone A6-17
Figure A6-17 A typical turbine blade showing twisted contour
The losses which prevent the turbine from being 100 percent efficient are due to a number of
reasons the turbine blades. A further 4.5 per cent loss would be incurred by aerodynamic losses
in the nozzle guide vanes, gas leakage over the turbine blade tips and exhaust system losses;
these losses are of approximately equal proportions. The total losses result in an overall
efficiency of approximately 92 per cent.
The basic components of the turbine are the combustion discharge nozzles, the nozzle guide
vanes, the turbine discs and the turbine blades. The rotating assembly is carried on bearings
mounted in common to the compressor shaft or connected to it by a self-aligning coupling.
Nozzle guide vanes
The nozzle guide vanes are of an aerofoil shape with the passage between adjacent vanes
forming a convergent duct. The vanes are located in the turbine casing in a manner that allows
for expansion. The nozzle guide vanes are usually of hollow form and may be cooled by passing
compressor delivery air through them to reduce the effects. of high thermal stresses and gas
loads.
A6-18
Figure A6-18 Typical nozzle guide vanes showing their shape and location. Courtesy
Rolls Royce.
Turbine discs
Turbine discs are usually manufactured from a machined forging with an integral shaft or with a
flange onto which the shaft may be bolted. The disc also has, around its perimeter, provision for
the attachment of the turbine blades. To limit the effect of heat conduction from the turbine
blades to the disc a flow of cooling air is passed across both sides of each disc.
Turbine blades
The turbine blades are of an aerofoil shape, designed to provide passages between adjacent
blades that give a steady acceleration of the flow up to the 'throat', where the area is smallest and
the velocity reaches that required at exit to produce the required degree of reaction.. The actual
area of each blade cross-section is fixed by the permitted stress in the material used and by the
size of any holes which may be required for cooling purposes (Part 9). High efficiency demands
thin trailing edges to the sections, but a compromise has to be made so as to prevent the blades
cracking due to the temperature changes during engine operation.
The method of attaching the blades to the turbine disc is of considerable importance, since the
stress in the disc around the fixing or in the blade root has an important bearing on the limiting
rim speed. The blades on the early Whittle engine were attached by the de Laval bulb root
fixing, but this design was soon superseded by the 'fir-tree' fixing that is now used in the
majority of gas turbine engines. This type of fixing involves very accurate machining to ensure
that the loading is shared by all the serrations. The blade is free in the serrations when the
turbine is stationary and is stiffened in the root by centrifugal loading when the turbine is
rotating. Various methods of blade attachment are shown in fig. 5-9; however, the B.M.W.
hollow blade and the de Laval bulb root types are not now generally used on gas turbine
engines.
A gap exists between the blade tips and casing, which varies in size due to the different rates of
expansion and contraction. To reduce the loss of efficiency through gas leakage across the blade
tips, a shroud is often fitted. This is made up by a small segment at the tip of each blade which
forms a peripheral ring around the blade tips. An abradable lining in the casing may also be
A6-19
used to reduce gas leakage. Active Clearance Control (ACC.) is a more effective method of
maintaining minimum tip clearance throughout the turbine cycle. Air from the compressor is
used to cool the turbine casing and when used with shroudless turbine blades, enables higher
temperatures and speeds to be used.
The flow characteristics of the turbine must be very carefully matched with those of the
compressor to obtain the maximum efficiency and performance of the engine. If, for example,
the nozzle guide vanes allowed too low a maximum flow, then a back pressure would build up
causing the compressor to surge; too high a flow would cause the compressor to choke. In either
condition a loss of efficiency would very rapidly occur.
Among the obstacles in the way of using higher turbine entry temperatures have always been
the effects of these temperatures on the nozzle guide vanes and turbine blades. The high speed
of rotation which imparts tensile stress to the turbine disc and blades is also a limiting factor.
Figure A6-19 PGT turbine rotor showing fir tree root attachment of turbine blades and blade clearances A6-20
Figure A6-20 Various methods of attaching blades to turbine discs. Courtesy Rolls
Royce
Nozzle guide vanes
Due to their static condition, the nozzle guide vanes do not endure the same rotational stresses as
the turbine blades. Therefore, heat resistance is the property most required. Nickel alloys are
used, although cooling is required to prevent melting. Ceramic coatings can enhance the heat
resisting properties and, for the same set of conditions, reduce the amount of cooling air
required, thus improving engine efficiency.
Turbine discs
A turbine disc has to rotate at high speed in a relatively cool environment and is subjected to
large rotational stresses. The limiting factor which affects the useful disc life is its resistance to
fatigue cracking. In the past, turbine discs have been made in ferritic and austenitic steels but
nickel based alloys are currently used. Increasing the alloying elements in nickel extend the life
limits of a disc by increasing fatigue resistance. Alternatively, expensive powder metallurgy
discs, which offer an additional 10% in strength, allow faster rotational speeds to be achieved.
Turbine blades.
The correct choice of blade material is important. The blades, while glowing red-hot, must be
strong enough to carry the centrifugal loads due to rotation at high speed. A small turbine blade
weighing only two ounces may exert a load of over two tons at top speed and it must withstand
the high bending loads applied by the gas to produce the many thousands of turbine horsepower necessary to drive the compressor. Turbine blades must also be resistant to fatigue and
thermal shock, so that they will not fail under the influence of high frequency fluctuations in the
gas conditions, and they must also be resistant to corrosion and oxidization. In spite of all these
demands, the blades must be made in a material that can be accurately formed and machined by
current manufacturing methods.
For a particular blade material and an acceptable safe life there is an associated maximum
permissible -turbine entry temperature and a corresponding maximum engine power. It is not
A6-21
surprising that metallurgists and designers are constantly searching for better turbine blade
materials and improved methods of blade cooling. Over a period of operational time the turbine
blades slowly grow in length. This phenomenon is known as creep and there is a finite useful
life limit before failure occurs. The early materials used were high temperature steel forgings,
but these were rapidly replaced by cast nickel base alloys which give better creep and fatigue
properties.
Close examination of a conventional turbine blade reveals a myriad of crystals that lie in all
directions (equi-axed). Improved service life can be obtained by aligning the crystals to form
columns along the blade length, produced by a method known as Directional Solidification. A
further advance of this technique is to make the blade out of a single crystal. Each method
extends the useful creep life of the blade and in the case of the single crystal blade, the
operating temperature can be substantially increased. A non-metal based turbine blade can
be manufactured from reinforced ceramics.
The balancing of a turbine is an extremely important operation in its assembly. In view of
the high rotational speeds and the mass of materials, any unbalance could seriously affect
the rotating assembly bearings and engine operation. Balancing is effected on a special
balancing machine.
Bearings and seals
The shafts on the air compressor and power turbine have bearings on both ends and associated
seals to allow free movement of the shaft The bearings are typically high integrity thrust and
journal bearings. The shaft rotates at hign velocity and the bearing must also cope with the
aggressive environment and temperature fluctuations. There are a range of potential damage
mechanisms ranging from wear and erosion of the surface to rolling contact fatigue and
cracking. Degradation is also possible in the seals and bearing support structure. A lubrication
system ensures free flow of oil to the bearings and seals to prevent gas leaks. There are a large
number of other seals within the turbine to control airflow and dispersion of gases.
Figure 21 Bearing design on modern gas turbine. Courtesy Rolls Royce. A6-22
MECHANICAL DRIVE
Output Shaft and Coupling
The output shaft provides direct drive for driven equipment. In most cases this will be to a
gearbox to give greater flexibility in the drive speeds for the gas turbine and the equipment.
Drive Gearboxes
The inclusion of a drive gearbox within the machine package allows the manufacturer to
optimise operating speeds of the Gas Turbine driver and Centrifugal Compressor separately.
The technical disadvantages of additional skid length, equipment complexity, and weight being
offset with benefits for the design of compressor and turbine. Gas Turbine packages will include
an Auxiliary Gearbox, normally integral to the cold end of the machine. This provides the
necessary linkage for turbine starting, and mechanical drives where required for oil or fuel
pumps. There are a limited number of safety issues from inclusion of a gearbox within a
machine package. The most serious are: the potential for accidental or failure engagement of
auxiliary drives, used to rotate the compressor at low speed, leading to massive overspeed and
usual disintegration of the drive; bursting of the gear wheels (design or manufacturing flaws),
fires due to leakage of lubricating oil.
Main Drive Coupling
The use of flexible couplings within a gas turbine machine package is essential to provide the
necessary degrees of freedom to enable the machine elements to be aligned, and compensate for
any flexibility inherent in the installation skid. Misalignment of the coupling, even within its
tolerance limits, puts increased loads on adjacent shaft bearings. It also reduces the service life
of the coupling, as flexible elements are subjected to greater strains. Coupling lubrication
(where required) and inspections needs to be proactively maintained as the coupling has
significant mass and has the potential to become a dangerous missile if it fails. Loss of drive is
not normally a safety-related incident; special design requirements apply if drive continuity is
critical.
Ancillary Gearbox
Mechanical or electrical power is required to run a number of turbine support systems including
cooling, lubrication and fuel injection. Drive is commonly take from the air compressor shaft in
the cold portion of the engine and converted for turbine system drive using a gearbox or small
generator. This should be distinguished from the auxiliary gearbox used for mechanical drive of
compressors and driven equipment, described separately in the main report.
Drive couplings
For dual-shaft turbine packages mechanical drive is achieved through an auxiliary gearbox with
flexible couplings. These are described in more detail under driven equipment in HSE Research
Report RR076.
EXHAUST SYSTEM
Exhaust air at very high temperatures is injected from the power turbine into the exhaust
system. This is cooled and dispersed to the flare stack or waste heat recovery unit (WHRU).
Approximately 50% of offshore turbine installations currently include waste heat recovery
A6-23
units. Because of the high temperatures the exhaust baffles are coated and lagged. Loss of
lagging following storm conditions and ignition of the lagging following an oil or fuel leak are
common sources of accidents. See analysis of dangerous occurrences and incidents for gas
turbines in main report.
The high velocity of the air can generate significant noise. Consequentially the exhaust system
will also include a silencer. Exhaust configuration may be axial, usual for WHRUs, or radial
allowing the exhaust air to be passed to the flare at a higher level in the installation.
ANCILLIARY SYSTEMS
The gas turbine is dependent on various ancillary systems for safe operation, operating
procedures and control system must ensure that these are operational prior to turbine start, and
at all times during operation.
Lubrication System
The supply of oil for lubrication of bearings and couplings, support to sealing systems and
hydraulic operation of actuators requires clean oil at appropriate pressures. For package units
this can be delivered from a common system feeding all elements within the package. Oil
pumps may be driven by electrical power or by auxiliary mechanical drives from the turbine.
Electrical drives are much simpler and make pump location much easier. Where the installation
has reliable electrical supplies this option would be preferred. If the package is required to
operate in stand-alone manner even after a total electrical failure, then shaft drives are required.
Where a common lubrication system is fitted, in particular one which also provides compressor
seal oil, there is a real issue of potential cross-contamination of the oil. Liquid fuel or the
heavier fractions of hydrocarbon gases can dissolve in oil, reducing its viscosity and increasing
its flammability. The fire hazard associated with this potential problem will be greatly reduced
if the oil system operates under a nitrogen atmosphere.
The most serious issues for the supply of oil to a machine package arise from either failure of
the supply that can lead to damage of the machines, or from oil spill or leakage resulting in a
fuel source for potential fires.
Process Coolers
Process coolers, e.g. Intercoolers, will typically be shell and tube heat exchangers built to a
recognised code. ASME and BS 5500 are commonly used. Ideally, cooling will be against a
closed fresh water cooling system, to minimise problems of corrosion, fouling and pollution.
Piping Systems
Piping systems are generally constructed to international standards, special standards are
required for fuel gas where double skinned piping is installed.
Control and Anti Surge Valves
The gas compressor is likely to have discharge control, recycle and anti-surge control valves,
the latter two duties may be combined. These valves are not necessarily provided by the
package vendor, but their specification, design, installation and control must be carefully
integrated into the operation of the package. Any changes in duty or design must be allowed for
in the valve design and set-up.
A6-24
Condition Monitoring
Condition monitoring on larger turbine packages will be provided as part of the package.
Vendors will offer their own preferred system, or will agree to tailor a system to suit the client's
requirements. It is important to ensure that the system provided suits the proposed method of
operating and maintaining the equipment.
Fuel and Ignition System
The fuel system will take Gas and/or Liquid Fuel from the installation at the available pressure,
filter the fuel(s) and raise pressure if necessary. The fuel system will control the rate of supply
of fuel(s) and isolate the supply when necessary.
Starter
To start the turbine it is necessary to rotate the turbine and air compressor, prior to injection and
ignition of fuel in the combustors. The starter is usually either pneumatic, hydraulic or a
variable speed ac motor. Start up is a safety critical event and needs careful control sequences.
Explosions have occurred with fuel build up after failed starts causing knock on damage
through to the exhaust system
All-electric Actuators
All-electric actuator have recently been developed to replace hydraulic actuator systems.
Hydraulic systems can suffer leaks, cleanliness issues,, complexity, poor efficiency and require
a separate servo system. Conventional all electric actuators have been tried previously but have
some drawbacks. Can’t be used in hazardous areas, EMI interference, need separate controller
in safe area, interconnect harnesses. A recent paper at IGTI 2004 reported on development of an
intrinsically safe, explosion-proof actuator that can be used in zoned areas giving improved
control response without overshoot.
Bearing Lube oil System
The supply of oil for lubrication of bearings and couplings, support to sealing systems and
hydraulic operation of actuators requires clean oil at appropriate pressures. For package units
this can be delivered from a common system feeding all elements within the package.
The oil pumps may be driven by electrical power or by auxiliary mechanical drives from the
turbine. Electrical drives are much simpler and make pump location much easier. Where the
installation has reliable electrical supplies this option would be preferred. If the package is
required to operate in stand-alone manner even after a total electrical failure, then shaft drives
are required.
Power requirements for control valves and other instruments must be considered. As the
package lubrication system will be very congested, and fairly inaccessible, oil leaks from pump
seals or pipe joints will be difficult to detect and repair.
Where a common lubrication system is fitted, in particular one which also provides compressor
seal oil, there is a real issue of potential cross-contamination of the oil. Liquid fuel or the
heavier fractions of hydrocarbon gases can dissolve in oil, reducing its viscosity and increasing
its flammability. The fire hazard associated with this potential problem is greatly reduced if the
oil system operates under a nitrogen atmosphere.
A6-25
The most serious issues for the supply of oil to a machine package arise from either failure of
the supply that can lead to damage of the machines, or from oil spill or leakage resulting in a
fuel source for potential fires. Technical and safety aspects of lubrication systems are described
in more detail in RR076.
Oil pumps
The turbine will include oil pumps to provide lubrication to the seals and bearings. These may
be motor or shaft driven.
Fuel boost pump (diesel)
Most turbines are capable of duel fuel operation. If diesel is used this will require a fuel boost
pump.
Cooling system
Turbines generate extremely high temperatures (2000 ºC or more) in the combustion and gas
generator systems. These temperatures are sufficient to cause melting or severe oxidation or
degradation of components. A sophisticated cooling system using cold air passed axially from
the outside of the air compressor is used to maintain temperatures within reasonable limits in the
power turbine and subsequent components. The transition piece on the combustor has to
encounter particularly high temperatures.
Sealing gas System
As well a soil seals associated with the bearings, the turbine includes a sophisticated gas sealing
system. This uses pressure differences to prevent leakage of turbine gases and air into
inappropriate parts of the system
Package mounting and skid
Mounting arrangements for the turbine package have been discussed earlier in the main report.
This is usually based on 3-point mounting of equipment on robust frames. Mounting
arrangements are particularly important on floating installations where larger degrees of tilt may
be incurred.
Anciliary Equipment and Systems
Ancilliary equipment includes the lube oil cooler (water, air), motor control center, switchgear,
neutral ground resistor and inlet fogger/cooler.
Published by the Health and Safety Executive
03/06
RR 430