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 bereproduced, stored in a retrieval system, or transmitted inany form or by any means (electronic, mechanical,photocopying, recording or otherwise) without the priorwritten 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 hmsolicensing@cabinet-office.x.gsi.gov.uk

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), micro-turbines, 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 iv

1 Introduction to Inspection Guidance Notes 1

1.1 BACKGROUND 11.2 MAP OF GUIDANCE PROCESS 11.3 APPLICATION OF GUIDANCE NOTES 2

2 Basics of Gas turbines 3

2.1 INTRODUCTION 32.2 SYSTEMS AND COMPONENTS 42.3 HOW A GAS TURBINE WORKS 52.4 WORKING CYCLE 62.5 PRESSURE, VOLUME AND TEMPERATURE 72.6 CHANGES IN VELOCITY AND PRESSURE 72.7 GAS TURBINES OFFSHORE 82.8 TYPES OF GAS TURBINE 92.9 PACKAGING CONCEPTS 92.10 TURBINE PACKAGES 102.11 DESIGN FACTORS 122.12 TURBINE CONFIGURATION 122.13 DRIVEN EQUIPMENT 132.14 OFFSHORE ENCLOSURES 142.15 GAS TURBINE GT CYCLES 142.16 FUELS 15

3 Applications Offshore 17

3.1 POWER GENERATION 173.2 GAS GATHERING 183.3 GAS LIFT 193.4 WATERFLOOD 193.5 EXPORT COMPRESSION 20

4 Offshore Packages 21

4.1 MODULAR TURBINE PACKAGES 214.2 DESIGN OPTIONS 224.3 FPSO TURBINE PACKAGES 22

5 Major Driven Equipment 25

5.1 ALTERNATORS 265.2 COMPRESSORS 27

Applications 29Package Elements 29Package Configuration 30Hazards 30PM84 Guidance 31Components 32

5.3 PUMPS 34

vii

6 Electrical Systems 35

6.1 ELECTRICAL SYSTEMS 356.2 ELECTRICAL SYSTEMS GUIDANCE 366.3 ELECTROMAGNETIC RADIATION 376.4 MAINTENANCE OF ELECTRICAL SYSTEMS 37

7 Control Systems 41

7.1 PM84 GUIDANCE ON CONTROL SYSTEMS 437.2 RECENT DEVELOPMENTS IN CONTROL SYSTEMS 43

Corrected parameter control 43Control Synchronisation 44Triple Modular Redundant TMR Control Systems 45Redundant Network Control 46Standard Control System 46Software Architecture for a Standard control system 47

8 Gas Turbines on UK Installations 49

8.1 PACKAGERS 508.2 SUPPLIERS 50

9 Safety Cases, Codes and Regulations 53

9.1 RELEVANT UK INSTALLATIONS 539.2 INFORMATION FROM SAFETY CASES 539.3 HSE GUIDANCE NOTE PM84 539.4 DESIGN CODES 549.5 EMISSION REGULATIONS 559.6 ELECTRICAL REGULATIONS 559.7 LEGAL REQUIREMENTS 56

10 Hazards and Failure Modes 59

10.1 WHAT CAN GO WRONG 5910.2 FAILURE MECHANISMS AND ANALYSIS 59

Creep 59Thermo-mechanical fatigue 60High-cycle fatigue 60Metallurgical embrittlement 60Environmental attack 60Foreign body damage 60Manufacture or repair 60Failure analysis 60Materials 61Air Compressors 62Combustors 62Turbines 63

10.3 PM84 ADVICE ON MECHANICAL FAILURES 6310.4 ANECDOTAL INFORMATION 6410.5 ACCIDENT, INCIDENT AND DANGEROUS OCCURRENCE DATA 65

Data extracted 65Analysis of Data 65

10.6 IMIA INDUSTRIAL GAS TURBINE MEMBERS FAILURE STATISTICS 69

viii

10.7 RELIABILITY DATA FOR GAS TURBINES 7010.8 SUMMARY TABLES BY SYSTEM AND COMPONENT 7010.9 OTHER HAZARDS 80

11 Maintenance and Inspection 81

11.1 OVERVIEW 8111.2 INSPECTION & REPAIR 82

Refurbishment of Gas Turbine Components 82Evaluation of damage 83

84 84 84 85 85 85 85 85 86

DisassemblyDimensional checkingNon-destructive testing (NDT)Metallurgical ExaminationDefining of workscopeProcessesNozzle and VanesBuckets and BladesQuality records

11.3 MAINTENANCE GUIDANCE 86

88 90 90 90

FuelsWater (or steam) InjectionCyclic EffectsRotor

11.4 DISASSEMBLY INSPECTIONS 94

94 94

Combustion InspectionHot-Gas-Path Inspection

11.5 MAJOR INSPECTION 96 11.6 TURBINE BORE INSPECTIONS 97 11.7 CLEANING 97 11.8 SUMMARY BY SYSTEM AND COMPONENT 99

12 Operational Issues 105

105 105

106 107

108 108

109 109

12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8 12.9 RISK ASSESSMENT FOR ROUTINE ACTIVITIES 111 12.10 ACCESS 112 12.11 HAZARD MANAGEMENT IN HOT-SPOTS 112 12.12 PRECAUTIONS AGAINST EXPLOSION 113 12.13 VENTILATION 114 12.14 FUEL SUPPLY SYSTEMS 116

HAZARDSSTART-UP AND SHUT-DOWNSURGE PREVENTIONRECYCLE FACILITYCONTROL SYSTEMSVIBRATION MONITORINGFIRE DETECTION REQUIREMENTSPRECAUTIONS AGAINST FIRE

12.15 GAS FUEL 11712.16 ADDITIONAL EXPLOSION PRECAUTIONS FOR LIQUID FUELS AND OILS 11712.17 EMERGENCY PROCEDURES 11812.18 AIR AND GAS SEALS 11812.19 CHANGEOVER IN DUEL FUEL SYSTEMS 118

ix

13 Recent Trends 119

13.1 MICROTURBINE DEVELOPMENT 119 13.2 DRY LOW EMISSIONS (DLE) 119 13.3 STEAM INJECTION FOR EMISSION REDUCTION AND POWER OUTPUT 120 13.4 WASTE HEAT RECOVERY UNITS 120 13.5 COMBINED CYCLE GAS TURBINES 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 re-issued, 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 BASICS OF GAS TURBINES

2.1 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 air-intake, 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.

B

C

A D

Pressure

Combustion heat energy added

Expansion through turbine

and nozzle

Compression pressure energy added

Ambient Air

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� Bearing lube oil system including tank and filters, pumps (main, pre/post, backup), x� Starter (usually either pneumatic, hydraulic or variable speed ac motor), x� Controls (on-skid, off-skid), x� Driven equipmentx� 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� Operating requirements

x� Spares inventory

x� Type selection – aeroderivative or industrial, one or two shaft

x� Site environment and fuel considerations

x� Power requirements

x� Installation – cranes, safe access, lay down areas, mounting, enclosures, auxiliary equipment

x� Noise levels- limits, support information, general requirements

x� Oil tank vents

x� Materials – specification,temperature, corrosion and environment resistance, coatings, certification

x� Starting drives - gas expansion starters, hydraulic motors, diesel engines

x� Foundations, baseplates and mountings

x� Controls and instrumentation

x� Inlet system – intake location, new configurations, material, leak prevention, joints and movement allowances

x� Air intake grids

x� Air compressor cleaning

x� Exhaust system – Exhaust emission, height, proximity to process equipment, rain ingress, maintenance access, recirculation

x� Combustion air filtration – requirements, anti-icing, shutters

x� Fire protection – ventilation dampers, extinguishing systems, enclosure surveillance

x� Acoustic enclosures – accessibility, ventilation, area classification

x� Fuels and fuel systems – fuel selection, gas fuels and systems, liquid fuels and systems, dual fuel systems, power augmentation

x� 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� Available Output Power Range: 20 kW- 250MW (25 hp – 350,000 hp)

x� Smaller units (60MW or below) are typically used offshore.

x� Typical Gas Turbine Simple Cycle Efficiency: 25- 35%

x� Output Speed Range: 3000 - 25000 rpm

x� Fuels: Natural Gas, Liquid Fuels or duel fuel

2.14 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 power-generation 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� Self-Generation- Power generation to meet needs of oil field or platform

x� Enhanced Oil Recovery (EOR)- Advanced technologies to improve oil recovery

x� Gas Lift - Injecting gas into the production well to help lift the oil

x� Waterflood - Injection of water into the reservoir to increase reservoir pressure and improve production

x� Gas Re-injection- Re-injection of natural gas into the reservoir to increase the reservoir pressure

x� Export Compression- Initial boosting of natural gas pressure from field into pipeline (a.k.a. header compression)

x� Gas Gathering- Collecting natural gas from multiple wells

x� Gas Plant and Gas Boost- Processing of gas to pipeline quality; i.e., removal of sulphur, water and CO. components

x� 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 Body Compressor Skid for Gas Gathering Application. Courtesy Solar

3.3 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 OFFSHORE PACKAGES

4.1 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� Starter

x� Lube oil

x� Fuel

21

x� Air-Intakex� 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� Installation of Foundation and Generator module 2h

x� Turbine module and air-intake module 4h

x� Total installation ½ day

x� 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� Step 1 Shutdown and disconnect combustion system x� Step 2 Disconnect air intake module x� Step 3 Remove turbine ready for transport

4.2 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� A sub-base providing added stiffness for gas turbine and compressor skids

x� 3-point mounts to give isolation from twisting and vibration

x� An inclinometer to give alarm and shutdown at high list, trim, pitch, roll angles

x� Baffles to provide a continued supply of lube oil at inclined operation

x� 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� Fuel System

x� Exhaust Duct

x� Lubricating Oil System

x� Compressor Dry Gas Seals & Support System

x� Drive Gearbox ( if required )

x� Auxiliary Gearbox

x� Shaft Couplings

x� Cooling System

x� Piping Systems

x� 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 pre-wiring) 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 ELECTRICAL SYSTEMS

6.1 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� Compliance of technical plant to UK and international standards.

x� Electrical protection systems to avoid overload

x� Enclosures and hazardous area classification

x� Site safety rules and operational procedures

x� Requirements for risk assessment

x� Identification and labelling systems and the positioning of labels and notices on switchgear, transformers, control gear and plant

x� Legal requirements particularly commissioning and work on live electrical systems

x� Electromagnetic radiation and protection measures for live conductors magnetic field risk and corona discharge

x� 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� Apparatus Tag number

x� Cable identifications correct to loop diagram/hook-up drawing

x� Apparatus has no unauthorised modifications

x� Any rectification work noted at previous inspections has been carried out suitably

x� Earth connections secure

x� No undue corrosion (especially on flanges for Ex d)

x� Cable entries tight

x� No degradation of required IP rating

x� No broken covers or fan cowls

x� No build up of dirt on cooling fins (especially on motors)

x� Electrical connections tight (especially Ex e and Ex n)

x� Correct lamp ratings

x� No changes to area classification. (If so, the type of protection or its apparatus group or T-class may not be suitable.)

x� No damage to associated cables x� No damage to apparatus x� Covers/lids correctly secured x� Apparatus mounting firm and acceptable x� Filters clean and free from dirt and debris x� Breathing and draining devices clean and free from dirt and debris x� Cable supports OK x� No external obstructions to flamepaths (Ex d) x� No excessive grease on flamepaths (Ex d) x� No hard setting compound on flamepaths (Ex d) x� No unauthorised gaskets (especially Ex d)

38

x� Gaskets of correct type

x� No excessive grease on bearings

x� No signs of excessive temperatures (e.g. brittle or burnt insulation)

x� No cracks to ceramic feedthroughs or insulators (especially Ex d, Ex e, and Ex de)

x� No obvious changes to surrounding processes which could affect area classification

x� No signs of leakage of filling medium (especially Ex o and Ex q)

x� Filling medium at required level (especially Ex o and Ex q)

x� No signs of leakage from stopper boxes or stopper glands (especially Ex d)

x� Electrical aspects remain secure: especially earth loop tests, and especially for Ex ia/ib. Compare value with that previously noted

x� No dirt or obstructions to fan covers

x� No signs of excessive vibration

x� Surveillance circuits functioning correctly (especially Ex p)

x� Correct associated apparatus installed (Ex ia/ib)

x� Conduit seals satisfactory at passage between non-hazardous area and hazardous area

x� 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 start-up 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� Dedicated PLC

x� Emergency shutdown system ESD

x� Temperature and vibration monitors

x� Overspeed\ monitors and trips

x� Fuel isolation and vent valves

x� Lubrication control systems

x� 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 15-100% 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.

PT Speed Speed

Exhaust Temperature

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 aero-derivative 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� Low cost and off-the shelf x� No re-engineering x� Quicker installation and commissioning (important for refits).

46

x� Allow to complete within 1 week outage

x� Improved product support

x� 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� Gas fuel actuator x� Liquid fuel actuator x� NOx actuatorx� 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

Turbine Fuel-Control

Core

Hardware Interface

Comm, ALM, SD

Custom

details

Figure 32 Schematic illustrating the software architecture for a standard control 10system

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� Trending and on-line capture

x� Datalogging for high speed events

x� Data event buffering (10ms resolution)

x� Simulation same or better than the requirements for an aeroderivative GT

PC System Emulation

Hardware Emulation

Target Hardware

GTC Application Programme

GAP

NETSIM Turbine

Simulator

Turbine Emulation

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

Rolls-Royce (Avon, Coberra, RB211)

27% Avon 1534/1535 RB211 Coberra 2000/6000 Olympus GT SK30

15MW 30MW 20MW 35MW

Avon RB211

15MW 30MW

General Electric Oil & Gas: 12% GE Frame 5 5MW GE-1201/1401A-C LM2500+ 25MW LM5000/6000

5MW 10-15MW 25MW 40-50MW

GE5 GE 10 LM 1600 LM 2500

5 MW 10 MW 16 MW 25 MW

5MW 10MW 16MW 25MW

Solar Turbines 11% Saturn 20 Centaur GSC 40/50 Mars 90/100 Taurus 60

1MW 3-4MW 8-10MW 6MW

Saturn 20 Centaur 40/50 Taurus 60/70 Mars 90/100 Titan 130

1 MW 3-4 MW 5-7 MW 8-10 MW 13 MW

1MW 3-4MW 5-7MW 8-10MW 13MW

Other 12% ABB GT35 Dresser KG2 MTU V16 Pratt & Witney ST18

1-2MW 12MW 2MW

51

RB

211

Avon

Co

be

rra

Ro

lls R

oyce

ww

w.r

olls

royce

.com

Satu

rn

Ce

nta

ur

Ta

uru

s

Ma

rs

Titan

So

lar

Typ

e t

itle

he

re

GE

Ind

ustr

ial T

urb

ines

Nu

ovo P

ign

eo

ne

Jo

hn

Bro

wn

Th

om

assen

Hita

ch

i-T

osh

iba

Ma

nufa

ctu

rin

g P

art

ne

rs

Ge

ne

ral E

lectr

ic

Als

tom

Po

we

r T

urb

ines

ww

w.a

lsto

m.c

om

Eu

rop

ea

n G

as T

urb

ine

s E

GT

(fo

rme

rly

Ru

sto

n)

De

mag

Dele

val

Sie

me

ns W

estin

gho

use

ww

w.ind

ustr

ial.t

urb

ines.s

iem

en

s.c

om

AB

B

Alli

so

n

Dre

sse

r

Ra

nd

, K

ong

sbe

rg

MA

N

Pra

tt &

Witn

ey

Oth

er

Off

sho

re G

as T

urb

ine

Su

pp

liers

Fig

ure

36

S

um

ma

ry o

f m

ain

off

sh

ore

ga

s t

urb

ine

su

pp

liers

, su

bsid

iary

co

mp

an

ies a

nd

ma

nu

factu

rin

g a

ssocia

tes

52

9 SAFETY CASES, CODES AND REGULATIONS

9.1 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� Hazards x� Risk assessment x� Precautions against fire x� Precautions against explosion x� Requirements to satisfy ATEX directive x� Ventilationx� Control systems x� Fuel supply systems x� Gas Fuel x� Additional explosion precautions for liquid fuels and oils x� Gas compressor stations x� Emergency procedures x� Mechanical failures x� Electrical issues x� Electromagnetic radiation x� 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� API 616 - Gas Turbines x� API 617 - Compressors x� API 614 - Lube Oil Systemx� API 670 - Machinery Protection

x� API 613 - Continuous Duty Gear x� API 677 - Auxiliary Drive Gearx� API 671 - Flexible Couplings

In addition there are codes governing testing and operation:

x� ASME PTC-22 Gas Turbine Testingx� 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 HAZARDS AND FAILURE MODES

10.1 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� Creep

x� Thermo-mechanical fatigue

x� High cycle fatigue

x� Embrittlement

x� Corrosion, environmental attack

x� Erosion

x� Oxidation

x� 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

Cyclic duty application

Rupture Creep deflection High cycle fatigue Corrosion Oxidation Erosion Rubs/ wear Foreign object damage

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� Ni or CO as matrix

x� 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.

x� Precipitate hardening is provided by elements like Al. For example J' Ni3Al is a main precipitate. The matrix is austenitic.

x� Higher strength alloys are cast (In738, ReneCo, GTD11), lower strength alloys are forged

x� 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.

x� 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.

x� Oxidation resistance comes from formation of a thin protective oxide layer such as Al2O3, NiAl2O4 or Cr2O3.

x� Thermal cycling, for example stressing on start-up or shut-down can cause spalling of the oxide layers.

61

x� Cr203 is better than Al203 for hot corrosion resistance. Salt or oxide deposit on the surface is accelerated at high temperature.

x� 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.

Count of Incident Id60

50

40

30

20

10

0

Total

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

Year

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.

70%

14%

16%

Faulty Design

Lack of Maintenance

Other Causes

Faulty Design

Lack of Maintenance

Other Causes

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

9%

5%

7%

7%

Maintenance Induced

Faults

15%

Design Faults

35%

Faulty Manufacture

11%

Faulty Installation

Unknown

Miscellaneous

Misuse

Lack of Maintenance

11% Maintenance Induced Faults

Design Faults

Faulty Manufacture

Faulty Installation

Unknown

Miscellaneous

Misuse

Lack of Maintenance

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

Ta

ble

5

Su

mm

ary

of

ma

in f

ailu

re m

od

es a

nd

asso

cia

ted

haza

rds b

y s

yste

m a

nd

co

mp

on

en

t.

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

AI

Air

In

tak

e A

ir i

nle

t C

rack

ing

, fr

actu

re -

im

pac

t d

amag

e d

ue

to i

ng

este

d

Kn

ock

-on

dam

age

to t

urb

ine.

Var

iab

le a

irfl

ow

to

d

ebri

s o

r d

uri

ng

mai

nte

nan

ce

turb

ine

AC

A

ir C

om

pre

sso

r R

oto

r A

ssem

bly

S

ee i

nd

ivid

ual

co

mp

on

ents

bel

ow

LP

co

mp

ress

or

(1

) S

tato

r o

r ro

tor

bla

de

dam

age

du

e to

fo

reig

n o

bje

ct

Pro

ject

ile

dam

age

to p

erso

nn

el.

Deb

ris

in a

irfl

ow

.

ing

esti

on

(2

) D

isc

fati

gu

e fa

ilu

re (

ver

y r

are)

(3

) F

ailu

re

No

n-u

nif

orm

air

flo

w. K

no

ck-o

n d

amag

e to

due

to b

uil

d e

rror

or

(4)

Fai

lure

foll

ow

ing s

urg

e.

com

pre

sso

r an

d t

urb

ine

HP

com

pre

ssor

A

s fo

r L

P C

om

pre

ssor,

plu

s (5

) B

leed

air

val

ve

fail

ure

(w

her

e fi

tted

), c

ausi

ng d

ebri

s to

fal

l in

to a

iurf

low

)

Ro

tor

Dis

cs

Pri

mar

y f

ailu

re v

ery

rar

e, f

atig

ue

mo

st l

ikel

y.

Roto

r bla

des

F

ailu

re d

ue

to i

mp

act

of

fore

ign o

bje

cts

mo

st c

om

mon:

Pro

ject

ile

risk

to p

erso

nnel

. K

nock

on d

amag

e.

over

tem

per

ature

in t

urb

ine

bla

des

, es

pec

iall

y H

P S

tage

Acc

eler

ated

cr

eep

dam

age

and

ox

idat

ion

if

1 b

lad

es,

also

co

mm

on

. o

ver

tem

per

atu

re.

Sta

tors

F

or

com

pre

sso

rs,

mo

st l

ikel

y f

ailu

re m

od

e d

ue

to

Kn

ock

on

dam

age.

Vib

rati

on

or

po

or

per

fora

mn

ce i

f im

pac

t fr

om

inges

ted a

rtic

les;

For

turb

ines

, (1

) im

pac

t ai

rflo

w r

estr

icte

d.

dam

age

du

e to

up

stre

am m

ech

anic

al f

ailu

re (

2)

ero

sio

n

du

e to

tem

per

atu

re e

ffec

ts o

r (3

) fa

ilu

re d

ue

to

ov

erte

mp

erat

ure

mo

st l

ikel

y f

ailu

re c

ause

s.

71

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

AC

C

om

pre

sso

r B

eari

ngs

(co

nt.

)

Sea

ls

Acc

esso

ry d

rive

Bea

rings,

if

trea

ted c

orr

ectl

y,

should

not

fail

, but

bea

rin

g f

ailu

re i

s p

erce

ived

as

com

mo

n.

Tak

ing

in

suff

icie

nt

care

duri

ng i

nst

alla

tion, or

inco

rrec

t tr

ansp

ort

atio

n o

f an

un

inst

alle

d e

ng

ine

new

ly o

ut

of

ov

erh

aul

or

rep

air,

can

cau

se d

amag

e le

adin

g t

o

infa

nti

le f

ailu

re.

Over

tem

per

ature

, in

suff

icie

nt

or

inco

rrec

t lu

bri

cati

on

also

are

co

mm

on

cau

ses

of

bea

rin

g d

istr

ess

lead

ing

to

fa

ilure

. G

as T

urb

ines

rel

y o

n t

hei

r bea

rings

to f

unct

ion

corr

ectl

y;

a bea

ring f

ailu

re i

nvar

iably

wil

l le

ad t

o v

ery

exte

nsi

ve

and

ex

pen

siv

e d

amag

e to

ro

tors

, b

lad

es a

nd

ca

sin

gs.

Sea

ls r

ely

ab

solu

tely

on

corr

ect

han

dli

ng

pro

ced

ure

s duri

ng i

nst

alla

tion,

and s

om

e al

so r

ely o

n c

orr

ect

lub

rica

tio

n a

nd

ro

tor

bal

ance

(ie

, la

ck o

f v

ibra

tio

n)

wh

ilst

ru

nn

ing

. A

dam

aged

sea

l m

ust

no

t b

e fi

tted

; se

al

fail

ure

soon a

fter

gas

turb

ine

repai

r or

over

hau

l ac

tivit

y

usu

ally

(but

not

alw

ays)

is

due

to i

nco

rrec

t m

ainte

nan

ce

pro

ced

ure

(s).

Wea

r an

d c

orr

osi

on o

r cr

ackin

g o

f gea

rwhee

ls,

Co

rro

sio

n o

r cr

ack

ing

of

shaf

ts

Mec

han

ical

fai

lure

. P

roje

ctil

e ri

sk t

o p

erso

nnel

.

Ex

ten

siv

e k

no

ck-o

n d

amag

e to

oth

er c

om

po

nen

ts

Gas

lea

kag

e w

ith

fir

e or

exp

losi

on r

isk

. P

oo

r p

erfo

rman

ce.

Mec

han

ical

mal

fun

ctio

n.

Red

uce

d t

imin

g a

nd

ef

fici

ency

.

72

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

AC

C

om

pre

sso

r C

asin

g

(co

nt.

) F

ailu

re u

nu

sual

un

less

du

rin

g c

atas

tro

ph

ic f

ailu

re o

f in

tern

al e

ng

ine

com

po

nen

ts (

eg, b

lad

e(s)

or

a d

isc)

w

hil

st r

un

nin

g;

ho

wev

er, v

ibra

tio

n c

an c

ause

cra

ckin

g

du

e to

fat

igu

e; i

mp

act

fro

m e

xte

rnal

so

urc

es -

to

ols

duri

ng m

ainte

nan

ce o

r ca

rele

ssnes

s w

hil

st a

cces

sing t

he

exte

rnal

surf

aces

duri

ng m

ainte

nan

ce,

for

inst

ance

- c

an

cau

se d

amag

e w

hic

h c

an d

eter

iora

te a

nd

cau

se c

asin

g

fail

ure

at

a la

ter

dat

e.

Pro

ject

ile

dam

age

to p

erso

nnel

or

adja

cent

pip

ework

.

Gas

lea

k w

ith

ris

k o

f fi

re o

r ex

plo

sio

n

AC

C

om

pre

sso

r C

ow

ls

(co

nt.

)

Inle

t guid

e van

es

Shaf

ts

Coupli

ngs

As

for

casi

ng

s; m

ost

lik

ely

so

urc

e is

dam

age

cau

sed

duri

ng m

ainte

nan

ce,

lead

ing t

o f

ailu

re a

t a

late

r dat

e.

Impac

t dam

age

due

to f

ore

ign o

bje

cts,

or

surg

e.

Ver

y r

are;

fat

igue

mo

st l

ikel

y

Ver

y r

are,

fat

igue

mo

st l

ikel

y

Pro

ject

ile

dam

age

to p

erso

nnel

or

adja

cent

pip

ework

.

Gas

lea

k w

ith

ris

k o

f fi

re o

r ex

plo

sio

n

Poor

turb

ine

oper

atio

n.

Ris

k o

f knock

-on p

roje

ctil

e d

amag

e

GG

G

as G

ener

ato

r C

om

bu

stio

n c

ham

ber

s F

atig

ue

due

to w

eaken

ing a

fter

form

atio

n o

f cr

acks

in

com

bust

ion c

ham

ber

lin

ers;

sec

ondar

y f

ailu

re

foll

ow

ing s

urg

e, o

r fo

reig

n o

bje

ct i

nges

tion,

or

com

pre

ssor

bla

de

fail

ure

, et

c.

Fuel

nozz

les

F

ailu

re d

ue

to v

ibra

tion e

ffec

ts;

also

fai

lure

due

to

inco

rrec

t or

impro

per

ly f

ilte

red f

uel

or

fuel

addit

ives

.

Hig

h r

isk o

f knock

-on d

amag

e to

pow

er t

urb

ine

Hig

h r

isk

of

kn

ock

-on

dam

age

to p

ow

er t

urb

ine.

In

corr

ect

fuel

/ ai

r m

ixin

g w

ith

ris

k o

f ex

plo

sio

n.

H

igher

em

issi

ons.

73

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

GG

G

as G

ener

ato

r S

wir

l v

anes

(c

on

t)

Co

atin

gs

Lin

ers

Tra

nsi

tio

n p

iece

Bu

cket

Imp

act

dam

age

or

ero

sio

n.

No

rmal

ly c

oat

ing

s, e

spec

iall

y t

ho

se o

n t

he

ho

ttes

t co

mp

on

ents

or

par

ts o

f g

as t

urb

ines

, fa

il d

ue

to

ov

erte

mp

erat

ure

eff

ects

.

Imp

act

or

ov

erte

mp

erat

ure

.

Imp

act

or

ov

erte

mp

erat

ure

.

Imp

act,

in

corr

ectl

y a

dju

sted

fu

el f

low

(o

ver

fuel

lin

g)

or

vib

rati

on.

No

n-u

nif

orm

fu

el m

ixin

g a

nd

ig

nit

ion

Acc

eler

ated

deg

radat

ion l

eadin

g t

o f

ailu

re o

f co

mp

on

ent

by

cre

ep, o

xid

atio

n o

r er

osi

on

.

Gas

lea

kag

e. H

igh

ris

k o

f d

amag

e to

Pow

er

Tu

rbin

e(P

T)

do

wn

stre

am

Gas

lea

kag

e. H

igh

ris

k o

f d

amag

e to

Pow

er T

urb

ine

(PT

) d

ow

nst

ream

Gas

lea

kag

e. H

igh

ris

k o

f d

amag

e to

Pow

er T

urb

ine

(PT

) d

ow

nst

ream

PT

P

ow

er T

urb

ine

Cas

ing

C

arel

essn

ess

du

rin

g m

ain

ten

ance

- i

mp

act

of

som

e so

rt,

or

inte

rnal

en

gin

e co

mp

on

ent

fail

ure

cau

sin

g t

he

casi

ng

to

ru

ptu

re, o

r p

rolo

ng

ed e

xp

osu

re t

o e

xce

ssiv

e vib

rati

on.

Shaf

ts

Unusu

al a

s a

pri

mar

y c

ause

, but

fati

gue

mo

st l

ikel

y.

HP

Turb

ine

O

ver

tem

per

atu

re;

imp

act

dam

age

to b

lad

es;

bea

rin

g

fail

ure

.

Gas

lea

kag

e. R

isk

of

fire

or

exp

losi

on

.

Hig

h e

ner

gy m

echan

ical

fai

lure

Pro

ject

ile

risk

to p

erso

nnel

and a

dja

cent

pip

ework

. K

no

ck-o

n f

ailu

re o

f o

ther

PT

co

mp

on

ents

.

Acc

eler

ated

deg

rad

atio

n.

74

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

LP

Turb

ine

PT

P

ow

er T

urb

ine

(co

nt.

)

Dis

cs

Bla

des

No

zzle

gu

ide

van

es

Bea

rings

Bea

ring s

eals

Air

and

gas

sea

ls

Su

pp

ort

rin

gs

As

above.

Unusu

al a

s a

pri

mar

y c

ause

, but

fati

gue

mo

st l

ikel

y.

Over

tem

per

ature

; im

pac

t dam

age;

bea

ring f

ailu

re.

Ov

erte

mp

erat

ure

, im

pac

t d

amag

e.

Lubri

cati

on i

ssues

- l

ack o

f, i

nco

rrec

t ty

pe,

or

ov

erte

mp

erat

ure

cau

sed

by

sam

e.

See

no

tes

for

Co

mp

ress

or

Bea

rin

gs,

wh

ich

als

o a

pp

ly h

ere.

See

als

o c

om

men

ts f

or

Com

pre

ssor

seal

s ab

ove.

P

T

seal

s al

so c

an s

uff

er f

rom

ex

ten

ded

exp

osu

re t

o h

igh

te

mp

erat

ure

s o

r h

igh

lev

els

of

vib

rati

on

.

Th

ese

rely

on

pre

ssu

re d

iffe

ren

tial

s: i

f th

e d

iffe

ren

ce

do

es n

ot

exis

t, t

hen

th

ey f

ail.

Co

rro

sio

n,

ero

sio

n,

crac

kin

g

Pro

ject

ile

risk

to p

erso

nnel

and a

dja

cent

pip

ework

. A

ccel

erat

ed d

egra

dat

ion. K

nock

-on f

ailu

re o

f oth

er

PT

co

mp

on

ents

Pro

ject

ile

risk

to

per

sonnel

and a

dja

cent

pip

ework

. A

ccel

erat

ed d

egra

dat

ion.K

nock

-on f

ailu

re o

f oth

er P

T

com

po

nen

ts

Pro

ject

ile

risk

to p

erso

nnel

and a

dja

cent

pip

ework

. A

ccel

erat

ed d

egra

dat

ion. K

nock

-on f

ailu

re o

f oth

er

PT

co

mp

on

ents

Red

uce

d t

urb

ine

per

form

ance

.

Mec

han

ical

fai

lure

. P

roje

ctil

e ri

sk t

o p

erso

nnel

.

Ex

ten

siv

e k

no

ck-o

n d

amag

e to

oth

er c

om

po

nen

ts

Lo

ss o

f lu

bri

cati

on

lea

din

g t

o b

eari

ng

sei

zure

an

d

fail

ure

. G

as l

eak

age

wit

h f

ire

or

exp

losi

on

ris

k. P

oo

r p

erfo

rman

ce.

Gas

lea

kag

e w

ith

fir

e or

exp

losi

on r

isk

. P

oo

r p

erfo

rman

ce.

Lo

ss o

f fu

nct

ion

EX

E

xh

aust

V

ibra

tio

n,

imp

act

dam

age

or

dam

age

du

e to

ov

er-

Lea

kag

e o

f h

ot

exh

aust

gas

es.

Ris

k o

f p

erso

nn

el

tem

per

ature

are

mo

st c

om

mo

n c

ause

s of

exhau

st

inju

ry.

Ignit

ion o

f fu

el o

r lu

bri

cant

leak

ed i

nto

fa

ilu

re.

insu

lati

on

.

75

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

FS

F

uel

sy

stem

F

uel

tan

k

Co

rro

sio

n, im

pac

t d

amag

e to

th

e ex

teri

or.

Fuel

pum

p

Fat

igue

fail

ure

of

inte

rnal

com

ponen

ts;

elec

tric

al

pro

ble

ms

or,

sim

ply

, o

ld a

ge.

Pip

ing

Over

pre

ssure

; fo

r so

lid p

ipes

, in

appro

pri

ate

use

(eg

, as

han

dhold

) w

hil

st f

itte

d -

fle

xib

le p

ipes

suff

er n

the

sam

e w

ay.

Occ

asio

nal

ly, b

ut

un

usu

ally

, co

rro

sio

n f

or

soli

d p

ipes

; ch

afin

g b

y s

ecuri

ng c

lips;

acc

iden

tal

dam

age

to b

raid

ing

fo

r fl

exib

le p

ipes

.

Fu

el i

nje

ctio

n s

yst

em

Co

nta

min

atio

n b

y f

ore

ign

ob

ject

s -

usu

ally

dir

t in

troduce

d i

n t

he

fuel

- o

r fa

ilure

of

inte

rnal

co

mponen

ts -

sh

afts

or

seal

s. O

ccas

ional

ly,

fail

ure

of

po

wer

su

pp

ly o

r in

corr

ect

sch

edu

lin

g d

uri

ng

set

up

at

man

ufa

ctu

re c

an c

ause

pro

ble

ms.

Fu

el l

eak

. R

isk

of

fire

or

exp

losi

on

.

Loss

of

turb

ine

ignit

ion. P

ote

nti

al r

isk o

f ex

plo

sion.

Fuel

, w

ater

or

lubri

cant

leak

. R

isk o

f fi

re o

r ex

plo

sion

Res

tric

ted f

uel

flo

w, non-u

nif

orm

com

bust

ion. P

oor

turb

ine

oper

atio

n.

Ris

k o

f dam

age

to c

om

bust

ion

syst

em

ST

S

tart

er

Fai

lure

to

sta

rt.

Fu

el b

uil

d u

p i

n c

om

bu

stio

n c

ham

ber

F

ailu

re t

o s

tart

. R

isk

of

exp

losi

on

if

fuel

bu

ild

-up

.

LO

L

ube

Oil

Syst

em

Pum

ps

Fai

lure

of

lubri

cant

flow

S

eizi

ng o

f co

mponen

ts, over

hea

ting, fa

ilure

Tan

ks

L

eak

age,

pre

ssu

re b

uil

d u

p

Lu

bri

can

t le

ak. R

isk

of

fire

, ex

plo

sio

n.

Sea

ls

Lea

kag

e L

ub

rica

nt

leak

. R

isk

of

fire

, ex

plo

sio

n.

AG

A

uxil

iary

Gea

rbox

All

M

echan

ical

fai

lure

. L

oss

of

funct

ion.

Loss

of

dri

ve.

Mec

han

ical

fai

lure

.

CL

C

ooli

ng s

yst

em

Over

hea

ting o

f bla

des

an

d o

ther

co

mponen

ts.

R

isk o

f co

mponen

t dis

tort

ion

, O

xid

atio

n or

fail

ure

. A

ccel

erat

ed c

reep

, o

xid

atio

n a

nd

ero

sio

n d

amag

e S

eizu

re.

Mec

han

ical

dam

age

to c

om

ponen

ts.

Ris

k o

f pro

ject

ile

dam

age

76

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

CS

C

ontr

ol

syst

em (

on S

kid

) O

per

atio

nal

contr

ols

Sen

sor

fail

ure

Indic

atio

ns

fail

Op

erat

or

con

tro

ls f

ail

Sen

sor

fail

ure

Spuri

ous

outp

ut

ES

D c

ondit

ion n

ot

det

ecte

d

ES

D s

yst

em f

ailu

re

Fai

l to

oper

ate

on d

eman

d

Oper

ator

unaw

are

of

haz

ardous

condit

ions

Op

erat

or

un

able

to

ex

erci

se s

afe

con

tro

l

Au

tom

atic

op

erat

ion

to

wit

hin

un

stab

le o

r h

azar

do

us

reg

ion

Oper

atio

n t

o w

ithin

unst

able

or

haz

ardous

regio

n

Unre

vea

led f

ailu

re i

n r

edundan

t E

SD

con

figura

tion -

deg

radat

ion o

f sa

fety

mar

gin

s

ES

D c

ondit

ion n

ot

det

ecte

d -

pla

nt

oper

atio

n b

eyond

safe

ty l

imit

s

Haz

ardous

pla

nt

condit

ion u

nm

itig

ated

ES

E

lect

rica

l S

yst

ems

All

In

corr

ect

sele

ctio

n f

or

haz

ard

ou

s ar

ea

Ignit

ion o

f haz

ardous

area

fla

mm

able

subst

ance

fro

m

inte

rnal

sp

arks

or

hot

surf

aces

Inad

equ

ate

mai

nte

nan

ce

Deg

rad

atio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

s

Deg

rad

atio

n o

f sa

feg

uar

ds

agai

nst

ele

ctro

cuti

on

du

e to

dir

ect

or

ind

irec

t co

nta

ct w

ith

haz

ard

ou

s el

ectr

ical

ch

arg

e

77

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

ES

E

lect

rica

l S

yst

ems

All

In

adeq

uat

e m

ain

ten

ance

H

azar

do

us

rele

ase

of

elec

tric

al e

ner

gy l

ead

ing

to

fir

e (c

on

t)

or

exp

losi

on

Inad

equ

ate

label

lin

g

Inad

equat

e is

ola

tion f

or

work

ing o

n e

lect

rica

l eq

uip

men

t

Cab

les

Inad

equ

ate

sup

po

rts

Mec

han

ical

dam

age

Sh

eath

dam

age

Insu

lati

on

dam

age

Ele

ctri

cal

fault

Mec

han

ical

dam

age

Insu

lati

on

dam

age

Insu

lati

on

dam

age

Ele

ctri

cal

fau

lt

Cir

cuit

tri

p/f

use

- l

oss

of

funct

ion

Spar

ks

- ig

nit

ion o

f haz

ardous

area

fla

mm

able

su

bst

ance

Conduit

syst

ems

Mec

han

ical

dam

age

C

able

dam

age

Ing

ress

of

haz

ard

ou

s ar

ea f

lam

mab

le s

ub

stan

ce -

v

iola

tio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

En

clo

sure

M

ech

anic

al d

amag

e

Ing

ress

of

haz

ard

ou

s ar

ea f

lam

mab

le s

ub

stan

ce -

v

iola

tio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

Mec

han

ical

dam

age

D

amag

e to

do

or

seal

s -

vio

lati

on

of

haz

ard

ou

s ar

ea

pro

tect

ion p

rinci

ple

78

ID

Sys

tem

C

om

po

nen

t F

ail

ure

Mo

de

Ha

zard

s

ES

E

lect

rica

l S

yst

ems

En

clo

sure

(c

on

t)

Sw

itch

gea

r

Isola

tors

Cir

cuit

bre

aker

s

Co

nd

uit

en

try

po

ints

no

t b

lan

ked

Inad

equ

ate

cab

le g

lan

ds

Co

ver

s le

ft o

ff

Inad

equ

ate

cov

er o

r d

oo

r se

als

Inad

equ

ate

shro

ud

ing

of

liv

e p

arts

Ele

ctri

cal

fault

Mec

han

ism

mal

funct

ion

Mec

han

ism

mal

funct

ion

Ing

ress

of

haz

ard

ou

s ar

ea f

lam

mab

le s

ub

stan

ce -

v

iola

tio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

Ing

ress

of

haz

ard

ou

s ar

ea f

lam

mab

le s

ub

stan

ce -

v

iola

tio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

Ex

po

sure

of

per

son

s to

ele

ctro

cuti

on

by

dir

ect

con

tact

w

ith

haz

ard

ou

s el

ectr

ical

ch

arg

e

Vio

lati

on

of

haz

ard

ou

s ar

ea p

rote

ctio

n p

rin

cip

le (

e.g

. bolt

s le

ft o

ut

of

flam

e pro

of

encl

osu

re d

oor)

Ex

po

sure

of

per

son

s to

ele

ctro

cuti

on

by

dir

ect

con

tact

w

ith

haz

ard

ou

s el

ectr

ical

ch

arg

e

Supply

tri

p/f

use

- l

oss

of

funct

ion

Spar

ks

- ig

nit

ion o

f haz

ardous

area

fla

mm

able

su

bst

ance

Unab

le t

o s

wit

ch o

r is

ola

te l

oad

s. H

eati

ng o

r ar

cing -

v

iola

tio

n o

f h

azar

do

us

area

pro

tect

ion

pri

nci

ple

Cat

astr

ophic

fai

lure

on f

ault

inte

rrupti

on -

explo

sion

Mec

han

ical

Dri

ve

Gea

rbox

Mec

han

ical

fai

lure

S

ee R

R076

Pro

ject

ile

risk

to p

erso

nnel

. L

oss

of

dri

ve

to d

riven

eq

uip

men

t. R

isk

of

surg

e o

r d

amag

e to

dri

ven

eq

uip

men

t.

Mai

n d

rive

coupli

ng

Mec

han

ical

fai

lure

See

RR

076

Pro

ject

ile

risk

to p

erso

nnel

. L

oss

of

dri

ve

to d

riven

eq

uip

men

t. R

isk

of

surg

e o

r d

amag

e to

dri

ven

eq

uip

men

t.

79

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� Access to enclosures

x� Risk of fire or explosion from gas or fuel leakage

x� Risk of projectile damage

x� Risk of fire from lubricant leakage

x� Risk of injury from touching hot components, particularly exhaust and combustion systems

x� 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 re-assemble.

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 inspection a 24,000 hours or 1200 starts

Major inspectionb 48,000 hours or 2400 starts

Factors impacting maintenance

Hours factors

x� Fuel Gas 1 Distillate 1.5 Crude 2 to 3 Residual 3 to 4

x� Peak load

x� Water/steam injection 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

8

2

20

a,b 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, head-end 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

17systems . 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

Ta

ble

7 S

um

ma

ry o

f in

sp

ectio

n p

ractice

fo

r g

as t

urb

ine

syste

ms a

nd

co

mp

on

en

ts

ID

Ins

pe

cti

on

P

urp

os

e o

f In

sp

ec

tio

n

Sy

ste

m

Co

mp

on

en

ts

Ins

pe

cti

on

SI

Sta

ndb

y I

nspe

ctions

Sta

ndb

y insp

ections a

re

perf

orm

ed o

n a

ll gas t

urb

ines b

ut

are

ap

plic

ab

le p

art

icu

larl

y t

o g

as

turb

ines u

se

d in p

eakin

g a

nd

inte

rmitte

nt-

duty

serv

ice w

here

sta

rtin

g r

elia

bili

ty is o

f prim

ary

concern

.

Sta

rt-u

p,

lubrication,

coolin

g,

cle

an

ing a

nd

fue

l syste

ms

Various

This

inspection inclu

des r

outinely

serv

icin

g t

he b

attery

syste

m,

changin

g f

ilters

, checkin

g o

il and w

ate

r le

vels

, cle

anin

g r

ela

ys a

nd c

heckin

g d

evic

e c

alib

rations.

Serv

icin

g

can b

e p

erf

orm

ed in o

ff-p

eak p

eri

ods w

ithout

inte

rrupting

the a

vaila

bili

ty o

f th

e t

urb

ine.

A p

erio

dic

sta

rt-u

p t

est

run is

an e

sse

ntia

l pa

rt o

f th

e s

tandb

y inspection.

RI

Runnin

g I

nspections

Runnin

g inspections c

onsis

t of

gen

era

l a

nd c

ontinu

ed

observ

ations m

ade w

hile

a u

nit is

opera

ting.

Esta

blis

hin

g b

aselin

e o

pera

tin

g

data

duri

ng initia

l sta

rt-u

p o

f a n

ew

u

nit a

nd

aft

er

an

y m

ajo

r dis

assem

bly

work

. T

his

baselin

e

serv

es a

s a

refe

rence f

rom

whic

h

subsequent

unit d

ete

riora

tion c

an

be m

easure

d.

Gas T

urb

ine

On-lin

e s

ensors

O

pera

tin

g insp

ection d

ata

to e

sta

blis

h n

orm

al eq

uip

ment

sta

rt-u

p p

ara

me

ters

as w

ell

as k

ey s

tea

dy s

tate

op

era

tin

g

para

mete

rs.

Ste

ady s

tate

is d

efined a

s c

onditio

ns a

t w

hic

h

no m

ore

tha

n a

5°F

/3°C

chang

e in w

heel spa

ce

tem

pera

ture

occurs

over

a 1

5-m

inute

tim

e p

eriod.

Data

must

be t

aken a

t re

gula

r in

terv

als

and s

hould

be

record

ed t

o p

erm

it a

n e

valu

ation o

f th

e t

urb

ine p

erf

orm

ance

and m

ain

tenance r

equirem

ents

as a

function o

f opera

ting

tim

e.

This

opera

ting inspection d

ata

inclu

des:

load v

ers

us

exh

au

st

tem

pe

ratu

re,

vib

ratio

n,

fue

l flo

w a

nd

pre

ssu

re,

beari

ng m

eta

l te

mpera

ture

, lu

be o

il pre

ssure

, exh

aust

gas

tem

pera

ture

s,

exhaust

tem

pera

ture

spre

ad v

ariation a

nd

sta

rt-u

p t

ime

.

This

lis

t is

only

a m

inim

um

an

d o

ther

para

me

ters

should

be

used a

s n

ecessary

. A

gra

ph o

f th

ese p

ara

mete

rs w

ill h

elp

pro

vid

e a

basis

for

judgin

g t

he c

onditio

ns o

f th

e s

yste

m.

Devia

tions f

rom

the n

orm

help

pin

poin

t im

pe

ndin

g t

rou

ble

, changes in c

alib

ration o

r dam

aged c

om

pone

nts

.

10

0

ID

Ins

pe

cti

on

P

urp

os

e o

f In

sp

ec

tio

n

Sy

ste

m

Co

mp

on

en

ts

Ins

pe

cti

on

DC

I D

isassem

bly

- C

om

bustion

Inspection

Re

lative

ly s

ho

rt d

isa

sse

mb

ly

sh

utd

ow

n in

sp

ectio

n.

Concentr

ate

s o

n t

he c

om

bustion

liners

, tr

ansitio

n p

ieces,

fuel

nozzle

s a

nd e

nd c

aps w

hic

h a

re

recogniz

ed a

s b

ein

g t

he f

irst

to

requ

ire r

ep

lace

ment

and r

epa

ir in

a g

oo

d m

ain

tenance p

rogra

m.

Com

bustion

Lin

ers

, tr

ansitio

n

pie

ces,

fuel nozzle

s,

end-c

aps

Re

lative

ly s

ho

rt d

isa

sse

mb

ly s

hu

tdo

wn

in

sp

ectio

n o

f fu

el

nozzle

s,

liners

, tr

ansitio

n p

ieces,

cro

ssfire

tubes a

nd

reta

iners

, spark

plu

g a

ssem

blie

s,

flam

e d

ete

cto

rs a

nd

com

busto

r flo

w s

leeves.

This

inspection c

oncentr

ate

s o

n t

he c

om

bustion lin

ers

, tr

ansitio

n p

iece

s,

fuel nozzle

s a

nd e

nd c

aps w

hic

h a

re

recogniz

ed a

s b

ein

g t

he f

irst

to r

equire r

epla

cem

ent

and

repair in a

good m

ain

tenance p

rogra

m.

Pro

per

inspection,

main

tenance a

nd r

epair o

f th

ese ite

ms w

ill c

ontr

ibute

to a

lo

nger

life o

f th

e d

ow

nstr

eam

part

s,

such a

s t

urb

ine n

ozzle

s

and b

uckets

.

HC

P

Dis

assem

bly

- H

ot

gas p

ath

in

sp

ection

The p

urp

ose o

f a h

ot-

gas-p

ath

in

spection is t

o e

xam

ine t

hose

part

s e

xposed t

o h

igh

tem

pera

ture

s f

rom

the h

ot

gases

dis

charg

ed f

rom

the c

om

bustion

pro

cess.

Hot

gas p

ath

A

s c

om

bustion

inspection.

Als

o

turb

ine n

ozzle

s,

sta

tionary

sta

tor

shro

uds a

nd t

urb

ine

buckets

The h

ot-

gas-p

ath

inspection in

clu

des t

he f

ull

scope o

f th

e

com

bustion inspectio

n a

nd,

in a

dd

itio

n,

a d

eta

iled

insp

ection o

f th

e t

urb

ine n

ozzle

s,

sta

tionary

sta

tor

shro

uds

and t

urb

ine b

uckets

.

To p

erf

orm

this

inspection,

the t

op h

alf o

f th

e t

urb

ine s

hell

must

be r

em

oved.

MI

Majo

r In

spection

The p

urp

ose o

f th

e m

ajo

r in

spection is t

o e

xam

ine a

ll of

the

inte

rnal ro

tatin

g a

nd s

tationary

com

ponents

fro

m t

he inle

t of

the

machin

e t

hro

ugh t

he e

xhaust

section o

f th

e m

achin

e.

A m

ajo

r in

spection s

ho

uld

be

sch

ed

ule

d in

acco

rda

nce

with

th

e

recom

mendations in t

he o

wner's

Main

tenance a

nd I

nstr

uctions

Ma

nu

al o

r a

s m

od

ifie

d b

y t

he

re

sults o

f pre

vio

us b

ore

scope a

nd

hot-

gas-p

ath

in

spection.

All

sig

nific

ant

com

ponents

V

arious

The w

ork

scope involv

es inspection o

f all

of

the m

ajo

r flange-t

o-f

lange c

om

ponents

of

the g

as t

urb

ine w

hic

h a

re

subje

ct

to d

ete

riora

tion d

uri

ng n

orm

al tu

rbin

e o

pera

tion.

This

inspection inclu

des p

revio

us e

lem

ents

of

the

com

bustion a

nd h

ot-

gas-p

ath

inspections.

The c

om

ple

te

flange-t

o-f

lange g

as t

urb

ine is la

yed o

pe

n t

o t

he h

orizonta

l jo

ints

to a

llow

inspections t

o b

e p

erf

orm

ed o

n indiv

idual

ite

ms.

Air I

nta

ke

Air inle

t In

spection f

or

corr

osio

n,

cra

cked s

ilencers

and loose p

art

s

10

1

ID

Ins

pe

cti

on

P

urp

os

e o

f In

sp

ec

tio

n

Sy

ste

m

Co

mp

on

en

ts

Ins

pe

cti

on

MI

Majo

r In

spection

See a

bove

Com

pre

ssor

Inle

t and f

low

path

C

om

pre

ssor

inle

t and c

om

pre

ssor

flo

wp

ath

are

inspecte

d

for

foulin

g,

ero

sio

n,

corr

osio

n a

nd leakage.

Roto

r A

ssem

bly

R

oto

r and s

tato

r bla

des a

re c

hecked f

or

tip c

leara

nce,

rubs,

impact

dam

age,

corr

osio

n p

itting,

bo

win

g a

nd c

rackin

g.

All

radia

l an

d a

xia

l cle

ara

nces a

re c

hecke

d a

gain

st

their

origin

al valu

es (

ope

nin

g a

nd c

losin

g).

Genera

tor,

Accessory

D

rives,

Driven

equ

ipm

ent

Check a

lignm

ent

- gas t

urb

ine t

o g

enera

tor/

gas t

urb

ine t

o

accessory

gear.

Driven e

quip

ment

will

be s

ubje

ct

to it's

ow

n

main

tenance r

equ

irem

ents

Casin

g,

Co

wls

and

fra

me

s/

diffu

se

rs

Casin

gs,

shells

and f

ram

es/

diffu

sers

are

inspecte

d f

or

cra

cks a

nd e

rosio

n.

Inle

t guid

e v

anes

The inle

t guid

e v

anes (

IGV

s)

are

inspecte

d,

lookin

g f

or

corr

osio

n,

bushin

g w

ear

and v

ane c

rackin

g.

Beari

ngs a

nd S

eals

B

eari

ng lin

ers

and s

eals

are

inspecte

d f

or

cle

ara

nce a

nd

we

ar.

Beari

ng h

ousin

gs w

ill b

e e

xam

ined f

or

corr

osio

n,

we

ar

and c

rackin

g

Gas G

enera

tor

(GG

) C

om

bustion s

yste

m

Com

bustion a

nd h

ot

gas p

ath

inspection a

s a

bove.

Check

fuel nozzle

s f

or

ero

sio

n a

nd b

lockag

e.

Rem

ote

vis

ual

insp

ection inte

rnally

by b

oro

scope.

Fuel syste

m

Inspect

for

leaks,

inte

grity

of

pip

e s

yte

ms,

blo

ckage o

f filte

rs,

co

nd

itio

n a

nd

blo

cka

ge

of

fue

l n

ozzle

s.

Bucket

Turb

ine b

uckets

are

rem

ove

d a

nd a

non-d

estr

uctive c

heck

of

buckets

and w

heel doveta

ils is p

erf

orm

ed (

firs

t sta

ge

bu

cke

t p

rote

ctive

co

atin

g s

ho

uld

be e

va

lua

ted

fo

r re

ma

inin

g

coating life).

Buckets

that

were

not

recoate

d a

t th

e h

ot-

gas-p

ath

in

sp

ectio

n s

ho

uld

be

re

pla

ce

d.

Tra

nsitio

n P

iece

Vis

ua

l e

xam

ina

tion f

or

oxid

atio

n,

cra

ckin

g,

ero

sio

n a

nd loss

of

wa

ll th

ickness.Inte

rnal vis

ual in

spection u

sin

g

boro

scopes.

N

on-

intr

usiv

e N

DE

exam

ination b

y t

herm

ogra

ph

y a

nd

oth

er

me

tho

ds.

Pe

ne

tra

nt

an

d M

PI

insp

ectio

ns in

ma

jor

overh

auls

.

Turb

ine N

ozzle

s

Seals

and h

oo

k f

its o

f tu

rbin

e n

ozzle

s a

nd d

iaphra

gm

s a

re

inspecte

d f

or

rubs,

ero

sio

n,

frettin

g o

r th

erm

al dete

riora

tion.

10

2

ID

Ins

pe

cti

on

P

urp

os

e o

f In

sp

ec

tio

n

Sy

ste

m

Co

mp

on

en

ts

Ins

pe

cti

on

Po

wer

Turb

ine (

PT

) C

asin

g

Casin

gs,

shells

and f

ram

es/

diffu

sers

are

inspecte

d f

or

cra

cks a

nd e

rosio

n.

Shafts

ND

E a

nd v

isual exam

ination f

or

cra

ckin

g.

ND

E m

eth

ods

may inclu

de s

pecia

lised u

ltra

sonic

s (

UT

) M

PI,

and

penetr

ant

meth

ods

MI

Majo

r In

spection

See a

bove

Po

wer

Turb

ine (

PT

) (C

ontinue

d)

Roto

rs

Roto

r in

spectio

ns r

ecom

me

nd

ed in t

he m

ain

tena

nce a

nd

inspection m

anual or

by T

echnic

al In

form

ation L

etters

should

be p

erf

orm

ed.

This

ma

y inclu

de d

ism

antlin

g,

vis

ua

l exam

ination,

dim

ensio

nal che

ckin

g,

assessm

ant

of

coating

conditio

ns a

nd N

DE

exam

ination b

y m

agnetic p

art

icle

in

spection (

MP

I),

radio

gra

phy,

therm

ogra

phy,

ultra

sonic

s

and o

ther

meth

ods f

or

cra

ckin

g e

rosio

n o

r corr

osio

n

da

ma

ge

, lo

ss o

f w

all

thic

kn

ess a

nd

blo

ckin

g o

f co

olin

g

hole

s.

Nozzle

guid

e v

anes

and s

hro

uds

Turb

ine s

tation

ary

shro

uds a

re c

hecke

d f

or

cle

ara

nce,

ero

sio

n,

rubbin

g,

cra

ckin

g,

and b

uild

-up.

Beari

ngs a

nd S

eals

B

eari

ng lin

ers

and s

eals

are

inspecte

d f

or

cle

ara

nce a

nd

we

ar.

Beari

ng h

ousin

gs w

ill b

e e

xam

ined f

or

corr

osio

n,

we

ar

and c

rackin

g

Exh

au

st

Exh

au

st

ba

ffle

s,

sile

ncer,

insu

lation

Exhaust

syste

ms a

re inspecte

d f

or

cra

cks,

bro

ken s

ilencer

panels

or

insula

tion p

anels

.

Genera

tor,

Accessory

D

rives,

Driven

equ

ipm

ent

Va

rio

us

Ch

eck a

lign

me

nt

- g

as t

urb

ine

to

ge

ne

rato

r/g

as t

urb

ine

to

accessory

gear.

Driven e

quip

ment

will

be s

ubje

ct

to it's

ow

n

main

tenance r

equ

irem

ents

Contr

ol syste

m (

on

Skid

) O

pera

tional co

ntr

ols

C

heck f

unctionalit

y a

nd s

ensor

conditio

n.

Check inte

gri

ty o

f ele

ctr

ical syste

ms.

Note

specific

guid

ance in P

M84.

Ele

ctr

ical syste

ms

Various

Main

tenance in

lin

e w

ith B

S E

N 6

0079-1

7 a

nd o

ther

IEC

re

gu

latio

ns c

on

cern

ing e

lectr

ical eq

uip

ment

in h

azard

ous

envir

onm

ents

. N

ote

specific

guid

ance in P

M84

Cle

anin

g S

yste

ms

Various

Gas t

urb

ines a

re s

ubje

ct

to p

eriodic

in-s

itu c

leanin

g b

y

inje

ction o

f w

ate

r dro

ple

tsta

nd o

ther

meth

ods t

o c

lear

the

flo

w p

ath

and r

em

ove a

ny a

ccum

ula

ted f

ou

ling o

r debri

s.

10

3

12 OPERATIONAL ISSUES

12.1 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 well-recognized 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. The integrity of lagging should be checked, particularly after storm conditions.

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. Re-circulation 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 RECENT TRENDS

13.1 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.power-hitachi.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

NOxCO

CO

Le

ve

l

65

0

100

NO

x L

eve

l

0

2000 Temperature (qC)

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 15-18MW 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

Ta

ble

8

The

ta

ble

giv

es e

xa

mp

les o

f o

bse

rva

tio

ns w

hic

h w

ou

ld in

dic

ate

no

t b

est

pra

ctice

in t

he o

pe

ratio

n /

ma

inte

na

nce

of

a g

as t

urb

ine

.

So

urc

e H

SE

Re

se

arc

h R

ep

ort

RR

07

6

ITE

M

TO

PIC

K

EY

OB

SE

RV

AT

ION

IM

PA

CT

IN

FE

RE

NC

E

AC

TIO

N

EQ

UIP

ME

NT

V

ibra

tion

Vib

rati

on m

onit

ors

not

funct

ionin

g, or

alar

ms

in

Sig

nif

ican

t vib

rati

on c

an

be

felt

Mac

hin

e d

amag

e, d

amag

e to

fu

el l

ines

, fu

el r

elea

ses.

B

lade

fail

ure

s.

Oper

ators

not

pay

ing a

tten

tion t

o

Rev

iew

vib

rati

on

mo

nit

ori

ng

vib

rati

on l

evel

s, n

ot

awar

e of

po

ten

tial

dam

age

Rev

iew

vib

rati

on

mo

nit

ori

ng

poli

cy /

pra

ctic

e

Fu

el

Hig

h f

uel

pre

ssu

res

( if

v

isib

le o

n l

oca

l g

aug

es)

Incr

ease

d r

isk

of

pip

e o

r jo

int

fail

ure

s (

par

ticu

larl

y

flex

ible

)

Fuel

nozz

le r

estr

icti

ons

or

exce

ss

fuel

flo

w

Ch

eck

fu

el p

ress

ure

vs.

ven

dor

fuel

flo

w.

Ch

eck

op

erat

ing

lo

gs

MA

INT

EN

AN

CE

V

enti

lati

on

Aco

ust

ic e

ncl

osu

re

ven

tila

tio

n l

ouv

ers

ver

y

dir

ty f

lam

mab

le m

ixtu

re.

Gas

or

ob

scu

red

Over

-hea

ting, ri

sk o

f fl

amm

able

mix

ture

det

ecti

on i

nef

fect

ive

Eff

ecti

ven

ess

of

ven

tila

tio

n i

s n

ot

chec

ked

C

arry

ou

t ai

r fl

ow

tes

t

Ven

tila

tion

Encl

osu

re d

oors

lef

t open

. P

anel

s re

mo

ved

W

rong v

enti

lati

on p

atte

rn,

over

hea

ting, gas

det

ecti

on

inef

fect

ive.

Nois

e em

issi

on

s

Op

erat

ors

are

un

awar

e o

f th

e p

ote

nti

al h

azar

d

Rev

iew

oper

atin

g/

mai

nte

nan

ce p

hil

oso

ph

y

Oil

lea

kag

e O

il a

bso

rben

t pad

s ar

ound

encl

osu

re b

ase

Fuel

or

lubri

cant

leak

age?

P

oo

l fi

res?

Fu

el m

ist?

O

per

ators

unab

le t

o c

onta

in f

uel

le

ak

Iden

tify

flu

id a

nd s

ourc

e.

Pla

n r

emed

ial

acti

on.

Oil

lea

kag

e O

il a

bso

rben

t pad

s ar

ound

encl

osu

re b

ase

Sli

pp

ery

flo

or

– p

erso

nn

el

inju

ry

Op

erat

ors

hav

e n

ot

con

sid

ered

ri

sk o

f in

jury

Id

enti

fy f

luid

an

d s

ourc

e.

Pla

n r

emed

ial

acti

on.

Mo

nit

or

con

dit

ion

of

flo

or,

w

arn

ing

sig

ns,

bar

rier

s

OP

ER

AT

ION

Aco

ust

ic e

ncl

osu

re

Vie

win

g w

ind

ow

s d

irty

/

obsc

ure

d /

no i

nte

rnal

li

gh

tin

g

Can

no

t se

e in

sid

e en

clo

sure

to

chec

k.

Un

nec

essa

ry e

ntr

ies.

In

crea

sed

per

son

nel

ris

k

Chec

ks,

if

mad

e, r

equir

e en

try t

o

encl

osu

re

Rev

iew

oper

atin

g

inst

ruct

ion

s -

pla

n

imp

rov

emen

ts

Acc

ess

Encl

osu

re a

cces

s w

ithout

per

mit

Incr

ease

d p

erso

nn

el r

isk

. S

earc

h p

rob

lem

s if

th

ere

is

an i

nci

den

t.

Ad

dit

ion

al h

azar

d o

f en

clo

sure

en

try i

s n

ot

reco

gn

ised

R

evie

w o

per

atin

g

inst

ruct

ions

& P

TW

contr

ol

12

4

ITE

M

TO

PIC

K

EY

OB

SE

RV

AT

ION

IM

PA

CT

IN

FE

RE

NC

E

AC

TIO

N

OP

ER

AT

ION

P

erso

nn

el s

afet

y

Aco

ust

ic e

ncl

osu

re d

oo

r ca

n b

e p

adlo

cked

P

ote

nti

al t

o t

rap p

erso

nn

el

insi

de

Tra

pp

ing

ris

k h

as n

ot

bee

n

reco

gn

ised

A

sses

s haz

ard, id

enti

fy i

f al

tern

ativ

e es

cape

exis

ts.

Inst

rum

ents

Contr

ol

pan

el o

r lo

cal

inst

rum

ent

dis

pla

ys

inac

cess

ible

/ d

irty

/

dam

aged

Op

erat

ors

do

no

t m

anag

e eq

uip

men

t, f

ault

s d

evel

op

u

n-c

hec

ked

. A

larm

s m

igh

t b

e m

isse

d.

Oper

ators

do n

ot

routi

nel

y c

hec

k

thes

e in

stru

men

ts

Rev

iew

oper

atin

g

inst

ruct

ion

s -

are

inst

rum

ents

nec

essa

ry o

r re

dundan

t.

Rei

nst

ate

or

rem

ov

e.

Ex

hau

st

Hig

h d

isch

arg

e te

mp

erat

ure

( al

arm

s in

or

sco

rch

ed d

uct

ing

)

Cre

ep f

ailu

re o

f bla

des

. M

issi

les.

Exhau

st d

uct

ing /

fl

exib

le f

ailu

re

Inte

rnal

pro

ble

ms

wit

h t

urb

ine,

fu

el c

on

tro

l p

rob

lem

s R

evie

w r

ecen

t oper

atin

g

tem

per

ature

and c

ondit

ion

mo

nit

ori

ng

dat

a

12

5

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� What is the basis for any components which have been found defective being left in service and not replaced.

x� Are the rejection criteria for defective components in accordance with offshore practice, where tighter definitions may be used than on onshore applications.

x� What is the reason for upgrades or chances to design

x� 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� Who provided it x� What documentation is available x� Amendment status x� Is the manufacturer aware any issues in this particular installation x� Are Manuals available and being used x� Updatesx� Right air, fuel x� 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� Fuel supply protected, inviolate x� No water (unless intended). water injection used in some GTs to enhance performance). x� Don't block exhausts x� If the GT needs lube oil it is stored in the right containers, recorded, right stuff. x� 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. PM84 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. RR076 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. Garside 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. Garside 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 465-474 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 16-59(93)E IMIA Conference, September http://www.imia.com/documents/development_and_operating_experience.htm

134

1993

38. Gas Turbine World 2005 Performance Specs, Gas Turbine Power Plant Ratings forProject 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 Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

AH001 AMERADA HESS F FP N/A 246 UK ALBA FSU CHEVRON F FSU N/A 425 UK ALBA NORTHERN CHEVRON F F N/A 409 UK ALWYN NORTH TOTAL E&P UK PLC F F N/A 290 UK AMETHYST BP SNS (N) F NUI N/A 372 UK ANASURIA SHELL U.K. (CENTRAL) F FPSO N/A 500 UK ANDREW BP MBU F F N/A 483 UK ANGLIA A GAZ DE FRANCE F F N/A 408 UK ANGLIA B GAZ DE FRANCE F SUBSEA N/A 0 UK ARBROATH PETROFAC F F N/A 354 UK

PRODUCTION SERVICES

ARCH ROWAN ROWAN DRILLING (UK) M N/A JU 188 USA LTD

ARDMORE ROWAN DRILLING (UK) F F N/A 603 UK (ROWAN GORILLA LTD VII) ARMADA BG INTERNATIONAL F F N/A 478 UK AUDREY PWD CONOCO PHILLIPS F NUI N/A 334 UK 49/11A AUK A SHELL U.K. (CENTRAL) F F N/A 88 UK BAE 6 TOWERS BAE F F N/A 0 UK AIR BALMORAL ENI F FP N/A 301 UK BAR 331 SAIPEM M N/A MH 0 NL BAR PROTECTOR SAIPEM M N/A MH 578 UK BARQUE PB 48/13A SHELL U.K. SOUTHERN F NUI N/A 364 UK

OPS BARQUE PL 48/14P SHELL U.K. SOUTHERN F F N/A 470 UK

OPS BEATRICE A TALISMAN ENERGY F F N/A 160 UK

(UK) LIMITED BEATRICE B TALISMAN ENERGY F F N/A 161 UK

(UK) LIMITED BEATRICE C TALISMAN ENERGY F F N/A 271 UK

(UK) LIMITED BELLWELL CONOCO PHILLIPS F SUBSEA N/A 0 UK BERYL A MOBIL NORTH SEA F F N/A 95 UK

LIMITED BERYL B MOBIL NORTH SEA F F N/A 174 UK

LIMITED BESSEMER PERENCO UK LIMITED F NUI N/A 490 UK BLEO HOLM BLUEWATER F FPSO N/A 520 UK

ENGINEERING BORGHOLM DOLPHIN DRILLING M N/A SS 341 UK DOLPHIN COMPANY BORGILA DOLPHIN DRILLING M N/A SS 582 UK DOLPHIN COMPANY BORGNY DOLPHIN DOLPHIN DRILLING M N/A SS 157 UK

COMPANY BORGSTEN DOLPHIN DRILLING M N/A SS 170 UK

A1-1

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

DOLPHIN COMPANY BOULTON CONOCO PHILLIPS F NUI N/A 511 UK BRAE A MARATHON OIL (UK) F F N/A 192 UK

LIMITED BRAE B MARATHON OIL (UK) F F N/A 332 UK

LIMITED BRENT A SHELL U.K. NORTHERN F F N/A 122 UK

OPS BRENT B SHELL U.K. NORTHERN F F N/A 107 UK

OPS BRENT C SHELL U.K. NORTHERN F F N/A 137 UK

OPS BRENT D SHELL U.K. NORTHERN F F N/A 124 UK

OPS BRIGANTINE BG SHELL U.K. SOUTHERN F NUI N/A 548 UK

OPS BRIGANTINE BR SHELL U.K. SOUTHERN F NUI N/A 554 UK

OPS BRITANNIA BOL (BRITANNIA F F N/A 489 UK

OPERATOR LIMITED) BRUCE BP (DBU) F F N/A 430 UK BUCHAN A TALISMAN ENERGY F FP N/A 89 UK

(UK) LIMITED BULFORD DOLPHIN DRILLING M N/A SS 304 UK DOLPHIN COMPANY BUZZARD FIELD ENCANA (U.K) LIMITED F F N/A 6067 UK BYFORD DOLPHIN DOLPHIN DRILLING M N/A SS 171 NOR

COMPANY CAISTER 44/23A CONOCO PHILLIPS F NUI N/A 431 UK CM (MURDOCH FIELD) CAMELOT CA MOBIL NORTH SEA F NUI N/A 362 UK CAMELOT CB MOBIL NORTH SEA F F N/A 435 UK CAPTAIN TEXACO F FPSO N/A 495 UK

CARRACK A SHELL U.K. SOUTHERN F F N/A 576 UK OPS

CASTORO 10 SAIPEM M N/A MH 900034 UK CASTORO SEI SAIPEM M N/A SS 9188 UK CECIL PROVINE ROWAN DRILLING (UK) M N/A JU 200 USA

LTD CENTRAL BRAE MARATHON OIL (UK) F F N/A 377 UK

LIMITED CHARLES ROWAN ROWAN DRILLING (UK) M N/A JU 182 USA

LTD CLAIR BP (DBU) F F N/A 6020 UK CLAYMORE TALISMAN ENERGY F F N/A 120 UK

(UK) LIMITED CLEETON P/Q BP SNS (N) F F N/A 319 UK CLYDE TALISMAN ENERGY F F N/A 286 UK

(UK) LIMITED CORMORANT A SHELL U.K. NORTHERN F F N/A 138 UK

OPS CORVETTE A SHELL U.K. SOUTHERN F NUI N/A 522 UK

OPS CRYSTAL OCEAN BROVIG M N/A MH 542 UNKNOWN CRYSTAL SEA BROVIG M N/A MH 552 UNKNOWN CSO ALLIANCE TECHNIP OFFSHORE M N/A MH 579 VARIOUS CSO APACHE TECHNIP OFFSHORE M N/A MH 0 VARIOUS

A1-2

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

CSO TECHNIP OFFSHORE M N/A SS 507 VARIOUS CONSTRUCTOR CSO INSTALLER TECHNIP OFFSHORE M N/A SS 0 VARIOUS DAVY PERENCO UK LIMITED F NUI N/A 491 UK DEEPSEA BERGEN ODFJELL M N/A SS 462 UK DEEPSEA DELTA ODFJELL M N/A SS 580 UK DEEPSEA TRYM ODFJELL M N/A SS 562 UK DOUGLAS (LBA) BHP BILLITON F F N/A 465 UK DSND MAYO SUBSEA 7 (UK) M N/A MH 0 VARIOUS DSND PELICAN SUBSEA 7 (UK) M N/A MH 900054 VARIOUS DUNBAR TOTAL E&P UK PLC F F N/A 447 UK DUNLIN A SHELL U.K. NORTHERN F F N/A 136 UK

OPS EAST BRAE MARATHON OIL (UK) F F N/A 454 UK

LIMITED EIDER SHELL U.K. NORTHERN F F N/A 350 UK

OPS ELGIN FRANKLIN TOTAL E&P UK PLC F F N/A 540 UK ENSCO 100 ENSCO M N/A JU 331 NL ENSCO 101 ENSCO M N/A JU 543 NL ENSCO 102 ENSCO M N/A JU 568 UK ENSCO 70 ENSCO M N/A JU 363 NL ENSCO 71 ENSCO M N/A JU 309 NL ENSCO 72 ENSCO M N/A JU 289 UK ENSCO 80 ENSCO M N/A JU 176 UK ENSCO 85 ENSCO M N/A JU 194 UK ENSCO 92 ENSCO M N/A JU 202 UK ERSKINE TEXACO F F N/A 504 UK ETAP BP MBU F F N/A 512 UK F G McCLINTOCK TRANSOCEAN SEDCO M N/A JU 317 WHE

FOREX FORTIES A APACHE NORTH SEA F F N/A 76 UK

LIMITED FORTIES B APACHE NORTH SEA F F N/A 103 UK

LIMITED FORTIES C APACHE NORTH SEA F F N/A 82 UK

LIMITED FORTIES D APACHE NORTH SEA F F N/A 104 UK

LIMITED FORTIES E APACHE NORTH SEA F F N/A 314 UK

LIMITED FRIGG CDPI TOTAL E&P NORGE AS F F N/A 108 UK FULMAR A SHELL U.K. (CENTRAL) F F N/A 152 UK GALAXY I GLOBAL SANTA FE M N/A JU 420 UK

DRILLING GALAXY II GLOBAL SANTA FE M N/A JU 518 CAN

DRILLING GALAXY III GLOBAL SANTA FE M N/A JU 538 UK

DRILLING GALLEON 48/20PN SHELL U.K. SOUTHERN F F N/A 455 UK

OPS GALLEON PG SHELL U.K. SOUTHERN F F N/A 477 UK

OPS GANNET A SHELL U.K. (CENTRAL) F F N/A 384 UK GLAS DOWR BLUEWATER F FPSO N/A 503 AFR

ENGINEERING GLOBAL KERR MCGEE F FPSO N/A 555 UK PRODUCER III

A1-3

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

(LEADON) GLOMAR GLOBAL SANTA FE M N/A JU 524 USA ADRIATIC IV DRILLING GLOMAR GLOBAL SANTA FE M N/A JU 257 UK ADRIATIC VI DRILLING GLOMAR GLOBAL SANTA FE M N/A JU 308 USA ADRIATIC VII DRILLING GLOMAR GLOBAL SANTA FE M N/A JU 214 UK ADRIATIC XI DRILLING GLOMAR ARCTIC I GLOBAL SANTA FE M N/A SS 256 USA

DRILLING GLOMAR ARCTIC GLOBAL SANTA FE M N/A SS 0 UK II DRILLING GLOMAR ARCTIC GLOBAL SANTA FE M N/A SS 281 UK III DRILLING GLOMAR ARCTIC GLOBAL SANTA FE M N/A SS 244 UK IV DRILLING GLOMAR BALTIC I GLOBAL SANTA FE M N/A JU 380 USA

DRILLING GLOMAR GRAND GLOBAL SANTA FE M N/A SS 299 CAN BANKS DRILLING GLOMAR GLOBAL SANTA FE M N/A JU 300 WHE LABRADOR I DRILLING GLOMAR NORTH GLOBAL SANTA FE M N/A SS 204 CAN SEA DRILLING GOLDENEYE SHELL U.K. (CENTRAL) F F N/A 4022 UK GRYPHON A KERR MCGEE F FPSO N/A 448 UK HAEWENE BRIM BLUEWATER F FPSO N/A 519 UK

ENGINEERING HAMILTON (LBA) BHP BILLITON F NUI N/A 468 UK HAMILTON BHP BILLITON F NUI N/A 467 UK NORTH (LBA) HARDING FIELD BP MBU F F N/A 476 UK HEATHER ALPHA DNO HEATHER LTD F F N/A 144 UK HENRY TRANSOCEAN SEDCO M N/A SS 333 CAN GOODRICH FOREX HEWETT FIELD PETROFAC F F N/A 11 UK

PRODUCTION SERVICES

HOTON BP SNS (N) F F N/A 560 UK HYDE 48/6 BP SNS (N) F NUI N/A 446 UK INDE 49/18A PERENCO UK LIMITED F NUI N/A 2 UK INDE 49/18B PERENCO UK LIMITED F NUI N/A 59 UK INDE 49/23A PERENCO UK LIMITED F F N/A 3 UK INDE 49/23C PERENCO UK LIMITED F F N/A 123 UK INDE 49/23D PERENCO UK LIMITED F NUI N/A 368 UK INDE 49/24J SHELL U.K. SOUTHERN F F N/A 17 UK

OPS INDE 49/24K SHELL U.K. SOUTHERN F F N/A 18 UK

OPS INDE 49/24L SHELL U.K. SOUTHERN F F N/A 145 UK

OPS INDE 49/24M SHELL U.K. SOUTHERN F F N/A 528 UK

OPS INDE 49/24N SHELL U.K. SOUTHERN F F N/A 529 UK

OPS IOLAIR TRANSOCEAN SEDCO M N/A SS 241 NOR

FOREX

A1-4

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

IRISH SEA HALLIBURTON M N/A JU 494 UK PIONEER MANUFACTURING &

SERVICES LTD J W MCLEAN TRANSOCEAN SEDCO M N/A SS 70 UK

FOREX JACK BATES TRANSOCEAN SEDCO M N/A SS 508 UK

FOREX JADE PHILLIPS NORTHERN F F N/A 558 UK

OPS JANICE KERR MCGEE F FPSO N/A 523 UK JOHN SHAW TRANSOCEAN SEDCO M N/A SS 388 UK

FOREX JUDY-JOANNE PHILLIPS NORTHERN F F N/A 449 UK

OPS JUNO MINERVA BP SNS (N) F F N/A 566 UK KAN TAN IV MAERSK COMPANY M N/A SS 248 WHE

LIMITED KETCH A SHELL U.K. SOUTHERN F F N/A 531 UK

OPS KITTIWAKE SHELL U.K. (CENTRAL) F F N/A 378 UK KOMMANDOR SUBSEA 7 (UK) M MH MH 0 VARIOUS SUBSEA LAPS FIELD MOBIL NORTH SEA F F N/A 8 UK LEIV EIRIKSSON OCEAN RIG LIMITED M N/A SS 549 NOR LEMAN 49/26A SHELL U.K. SOUTHERN F F N/A 12 UK

OPS LEMAN 49/27A PERENCO UK LIMITED F F N/A 4 UK LEMAN 49/27B PERENCO UK LIMITED F F N/A 5 UK LEMAN 49/27C PERENCO UK LIMITED F NUI N/A 6 UK LEMAN 49/27D PERENCO UK LIMITED F NUI N/A 7 UK LEMAN 49/27E PERENCO UK LIMITED F NUI N/A 22 UK LEMAN 49/27F PERENCO UK LIMITED F NUI N/A 58 UK LEMAN 49/27G PERENCO UK LIMITED F NUI N/A 287 UK LEMAN 49/27H PERENCO UK LIMITED F NUI N/A 253 UK LEMAN 49/27J PERENCO UK LIMITED F NUI N/A 254 UK LEMAN B 49/26B SHELL U.K. SOUTHERN F F N/A 13 UK

OPS LEMAN BT 49/26B SHELL U.K. SOUTHERN F NUI N/A 16 UK

OPS LEMAN C 49/26C SHELL U.K. SOUTHERN F F N/A 14 UK

OPS LEMAN D 49/26D SHELL U.K. SOUTHERN F F N/A 15 UK

OPS LEMAN E 49/26E SHELL U.K. SOUTHERN F F N/A 189 UK

OPS LEMAN F 49/26F SHELL U.K. SOUTHERN F F N/A 284 UK

OPS LEMAN G 49/26G SHELL U.K. SOUTHERN F F N/A 285 UK

OPS LENNOX (LBA) BHP BILLITON F NUI N/A 466 UK LOGGS CENTRAL CONOCO PHILLIPS F NUI N/A 326 UK LOGGS CONOCO PHILLIPS F NUI N/A 348 UK SATELLITES LOMOND BP MBU F F N/A 418 UK LORELAY ALLSEAS M N/A MH 0 VARIOUS LYELL KERR MCGEE F SUBSEA N/A 422 UK MAERSK CURLEW MAERSK COMPANY F FPSO N/A 510 UK

LIMITED

A1-5

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

MAERSK MAERSK COMPANY M N/A JU 211 DK ENDEAVOUR LIMITED MAERSK MAERSK COMPANY M N/A JU 506 UK ENDURER LIMITED MAERSK MAERSK COMPANY M N/A JU 247 UK ENHANCER LIMITED MAERSK MAERSK COMPANY M N/A JU 539 DK EXERTER LIMITED MAERSK MAERSK COMPANY M N/A JU 439 UK GALLANT LIMITED MAERSK GIANT MAERSK COMPANY M N/A JU 292 NOR

LIMITED MAERSK MAERSK COMPANY M N/A JU 293 DK GUARDIAN LIMITED MAERSK MAERSK COMPANY M N/A JU 581 UK INNOVATOR LIMITED MAERSK MAERSK COMPANY M N/A SS 371 NOR JUTLANDER LIMITED MAGELLAN GLOBAL SANTA FE M N/A JU 438 UK

DRILLING MAGNUS 211/12 BP (DBU) F F N/A 203 UK MARIANOS TECHNIP OFFSHORE M N/A SS 575 VARIOUS MARKHAM ST1 LASMO NETHERLANDS F F N/A 456 UK

BV MCP 01 TOTAL E&P UK PLC F F N/A 119 UK MILLER BP MBU F F N/A 369 UK MONARCH GLOBAL SANTA FE M N/A JU 346 UK

DRILLING MONITOR GLOBAL SANTA FE M N/A JU 406 UK

DRILLING MONTROSE PETROFAC F F N/A 111 UK

PRODUCTION SERVICES

MORECAMBE BAY BRITISH GAS F F N/A 340 UK HYDROCARBON RESOURCES LIMITED

MPSV SHELL U.K. SOUTHERN M N/A JU 5023 UK OPS

MSV REGALIA PROSAFE OFFSHORE M N/A SS 288 NOR LTD

MURCHISON CNR (CANADIAN F F N/A 158 UK 211/19 NATIONAL RESOURCE) MURDOCH CONOCO PHILLIPS F F N/A 565 UK COMPLEX NAVIS EXPLORER DOLPHIN DRILLING M N/A DS 567 UK

COMPANY NELSON SHELL U.K. (CENTRAL) F F N/A 407 UK NEPTUNE BP SNS (N) F NUI N/A 537 UK NINIAN CENTRAL CNR (CANADIAN F F N/A 153 UK

NATIONAL RESOURCE) NINIAN CNR (CANADIAN F F N/A 151 UK NORTHERN NATIONAL RESOURCE) NINIAN CNR (CANADIAN F F N/A 141 UK SOUTHERN NATIONAL RESOURCE) NOBLE AL WHITE NOBLE DRILLING M N/A SS 252 UK NOBLE GEORGE NOBLE DRILLING M N/A JU 458 UK SAUVAGEAU NOBLE JULIE NOBLE DRILLING M N/A JU 533 NL

A1-6

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

ROBERTSON NOBLE LYNDA NOBLE DRILLING M N/A JU 249 UK BOSSLER NOBLE PIET VAN NOBLE DRILLING M N/A JU 342 UNKNOWN EDE NOBLE RONALD NOBLE DRILLING M N/A JU 236 UK HOOPE NOBLE TON VAN NOBLE DRILLING M N/A SS 414 UK LANGEVELD NORDIC APOLLO UGLAND STENA F FPSO N/A 547 UK

STORAGE NORPIPE PHILLIPS NORWAY F F N/A 226 UK NORTH SHELL U.K. NORTHERN F F N/A 183 UK CORMORANT OPS NORTH EVEREST BP MBU F F N/A 417 UK NORTH SEA NORTH SEA F FPSO N/A 499 UK PRODUCER PRODUCTION NORTH WEST BP (DBU) F F N/A 187 UK HUTTON NORTHERN PETROFAC F FPSO N/A 167 UK PRODUCER PRODUCTION

SERVICES OCEAN ALLIANCE DIAMOND OFFSHORE M N/A SS 359 NOR

DRILLING OCEAN AMERICA DIAMOND OFFSHORE M N/A SS 45 USA

DRILLING OCEAN DIAMOND OFFSHORE M N/A SS 282 UK GUARDIAN DRILLING OCEAN NOMAD DIAMOND OFFSHORE M N/A SS 264 UK

DRILLING OCEAN PRINCESS DIAMOND OFFSHORE M N/A SS 218 UK

DRILLING OCEAN RIG 2 OCEAN RIG LIMITED M N/A SS 550 WHE OCEAN VALIANT DIAMOND OFFSHORE M N/A SS 385 AFR

DRILLING OCEAN DIAMOND OFFSHORE M N/A SS 452 UK VANGUARD DRILLING OCEAN VICTORY DIAMOND OFFSHORE M N/A SS 42 USA

DRILLING ORELIA TECHNIP OFFSHORE M N/A DSV 266 VARIOUS OSI (LBA) BHP BILLITON F FSU N/A 480 UK PAUL B LOYD TRANSOCEAN SEDCO M N/A SS 398 UK JUNIOR FOREX PETROJARL PGS PRODUCTION AS F FPSO N/A 486 UK FOINAVEN PETROJARL I PGS PRODUCTION AS F FPSO N/A 352 NOR PETROLIA PETROLIA DRILLING M N/A SS 242 UK

LTD PICKERILL PERENCO UK LIMITED F F N/A 401 UK PIPER B TALISMAN ENERGY F F N/A 391 UK

(UK) LIMITED POLYCONCORD RASMUSSEN A/S M N/A SS 219 UK POLYCONFIDENC RASMUSSEN A/S M N/A SS 374 USA E PORT REGENCY RASMUSSEN A/S M N/A SS 215 UNKNOWN PORT RIGMAR PORT RIGMAR AS M N/A JU 492 NOR PRIDE NORTH PRIDE NORTH SEA LTD M N/A SS 208 UK ATLANTIC

A1-7

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

PRIDE NORTH SEA PRIDE NORTH SEA LTD M N/A SS 112 UK PUFFIN SHELL U.K. (CENTRAL) F F N/A 6026 UK RAMFORM BANFF PGS PRODUCTION AS F FPSO N/A 525 UK RAVENSPURN BP SNS (N) F F N/A 356 UK NORTH RAVENSPURN BP SNS (N) F NUI N/A 357 UK NORTH ST2 & ST3 RAVENSPURN BP SNS (N) F NUI N/A 320 UK SOUTH ROCKWATER 1 SUBSEA 7 (UK) M MH MH 0 VARIOUS ROUGH FIELD CENTRICA STORAGE F F N/A 79 UK

LTD ROWAN ROWAN DRILLING (UK) M N/A JU 272 USA CALIFORNIA LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 283 USA II LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 559 USA III LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 358 USA IV LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 526 CAN V LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 544 USA VI LTD ROWAN GORILLA ROWAN DRILLING (UK) M N/A JU 545 UK VII LTD ROWAN HALIFAX ROWAN DRILLING (UK) M N/A JU 237 USA

LTD S7000 SAIPEM M N/A SS 347 VARIOUS SAFE BRITANNIA PROSAFE OFFSHORE M N/A SS 217 NOR

LTD SAFE CALEDONIA PROSAFE OFFSHORE M N/A SS 213 NOR

LTD SAFE LANCIA PROSAFE OFFSHORE M N/A SS 255 UK

LTD SAFE PROSAFE OFFSHORE M N/A SS 553 NOR SCANDINAVIA LTD SALTIRE A TALISMAN ENERGY F F N/A 405 UK

(UK) LIMITED SANTA FE 135 GLOBAL SANTA FE M N/A SS 245 UK

DRILLING SANTA FE 140 GLOBAL SANTA FE M N/A SS 250 UK

DRILLING SANTA FE GLOBAL SANTA FE M N/A JU 35 UK BRITANNIA DRILLING SCARABEO 6 SAIPEM M N/A SS 280 UK SCHIEHALLION BP (DBU) F FPSO N/A 509 UK SCHOONER A SHELL U.K. SOUTHERN F F N/A 469 UK

OPS SCOTT FIELD ENCANA (U.K) LIMITED F F N/A 434 UK SEAFOX 2 WORKFOX UK LTD M N/A JU 268 NL SEAFOX 3 WORKFOX UK LTD M N/A JU 259 NL SEAFOX 4 WORKFOX UK LTD M N/A JU 482 NL SEAN P 49/25A SHELL U.K. SOUTHERN F F N/A 279 UK

OPS SEAN RD SHELL U.K. SOUTHERN F F N/A 278 UK

OPS SEAWAY STOLT OFFSHORE M N/A MH 0 VARIOUS

A1-8

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

COMMANDER SEAWAY CONDOR STOLT OFFSHORE M N/A MH 900010 UNKNOWN SEAWAY STOLT OFFSHORE M N/A MH 574 VARIOUS DISCOVERY SEAWAY EAGLE STOLT OFFSHORE M N/A MH 0 VARIOUS SEAWAY FALCON STOLT OFFSHORE M N/A MH 573 VARIOUS SEAWAY STOLT OFFSHORE M N/A MH 0 VARIOUS KINGFISHER SEAWELL WELL OPERATORS UK M N/A MH 311 UK

LTD SEDCO 704 TRANSOCEAN SEDCO M N/A SS 83 UK

FOREX SEDCO 706 TRANSOCEAN SEDCO M N/A SS 394 UK

FOREX SEDCO 711 TRANSOCEAN SEDCO M N/A SS 220 UK

FOREX SEDCO 712 TRANSOCEAN SEDCO M N/A SS 276 UK

FOREX SEDCO 714 TRANSOCEAN SEDCO M N/A SS 258 UK

FOREX SEILLEAN TRANSOCEAN SEDCO F FPSO N/A 383 WHE

FOREX SEMAC I SAIPEM M N/A SS 9002 UK SHEARWATER SHELL U.K. (CENTRAL) F F N/A 541 UK SHELF EXPLORER TRANSOCEAN SEDCO M N/A JU 201 EUR

FOREX SKANDI NAVICA SUBSEA 7 (UK) M N/A MH 0 VARIOUS SKIFF PS SHELL U.K. SOUTHERN F NUI N/A 546 UK

OPS SOLE PIT CLIPPER SHELL U.K. SOUTHERN F F N/A 365 UK 48/19A OPS SOLITAIRE ALLSEAS M N/A MH 0 VARIOUS SOVEREIGN TRANSOCEAN SEDCO M N/A SS 261 UK EXPLORER FOREX STANISLAV SEAWAY HEAVY LIFT M N/A MH 428 VARIOUS YUDIN STENA DEE STENA DRILLING LTD M N/A SS 318 UK STENA SPEY STENA DRILLING LTD M N/A SS 221 UK TARTAN A TALISMAN ENERGY F F N/A 159 UK

(UK) LIMITED TERN A SHELL U.K. NORTHERN F F N/A 353 UK

OPS THAMES A 49/28 MOBIL NORTH SEA F F N/A 306 UK THIALF HEEREMA M N/A SS 349 VARIOUS THISTLE A DNO THISTLE LTD F F N/A 125 UK TIFFANY ENI F F N/A 400 UK TOG MOR ALLSEAS M N/A MH 20 VARIOUS TOISA POLARIS SUBSEA 7 (UK) M N/A MH 0 VARIOUS TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 463 EUR ARCTIC FOREX TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 118 UK EXPLORER FOREX TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 481 UK LEADER FOREX TRANSOCEAN TRANSOCEAN SEDCO M N/A JU 294 UK NORDIC FOREX TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 572 UK PROSPECT FOREX

A1-9

Installation Dutyholder Fixed/ Type of Type of Reg Location

Mobile Fixed Mobile No.

TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 475 EUR SEARCHER FOREX TRANSOCEAN TRANSOCEAN SEDCO M N/A SS 166 EUR WILDKAT FOREX TRENCH SETTER ALLSEAS M N/A MH 21 VARIOUS TRENT 43/24 PERENCO UK LIMITED F NUI N/A 497 UK TRITON AMERADA HESS F FPSO N/A 536 UK TYNE PERENCO UK LIMITED F NUI N/A 498 UK UISGE GORM BLUEWATER F FPSO N/A 493 UK

ENGINEERING UNITY APACHE NORTH SEA F F N/A 427 UK

LIMITED VIKING 49/17B CONOCO PHILLIPS F F N/A 10 UK VIKING CONOCO PHILLIPS F NUI N/A 19 UK SATELLITES WAVENEY BP SNS (N) F F N/A 521 UK WELL SERVICER TECHNIP OFFSHORE M N/A SS 312 VARIOUS WELLAND 53/4A MOBIL NORTH SEA F NUI N/A 393 UK WEST ALPHA SMEDVIG LTD M N/A SS 450 UNKNOWN WEST NAVION SMEDVIG LTD M N/A MH 557 UNKNOWN WEST SOLE A BP SNS (N) F F N/A 27 UK WEST SOLE B BP SNS (N) F NUI N/A 28 UK WEST SOLE C BP SNS (N) F NUI N/A 29 UK WEST SOLE BP SNS (N) F F N/A 0 UK NEWSHAM WINDERMERE RWE / DEA F F N/A 502 UK

Key

F Fixed

M Mobile

FPSO Floating, Production, Storage and Offloading Vessel

FSU Floating Storage Unit

MH Mono Hull

SS Semi- Submersible

JU Jack-Up

DSV Drilling Service Vessel

NUI Normally Unmanned Installation

A1-10

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� API 616 - Gas Turbines x� API 617 - Compressors x� API 614 - Lube Oil Systemx� API 670 - Machinery Protection x� API 613 - Continuous Duty Gear x� API 677 - Auxiliary Drive Gearx� API 671 - Flexible Couplings

In addition there are codes governing testing and operation:

x� ASME PTC-22 Gas Turbine Testingx� 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� ISO Rating,x� Normal Operating Point, x� Maximum Continuous Speed, x� 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� Definitionsx� Selection and evaluation x� Range and variety of gas turbines x� Prototype gas turbines x� Complete unit responsibility

Technical information

x� Operating requirements

x� Spares inventory

x� Type selection – aeroderivative or industrial, one or two shaft

x� Site environment and fuel considerations

x� Power requirements

x� Use of standard packages

x� Installation – cranes, safe access, lay down areas, mounting, enclosures, auxiliary

equipment

x� Noise levels- limits, support information, general requirements

x� Oil tank vents

x� Materials – specification,temperature, corrosion and environment resistance,

coatings, certification

x� Starting drives - gas expansion starters, hydraulic motors, diesel engines

x� Foundations, baseplates and mountings

x� Controls and instrumentation

x� Inlet system – intake location, new configurations, material, leak prevention, joints

and movement allowances

x� Air compressor cleaning

x� Exhaust system – Exhaust emission, height, proximity to process equipment, rain

ingress, maintenance access, recirculation

x� Combustion air filtration – requirements, anti-icing, shutters

x� Fire protection – ventilation dampers, extinguishing systems, enclosure surveillance

x� Acoustic enclosures – accessibility, ventilation, area classification

x� Fuels and fuel systems – fuel selection, gas fuels and systems, liquid fuels and

systems, dual fuel systems, power augmentation x� 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� Requisitioning binder containing data sheets x� Metallic materials - selected standards x� Metallic materials - prevention of brittle fracture x� Noise control x� Installation of rotating equipment x� combustion gas turbines (amendments/ supplements to API 616) x� field inspection prior to commissioning of mechanical equipment x� fire-fighting systems x� data/requisition sheet for equipment noise limitation x� 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� Definitionsx� Basic design x� Referenced standards x� Pressure casings x� Combustors and fuel nozzles x� Casing connections x� Rotating elements x� Sealsx� Dynamics x� Bearings and bearing housings x� Lubricationx� Materials

A2-4

x� Name plates and rotational arrows

x� Accessories - starting and helper driver gears, couplings and guards mounting plates

x� Controls and instrumentation

x� Insulation, weatherproofing, fire protection

x� Acoustic enclosure

x� Piping and appurtenances

x� Inlet coolers

x� Fuel system treatment

x� Inspection and tests

x� Preparation for shipment

x� 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 % UK Models UK Models Worldwide

Solar Turbines 11% Saturn 20 1MW Saturn 20 1MW Centaur GSC 40/50 Taurus 60/70 Mars 90/100

3-4MW 5-7MW 8- 10MW

Centaur 40/50 Taurus 60/70 Mars 90/100 Titan 130

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 % UK Models UK Models Worldwide

Rolls-Royce (Avon, Coberra, RB211)

27% 501 Avon 1534/1535 Coberra 2000/6000 RB211

5MW 15MW 15MW 30MW

501 Avon RB211 Trent

5MW 15MW 30MW 50MW

Olympus GT SK30 35MW

Paul Fletcher (stand-in for Tomas, Mon PM) Turbine Designer

A4-3

1

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 % UK Models UK Models Worldwide

Siemens-Westinghouse 46% Tornado G8000/8004 8MW Typhoon 5MW (Alstom, Ruston, EGT) Alstom Ruston 14MW Tornado 8MW

TB3000/4500/5000 Cyclone 13MW PGT10 14MW PGT10 14MW

Alstom had previously absorbed the turbine businesses of EGT and Ruston.

Siemens Frank Carchedi (Simens (UK) compressor aerodynamics Oil & Gas Mon 14.30

A4-4

2

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 % UK Models UK Models Worldwide

General Electric Oil & 12% GE Frame 5 5MW GE5 5MW Gas: GE-1201/1401A-C 10-15MW GE 10 10MW

LM2500+ 25MW LM 1600 16MW LM5000/6000 40-50MW 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 % UK Models UK

ABB 12% ABB GT35 Dresser Rand Dresser KG2, KG3 1-2MW

MTU V16 12MW Pratt and Witney Pratt & Witney ST18 2MW

A4-5

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

3Turbine World 2005 Performance Specifications .

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.

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

3

A5-2

Ma

nu

fac

ture

r M

od

el

Ye

ar

ISO

IS

O B

ase

Bas

e

Ra

tin

g

Ra

tin

g

Heat

Eff

icie

ncy P

ressu

re

Flo

w

Sp

ec

ific

T

urb

ine

E

xh

au

st

Ap

pro

x

Ap

pro

xim

ate

Co

mm

en

ts

Rate

R

ati

o

Po

wer

Sp

ee

d

Te

mp

W

eig

ht

Dim

en

sio

ns

(f

t)

MW

kW

B

tu/k

Wh

%

(lb/s

ec)

kW

/lb

rpm

°F

lb

L

W

H

1st

year

600

0h p

er

Low

er

Heating V

alu

e

A

t base

Per

lb o

f O

utp

ut

unit

year

or

(LH

V)

loa

d

air p

er

sh

aft

availa

ble

m

ore

second

GE

G

E5

199

9

6 M

W

5,5

00

11,1

30

30.7

%

14.8

43.1

128

16,6

30

1,0

65

116,1

60

19

8

10 I

DLE

GE

G

E10

200

0

11 M

W

11,2

50

108

84

31.4

%

15.5

104.7

11,0

00

900

749

70

30

8

20

GE

LM

16

00P

E

198

9

15 M

W

14,8

98

100

94

33.8

%

21.3

109.7

136

7,9

00

894

190

00

0

50 1

2

15 W

ate

r

GE

LM

2500+

199

7

30 M

W

30,4

63

8,8

54

38.5

%

22.6

191.3

159

360

0

960

260,0

00

57

9

10 D

LE

6S

tg

GE

LM

25

00P

E

198

1

22 M

W

22,3

46

9,6

30

35.4

%

18.0

153.6

145

300

0

100

1

250,0

00

57

9

10 d

ry

GE

LM

60

00

199

2

43 M

W

43,0

76

8,2

55

41.3

%

30.0

288.8

149

3,6

00

840

68,3

42

31 1

4

14 S

ize w

/o G

T

enclo

sure

GE

P

GT

10

10 M

W

10,2

20

109

40

31.2

%

13.8

93.3

7,9

00

910

595

35

27

8

13

GE

P

GT

16

198

9

14 M

W

13,7

20

976

4

34.9

%

20.2

104.3

7,9

00

919

418

95

27

8

12

GE

P

GT

20

200

1

17 M

W

17,4

64

970

6

35.2

%

15.7

137.7

6,5

00

887

830

18

30

GE

P

GT

20

200

1

17 M

W

17,4

69

9,7

21

35.1

%

18.0

137.8

127

6,5

00

887

83,0

03

30 1

1

11 s

ize w

/o G

T

enclo

sure

GE

P

GT

25

198

1

22 M

W

22,4

17

940

3

36.3

%

17.9

151.9

6,5

00

976

830

18

30 1

1

11

GE

P

GT

25+

199

6

30 M

W

30,2

26

861

2

39.6

%

21.5

185.9

6,1

00

931

678

04

21

GE

P

GT

5

5 M

W

5,2

20

127

24

26.8

%

9.1

54.2

10,2

90

973

617

40

28

8

10

Rolls

Ro

yce

501-K

B5S

199

0

4 M

W

389

7

11 7

47

29.1

%

10.3

33.9

Ib

115

142

00

104

0

250

00

Ratin

gs a

t sea

leve

l, 1

5 d

eg

C

Rolls

Ro

yce

501-K

B7S

199

2

5 M

W

524

5

10 8

48

31.5

%

13.9

46.6

Ib

113

146

00

928

250

00

No e

xte

rnal

pre

ssure

losses

Rolls

Ro

yce

501-K

H5

198

2

6 M

W

644

7

8 5

09

40.1

%

12.5

40.6

159

146

00

986

250

00

8

Case s

team

in

jecte

d 2

.73

kg/s

ec

Rolls

Ro

yce

501-K

C5

199

0

4 M

W

410

0

849

5

29.6

%

9.4

34.2

159

136

00

106

0

250

00

8

501-K

C5 G

as

gen

era

tor

Rolls

Ro

yce

501-K

C7

199

2

6 M

W

551

8

790

2

31.7

%

13.5

46.2

159

136

00

968

260

00

8

501-K

C7 G

as

gen

era

tor

Rolls

Ro

yce

Avon-1

53

5

1,9

88

15 M

W

15,1

80

8,6

60

29.4

%

8.8

170

89

550

0

827

50,0

00

Avon 1

535 G

as

Genera

tor

Rolls

Ro

yce

Avon2

64

8

1,9

88

15 M

W

15,1

80

8,6

60

29.4

%

8.8

170

92

550

0

827

50,0

00

Avon 1

535 G

as

Genera

tor

Rolls

Ro

yce

Avon 2

656

1,9

88

16 M

W

15,6

60

8,4

05

30.3

%

8.8

170

153

495

0

818

52,0

00

Avon 1

535 G

as

Genera

tor

A5

-3

Ma

nu

fac

ture

r M

od

el

Ye

ar

ISO

IS

O B

ase

Bas

e

Ra

tin

g

Ra

tin

g

Heat

Eff

icie

ncy P

ressu

re

Flo

w

Sp

ec

ific

T

urb

ine

E

xh

au

st

Ap

pro

x

Ap

pro

xim

ate

Co

mm

en

ts

Rate

R

ati

o

Po

wer

Sp

ee

d

Te

mp

W

eig

ht

Dim

en

sio

ns

(f

t)

MW

kW

B

tu/k

Wh

%

(lb/s

ec)

kW

/lb

rpm

°F

lb

L

W

H

1st

year

600

0h p

er

Low

er

Heating V

alu

e

A

t base

Per

lb o

f O

utp

ut

unit

year

or

(LH

V)

loa

d

air p

er

sh

aft

availa

ble

m

ore

second

Rolls

Ro

yce

Cob

err

a

264

8

1,9

89

15 M

W

15,1

80

8,6

60

29.4

%

8.8

170.1

92

5,5

00

1,1

41

50,0

00

Avon 1

535 G

as

Genera

tor

Rolls

Ro

yce

Cob

err

a

265

6

1,9

90

16 M

W

15,6

60

8,4

05

29.4

%

8.8

169.4

154

4,9

50

1,1

45

52,0

00

Avon 1

535 G

as

Genera

tor

Rolls

Ro

yce

Cob

err

a

655

6

199

2

26 M

W

26,0

25

8,6

60

29.4

%

20.1

203.3

136

4,9

50

1,3

50

58,0

00

RB

11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

Cob

err

a

656

2

199

3

26 M

W

25,9

30

9 4

15

29.4

%

20.8

208.7

136

4,8

00

1,4

04

58,0

00

RB

11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

RB

21

1 6

556

199

2

26 M

W

26,0

20

710

0

34.6

%

20.1

203

136

4,9

50

910

50,0

00

29. 8 1

3

14 R

B11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

RB

21

1 6

562

199

3

29 M

W

28,5

00

670

5

36.7

%

20.8

209

136

4,8

00

917

50,0

00

30. 1 1

3

14 R

B11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

RB

21

1-6

562

DLE

199

3

28 M

W

275

20

670

5

36.3

%

20.8

202

136

480

0

932

580

00

RB

11 -

24G

T

Ga

s G

en

era

tor

- S

team

inje

ction

Rolls

Ro

yce

RB

21

1-6

762

DLE

199

9

30 M

W

295

00

656

5

37.7

%

21.5

211

140

480

0

920

570

00

RB

11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

RB

21

1-6

761

DLE

200

0

32 M

W

321

20

629

0

39.3

%

21.5

208

154

485

0

938

570

00

RB

11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

Tre

nt

60

IDLE

199

6

52 M

W

516

85

8 1

38

41.9

%

34

341

152

360

0

825

286

59

8

RB

11 -

24G

T

Gas G

enera

tor

Rolls

Ro

yce

Tre

nt

60

WL

E

200

1

58 M

W

580

00

8 3

46

40.9

%

36

365

159

300

0

794

286

59

8

RB

11 -

24G

T

Ga

s G

en

era

tor

- W

ate

r in

jecte

d

Sie

me

ns

Torn

ado

198

1

7 M

W

664

0

107

60

31.0

%

11.3

60.6

110

110

53

860

121

25

3

37 1

1

8 A

lsto

m -

EG

T

Sie

me

ns

Typh

oo

n

5 M

W

485

0

102

73

31.0

%

14

43.2

112

173

84

954

745

15

27

8

11 A

lsto

m -

EG

T

Sie

me

ns

SG

T-1

00

198

9

4 M

W

435

0

113

70

30.0

%

13.0

39.0

112

165

00

981

781

75

33

8

11 T

yph

oo

n 4

.35

Sie

me

ns

SG

T-1

00

198

9

5 M

W

470

0

113

09

30.2

%

14.1

42.0

112

173

84

975

781

75

33

8

11 T

yph

oo

n 4

.70

Sie

me

ns

SG

T-1

00

199

7

5 M

W

505

0

112

94

30.2

%

14.3

43.0

117

173

84

101

5

781

75

33

8

11 T

yph

oo

n 5

.05

Sie

me

ns

SG

T-1

00

199

8

5 M

W

525

0

112

03

30.5

%

14.8

46.0

114

173

84

986

781

75

33

8

11 T

yph

oo

n 5

.25

Sie

me

ns

SG

T-2

00

198

1

7 M

W

675

0

108

24

31.5

%

12.3

65.0

104

110

53

871

124

00

0

41

8

11 T

orn

ado

A5

-4

Ma

nu

fac

ture

r M

od

el

Ye

ar

ISO

IS

O B

ase

Bas

e

Ra

tin

g

Ra

tin

g

Heat

Eff

icie

ncy P

ressu

re

Flo

w

Sp

ec

ific

T

urb

ine

E

xh

au

st

Ap

pro

x

Ap

pro

xim

ate

Co

mm

en

ts

Rate

R

ati

o

Po

wer

Sp

ee

d

Te

mp

W

eig

ht

Dim

en

sio

ns

(f

t)

MW

kW

B

tu/k

Wh

%

(lb/s

ec)

kW

/lb

rpm

°F

lb

L

W

H

1st

year

600

0h p

er

Low

er

Heating V

alu

e

A

t base

Per

lb o

f O

utp

ut

unit

year

or

(LH

V)

loa

d

air p

er

sh

aft

availa

ble

m

ore

second

Sie

me

ns

SG

T-3

00

199

5

8 M

W

790

0

109

37

31.2

%

13.8

66.0

120

140

10

999

126

00

0

40

8

12 T

em

pest

Sie

me

ns

SG

T-4

00

199

7

13 M

W

129

00

981

7

34.8

%

16.9

87.0

148

950

0

103

1

165

00

0

61

9

13 C

yclo

ne

Sie

me

ns

SG

T-5

00

196

8

17 M

W

170

00

106

00

32.2

%

12.0

203.5

84

300

0/

360

0

707

331

00

0

68 1

6

13 G

T35 C

Sie

me

ns

SG

T-6

00

198

1

25 M

W

247

70

998

5

34.2

%

14.0

177.3

140

770

0

100

9

335

00

0 1

68 1

5

17 G

T10 B

Sie

me

ns

SG

T-7

00

199

9

29 M

W

290

60

948

0

36.0

%

18.0

201.0

145

650

0

964

353

00

0

68 1

5 1

8

GT

10 C

Sie

me

ns

SG

T-8

00

199

8

45 M

W

450

00

921

5

37.0

%

19.3

287.0

157

660

0

100

1

379

00

0

56 1

5

13 G

TX

10

0

Sie

me

ns

SG

T-9

00

198

2

50 M

W

495

00

104

50

32.7

%

15.3

386.0

128

542

5

957

276

00

0

50 1

2

14

Sola

r S

atu

rn 2

0

198

5

1 M

W

120

0

140

25

24.3

%

6.8

14.4

83

225

16

940

198

00

20

6

7

Sola

r S

atu

rn 2

0

GS

198

4

1 M

W

121

0

140

25

24.3

%

6.8

14.4

83

225

16

940

220

00

18

6

7

Sola

r C

enta

ur

40

GS

199

2

4 M

W

351

5

122

40

27.9

%

9.8

41.0

84

149

50

820

523

70

29

8

7

Sola

r C

enta

ur

50

GS

199

3

5 M

W

460

0

122

70

29.3

%

10.6

41.6

109

149

50

510

270

80

18

8

9

Sola

r T

auru

s 6

0

GS

199

2

6 M

W

550

0

112

20

31.5

%

11.5

48.3

118

149

51

950

671

40

29

8

7

Sola

r T

auru

s 6

5

200

5

6 M

W

600

0

103

75

32.9

%

15.0

43.2

139

149

50

101

7

727

00

32

8

10

Sola

r T

auru

s 7

0

199

4

8 M

W

752

0

101

00

33.8

%

16.1

59.4

127

152

00

905

110

92

3

34

9

11

Sola

r M

ars

90 G

S

199

4

9 M

W

945

0

107

10

31.9

%

16.1

88.5

107

870

149

00

0

48

9

12

Sola

r M

ars

100 G

S

199

4

11 M

W

106

95

105

15

33.0

%

17.4

91.7

116

111

68

905

137

75

0

48 1

0

12

Sola

r T

itan 1

30 G

S

199

8

15 M

W

150

00

969

5

35.2

%

15.0

109.8

137

111

70

925

147

59

9

46 1

0

11

Oth

er

KG

2-3

C

196

8

1 M

W

149

9

212

02

16.1

%

3.9

28.2

53

180

00

rpm

105

8

363

75

21

7

9

Oth

er

KG

2-3

E

198

9

2 M

W

189

5

204

21

16.7

%

4.7

33.0

57

188

00

rpm

102

0

385

80

21

7

9

Oth

er

DR

60G

199

0

14 M

W

137

75

975

2

35.0

%

21.5

104.0

132 700

0 r

pm

102

0

227

07

5

42 1

2

11

Oth

er

DR

61

198

6

22 M

W

223

02

942

2

36.2

%

18.1

150.0

149 550

0 r

pm

986

352

73

5

49 1

3

18

Oth

er

DR

61 G

197

3

24 M

W

238

73

989

37.6

%

18.4

153.0

156 360

0 r

pm

992

308

64

5

48 1

2

18

A5

-5

Ma

nu

fac

ture

r M

od

el

Ye

ar

ISO

IS

O B

ase

Bas

e

Ra

tin

g

Ra

tin

g

Heat

Eff

icie

ncy P

ressu

re

Flo

w

Sp

ec

ific

T

urb

ine

E

xh

au

st

Ap

pro

x

Ap

pro

xim

ate

Co

mm

en

ts

Rate

R

ati

o

Po

wer

Sp

ee

d

Te

mp

W

eig

ht

Dim

en

sio

ns

(f

t)

MW

kW

B

tu/k

Wh

%

(lb/s

ec)

kW

/lb

rpm

°F

lb

L

W

H

1st

year

600

0h p

er

Low

er

Heating V

alu

e

A

t base

Per

lb o

f O

utp

ut

unit

year

or

(LH

V)

loa

d

air p

er

sh

aft

availa

ble

m

ore

second

Oth

er

DR

61 G

P

(SA

C)

199

8

31 M

W

313

80

863

8

39.5

%

22.8

192.0

163 360

0 r

pm

959

352

73

5

48 1

2

18

Oth

er

Vectr

a-4

0G

199

8

31 M

W

313

80

841

6

40.6

%

22.8

186.0

169 620

0 r

pm

955

352

73

5

48 1

4

18

Oth

er

DR

63G

199

2

43 M

W

429

84

824

5

41.4

%

29.6

282.0

152 360

0 r

pm

824

485

01

0

60 1

4

23

Oth

er

ST

18

199

5

2 M

W

196

1

112

37

3.0

.4%

14

17.6

111

189

00

990

772

5

2

3

Co

nve

rsio

n F

ac

tors

ºC =

(ºF

-32

) /1

.8

lb x

0.4

54

= k

g

lb/h

ph

x 0

.60

8 =

kg

/kW

h

ºF =

(ºC

x 1

.8)

+3

2

kg

x 2

.20

5 =

lb

k

g/k

Wh

x 1

.64

4 =

lb

/hp

h

kW

x 1

.34

1 =

hp

B

tu x

1.0

55

= k

J h

ph

x 2

.68

5 =

MJ

hp

x 0

.74

6 =

kW

k

J x

0.9

48

= B

tu

MJ

x 0

.37

3 =

hp

h

1 k

Wh

=8

59

.8 k

cal

= 3

41

3 B

tu

Btu

/lb

x 2

.32

6 =

kJ/

kg

J

x 0

.23

9 =

cal

ori

e 1

hp

-hr

= o

.74

6 k

Wh

= 2

54

5 B

tu

kJ/

kg

x 0

.43

0 =

Btu

/lb

ca

lori

e x

0.2

39

= J

So

urc

e S

upp

lier

info

rma

tio

n a

nd

20

05

GT

W T

urb

ine S

pe

cific

ations

A5

-6

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� Rotorsx� Bladesx� Stator vanesx� Discsx� Casingx� Rotor shaftx� 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 two-stage, 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 horse-power 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