Fluids Spec 65-0027 Issue6 07 01 13

FLUIDS SPECIFICATION REPORT 65/0027 Pete Martin Product Development Issue 6 07/01/13

This documentation and any information or descriptive matter set out hereon are the confidential and copyright property of Siemens Industrial Turbomachinery Ltd and must not be disclosed, loaned, copied or used for manufacturing, tendering or for any other purpose without their written consent.

Title Fluids Specification for Air, Fuel, Lubricating Oil, Water and Steam for Siemens Industrial Turbomachinery Ltd’s range of Industrial Gas Turbines

Report by Pete Martin

AUTHOR APPROVED P. Martin G. Milner Compressors and Rotors P. Walker Metallurgical Laboratory CHECKED G. Davies Fluid Systems J. May P. Box Turbines J. May Combustion J. Henderson R. Wells Legal Compressors Specialist

M. Hughes Mechanical Integrity

ISSUE DATE PAGES ALTERATION CHECKED 1 1.12.96 ALL None See issue 1 2 14.4.00 ALL Yes See issue 2

3 20.10.00 sections 3, 4 & appendices.

Added kerosene, LPG, Naphtha, Low CV, Med CV & High CV gases

See issue 3

4 25.4.01 section 6.4.3 section 7.3.5

Antifreeze changed for new water wash system 1 ppm sulphur limit specified for injection water

See issue 4

5 24.12.06 sections 1, 3, 4 & A3

Revised contaminant limits all sources, air and fuels. Ash sticking temperature added for liquid

fuels. Revised limits for transient variation of Cv.

See issue 5

6 20.02.12 sections 1,2, 3, 4, 5, 6, 7, 8, 9, 10,

A1 & A3

Statement to say gas fuels outside standard range are defined in 65/0127. Fuel contaminants - silica and SiO2 changed to silicon and levels changed appropriately. Gas fuel limits for C4-C10 hydrocarbon compounds added. Max temp of gas fuel increased to 120ºC. Min temp of 250ºC for low CV gas (3.1 - 4.7 MJ/m3) added. Instrument air std changed to ISO 8573.1:2010 [4:2:3] (from

See issue 6



[3.3.3]). Allowable contamination levels and allowable temperature range of instrument air added. Comment added "up to 5% H2S in the gas fuel can be considered for SGT300, but requires approval by Siemens Product Management" for gas fuel. SGT-400B added to table 3.4. Standards updated for diesel fuels, limits added for halogens, Mg, Li, Al. Particulate matter for diesel reduced to 10(max) [mg/kg]2. Diesel pour point added, cloud point temp reduced, total acidity added. Ash sticking temperature requirement removed for all liquid fuels. Limits for Al, Li, Si, halogens added to naphtha and LPG. Comment added to use latest standard (some stds added). Kerosene stds added and one std changed. Lube oil stds changed, i.e. BS 489:1983 and BS 489:1999 removed, BS ISO 8068 added. Comment added to not mix grades of lube oil. Corrosion prevention std updated. Open cup flash point of lube oil added, closed cup flash point of lube oil set at 195ºC for all viscosities. Max water, and lead content in lube oil added, filterability requirements added, time for total acid number changed, copper corrosion changed, cleanliness at delivery changed. Comment added to state spec must be met even after oil has been stored. Statement added to say no liquid is allowed in the gas fuel. Limit of 0.5ppmm and 2ppmm contamination of gas from lube oil from gas fuel compressor added for DLE and conventional burner systems respectively. Statement added to say gas must be maintained at least 20ºC above dew points for sufficient time prior to the turbine skid edge to allow liquids to evaporate. Section on cooling liquids added. Some parts have been re-written for clarification and some fluid/gas properties/contaminants testing stds have been updated/changed



Contents Section 1 Introduction ................................................................................................................................................................8

1.1 Responsibility ..............................................................................................................................................................8 1.2 Applicability ................................................................................................................................................................8 1.3 System Integrity...........................................................................................................................................................9 1.4 Relevant Standards ......................................................................................................................................................9 1.5 Contamination Limits ..................................................................................................................................................9

Section 2 Air.............................................................................................................................................................................11 2.1 Applicable Standard ..................................................................................................................................................11 2.2 Combustion Air .........................................................................................................................................................11 2.3 Inlet Air Temperature ................................................................................................................................................12 2.4 Instrument Air............................................................................................................................................................13

2.4.1 Contamination and humidity ............................................................................................................................13 2.4.2 Temperature .....................................................................................................................................................13

Section 3 Gas Fuel....................................................................................................................................................................14 3.1 Acceptable Gas Fuels ................................................................................................................................................14

3.1.1 General.............................................................................................................................................................14 3.1.2 Wobbe Range Expansion .................................................................................................................................16 3.1.3 High Hydrogen Gases ......................................................................................................................................16 3.1.4 Higher Hydrocarbon Content ...........................................................................................................................16

3.2 Emissions...................................................................................................................................................................16 3.3 Contaminant Limits for Gas Fuel...............................................................................................................................17

3.3.1 Liquid Content in Gas Fuel ..............................................................................................................................17 3.3.2 Gas Compressor Lubricating Oil Content ........................................................................................................17 3.3.3 Solid Particles ..................................................................................................................................................17 3.3.4 Sulphur and Hydrogen Sulphide ......................................................................................................................17 3.3.5 Water................................................................................................................................................................20 3.3.6 Fuel Analysis....................................................................................................................................................20

3.4 Temperature...............................................................................................................................................................20 3.5 Variation in Net Calorific Value and Wobbe Index of Gas Fuel ...............................................................................20 3.6 Gases with Calorific Value Outside the Standard Range...........................................................................................20

3.6.1 Low CV Gases (Wobbe 3.1- 4.7 MJ/m3) .........................................................................................................21 3.6.1.1 Starting.............................................................................................................................................................21 3.6.1.2 Contamination limits of Low CV gases............................................................................................................21 3.6.1.3 Tars ..................................................................................................................................................................21 3.6.1.4 NH3 and HCN..................................................................................................................................................22 3.6.1.5 Dew Point.........................................................................................................................................................22 3.6.1.6 Hydrogen content of Low CV gas....................................................................................................................22 3.6.1.7 Supply Temperature of Low CV gas................................................................................................................22 3.6.2 Medium CV Gases (Wobbe 15 - 37 MJ/m3) ....................................................................................................23 3.6.2.1 Starting.............................................................................................................................................................23 3.6.2.2 Contaminants of Medium CV gas ....................................................................................................................23 3.6.2.3 Tars ..................................................................................................................................................................23 3.6.2.4 Dioxins and Furans ..........................................................................................................................................23 3.6.2.5 Dew Point.........................................................................................................................................................24 3.6.2.6 Hydrogen content of Medium CV gas derived from organic material. ............................................................24 3.6.3 High CV gases (Wobbe 49 - 67 MJ/m3) ..........................................................................................................24 3.6.3.1 Well Head Gases..............................................................................................................................................24 3.6.3.2 LPG..................................................................................................................................................................24

Section 4 Liquid Fuels..............................................................................................................................................................26 4.0 Applicable Standards.................................................................................................................................................26 4.1 Requirements.............................................................................................................................................................26

4.1.1 Contaminants ...................................................................................................................................................26



4.1.2 General.............................................................................................................................................................26 4.1.3 Sulphur.............................................................................................................................................................27

4.2 Nitrogen.....................................................................................................................................................................27 4.3 Emissions...................................................................................................................................................................27 4.4 Diesel Fuels ...............................................................................................................................................................28 4.5 LPG as liquid.............................................................................................................................................................30 4.5 LPG as liquid.............................................................................................................................................................30 4.6 Naphtha .....................................................................................................................................................................32 4.7 Kerosene....................................................................................................................................................................34

Section 5 Lubrication Oil..........................................................................................................................................................36 5.0 Applicable Standards.................................................................................................................................................36 5.1 Introduction ...............................................................................................................................................................36 5.2 Requirements.............................................................................................................................................................36

5.2.1 General.............................................................................................................................................................36 5.2.2 Additives..........................................................................................................................................................36 5.2.3 Mixing Oils of Different Grades, Types or from Different Manufacturers ......................................................36 5.2.4 Notification of Changes to Formulation...........................................................................................................36 5.2.5 Viscosity ..........................................................................................................................................................37 5.2.6 Viscosity Index Improvers ...............................................................................................................................37 5.2.7 Corrosion Prevention .......................................................................................................................................37 5.2.8 FZG Index (Forschungssteelle für Zahnräder und Getriebebau)......................................................................37 5.2.9 Preservation .....................................................................................................................................................37 5.2.10 Service Life......................................................................................................................................................37 5.2.11 Non-standard Ancillaries .................................................................................................................................37

5.3 Siemens Industrial Turbomachinery Ltd Lubricating Oil Specification ....................................................................37 5.4 BS ISO 8068 Specification for lubricating oils for turbines......................................................................................37

Section 6 Compressor Washing Water And Cleaning Fluids ...................................................................................................40 6.1 Introduction ...............................................................................................................................................................40 6.2 Washing Water ..........................................................................................................................................................40

6.2.1 General.............................................................................................................................................................40 6.2.2 Dissolved Solids...............................................................................................................................................40 6.2.3 Silica ................................................................................................................................................................40 6.2.4 Acidity..............................................................................................................................................................40 6.2.5 Electrical Conductivity.....................................................................................................................................40

6.3 Cleaning Fluid ...........................................................................................................................................................40 6.3.1 Definition .........................................................................................................................................................40 6.3.2 Requirements ...................................................................................................................................................40 6.3.3 Health And Safety Recommendations..............................................................................................................40 6.3.4 Approved Cleaning Fluids ...............................................................................................................................41

6.4 Cleaning Solution ......................................................................................................................................................41 6.4.1 Definition .........................................................................................................................................................41 6.4.2 Requirements ...................................................................................................................................................41 6.4.3 Antifreeze.........................................................................................................................................................41

Section 7 Injection Water .........................................................................................................................................................43 7.1 Introduction ...............................................................................................................................................................43 7.2 Temperature and Pressure .........................................................................................................................................43 7.3 Requirements.............................................................................................................................................................43

7.3.1 General.............................................................................................................................................................43 7.3.2 Total Solids-Concentration Limit.....................................................................................................................43 7.3.3 Un-dissolved Solids - Size limit......................................................................................................................43 7.3.4 Total Dissolved Solids .....................................................................................................................................43 7.3.5 Specific Solids .................................................................................................................................................45 7.3.6 Acidity..............................................................................................................................................................45 7.3.7 Electrical Conductivity.....................................................................................................................................45

Section 8 Evaporative Cooling Water ......................................................................................................................................46



8.1 Introduction ...............................................................................................................................................................46 8.2 Requirements.............................................................................................................................................................46 8.3 Water Carryover ........................................................................................................................................................46

Section 9 Injection Steam.........................................................................................................................................................47 9.1 Introduction ...............................................................................................................................................................47 9.2 Steam Quality Requirements .....................................................................................................................................47

9.2.1 General.............................................................................................................................................................47 9.2.2 Steam Pressure .................................................................................................................................................48 9.2.3 Steam Temperature ..........................................................................................................................................48

9.3 Steam Purity Requirements........................................................................................................................................49 9.3.1 Total Solids......................................................................................................................................................49 9.3.2 Total Dissolved Solids (TDS)..........................................................................................................................49 9.3.3 Specific Solids .................................................................................................................................................50 9.3.4 Total Dissolved Solids Monitoring by Conductivity Measurement .................................................................50 9.3.5 General Steam Purity .......................................................................................................................................51 9.3.6 Boiler Water Total Dissolved Solids ...............................................................................................................51

Section 10 Cooling Liquids................................................................................................................................................52 Appendix A1 Contaminants ...................................................................................................................................................53

A1.1 Comments on Contaminants .....................................................................................................................................53 A1.1.1 Vanadium.........................................................................................................................................................53 A1.1.2 Sodium and Potassium.....................................................................................................................................53 A1.1.3 Calcium and Magnesium..................................................................................................................................53 A1.1.4 Lead .................................................................................................................................................................53 A1.1.5 Zinc ..................................................................................................................................................................53 A1.1.6 Mercury............................................................................................................................................................53 A1.1.7 Sulphur.............................................................................................................................................................53 A1.1.8 Lithium.............................................................................................................................................................54 A1.1.9 Chlorine, Fluorine and other Halogens ............................................................................................................54 A1.1.10 Silicon/Silica/Siloxanes....................................................................................................................................54 A1.1.11 Ash...................................................................................................................................................................54 A1.1.12 Other Trace Metals ..........................................................................................................................................54 A1.1.13 Contaminants not listed above .........................................................................................................................54

A1.2 Contaminant Levels on a Customer Fuel Equivalent Basis .......................................................................................55 A1.2.1 Calculation Method for Contaminant Levels on a Customer Fuel Equivalent Basis........................................55 A1.2.2 Calculation of Contaminant Limit based on Customer’s Fuel CV ...................................................................56

Appendix A2 Gas Fuels..........................................................................................................................................................57 A2.1 Calorific Value & Wobbe Index................................................................................................................................57 A2.2 H2S Limit for Customer’s Fuel on a Fuel Equivalent Basis.......................................................................................59 A2.3 Pressure .....................................................................................................................................................................59

Appendix A3 Liquid Fuels .....................................................................................................................................................60 A3.1 Properties of Liquid Fuel and Significance of Parameters.........................................................................................60

A3.1.1 Viscosity ..........................................................................................................................................................60 A3.1.2 Carbon Residue................................................................................................................................................60 A3.1.3 Distillation Recovery .......................................................................................................................................60 A3.1.4 Flash Point .......................................................................................................................................................60 A3.1.5 Water................................................................................................................................................................60 A3.1.6 Particulate Matter.............................................................................................................................................61 A3.1.7 Total Ash..........................................................................................................................................................61 A3.1.8 Metallic Ashes..................................................................................................................................................61 A3.1.9 Sulphur.............................................................................................................................................................61 A3.1.10 Copper Strip corrosion.....................................................................................................................................61 A3.1.11 Cold Filter Plugging Point ...............................................................................................................................61 A3.1.12 Cloud Point ......................................................................................................................................................62 A3.1.13 Pour Point ........................................................................................................................................................62 A3.1.14 Density .............................................................................................................................................................62



A3.1.15 Oxidation Stability ...........................................................................................................................................62 A3.1.16 Vapour Pressure...............................................................................................................................................62 A3.1.17 Supply Temperature.........................................................................................................................................62 A3.1.18 Fuel Handling Requirements............................................................................................................................62

A3.2 International Diesel Fuel Specifications ....................................................................................................................63 Appendix A4 LPG and Naphtha fuels ....................................................................................................................................64

A4.1 General ......................................................................................................................................................................64 A4.1.1 Liquid Petroleum Gas Fuel ..............................................................................................................................64 A4.1.2 Naphtha Fuel....................................................................................................................................................64

A4.2 Significance of Parameters and Required Limits.......................................................................................................64 A4.2.1 Composition.....................................................................................................................................................64

A4.3 LPG and Naphtha - Supply Conditions ....................................................................................................................67 A4.3.1 Gaseous LPG ...................................................................................................................................................67 A4.3.2 LPG and Naphtha - Handling and Storage.......................................................................................................67

A4.4 Fuel Supply Quality Control Procedure.....................................................................................................................67



List of Tables Table 1.1 The Company’s engines .....................................................................................................................................8 Table 1.2 Siemens Industrial Turbomachinery Ltd total allowable contamination limits ................................................10 Table 2.1 Siemens Industrial Turbomachinery Ltd combustion air contamination limits ................................................12 Table 2.2 Instrument Air Quality .....................................................................................................................................13 Table 3.1 Gas Properties for gas of Wobbe Index 15-67 MJ/m3......................................................................................15 Table 3.2 Gas Properties for gas of Wobbe Index 3.1-4.7 MJ/m3....................................................................................15 Table 3.3 Limit of higher hydrocarbon species in gas fuel ..............................................................................................16 Table 3.4 H2S in gas fuel limits for Siemens Industrial Turbomachinery Ltd engines.....................................................19 Table 3.5 Classification of Non Standard Gases..............................................................................................................21 Table 3.6 Contaminant Limits of Low CV gases .............................................................................................................22 Table 3.7 Siemens Industrial Turbomachinery Ltd Fuel Specification for Gaseous LPG Options ..................................25 Table 4.1 Siemens Industrial Turbomachinery Ltd Diesel Fuel Specification .................................................................28 Table 4.2 The Company’s Fuel Specification for LPG used as Liquid ............................................................................31 Table 4.3 The Company’s Fuel Specification for Naphtha System Options ....................................................................33 Table 4.4 The Company’s Kerosene Specification for Standard Burners ........................................................................34 Table 4.5 The Company’s Kerosene Specification for Low CV Gas Applications..........................................................35 Table 5.1 The Company’s Lubricating Oil Specification.................................................................................................39 Table 6.1 Cleaning Solution Requirements......................................................................................................................41 Table 7.1 Particle Size Distribution .................................................................................................................................43 Table 7.2 Allowable Total Dissolved Solids....................................................................................................................44 Table 7.3 Allowable Specific Dissolved Solids ...............................................................................................................45 Table 9.1 Steam Pressure .................................................................................................................................................48 Table 9.2 Minimum Steam Temperature..........................................................................................................................48 Table 9.3 Allowable Total Dissolved Solids....................................................................................................................49 Table 9.4 Limits for Specific Dissolved Solids [ppmm] ..................................................................................................50 Table 9.5 Limits for Silica (SiO2) [ppmm].......................................................................................................................50 Table 9.6 Maximum Allowable Continuous Operating Conductivity Levels...................................................................50 Table 9.7 Conductivity Control Limits ............................................................................................................................51 Table A1.1 Full Load AFRs for The Company’s engines..................................................................................................56 Table A2.1 Constituent range for Natural Gas....................................................................................................................57 Table A3.1 Comparison of diesel Fuel Specifications ........................................................................................................63



Section 1 Introduction

1.1 Responsibility

It is the responsibility of the customer to ensure that where required by this specification Siemens Industrial Turbomachinery Ltd’s (the Company) approval has been sought for use of the fluid. It is also the responsibility of the customer to ensure on a continuing basis that all fluids entering the Company engines listed in section 1.2 below are compliant with this specification. If at any time a customer wishes to use a fluid which fails to fulfil any of the requirements of this specification, the Company must be consulted and its prior written approval given.

1.2 Applicability

This specification defines the conditions for all fluids used in the Company’s engines listed below. Limits are provided for contamination levels as well as properties such as viscosity and flash point and supply conditions. These limits and properties are set to avoid problems associated with fluids occurring within the design life of the engine. However, no liability is extended to conditions not covered in this specification. Equally the limits and properties referred to above do not preclude the raising of certain limits, where these have been requested and approved by the Company in writing. Notwithstanding the use of fluids as set out in and prescribed by this document the Company cannot ensure that the emissions thereby produced will satisfy the requirements of any environmental, health and safety or other legislation, regulations or guidance. The responsibility for complying with any such legislation, regulations or guidance lies with the customer. This specification is applicable to the following product range, known as the Company’s engines, but because of differences in their specification, not all fuels are available on all engines.

Engine Name Configuration

TA Twin Shaft TB Twin Shaft TD Single Shaft TE Single Shaft TF Single Shaft RH Hurricane Single Shaft SGT-100-1S Single Shaft SGT-100-2S Twin Shaft SGT-200-1S Single Shaft SGT-200-2S Twin Shaft SGT-300-1S Single Shaft SGT-300-2S Twin Shaft SGT-400A Twin Shaft SGT-400B Twin Shaft

Table 1.1 The Company’s engines



1.3 System Integrity

This specification covers all fluids entering the gas turbine. It is the customer’s responsibility to ensure that all pipe work and fittings are free of rust and debris. This is particularly applicable on commissioning and prolonged periods without use.

1.4 Relevant Standards

This company specification references standards from various organisations. Where these standards include reference to a particular year, then the company specification requires this standard to be adhered to. Where the year has not been quoted the standard has been included for reference, or the latest standard is to be applied.

1.5 Contamination Limits

This section details the maximum allowable contamination levels from all fluids that may be used in the Company’s engines. Explanations are provided, in the appendices, as to why each limit is set. A calculation procedure is given for determining the total level of contamination entering the engine.

An explanation of the significance of each contaminant is given in Appendix A1.1 Contamination can arise from the following sources:

• Air • Fuel, gas or liquid • Injection fluids, water or steam • Evaporative cooling water • Oil carry over from gas fuel compressors • Lubricating oil • Compressor cleaning solutions and rinse water

However, contamination by the engine lubricating oil is considered negligible due to the minimal amount of leakage past seals in a machine maintained to the Company’s recommended schedule. Similarly, contamination by cleaning solutions, using the Company’s approved reagents and rinsing water, is considered minimal due to the small volumes involved and the relative infrequency of the cleaning cycles. Hence these are not considered in the concentration table and calculations discussed below. However their composition is still controlled as detailed in the appropriate section. Table 1.2 details the maximum limit from ALL sources for each of the listed contaminants when calculated on the Company’s reference fuel equivalent basis . The limits for customer fuels within several ranges of net calorific value are also included in Table 1.2. More accurate limits for a precise net calorific value can be calculated if preferred. The reference fuel definition and the calculation involved are detailed in Appendix A1.2.2. There may be other additional more stringent limits for EACH fluid as detailed in the appropriate section. This may be due to systems or other requirements as necessary to protect the engines or ancillaries. The omission of a given contaminant from this specification does not constitute the Company’s authorisation of an unlimited level of this contaminant or its acceptance. All contaminants and their level must be declared to the Company as well as any changes in contaminant levels as a result of any changes of fluid.



Compliance with both the individual requirements of each fluid and the maximum aggregate amount from all sources as specified in Table 1.2 must be ensured at all times. The total level of each contaminant, from all sources must be calculated using the equation in Appendix A1.2.1, which provides a customer fuel equivalent level which has to be lower than the appropriate limit in Table 1.2.

[1] ppmm Parts per million by mass based on the fuel used [2] Sulphur in elemental form not allowed in gas fuel [3] 90% <5 µm 100% < 10 µm

Table 1.2 Siemens Industrial Turbomachinery Ltd total allowable contamination limits

from ALL sources on fuel equivalent basis

The Company reference fuel

Range of Net Calorific Value of Customer fuels

Net Calorific Value of fuel, MJ/kg 48.16 4-10 10-20 20-30 30-40 40-50 50-60 60-70 70-80

Maximum allowable concentration from ALL sources on fuel equivalent basis ppmm [ 1 ].

Where elements are referred to, the limits apply to the elements regardless of what

compound they are in, with the exception of sulphur as in note 2.

Vanadium, V 0.5 0.04 0.1 0.2 0.3 0.4 0.5 0.6 0.7

Sodium plus Potassium, Na+K 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Calcium plus Magnesium, Ca+Mg 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Lead, Pb 0.5 0.04 0.1 0.2 0.3 0.4 0.5 0.6 0.7

Zinc, Zn 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Mercury, Hg 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Sulphur, S [ 2 ] 10000 8000 2000 4000 6000 8000 10000 12000 14000

H2S (gas fuel only) see section 3.3.4 Lithium, Li 0.5 0.04 0.10 0.2 0.3 0.4 0.5 0.6 0.7

Other metals 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Silicon 0.02 0.002 0.004 0.008 0.012 0.016 0.021 0.025 0.029

Halogens, F+Cl+Br+I 1.0 0.08 0.2 0.4 0.6 0.8 1.0 1.2 1.4

Other non-combustibles including ash 100 8 20 41 62 83 103 124 145

Combustible solids [ 3 ] 3 0.25 0.62 1.25 1.87 2.49 3.00 3.7 4.4



Section 2 Air

2.1 Applicable Standard ISO 8573-1 2010 [4:2:3] Instrument Air Quality

2.2 Combustion Air In most conditions atmospheric air quality does not give rise to problems provided the air is drawn from a clean source and filtered correctly. Attention is brought to the fact that gas turbine emissions may be affected by the level of contaminants in the air (see section 3.2). It may be possible to operate engines in areas of extreme atmospheric pollution or contamination, provided that prior written approval is obtained from the Company by submission of a site air quality survey which must include a complete analysis of representative samples of the air as it will be supplied to the Company air filter inlet, covering the full range of contaminant concentrations and also including adequate information for specification of filters and other treatment as required. For satisfactory operation, the air entering the engine must meet the following requirements:

THE PARTICULATE CONTENT OF THE AIR ENTERING THE ENGINE AFTER FILTRATION MUST BE SUCH THAT THE CONTAMINANTS FROM ALL SOURCES DO NOT EXCEED THE LEVELS IN TABLE 2.1. For on shore average populated residential areas and light industrial complexes this can usually be achieved as follows:

a.1. The air must be drawn from as high above ground as is practicable to reduce the risk of contaminants entering the engine. Particulate loading decreases rapidly with height therefore most filtration systems are mounted above ground level.

a.2. A minimum of 98% by mass of all particles shall be arrested by the air filter. (ASHRAE 52/76 or BS EN 779) a.3. A minimum of 99.9% of particles sized 5 microns or greater shall be removed by the air filtration system. a.4. For saline applications such as marine environments the air filtration system shall not pass greater than 0.01ppmm (parts per million by mass) salt when tested using a 30 knot aerosol holding 3.6 ppmm salt (as per NGTE test, now Defence and Evaluation Research Agency). a.5. Free water must be prevented from entering the engine by selection of an appropriate system. The Company will be pleased to advise on a suitable system.



b. For heavy industrial sites or particularly dirty environments, with large amounts of fine dust in the air, the filter shall also meet BS 3928 (EUROVENT 4/4) efficiency (sodium flame efficiency > 99.97% (EU 12)).

c. Cases where it is possible that the air will not comply with the criteria listed in section 2.2 (a.1 to a.5) or exceeds any of the contaminant levels in Table 1.2, will constitute cases of extreme atmospheric pollution as referred to earlier in this section and must be notified to the Company at the earliest opportunity, and in any event before use of the engine. d. The maximum level of combustibles in the air entering the engine must be less than 5 ppmm. Therefore the entrainment of exhaust fumes, lubricant oil breathers and gas vents must be avoided. * ppmm Parts per million by mass ** Sulphur in elemental form is not allowed *** ppmv Parts per million by volume **** 90% <5 µm 100% < 10 µm

Table 2.1 Siemens Industrial Turbomachinery Ltd combustion air contamination limits

2.3 Inlet Air Temperature

The inlet air temperature range for normal operation of a given Company engine is as specified in the contract. Where icing conditions prevail the necessary precautions, to be determined by the Company at the enquiry stage, must be taken to prevent its formation in the intake system as this may result in damage to the gas turbine.

ppmm*

(unless otherwise stated)

Vanadium, V 0.0075

Sodium plus Potassium, Na+K 0.009

Calcium plus Magnesium, Ca+Mg 0.015

Lead, Pb 0.0075

Zinc, Zn 0.015

Mercury, Hg 0.015

Sulphur, S ** 45

H2S (gas fuel only) ppmv*** 44

Lithium, Li 0.0075

Other metals 0.015

Silicon 0.0003

Halogens, F+Cl+Br+I 0.015

Other non-combustibles including ash 1.5

Combustible solids **** 0.045



2.4 Instrument Air

2.4.1 Contamination and humidity

The instrument air must be to the quality requirements set out in ISO 8573-1:2010 [4:2:3] (see section 6.1 of ISO 8573-1 2010 for terminology) and Table 2.2. The air must be delivered at conditions specified by the Company.

Quality class

Maximum number of

particles of size 1.0-5.0 µm

per m3

Humidity (water)

pressure dew point

maximum at 1 bar a

(oC)

Oil

(aerosol, liquid and vapour)

maximum

mg/m3

[4:2:3]

10000

- 40

1

from Air Contamination Classifications ISO 8573-1 2010

Table 2.2 Instrument Air Quality

The instrument air must also satisfy the contamination limits specified in section 2.2

2.4.2 Temperature

The maximum allowed temperature of the instrument air is 65ºC. The minimum allowed temperature of the instrument air is -20ºC.



Section 3 Gas Fuel

3.1 Acceptable Gas Fuels

3.1.1 General Most types of gaseous fuel may be burned including pipeline natural gas, various process gases, high calorific value gases such as refinery gas, well head gas, liquid petroleum gas (LPG) and also gases with medium and low calorific values such as landfill gas and biogas produced from the degradation of organic material. The Company must in all cases have granted its prior written approval in respect of the gas fuel to be used.

For satisfactory operation the fuel must meet the criteria in Table 3.1 for gases of Wobbe Index 15-67 MJ/m3 or Table 3.2 for gases of Wobbe Index 3.1-4.7MJ/m3 together with all other relevant parts of this document. If at any time a gas fails to fulfil any of the relevant requirements of this specification it will no longer be acceptable. If at any time a customer wishes to use a fuel which fails to fulfil any of the requirements of this specification, the Company must be consulted and its prior written approval given.

It is the customer’s responsibility to ensure, on a continuing basis, that the gas fuel used from time to time, complies with all relevant parts of this specification document. FAILURE TO COMPLY MAY RESULT IN SERIOUS PHYSICAL DAMAGE TO THE CUSTOMERS EQUIPMENT AND INJURY TO PERSONNEL.



PROPERTY RANGE/VALUE COMMENT

Wobbe Index at gas supply temperature

15-67 MJ/m3

As defined in Appendix A2.1

Special restrictions & criteria apply for values outside the range 37-49 MJ/m3 (see section 3.6)

Gas supply temperature

minimum 20ºC above the dew point at supply pressure.

Must be maintained up to the Siemens skid edge

Max gas supply temperature*

120ºC

120ºC is limit of fuel system electrical component

Min gas supply temperature*

2.5ºC 2.5ºC limit is to avoid vent freezing

* These gas temperature limits do not apply to the TA, TB, TD, TE, TF, RH Hurricane engines. For these engines other limits apply.

Table 3.1 Gas Properties for gas of Wobbe Index 15-67 MJ/m 3

PROPERTY RANGE/VALUE COMMENT

Wobbe Index at gas supply temperature

3.1 – 4.7 MJ/m3

As defined in Appendix A2.1

Special restrictions & criteria apply for values outside the range 37-49 MJ/m3 (see section 3.6)

Gas supply temperature

minimum 20 ºC above the dew point at supply pressure.

Must be maintained up to the Siemens skid edge

Max gas supply temperature*

400 ºC

Gas fuel temperatures of greater than 120ºC supply require a different gas fuel system than for cooler gas fuel supplies

Min gas supply temperature*

250 ºC

* These gas temperature limits do not apply to the TA, TB, TD, TE, TF, RH Hurricane engines. For these engines other limits apply.

Table 3.2 Gas Properties for gas of Wobbe Index 3.1-4.7 MJ/m 3



3.1.2 Wobbe Range Expansion Gases with a Wobbe Index within the standard range of 37 - 49 MJ/m3 can be burnt in all engines subject to meeting relevant specifications and requirements, and in particular subject to the requirements in section 3.1. The release status of products and ratings for gas fuels outside this standard range are defined in the Company’s Product Availability Matrix, 65/0127. Requests to operate on non-standard fuels must be notified to the Company at the earliest opportunity, and in any event before use of the engine. Gases outside the standard range will be subject to special considerations and restrictions as detailed in section 3.6.

3.1.3 High Hydrogen Gases A mixture of methane and up to 5% hydrogen by volume is acceptable for use in DLE combustion systems. For diffusion flame combustion up to 13% hydrogen by volume in methane is acceptable. Higher levels of hydrogen or mixtures containing significant levels of other combustible gases must be referred to the Company. Other restrictions may apply to the hydrogen content for gases outside the standard range of Wobbe Index (37-49 MJ/m3).

3.1.4 Higher Hydrocarbon Content Where a gas contains hydrocarbon gases heavier than methane in greater levels than the values in Table 3.3, this must be referred to product management for consideration. Note that whatever the gas composition there must be no liquid, and the gas must have at least 20ºC superheat, as specified in section 3.3.1.

No. of C atoms % by volC4 5.0C5 1.5C6 0.45C7 0.25C8 0.05C9 0.01C10 0.005

Table 3.3 Limit of higher hydrocarbon species in gas fuel

3.2 Emissions

Compliance with this specification, including any written approval granted by the Company pursuant to its terms, does not guarantee that exhaust emissions will comply with any regulations. In order to determine the expected emissions or provide a guarantee it is essential that the Company is provided with a full and accurate analysis of the gas. It should also be noted that gas turbine emissions may be affected by the level of contaminants in the air. Any emissions guarantees will be in respect of the given increase over the background levels already present in the site ambient air.

3.3 Contaminant Limits for Gas Fuel



The contaminant limits specified in Table 1.2 are the maximum aggregate levels from all sources including gaseous fuels. They apply to all gaseous fuels used in the Company’s engines, and must not be exceeded without the Company’s prior written consent. If there is any conflict between the levels below and those in section 1.5 the lower levels will take precedence.

3.3.1 Liquid Content in Gas Fuel There must be no liquid in the gas fuel at the turbine skid edge. Suitable fuel treatment technology must be employed where gas quality cannot be assured to eliminate the possibility of contamination of the gas with liquid. An example of this would be to include a coalescer system. The gas must be supplied at the turbine skid edge at 20ºC above the hydrocarbon and water dew points at the gas supply pressure at the turbine skid edge. The fuel must be maintained at such conditions for sufficient time before the turbine skid edge such that there is no condensate in the fuel, i.e. such that any liquid droplets have had time to evaporate. This will avoid liquid slugs suddenly entering the gas turbine via the gas fuel system, which could result in damage to turbine components or over fuelling of the turbine.

3.3.2 Gas Compressor Lubricating Oil Content In cases where a fuel gas compressor is to be used, contamination by compressor lubricating oil or lubricating oil vapour is to be limited as follows:

For DLE configurations 0.5 ppmm maximum contamination of the gas is allowed For conventional diffusion flame burner configurations 2 ppmm maximum contamination of the gas is allowed.

These limits are the maximum allowable compressor lubricating oil in the gas fuel at any instance in time. It is not permitted to use a measurement approach whereby a quantity of compressor lubricating oil in any phase is averaged over a period of time to derive the contamination level in the gas fuel. It is required that vapour in the gas fuel does not accumulate into slugs of liquid under any circumstances. Liquid slugs suddenly entering the gas turbine via the gas fuel system could result in damage to turbine components or over fuelling of the turbine.

3.3.3 Solid Particles Additionally to avoid problems associated with deposition of small particles the following limits apply:

i) Total solid contaminants must not exceed a maximum of 20 ppmm. ii) It is required that 99%, measured on a mass basis, of the solid particle contaminants in (i) above, must be below 10 µm and none greater than 15 µm.

3.3.4 Sulphur and Hydrogen Sulphide Table 3.4 provides the Levels of H2S permitted in the Company’s reference fuel. These are dependent on the engine model and operating conditions. The allowable level of H2S in a customer gas fuel is dependent on its net calorific value. Table 3.4 also gives limits for customer fuels within several ranges of net calorific value. More accurate limits for a precise net calorific value can be calculated if preferred. The reference fuel definition and the calculations involved are detailed in Appendix A2.2. It is important to note that, whereas the aggregate limits in Table 1.2 are in mass terms and are referenced to mass based net calorific value, because the limits for H2S are expressed on a volume basis it is essential that net calorific values on a volume basis, MJ/Nm3, are used to extract the relevant value from Table 3.4 or to perform the calculations in Appendix A2.2.



Any other sulphur compounds, such as mercaptans, which are present in the gas, must be included as H2S in proportion to the amount of sulphur they contain. Furthermore if sulphur compounds are introduced into the engine in any other fluid, such as combustion air, their presence must be allowed for by calculation of a fuel equivalent concentration on a volume basis. However it is important to remember that elemental sulphur is not allowed (see appendix A1.1.7). The H2S limits for gas fuel provided by this section take priority over the sulphur limits given in Table1.2. Where the sulphur content of the fuel is above 0.1%wt (0.05%vol H2S) all fuel supply pipes from source to the combustor shall be stainless steel with good corrosion resistance such as AISI 304, 310, 316 or 321, to avoid corrosion products, such as iron sulphide, building up in supply lines.



Company Ref Fuel

Range of Net

Calorific Value of

Customer fuels

Net Calorific Value of fuel, MJ/(st)m3 34.795 4-10 10-20 20 - 30 30 - 40 40 - 50 50 - 60

Model Configuration Rating % H2S limit by volume

TA Twin Shaft ALL 3 0.34 0.86 1.72 2.58 3.44 4.31

TB 5000 Twin Shaft ALL 3 0.34 0.86 1.72 2.58 3.44 4.31

TD Single Shaft ALL 3 0.34 0.86 1.72 2.58 3.44 4.31

TE Single Shaft ALL 3 0.34 0.86 1.72 2.58 3.44 4.31

TF Single Shaft ALL 3 0.34 0.86 1.72 2.58 3.44 4.31

RH Hurricane Single Shaft 1.65 MW(e) 0.5 0.06 0.14 0.29 0.43 0.57 0.72

SGT-100-1S Single Shaft 4.35 MW(e) 0.5 0.06 0.14 0.29 0.43 0.57 0.72





SGT-100-2S Twin Shaft 4.85 MW(m) 0.5 0.06 0.14 0.29 0.43 0.57 0.72

SGT-100-2S Twin Shaft 5.4 MW 0.5 0.06 0.14 0.29 0.43 0.57 0.72

SGT-100-2S Twin Shaft 5.7 MW 0.5 0.06 0.14 0.29 0.43 0.57 0.72

SGT-200-1S Single Shaft 6.45 MW(e) 1 0.11 0.28 0.57 0.86 1.14 1.43

SGT-200-1S Single Shaft 6.75 MW(e) 1 0.11 0.28 0.57 0.86 1.14 1.43

SGT-200-2S Twin Shaft 6.84 MW(m) 1 0.11 0.28 0.57 0.86 1.14 1.43

SGT-200-2S Twin Shaft 7.68 MW(m) 1 0.11 0.28 0.57 0.86 1.14 1.43

SGT-300-1S Single Shaft 7.7 MW(e) 1 (see note) 0.11 0.28 0.57 0.86 1.14 1.43

SGT-300-2S Twin Shaft 8.2 MW 1 (see note) 0.11 0.28 0.57 0.86 1.14 1.43

SGT-400A Twin Shaft 12.9 MW(e) 0.5 0.06 0.14 0.29 0.43 0.57 0.72

SGT-400B Twin Shaft 14.4 MW(e) 0.5 N/A N/A N/A 0.43 0.57 N/A

Note Up to 5% H2S can be considered for SGT300, but requires approval by Siemens Product Management

Table 3.4 H 2S in gas fuel limits for Siemens Industrial Turbomachinery Ltd engines

Further reduction of the limits in Table 3.4 may be required to meet relevant emission regulations (see section 3.2). Conditions allowing the deposition of elemental sulphur from the gas fuel must be avoided (see appendix A1.1.7).

3.3.5 Water To avoid problems associated with slugs of water entering the gas turbine, it is recommended that the best available technology is employed to eliminate the possibility of contamination of the gas with water droplets.



To avoid problems arising from the formation of acids in the fuel system, no free water is allowed, i.e. the gas must not be saturated with water. To achieve this, the gas temperature must be at least 20ºC above the dew point, calculated for the gas composition including water vapour, at the supply pressure to the turbine skid. This is especially important where the gas has an appreciable amount of H2S or CO2 present. CO2 is particularly corrosive to the fuel system due to the formation of carbonic acid in the presence of free water. The actual supply temperature can be obtained by reference to the Company.

3.3.6 Fuel Analysis A complete representative sample fuel analysis, including contaminants, detailing properties of the fuel as it will be supplied to the turbine skid edge connection flange, must be submitted to the Company for prior written approval in all cases.

3.4 Temperature

In addition to the temperature limit set by the dew point, as referred to in sections 3.3.1 and 3.3.5, the gas must not be supplied at a temperature in excess of 120°C, to avoid problems with fuel system electrical components, or below 2.5°C to avoid free zing of vents (see table 3.1 and table 3.2). However, higher temperatures can be accommodated but require system modifications and consultation with and the prior written approval of the Company are necessary. The specific temperature requirements at skid edge are defined by the appropriate fuel system piping and instrumentation diagram. Note that for TA, TB type engines, a maximum temperature of 70°C applies, but a fully engineered option exists to accommodate temperatures up to 120°C with systems modifications. In all such cases the Company must be consulted and its prior written permission given.

3.5 Variation in Net Calorific Value and Wobbe Index of Gas Fuel

The expected variation in net calorific value (CV) and Wobbe Index must be submitted to the Company for approval. The Company’s typical gas turbine control system is designed to accept a maximum transient variation in Wobbe Index in MJ/(st)m3 during normal operation of 4%/minute. The control system is optimised for specific values of CV and relative density of the gas fuel. If the fuel deviates from either of these by more than 5%, the full operability of the engine may be lost. For example, full load may not be achievable. At start up the CV of the gas supplied must be within +/- 5% of the control value. If the CV is outside this range the start parameter will have to be reset.

3.6 Gases with Calorific Value Outside the Standard Range The capability exists to burn fuels outside the Standard Range of Wobbe Index 37-49 MJ/m3, such as those in Table 3.5. However specific combustion equipment is required and in all cases the Company’s prior written permission, as referred to earlier in this section, for the use of the proposed gas must be obtained. Gases with Wobbe Index outside the standard range must conform to all the requirements of sections 3.1 to 3.5, but are also subject to the special restrictions detailed below.



It will be necessary to provide the Company with a complete gas composition, expected variation of composition, and rate of change of composition, in order for an assessment of the fuel to be made. At the enquiry stage, the expected concentration of each contaminant, in the gas to be used, must be declared to the Company, as severe operational problems, reduction in turbine life or contravention of emissions regulations or other relevant legislation can occur. Sections 3.6.1, 3.6.2 and 3.6.3 contain preliminary estimates only.

Gas Examples Wobbe MJ/m3* LCV MJ/m3 LCV MJ/kg High Calorific Value Gaseous LPG

Well head gas 59 - 64 49 - 67

86 - 90 45 - 48

Medium Calorific Value Landfill gas Well head gas

13 - 19 25 - 37

13.5 - 19.0 10.2 - 16.0

Low Calorific Value Biogas 3.1 - 4.7 4.2 - 5.9 4.1 - 5.4

*Wobbe Index is calculated at the temperature at the point of entry to the burner.

Table 3.5 Classification of Non Standard Gases

3.6.1 Low CV Gases (Wobbe 3.1- 4.7 MJ/m3) This category includes gases produced by the gasification of organic material.

3.6.1.1 Starting A high quality kerosene, as specified in Table 4.5, is required for starting and a minimum load is required before changeover to the main fuel can take place. Details will be provided on application to the Company.

3.6.1.2 Contamination limits of Low CV gases The limits imposed by Table 1.2 will apply, but additional restrictions are imposed below. Low CV gases are generally produced by the gasification of biomass or fossil fuel and will contain various hydrocarbons and gaseous contaminants which are not normally present in more standard fuels. The number and concentration of these compounds will depend on the gasified material. It is therefore necessary that a full list, and the expected concentration of each compound in the gas to be used, must be declared on application to the Company for its prior written approval. The acceptable levels of some of the contaminants known to be present in biogas are shown in Table 3.6.

3.6.1.3 Tars The heavy hydrocarbons or tars present in the fuel must be limited to avoid carbon deposition or the formation of liquid slugs. In general, there are a large number of possible compounds and it is therefore necessary that the expected concentration, in the gas to be used, of each compound, must be declared to the Company at the enquiry stage. The acceptable levels of naphthalene and tars are shown in Table 3.6. The limit imposed on lubricating oil must also include those tars which are liquid at the gas supply conditions.



In cases where the gas fuel may contain polycyclic aromatic hydrocarbons which are known precursors to the production of dioxins and furans, in addition to the above restriction such precursors will not be allowed.

3.6.1.4 NH3 and HCN NH3 and HCN or other compounds containing nitrogen, will contribute to atmospheric pollution, in the form of NOx and their concentration may have to be controlled to comply with applicable regulations. In order to determine the expected emissions or provide a guarantee it is essential that the Company is provided with a full and accurate analysis of the gas.

Contaminant ppmm

Benzene 5500

Toulene 800

Xylene 800

Naphtalene 1600

Tars (plus liquid carry over) 2

NH3 + HCN see note 3.6.1.4

Table 3.6 Contaminant Limits of Low CV gases

3.6.1.5 Dew Point The minimum temperature at which the gas can be supplied to the gas turbine is 20ºC above the dew point, as defined in section 3.3.1, in addition to the other temperature requirements given in table 3.2. However as the variability in composition is greater for these gases than other gases, such as pipeline natural gas, it may be necessary in practice to set an additional safety margin so that the minimum temperature is maintained. Details will be provided on application to the Company for its prior written approval in respect of the gas to be used.

3.6.1.6 Hydrogen content of Low CV gas Low CV gases can contain various components, such that the increase in flame speed with hydrogen content may be different to that for methane. Gases containing hydrogen must be referred to the Company.

3.6.1.7 Supply Temperature of Low CV gas For low calorific value gases produced by the gasification of organic material, supply temperatures up to 400ºC are acceptable. Please refer these to the Company.

3.6.2 Medium CV Gases (Wobbe 15 - 37 MJ/m3) Various gases of CV in the range 15-37 MJ/m3 may also be considered, e.g. poor quality natural gas, sewage gas, landfill gas etc. These gases usually consist predominantly of paraffin hydrocarbons with an inert content of up to 50%, but carbon monoxide and hydrogen may also be present in significant amounts. The wide variety of possible gas compositions means that the Company’s prior written approval in respect of each gas to be used must be obtained.



The following special considerations will apply, but all other aspects of this Fluids Specification still apply to these gases.

3.6.2.1 Starting

In some cases a liquid fuel may be required for starting and a minimum load may be required before changeover to the main fuel can take place. Details will be provided on application to the Company.

3.6.2.2 Contaminants of Medium CV gas Some gases within this category may be contaminated by metals and other elements which are not normally found in natural gases. Only those contaminants which are listed in Table 1.2 are allowed. Other contaminants cannot be tolerated. Severe operational problems can be experienced with contaminants such as tar, naphthalene, amines and siloxanes. Other trace metals may form deposits whose presence can increase the oxidation rate of blade and vane alloys due to their attack on the protective oxide coating. Hence the intake of substances such as cadmium, antimony and other trace metals must be prohibited. Your attention is drawn to section A1.1.13 in the appendix.

3.6.2.3 Tars Many gasification processes will produce gases containing a wide range of aromatic hydrocarbons. Only those hydrocarbons which are known to be completely vaporised at the supply conditions to the turbine skid are allowed. This is to avoid the possibility of liquid slugs, having a high energy content causing excessive heat release rates in the gas turbine. Heavy hydrocarbons known as tars must be removed from the gas fuel. These tars are similar in behaviour to gas compressor lubricating oil and the sum of tars present in the fuel and contamination by lubricating oil, liquid and vapour, from any compressor used to compress gas is to be limited to a maximum of 2 ppmm in the gas. In cases where the gas fuel may contain polycyclic aromatic hydrocarbons which are known precursors to the production of dioxins and furans, in addition to the above restriction such precursors will not be allowed.

3.6.2.4 Dioxins and Furans Extremely stringent limits for dioxins and furans are set by environmental authorities. These compounds may be formed in gasification processes and already be part of the tars present in the gas. They may also be produced in the gas turbine, by the halogenation of polycyclic aromatic hydrocarbons which may be in the tar. Therefore any dioxins and furans present in the fuel gas must be removed before delivery to the gas turbine skid edge.

3.6.2.5 Dew Point The minimum temperature, at which the gas can be supplied to the gas turbine, is 20°C above the dew point, as defined in section 3.3.1, in addition to the other temperature requirements given in table 3.1. However as the variability in composition is greater for these gases than other gases, such as pipeline natural gas, it may be necessary in practice to set an additional safety margin so that the minimum temperature is maintained. Details will be provided at the tendering stage.



3.6.2.6 Hydrogen content of Medium CV gas derived from organic material. Medium CV gases can contain various components, such that the increase in flame speed with hydrogen content may be higher than that for methane described in section 3.1.3 and therefore must be notified to the Company at the earliest opportunity, and in any event before use of the engine, as it may be necessary to further restrict the hydrogen concentration of this type of gas.

3.6.3 High CV gases (Wobbe 49 - 67 MJ/m3)

Gases of CV greater than that of pipeline quality natural gas can also be burned, e.g. well head gas, LPG, etc. These gases consist predominantly of paraffin hydrocarbons with little or no inert content and have temperature corrected Wobbe Indices in the range 49 to 67 MJ/m3. This covers the range from the top limit of pipeline natural gases up to gaseous LPG. The Company’s prior written approval in respect of the gas to be used must be obtained.

3.6.3.1 Well Head Gases As these gases have a Wobbe Index greater than 49 MJ/m3, each gas must be considered on an individual basis by the Company for its suitability and for the setting of appropriate emissions guarantees. All other aspects of this Fluids Specification still apply to these gases.

3.6.3.2 LPG The following specification is for applications in which the LPG is vaporised and supplied to the turbine as a gas. However, unless otherwise stated, the values given in Table 3.7 are for the LPG in the liquid form, before the vaporiser and not as supplied to the turbine. This specification also applies to propane supplied in cylinders for propane assisted starting on liquid.



PROPERTY LIMITS - note 1 TEST METHOD note 7 ASTM ISO IP DIN BS 1 CONSTITUENTS C2 [%mol] 5 (Max) D2163 C3 [%mol] 90 (Min) D2163 C4 [%mol] 10 (Max) D2163 C5 [%mol ] 2 (Max) D2163 Total Olefins [% mol] 25 (Max) D2163 Mono-Olefins 25 (Max) D2163 Di-Olefins 0.5 (Max) D2163 Acetylenes [% mol] 0.5 (Max) D2163 Carbon/Hydrogen ratio note 2 D2163 Total Sulphur [ppmm] 200 (Max) D2784 Mercaptan Sulphur [ppmm] 50 (Max) 2000:

part 272 Hydrogen Sulphide [ppmm] 0.5 (Max) D2420 2 VOLATILITY Flash Point [oC] Below Minus (-) 80oC

or legal limit. D56

Gauge vapour pressure at 40.0 oC [Barg] 15.6 (Max) D1267 161 3 FLUIDITY Relative Density at 15 oC 0.585 (Max) D1657 4 COMBUSTION / FLUIDITY Net Calorific Value [MJ/kg] 45 to 48 D4809 Gross Calorific Value [MJ/Kg] note 2 D4809 Wobbe Index (MJ/m3) note 3 5 CORROSION Copper strip corrosion, 3hrs at 50 oC Class 1 (Max) D1838 6 CONTAMINANTS Residue on evaporation 100 ml, ml - note 4 0.002 (Max) D2158 Residue from Oil Stain Observation Pass - note 5 D2158 Water content [ppmm] 30 (Max) D1744 74 Particulate matter [ppmm] - note 4

Solid Particle Size [µm ] 20 (Max) 10 (Max)

51.419

Total Ash [ppmm] - note 4 20 (Max) D473 53 4450 Vanadium 0.5 (Max) note 6 Sodium + Potassium 1 (Max) note 6 Calcium 1 (Max) note 6 Lead 1 (Max) note 6 Zinc 1 (Max) note 6 Mercury 1 (Max) note 6 Other metals 0.5 (Max) note 5

NOTES

1/ Fuel Limits based on average world wide specifications for Propane. 2/ Information is requested for inclusion in the Siemens data base. 3/ Siemens require a knowledge of Wobbe Index for pressure drop calculation. 4/ Total residue and solid contaminants must be less than 20 ppmm at skid edge. 5/ An acceptable product shall not yield a persistent oil ring when 0.3 ml of solvent residue is added to a filter paper, in 0.1ml increments and examined in daylight after 2 min as described in Test Method D2158. 6/ Use latest atomic absorption technique for the determination of trace metals in fuels. 7/ The latest revision or edition of each test method is to be used.

Table 3.7 Siemens Industrial Turbomachinery Ltd Fuel Specification for Gaseous LPG Options (unless otherwise stated this specification assumes that the LPG is in the liquid form before the

vaporiser and not as supplied to the turbine)



Section 4 Liquid Fuels

4.0 Applicable Standards

The following standards have been used in the compilation of the liquid fuel specification contained within this section and provide a useful background:

BS 2869 Specification for fuel oils for agricultural, domestic and industrial engines and boilers BS EN 590 Automotive fuels - Diesel - Requirements and test methods ASTM D975 Standard Classification of Diesel Fuel Oils ASTM D2880 Standard Specification of Gas Turbine Fuel Oils

ISO 4261 Petroleum Products - Fuels (class F) - Specification of gas turbine fuels for industrial and marine applications BS 4250 Specification for Commercial Butane and Commercial Propane

ASME D1835 Standard Specification for Liquefied Petroleum Gases ASTM D1655 Standard Specification for Aviation Turbine Fuels

4.1 Requirements This section defines the quality and characteristics of liquid fuels required for use in the Company’s engines listed in Table 1.1. The Company must in all cases have granted its prior written approval in respect of the liquid fuel to be used. The customer must regularly consult with the fuel supplier prior to delivery to ensure that the fuel continues to meet this specification.

4.1.1 Contaminants The contaminant limits specified in Table 1.2 are the maximum aggregate levels from all sources including liquid fuels. They apply to all fuels used in the Company’s engines, and must not be exceeded without the Company’s prior written consent. The limits are dependent on the net calorific value of the fuel as shown in Table 1.2. The omission of a given contaminant does not constitute the Company’s authorisation of an unlimited level of this contaminant or its acceptance. All contaminants and their level must be declared to the Company as well as any changes in contaminant levels as a result of changing the fuel quality.

4.1.2 General The fuel should be hydrocarbon compounds originating from crude oil feed stock. Also, fuels from other sources may be suitable provided that details of these have been supplied to the Company and the Company’s prior written permission for their use has been given. All fuels must be clean, clear and bright, contain no free or suspended water and no particulate matter or pipeline scale and must be filtered within the customer's bulk storage system to remove all particles above 10 µm. Individual



properties of liquid fuel and their significance are discussed in Appendix 3. The pressure requirements at skid edge are defined by the appropriate fuel system piping and instrumentation diagram.

4.1.3 Sulphur Where the sulphur content of the fuel is above 0.1%wt all fuel supply pipes from source to the combustor shall be stainless steel with good corrosion resistance such as AISI 304, 310, 316 or 321, to avoid corrosion products, such as iron sulphide, building up in supply lines.

4.2 Nitrogen

Nitrogen in liquid fuels is not in any way harmful to the gas turbine, but fuel bound nitrogen (FBN) will be converted to nitrogen oxides (NOx) that must be allowed for if there are applicable exhaust emissions regulations.

4.3 Emissions Compliance with this specification, including any written approval granted by the Company pursuant to its terms, does not guarantee that exhaust emissions will comply with any applicable regulations. In order to accurately determine the expected emissions it is essential that the Company is provided with an accurate analysis of the FBN. It should also be noted that gas turbine emissions may be affected by the level of contaminants in the air. Any emissions guarantees will be in respect of the given increase over the background levels already present in the site ambient air.



4.4 Diesel Fuels Table 4.1 details the requirements of diesel fuels for use in the Company’s engines. The suitability of commercially available diesel fuels can be established by comparison of their properties with the Company’s liquid fuel specification given in Table 4.1. Table A3.1 compares the Company’s liquid fuel specification to the diesel fuel standards listed in the introduction to this section.

Table 4.1 Siemens Industrial Turbomachinery Ltd Diesel Fuel Specification PROPERTY LIMITATION TEST METHOD4

1. Appearance Clear & bright, no free or suspended water and no particulate matter present

Visual inspection

2. Viscosity, kinematic at 40.0°C,(104°F) [mm 2/s] 2.0 (min.)

7.5 (max.)

ISO 3104 ASTM D445 IP71

3. Carbon residue

Micro method, % weight on 10% distillation residue

0.3 (max.) ISO 10370 IP 398 ASTM D4530

4.

Distillation recovery [% v/v] Recovered at 250°C Recovered at 350°C Recovered at 370°C

65 (max.) 85 (min) 95 (min)

ISO 3405 ASTM D86 IP 123

5. Flash point (closed cup Pensky-Martens) [°C] see section A3.1.4 ISO 2719 ASTM D93 IP 34 EN 22719

6. Water content [mg/kg] 2 200 (max.) ISO 12937 ASTM D6304 IP438

7. Particulate matter [mg/kg] 2 10 (max.) ISO 12662 IP 440

8. Total Ash [ % w/w ] 2 0.01 (max.) ISO 6245 ASTM D 482

9. Metallic ash2 [ppmm]: Vanadium Sodium + potassium Calcium + magnesium Lead Zinc Lithium Aluminium Mercury Other metals

0.5 1 1 0.5 1 0.5 1 1 0.5

IP PM-CW (for all) IP 470 or IP 501 (all except lithium) Atomic fluorescence spectrometry for Hg

10. Silicon 0.02 ppmm IP 501 ASTM D5184

11. Halogens (Fluorine, chlorine, bromine, iodine) 1 ppmm IP510 EN 14077

12. Sulphur content [% w/w] 2 0.5 (max.)3

May be raised by agreement with the Company as allowed by section 1.1

EN 24260 ISO 8754 IP 336 IP61 ASTM D129 ASTM D4294



13. Copper strip corrosion, 3hrs at 50°C Class 1 ( max.) May be raised by agreement with the Company as allowed by section 1.1

ISO 2160 ASTM D130 IP 154

14. Cold filter plugging point [°C]

see note A3.1.11

-20 (max.) And at least 10°C below fuel temperature under all conditions

EN 116 ASTM D6371 IP 309

15. Cloud point [°C]

see note A3.1.12

-15 (max.)

And at least 5°C below fuel temperature under all conditions

ISO 3015 EN 23015 ASTM D2500 IP 219

16 Pour point [°C]

see note A3.1.13

-20 (max.)

And at least 10°C below fuel temperature under all conditions

ISO 3016 ASTM D97

17. Density at 15°C [kg/m 3] 820 (min.)

860 (max.)

ISO 3675 ISO 12185 ASTM D4052 ASTM D1298 IP 160 IP 365

18. Oxidation stability [g/m3] 25 (max.) ISO 12205 ASTM D2274 IP 388

19. Reid Vapour Pressure at supply temperature max =0.14 bara ISO 3007

IP 69

ASTM D323

20. Total Acidity Max 0.1 mg KOH/g ASTM D3242 IP 354

21. Supply Temperature Min 0°C, (32°F) Max 60 °C, (140°F)

Notes: 1 For fuels with viscosity lower than 2.0 mm2/s special fuel pumps may be required and the Company’s prior written approval will be required.

2 Total contaminant levels from all sources based on the Company’s reference fuel calorific value; see table 1.2. 3 Where the sulphur content of the fuel is above 0.1%wt all fuel supply pipes from source to the combustor shall be of stainless steel to avoid corrosion products, iron sulphide, building up in supply lines. 4 The latest revision or edition of each test method is to be used.



4.5 LPG as liquid

LPG can be used, supplied to the engine in the liquid phase, subject to the prior written approval of the Company. Special requirements apply to the use of LPG as liquid, which are given in Table 4.2 and a non-standard fuel supply system is required. Additional information is provided in Appendix 4.



Table 4.2 The Company’s Fuel Specification for LPG used as Liquid PROPERTY LIMITS - note 1 TEST METHOD note 6 ASTM ISO IP DIN BS 1 CONSTITUENTS C2 [%mol] 5 (Max) D2163 C3 [%mol] 60 (Max) - note 2 D2163 C4 [%mol] 40 (Min) - note 2 D2163 C5 [%mol ] 5 (Max) D2163 Total Olefins [% mol] 60 (Max) D2163 Mono-Olefins 60 (Max) D2163 Di-Olefins 0.5 (Max) D2163 Acetylenes [% mol] 0.5 (Max) D2163 Carbon/Hydrogen ratio note 3 D2163 Total Sulphur [ppmm] 200 (Max) D2784 Mercaptan Sulphur [ppmm] 50 (Max) 2000:

part 272 Hydrogen Sulphide [ppmm] 0.5 (Max) D2420

2 VOLATILITY Flash Point [oC] Below Minus (-) 60oC

or legal limit. D56 -97A

Gauge vapour pressure at 40.0 oC [Barg] 8.0 (Max) - note 2 D1267 161 3 FLUIDITY Relative Density at 15 oC 0.585 (Max) D1657

4 COMBUSTION Net Heat of Combustion [MJ/kg] 44 to 47 D4809 Gross Calorific Value [MJ/Kg] note 3 D4809 5 CORROSION Copper strip corrosion, 3hrs at 50 oC Class 1 (Max) D1838 6 CONTAMINANTS Residue on evaporation 100 ml, ml 0.05 (Max) D2158 Residue from Oil Stain Observation Pass - note 4 D2158 Water content [ppmm] 30 (Max) D1744 74 Particulate matter [ppmm]

Particle size [µm ] 24 (Max) 10 (Max)

51.419

Total Ash [ppmm] 100 (Max) D473 53 4450 Vanadium 0.5 (Max) note 5 Sodium + potassium 1 (Max) note 5 Calcium 1 (Max) note 5 Lead 0.5 (Max) note 5 Zinc 1 (Max) note 5 Aluminium 1 (Max) note 5

IP PM-CW IP 470 or IP 501

Mercury 1 (Max) Atomic fluorescence spectrometry Lithium 0.5 (Max) IP PM-CW Other metals 0.5 (Max) note 5 Silicon 0.02 (Max) D5184 501 Halogens (fluorine chlorine bromine

iodine) 1 (Max) 510 EN

14077 NOTES

1/ Fuel Limits based on average world wide specifications for LPG, but with additional limits on C3/C4/Vapor pressure levels. 2/ Fuels with higher propane content/ vapour pressure than above to be referred to Siemens Industrial Turbomachinery Ltd combustion group. 3/ Information is requested for inclusion in the Siemens data base. 4/ An acceptable product shall not yield a persistent oil ring when 0.3 ml of solvent residue is added to a filter paper, in 0.1ml increments and examined in daylight after 2 min as described in Test Method D2158. 5/ Use the latest atomic absorption technique for the determination of trace metals in fuels. 6/ The latest revision or edition of each test method is to be used. 7/ The total amount of any particular contaminant from all sources based on the Company’s reference fuel calorific value (as stated in section

1.5) cannot be exceeded



4.6 Naphtha

Naphtha can be used subject to the prior written approval of the Company. The Naphtha must conform to the specification in Table 4.3 and a non-standard fuel supply system is required. Additional information is provided in Appendix 4.



Table 4.3 The Company’s Fuel Specification for Naphtha System Options PROPERTY LIMITS- note 1 TEST METHOD note 6 ASTM ISO IP DIN BS 1 COMPOSITION Saturates = Paraffins & Naphthenes [% mol] No Limit - note 2 D1319 Aromatics [% mol] 25 (Max) D1319 Total Olefins [% mol] 5 (Max) D1319 Carbon/Hydrogen ratio note 2 D1319 Total Sulphur [ppmm] 200 (Max) - note 3 D129 8754 61 Mercaptan Sulphur [ppmm] 50 (Max) - note 3 D3227 Hydrogen Sulphide [ppmm] 0.5 (Max) - note 3 D2420 2 VOLATILITY Distillation : note 4 D86 Initial Boiling Point [oC] 35 (Min) D86 123 Final Boiling Point [oC] 200 (Max) D86 123 Flash Point [oC] As applicable laws D56 170/34 Reid vapour pressure at 37.8 oC (Bara) 0.9 (Max) D323-94 3 FLUIDITY Relative Density at 15 oC 0.65 to 0.79 D1298 160 Viscosity, kinematic at 20.0 oC [mm2 /s] 0.6 (Min) D445 3104 71 Lubricity note 2 D6079 4 COMBUSTION Net Heat of Combustion [MJ/kg] 43 to 46 D4809 Gross Calorific Value [MJ/kg] note 2 D4809 5 CORROSION Copper strip corrosion, 3hrs at 50 oC Class 1 (Max) D130-94 2160 154/93 6 STABILITY Oxidation stability [g/m3] 25 (Max) D873

D3241

7 CONTAMINANTS Saybolt Colour +25(min) D156-94 Carbon Residue, Conradson

[ % weight on 10% distillation residue] 0.2 (Max) D189 10370 13

Water content [ppmm] 50 (Max) note 3 D1744 74 Particulate matter [ppmm]

Particle size [µm ] 24 (Max) 10 (Max)

51.419

Total Ash [ppmm] 100 (Max) D473 53 4450 Vanadium 0.5 (Max) note 5 Sodium + potassium 1 (Max) note 5 Calcium 1 (Max) note 5 Lead 0.5 (Max) note 5 Zinc 1 (Max) note 5

IP PM-CW IP 470 or IP 501

Aluminium 1 (Max) note 5 Mercury 1 (Max) note 5 Atomic fluorescence spectrometry Lithium 0.5 (Max) IP PM-CW Other metals 0.5 (Max) note 5

Silicon 0.02 (Max) D5184 501

Halogens (fluorine chlorine bromine iodine) 1 (Max) 510 EN 14077 NOTES

1/ The Naphtha specification is based on published specifications with some additional constraints (see note 3). 2/ Information is requested for inclusion in the Siemens data base. 3/ Fuels with higher Sulphur/Water content than above to be referred to the Company. 4/ Full distillation curve is requested for inclusion in the Siemens data base. 5/ Latest atomic absorption technique for the determination of trace metals in fuels. 6/ The latest revision or edition of each test method is to be used. 7/ The total amount of any particular contaminant from all sources based on the Company’s reference fuel calorific value (as stated in section 1.5) cannot be exceeded



4.7 Kerosene

To be acceptable for most of the Company’s burner configurations a kerosene fuel must conform to Table 4.4. Good quality kerosene fuels are normally acceptable, but may require a special fuel pump. Examples of acceptable specifications for kerosene are BS 2869 C1 and C2 and Jet A1. Certain burners, designed to burn gases of low CV, require a more tightly controlled quality liquid fuel and to accommodate this, a kerosene fuel conforming to the entire specification shown in Table 4.5 is required. The Kerosene shall be clear, bright, and visually free from solid matter and un-dissolved water at normal ambient temperature.

Table 4.4 The Company’s Kerosene Specification for Standard Burners

POINT PROPERTY Limits TEST METHODS2

1. Kinematic Viscosity at 40oC (mm2/s) min 1.0 ASTM D445 / IP 71 / BS EN ISO 3104

max 2.0

2. Distillation Recovery at 200oC (%v/v) min 15 ISO 3405 / ASTM D86 / IP 123

3. Final Boiling Point (oC) min 280 ISO 3405 / ASTM D86 / IP123

4. Flash point (oC) min 38 ISO 13736 / IP 170

5. Copper corrosion (3 hrs at 100oC) (class) max 1 ASTM D130 / IP 154 / BS EN ISO 2160

6. Reid Vapour Pressure at 38oC (bara) max 0.14 ISO 3007 / IP 69 / ASTM D323

7. Smoke Point (mm) min 19 ASTM D1322 / IP 57/95 / BS EN ISO 2000-57

8. Char Value (mg/kg) max 20 BS 2000-10

9. Sulphur (%w/w) 1 max 0.3 ASTM D1266 / IP 107 / BS 2000-107

10. Density at 15oC (kg/m3) min 775 ASTM D1298 / IP160 / BS EN ISO 3675

max 840

11. Contaminants (ppmm) 3 V max 0.5 Na+K max 1 Ca max 1 Pb max 0.5 Zn

Hg max max

1 1

Li max 0.5 Other metals max 0.5 Si max 0.02 Halogens max 1 Particulates max 24 Water max 200 Total Ash max 100

Notes 1 Where the sulphur content of the fuel is above 0.1%wt all fuel supply pipes from source to the combustor shall be of stainless steel to avoid corrosion products, iron sulphide, building up in supply lines. 2 The latest revision or edition of each test method is to be used. 3 The total amount of any particular contaminant from all sources based on the Company’s reference fuel calorific value (as stated in section 1.5) cannot be exceeded



Table 4.5 The Company’s Kerosene Specification for Low CV Gas Applications

POINT PROPERTY Limits TEST METHODS2

1 Kinematic Viscosity at 40oC (mm2/s) min 1.15 ASTM D445 / IP 71 / BS EN ISO 3104

2 Distillation Recovery at 200oC (%v/v) min 15 BS 7392

max 60

3 Final Boiling Point (oC) min 280 ASTM D86 / IP123 / BS 7392

4 Distillation Residue (% v/v) max 1.5 ASTM D86 / IP123

5 Distillation Loss (%v/v) max 1.5 ASTM D86 / IP123

6 Flash Point (oC) min 43 IP 170 / BS EN ISO 13736

7 Copper Corrosion (3 hrs at 100oC) (class) max 1 ASTM D130 / IP 154 / BS EN ISO 2160

8 Silver Strip (corrosion test) (class) max 2 IP 227

9 Smoke Point (mm) min 34 ASTM D1322 / IP 57/95 / BS EN ISO 2000-57

10 Char Value (mg/kg) max 10 BS 2000-10

11 Aromatics (% v/v) max 22 ASTM D1319 / IP156

12 Sulphur (%w/w) 1 max 0.3 ASTM D1266 / IP 107 / BS 2000-107

13 Sulphur Mercaptan (% w/w) max 0.003 ASTM D3227 / IP342

14 Density at 15oC (kg/m3) min 775 ASTM D1298 / IP160 / BS EN ISO 3675

max 840

15 Cold Filter Plugging Point (oC) max -12 BS EN 116

16 Existent Gum (mg/100ml) max 7 ASTM D381 / IP131

17 Contaminants (ppmm) 3 V max 0.5 Na+K max 1 Ca max 1 Pb max 0.5 Zn

Hg max max

1 1

Li max 0.5 Other metals max 0.5 Si max 0.02 Halogens max 1 Particulates max 24 Water max 200 Total Ash max 100

Notes 1 Where the sulphur content of the fuel is above 0.1%wt all fuel supply pipes from source to the combustor shall be of stainless steel to avoid corrosion products, iron sulphide, building up in supply lines. 2 The latest revision or edition of each test method is to be used. 3 The total amount of any particular contaminant from all sources based on the Company’s reference fuel calorific value (as stated in section 1.5) cannot be exceeded



Section 5 Lubrication Oil

5.0 Applicable Standards BS ISO 8068 Lubricants, industrial oils and related products (class L) –

Family T (Turbines) – Specification for lubricating oils for turbines BS 4231 Viscosity classification for industrial liquid lubricants

5.1 Introduction This section defines the quality and characteristics of lubricating oils required for use in the Company’s engines listed in Table 1.1. It is the responsibility of the Customer, in consultation with the oil supplier to ensure that the provisions of this specification are met. This specification requires the oil to conform to the requirements of BS ISO 8068 ‘Lubricants, industrial oils and related products (class L) – Family T (Turbines) – Specification for lubricating oils for turbines’; classification L-TGE, plus additional tests and requirements, as defined below. The oil must conform to these specifications after storage, if it is stored. L-TGE lubricants are mineral oils with suitable antioxidants and corrosion inhibitors, for the lubrication of steam turbines and gas turbines (normal service), with additional extreme-pressure performance to lubricate gear systems.

5.2 Requirements The lubricating oils used in the Company’s engines must adhere to the following properties.

5.2.1 General When supplied, the oil shall be a turbine quality petroleum product with additives to meet the requirements of this specification. It shall be free from water, suspended matter, dirt, and other impurities. The Company’s recommendations (available on request) for flushing the lubricating system must be strictly followed during commissioning and after any repairs or modifications.

5.2.2 Additives The additives shall be completely soluble in the oil, uniformly distributed in it, stable at all temperatures, above the specified pour point, and up to and including 139°C (280°F) and unaffected by the presence of water.

5.2.3 Mixing Oils of Different Grades, Types or from Different Manufacturers Oils of different grades, different types, or from different manufacturers must not be combined. Oil used for top-up purposes must be of the same grade as the oil already in use for the turbine. If the oil requires replacing, then the relevant Company servicing procedure must be used.

5.2.4 Notification of Changes to Formulation The Customer must request from the lube oil supplier, notification of any changes to the formulation of a branded grade supplied for use in the turbine and give notification to the Company prior to its use in the turbine and obtain the Company’s prior written approval of the proposed use of the revised specification for the oil. The Customer shall be under a continuing obligation to ensure the suitability of the lubricating oil proposed to be used from time to time in the Company’s engines.



5.2.5 Viscosity The normal requirements for all the Company’s engines except the Hurricane, shall be ISO VG 46 viscosity for normal temperature climate, as specified in BS 4231. The Hurricane must operate on ISO VG 46 for normal temperature climates. Special cases of high or low ambient or driven machinery requirements may necessitate the use of heavier or lighter viscosity grades ISO/VG 68 or ISO/VG 32 respectively. These cases must be referred to the Company for its prior written approval before the heavier or lighter grade oil is used in the engine

5.2.6 Viscosity Index Improvers The use of Viscosity Index Improvers in lubrication oils is not allowed by the Company for its engine range.

5.2.7 Corrosion Prevention By agreement between the customer and the Company, the determination of rust-preventing characteristics of the lubrication oil may be carried out using distilled water in place of synthetic sea water. In this case Procedure A of BS 2000: Part 135 shall be carried out with the inclusion of the modification given in appendix A of BS 489: 1999.

5.2.8 FZG Index (Forschungssteelle für Zahnräder und Getriebebau) An ‘FZG’, gear machine is used to determine the relative load carrying capacity of the lubricating oil. An FZG index refers to a maximum load beyond which steel/ steel gears will fail by scoring/scuffing.

5.2.9 Preservation The oil shall be suitable for preservation of the engine and components, during storage and downtime, for a minimum period of 90 days. If storage or down-time in excess of 90 days is expected then the Customer shall consult the oil supplier for advice on preservation and re-commissioning.

5.2.10 Service Life The Customer must obtain from the oil supplier permissible levels of contamination or property changes which limit the service life of the oil, such as water content, increase in total acidity, change in viscosity, loss of oxidation resistance, etc. and carry out frequent checks to determine the suitability of the oil.

5.2.11 Non-standard Ancillaries In the case of engines being fitted with special ancillaries such as hydrostatic units, the Customer will be informed by the Company whether a need for specific lubrication oils has arisen.

5.3 Siemens Industrial Turbomachinery Ltd Lubricating Oil Specification

The requirements of lubricating oil for use in the Company’s engines are given in Table 5.1.

5.4 BS ISO 8068 Specification for lubricating oils for turbines The specification for turbine oils L-TGE contained within BS ISO 8068 conforms to the Company’s lubricating oil specification given in Table 5.1 with the following exceptions: • Inorganic acidity • Viscosity index • Closed flash point • Open flash point • Water content • Lead content



• Zinc content • FZG index



Table 5.1 The Company’s Lubricating Oil Specification Viscosity Class (ISO 3448) Property

Min/max/ nominal

32

46

68

Test method Alternative test method1

Kinematic Viscosity (ν) @40°C [mm2/s]

minimum maximum

28.8 35.2

41.4 50.6

61.2 74.8

ISO 3104

IP 71 & ASTM D445 ISO 3104 ISO 3105 ISO 3106

Viscosity Index minimum 90 90 90 ISO 2909

ASTM D2270 IP 226 ISO 2909

Pour Point [°C]

maximum -6 -6 -6 ISO 3016

IP 15 & ASTM D97

Flash Point [°C] Open (Cleveland) Closed(Pensky-Martens)

minimum 210 195

210 195

210 195

ISO 2592 ISO 2719

ASTM D92 IP 34 ASTM D93 ISO 2719

Total acid number [mg KOH/g]

maximum 0.20 0.20 0.20 ISO 6618 ISO 6619 ISO 7537

IP139 ASTM D974

Inorganic Acidity mg KOH/g

Nil Nil Nil BS 2000 Pt: 182

IP 182

Water content [ppmm] maximum 200 200 200 ISO 6296 ISO12937

Foaming (tendency/stability) c [ml/ml] — sequence 1 °C at 24 °C — sequence 2 °C at 93 °C — sequence 3 °C at 24 °C after 93 °C

maximum

450/0 50/0 450/0

450/0 50/0 450/0

450/0 50 /0 450/0

ISO 6247

Air Release Time

at 50°C [minutes]

maximum

5 5 6 ISO 9120

IP 313 ASTM D3427

Copper Corrosion (3 h at 100°C)

maximum 1

1

1

ISO 2160

IP 154 BS 2000 : Part 154 ASTM D130

Corrosion Preventing Characteristics (24 hour test)

Pass

Pass

Pass

ISO 7120(B) IP 135 Procedure B ASTM D665 BS2000: Part 135 (see section 5.2.8 herein)

Total Oxidation Stability - total acid number at 1000 h [mg KOH/g] - time for total acid number 2mg KOH/g [h] - sludge after 1000 h [mg]

maximum minimum maximum

0.3

3500 200

0.3

3000 200

0.3

2500 200

ISO 4263-1

Filterability (dry) [%] minimum 85 85 85 ISO 13357-2 Filterability (wet) [%] Pass Pass Pass ISO 13357-1 Load carrying capacity- FZG Test (A/8,3/90) Failure load stage

minimum

6

6

6

ISO 14635-1

CEC L-07-A ASTM D5182

Cleanliness at delivery stage Lube oil without hydrostart & hydraulic circuits Lube oil with hydrostart & hydraulic circuits

maximum maximum

- / 17 / 14

19 / 17/ 14

- / 17 / 14

19 / 17/ 14

- / 17 / 14

19 / 17/ 14

ISO 4406

Zinc content ppmm

maximum

80

80

80

Suitable spectrometric analysis

Lead content ppmm

maximum

20

20

20

Suitable spectrometric analysis

1 The latest revision or edition of each test method is to be used.



Section 6 Compressor Washing Water And Cleaning Fluids

6.1 Introduction This section defines the requirements for the washing water and cleaning fluid for hot or cold compressor cleaning.

6.2 Washing Water

Only demineralised water which meets the following conditions can be used to dilute the cleaning fluid to make the cleaning solution, and for rinsing.

6.2.1 General The water is to be clear, colourless and free from solids in suspension.

6.2.2 Dissolved Solids The total amount of dissolved solids is not to exceed 10 ppmm.

6.2.3 Silica The total silica content (as SiO2) is not to exceed 3 ppmm.

6.2.4 Acidity The pH value is to lie within the range 5.0 - 7.5.

6.2.5 Electrical Conductivity The electrical conductivity at 20°C + 5°C must not exceed 11 µS/cm.

6.3 Cleaning Fluid

This sub section defines the requirements of a cleaning fluid for use in the Company’s engines as defined in section 1.

6.3.1 Definition A cleaning fluid refers to a concentrate to be diluted with demineralised water before use.

6.3.2 Requirements 6.3.2.1 The cleaning fluid shall consist of a suitable corrosion inhibited, stable odourless solution of

non toxic biodegradable surface active agents and/or emulsifiers. 6.3.2.2 It shall be homogeneous and totally free from suspended matter and deposits. 6.3.2.3 It must not contain phenols or cresols. 6.3.2.4 There must be no evidence of separation of component parts or precipitation when the

cleaning fluid is diluted with water or antifreeze mixture. 6.3.2.5 The manufacturer’s shelf life of the cleaning fluid shall be a minimum of two years and the

product must be clearly labelled with a “use by” date.

6.3.3 Health And Safety Recommendations The fluid must be used in accordance with the supplier’s health and safety data sheets and disposed of in line with the appropriate legislation and/or regulations. Many cleaning agents contain chemicals which can cause injury through prolonged or repeated physical contact or inhalation. Protective clothing and adequate ventilation should be provided during handling in accordance with supplier recommendations.



6.3.4 Approved Cleaning Fluids

A list of all cleaning fluids, approved by the Company from time to time, is available from the Company on request. Your attention is drawn to the fact that the list may be changed from time to time and that regular enquiry of the Company on this issue is recommended.

6.4 Cleaning Solution

6.4.1 Definition A cleaning solution refers to the solution as injected into the turbine.

6.4.2 Requirements 6.4.2.1 The cleaning solution shall have the following compositional restrictions.

Sodium, Potassium and Lithium, Na+K+Li 25 ppmm max. (combined total) Calcium + Magnesium, Ca+Mg 10 ppmm max. (combined total) Lead and Vanadium, Pb+V 0.25 ppmm max. (combined total) Chlorine, Cl 30 ppmm max. Sulphur, S 50 ppmm max. pH 6.5 to 9.0 Particulate matter or suspended solids 0.001%w/w max. Ash @ 1050° C 0.004 % w/w max.

Table 6.1 Cleaning Solution Requirements

Limits in table 1.2 also apply to table 6.1

6.4.2.2 The cleaning solution must not affect abradable coatings, rubber, paints, aluminium coatings nor pit steel or nickel based materials.

6.4.2.3 Where the cleaning fluid is supplied as concentrate it shall be diluted with demineralised

water as per manufacturer’s instruction before injection into the engine. 6.4.2.4 The omission of a given contaminant from section 6.4.2.1 does not constitute the Company’s

authorisation of an unlimited level of this contaminant or its acceptance. All contaminants and their level must be declared to the Company as well as any changes in contaminant levels as a result of changing the cleaning solution.

6.4.3 Antifreeze When liquid washing during cold weather, it is necessary to add anti-freeze to the demineralised water to prevent the formation of ice in the compressor. Mono Propylene glycol, technical grade, must be used with any wash systems having heaters, such as the new high pressure wash system. Mono Propylene glycol also goes by the name 1,2-propanediol, and propylene glycol. It must comply with ASTM D5216. On no account should Methanol (methyl alcohol) be used with any wash systems with heaters, because of the danger of vaporising the highly flammable methanol. However methanol, which conforms to BS



506 part 1:1986, may be used in older systems which operate at lower temperatures. Where methanol is not compatible with the customers chosen cleaning fluid the less effective anti-freezes ethanol or iso propyl alcohol (IPA) may be used as an alternative for unheated systems only. Dipropylene glycol, tri propylene glycol and ethylene glycol are specifically prohibited from use with any wash system.

WARNING:

MANY ANTIFREEZES ARE HIGHLY FLAMMABLE AND TOXIC TO VARYING DEGREES. HANDLING AND STORAGE MUST ONLY TAKE PLACE IN A WELL VENTILATED AREA. THE APPROPRIATE PROTECTIVE CLOTHING E.G. RUBBER GLOVES, BREATHING APPARATUS ETC., MUST BE WORN AS PER SUPPLIER INSTRUCTIONS.



Section 7 Injection Water

7.1 Introduction

This section defines the quality of water used to control emissions, or enhance power.

7.2 Temperature and Pressure The injection water is supplied to the skid edge of the water injection module at conditions defined on the appropriate piping and instrumentation diagram.

7.3 Requirements The injection water quality must conform to the following requirements:

7.3.1 General The water is to be clear, colourless and free from solid material.

7.3.2 Total Solids-Concentration Limit At all times the total contaminants entering the turbine from all sources shall comply with section 1. However the following additional limitations apply to injection water. These are based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted accordingly. The total maximum dissolved and un-dissolved solids limit is 2.0 ppmm.

7.3.3 Un-dissolved Solids - Size limit The injection water must be supplied clean at the injection module with a filtration size limit of no larger than Beta10 = 75 (10 µm). This represents a 10 µm filter operating at 98.7% efficiency. The particle

size distribution of the water downstream of the filter is as shown in Table 7.1:

Particle Size (µm)

% of Total

10 - 20 1.3 < 10 98.7

Table 7.1 Particle Size Distribution

7.3.4 Total Dissolved Solids The following limitation applies to total dissolved solids. These are based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted accordingly as explained in Appendix A 1.2. This is summarised in Table 7.2 for various steam to fuel ratio ranges and the company’s reference fuel:



Water / Fuel Ratio 0 to 1:1 1:1 to 2:1

Allowable Total Dissolved Solids [ppmm]

1.0 0.50

Table 7.2 Allowable Total Dissolved Solids



7.3.5 Specific Solids a) Metals In addition to the Total Dissolved Solids limits already specified, the following limitation applies to specific dissolved solids. These are based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted accordingly as explained in Appendix A 1.2. The limits in Table 7.3 are subject to the limits in Table 7.2 for total dissolved solids.

Vanadium, V 0.5 ppmm max Calcium + Magnesium, Ca + Mg 1.0 ppmm max (combined total) Sodium + Potassium, Na + K 0.2 ppmm max (combined total) Lead, Pb 0.1 ppmm max Lithium, Li 0.5 ppmm max

Table 7.3 Allowable Specific Dissolved Solids

Limits in table 1.2 also apply to table 7.3

b) Silica (SiO2)

In addition to the Total Solids limits already specified, the maximum silica content is limited to 0.04 ppmm, based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted as explained in Appendix A 1.2. c) Sulphur

In addition to the Total Solids limits already specified, the maximum sulphur content is limited to 1.0 ppmm, based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted as explained in Appendix A 1.2.

7.3.6 Acidity The injection water, when free from carbon dioxide, must have a pH value between 6.5 and 7.5.

7.3.7 Electrical Conductivity The electrical conductivity at 20°C ± 5°C must not exceed 1.5 µS/cm. These are based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different water to fuel ratios and customer fuels, the limits must be adjusted accordingly. The Company recommends that the conductivity is continually monitored and the water supply switched off if the above value is exceeded.



Section 8 Evaporative Cooling Water

8.1 Introduction At high ambient temperatures and low relative humidity, water may be used to cool the air before it enters the engine. By giving up heat to evaporate the water, the incoming air could be cooled, from its dry bulb temperature to near its wet bulb temperature before entering the engine. A temperature reduction of 90% of the theoretical temperature difference can be achieved using commercially available coolers. As a result of the reduction in temperature, the mass flow of air into the engine increases. The total mass flow is also increased by the addition of the evaporated water and both factors result in an increase in the turbine output power.

8.2 Requirements The evaporative cooling water quality must as a minimum conform to the requirements set out in section 7.3 above.

8.3 Water Carryover Carryover of un-evaporated water should be avoided. In practice water carry-over WILL occur under certain circumstances. This MUST be minimised so that the total customer fuel equivalent contaminant level concentration must not exceed the limits defined in Table 1.2. See section A1.2.1 for Fuel Equivalent Concentration calculation.



Section 9 Injection Steam

Reference can be made to the following standards for guidance on boiler feed water treatment and boiler water conditions necessary to meet the limits contained within this document. BS 2486 : 1997 Recommendations for Treatment of Water for Steam Boilers & Water Heaters

Other equivalent standards would also be applicable. The additional recommendations for boiler water total dissolved solids (section 9.3.6) should be considered as early as possible in the boiler selection stage.

9.1 Introduction This section defines the quality of steam used for primary and secondary injection for use in the Company’s engines. Steam injection is used for NOx emission suppression and power enhancement. In some engines the amount of secondary steam injected is larger than that for primary steam injection and therefore more power enhancement could be achieved. The reduction in NOx emissions is greater for primary steam injection than that achieved by the same mass of secondary steam.

9.2 Steam Quality Requirements The steam quality must conform to the following requirements:

9.2.1 General The Customer is responsible for ensuring that steam continuously leaves the boiler in a superheated state to prevent the carryover of boiler water. The minimum degree of superheat required is 30°C, t herefore the steam temperature, when measured downstream from the boiler on the Company’s steam control unit must be a minimum of 30°C above steam saturation temperature at the pressure given in section 9.2.2. For design purposes, it is recommended by the Company that the designed boiler outlet superheat temperature is at least the sum of the 30°C minimum and expected distribution line temperature losses. This will result in a minimum required boiler outlet superheat temperature greater than 30°C. Expanding the steam across a pressure reducing valve to provide a gain in superheat temperature is not recommended by the Company as a suitable method for achieving the 30°C limit downstream of the steam control unit. Superheat gains should not therefore be subtracted from the 30°C limit to arr ive at a lower minimum designed boiler outlet superheat temperature.



9.2.2 Steam Pressure The Customer must ensure that the steam supply pressure is controlled so that it meets the following specific engine requirements at entry to the Company’s steam control unit.

Engine Type Steam Pressure [bara]

TB5000 15.0 ± 0.5

SGT-200 17.5 ± 0.5

SGT-100 18.5 ± 0.5

SGT-300 18.5 ± 0.5

SGT-400 21.0 ± 0.5

Table 9.1 Steam Pressure

To compensate for any fluctuation in boiler outlet pressure due to process steam demand, it would be advisable to generate steam at higher pressures than those required and control the downstream pressure through a pressure reducing system. Higher pressure and wider fluctuation limits than given above can be accommodated within the overall system, however, the steam package will become non standard as a result. In all cases when higher pressure/wider fluctuation limits are required, a request for these must be made to the Company, in order to determine if the request can be accommodated and if so at what temperature. The Company’s prior written permission to operate outside the given parameters must be obtained. Any proposed variation from this would need to be discussed with and given the prior written approval of the Company.

9.2.3 Steam Temperature If the steam temperature, measured at the steam control unit, falls more than 5°C below the required minimum of 30°C of superheat at the supply pressure , the steam supply will automatically be isolated. Table 9.2 gives the minimum steam temperatures at entry to the steam control unit, inclusive of the 30°C superheat margin when it is supplied at the pr essures given in Table 9.1.

Engine Type Temperature [°C]

TB5000 228

SGT-200 235

SGT-100 238

SGT-300 238

SGT-400 245

Table 9.2 Minimum Steam Temperature



The maximum allowable primary steam temperature at entry to the Company’s steam control unit is 370°C for SGT-100, SGT-200 and SGT-300 and 290°C for TA, TB, TD, TE and TF. The maximum allowable secondary steam temperature at entry to the Company’s steam control unit, is 370°C for all engines. If steam is available at a high temperature and this is below the maximum temperature limits above then it is preferable to maintain the steam at that temperature rather than to use spray attemperation for superheat reduction. If high temperature steam is going to be used for NOx reduction then expected emission levels need to be determined by the Company. If spray attemperation is utilised to reduce the steam temperature, to below the maximum allowable temperature, it is important to use water of a high purity such that the resultant steam is still within the required purity limits.

9.3 Steam Purity Requirements At all times the total contamination entering the turbine from all sources shall comply with section 1.5. In addition the steam purity must conform to the following requirements:

9.3.1 Total Solids It is the customer’s responsibility to ensure that damaging particles from the pipe work must not enter the engine via the steam. Measures which would normally be considered are the use of stainless steel pipework, flushing according to the Company’s procedure, prior to use and after prolonged shutdowns and the use of appropriate strainers. The maximum total dissolved and un-dissolved solids limit is 2.0 ppmm at 1:1 steam to fuel ratio, and the Company’s reference fuel. For different steam to fuel ratios and customer fuels, the limits must be adjusted accordingly as explained in Appendix A1.2.

9.3.2 Total Dissolved Solids (TDS) The following limitation applies to dissolved solids. These are based on a 1:1 steam to fuel ratio and the Company’s reference fuel. For different steam to fuel ratios and customer fuels, the limits must be adjusted accordingly as explained in Appendix A 1.2. This is summarised in the table below for various steam to fuel ratio ranges and the company’s reference fuel:

Steam / Fuel Ratio 0 to 1:1 1:1 to 2:1 2:1 to 3:1 3:1 to 4:1 4:1 to 5:1

Allowable Total Dissolved Solids [ppmm]

1.0 0.50 0.33 0.25 0.2

Table 9.3 Allowable Total Dissolved Solids



9.3.3 Specific Solids a). Metals

In addition to the Total Dissolved Solids (TDS) limits already specified, the Company also imposes maximum levels on certain elements on an individual basis. These limits are based on a 1:1 steam to fuel ratio and the Company’s reference fuel. For different steam to fuel ratios and customer fuels, the limits must be adjusted accordingly as explained in Appendix A1.2. This is summarised in Table 9.4 for various steam to fuel ratio ranges and the company’s reference fuel. The limits in Table 9.4 are subject to the limits in Table 9.3 for total dissolved solids. Steam / Fuel Ratio 0 to 1:1 1:1 to 2:1 2:1 to 3:1 3:1 to 4:1 4:1 to 5:1

Vanadium, V 0.5 0.25 0.167 0.125 0.1

Sodium + Potassium, Na+K 0.2 0.10 0.067 0.05 0.04

Calcium + magnesium, Ca + Mg 1.0 0.5 0.333 0.25 0.2 Lead, Pb 0.1 0.05 0.033 0.025 0.02 Lithium, Li 0.5 0.25 0.167 0.125 0.1

Table 9.4 Limits for Specific Dissolved Solids [ppmm]

b). Silica (SiO2) In addition to the Total Solids limits already specified, the maximum silica content is limited to 0.04 ppmm, based on a 1:1 water to fuel ratio and the Company’s reference fuel. For different steam to fuel ratios and customer fuels, the limits must be adjusted as explained in Appendix A 1.2. This is summarised in Table 9.5 for various steam to fuel ratio ranges and the company’s reference fuel.


Silica, SiO2 0.04 0.02 0.013 0.01 0.008

Table 9.5 Limits for Silica (SiO 2) [ppmm]

9.3.4 Total Dissolved Solids Monitoring by Conductivity Measurement Although a boiler can be designed to produce steam to a TDS ppm limit, it is recognised that process monitoring of TDS is likely to be performed by conductivity measurement. To allow corrective action to be taken by the user if purity limits are exceeded, continuous or frequent measurement of steam conductivity is an essential requirement. Steam sampling should be in accordance with recommendations in BS 3285 entitled ‘Methods of Sampling Superheated Steam’. The maximum continuous levels for conductivity are defined in Table 9.6 below :


Maximum Continuous Conductivity

[ µS/cm ]

1.5 0.75 0.5 0.4 0.3

Table 9.6 Maximum Allowable Continuous Operating Conductivity Levels



If steam conductivity levels are being continuously monitored and the instrument signal is being processed by the Turbine Control Module (TCM) then the following levels should produce warning and steam system shutdown conditions. Steam / Fuel Ratio 0 to 1:1 1:1 to 2:1 2:1 to 3:1 3:1 to 4:1 4:1 to 5:1

Warning Level Conductivity [µS/cm ] 1.5 0.75 0.5 0.4 0.3

Shutdown Level Conductivity [µS/cm ]* 4.5 2.25 1.5 1.2 0.9

* Level maintained for more than 2 minutes before shutdown.

Table 9.7 Conductivity Control Limits

In all cases where continuous measurement of conductivity is being undertaken, the shutdown levels specified in Table 9.6 will initiate a steam shutdown only after being sustained at or above the stated levels for a period of 2 minutes. This should largely eliminate the effects of short term spurious signals.

If conductivity is being monitored continuously and the signal received at the TCM is exceeding the warning level for a period of 24 hours, then the steam system will be shut down automatically. Manual measurement of conductivity does not afford the same level of protection to that given by continuous monitoring and accordingly is not recommended by the Company. However, if conductivity is being measured manually and a warning level is exceeded, thereby suggesting a step change or rising trend in boiler operating conductivity, then the steam system should be shutdown and the causes investigated and rectified. Please note that conductivity monitoring equipment is not included in the Company’s steam control module and must be supplied by the customer.

9.3.5 General Steam Purity Acceptable levels of pH (alkalinity/acidity), oxygen and other contaminants not specifically mentioned within this section of the specification will be maintained by following water treatment and boiler operating recommendations made in BS 2486.

9.3.6 Boiler Water Total Dissolved Solids As steam purity is directly proportional to boiler water TDS for any given percentage water carry-over, consideration must be given to boiler water TDS levels. BS 2486 and the ABMA recommend limits for boilers operating at steady state, full load conditions. To increase the likelihood of steam purity limits being maintained during unsteady operating conditions, compliance with one of the following precautions is recommended: i) Limits must be set at 20% of those recommended by BS 2486. ii) Alternatively, increased safety margins can be designed into boiler separation equipment to reduce water carry over to 20% of the design value for full load operation.



Section 10 Cooling Liquids

If auxiliary units or driven units require cooling water or other cooling liquids, then this will be dealt with on a case by case basis.



APPENDICES

Appendix A1 Contaminants

A1.1 Comments on Contaminants The following subsections explain why the Company limits the intake of contaminants into its gas turbines.

A1.1.1 Vanadium The presence of vanadium is usually associated with liquid fuel only and not gas fuel. Vanadium readily forms low melting point compounds such as oxides and metal vanadates (in the presence of sodium or potassium) which can cause severe corrosion attack on hot section materials.

A1.1.2 Sodium and Potassium As mentioned above, sodium and potassium can combine with vanadium to form metal vanadates which are corrosive to the high temperature alloys used in hot section components. Metal sulphates can also form when combined with fuel sulphur which are similarly detrimental to hot section materials.

A1.1.3 Calcium and Magnesium These compounds are not themselves corrosive and magnesium can, in fact, inhibit the action of vanadium compounds. However, both can form hard scales in the gas turbine which are difficult to remove by washing the gas turbine.

A1.1.4 Lead Lead occurrence tends to be very low unless the fuel has been contaminated, normally either during transport or storage. However, lead is corrosive to hot section materials, and it can reverse the beneficial inhibiting effect of magnesium on vanadium compound attack.

A1.1.5 Zinc Zinc can form corrosive salts with sulphur and other elements that can attack the high temperature nickel based alloys found in gas turbine hot section components.

A1.1.6 Mercury The effects of mercury have not been experienced, but it is known to dissolve many metals to form amalgams, and therefore it is restricted as a precautionary measure.

A1.1.7 Sulphur Sulphur intake into a gas turbine is normally contained in the fuel in the form of fuel bound sulphur in the case of liquid fuel or hydrogen sulphide (H2S) in the case of gas fuel. These burn in the combustor to produce oxides such as sulphur dioxide and sulphur trioxide or low melting point metal sulphates in the presence of sodium and potassium. These compounds can deposit in the gas turbine hot section and attack its components.

Hydrogen sulphide gas is corrosive to various materials, and increasingly so when in the presence of water or high pressure. Water can combine with H2S producing sulphurous acid, while pressure can



increase attack rates. In addition to being highly poisonous in the event of leakage, high levels of H2S require systems modifications to protect against its corrosiveness due to normal system materials being incompatible. It is also necessary to avoid condensation in all plant downstream of the turbine, by maintaining the exit of the exhaust stack above the dew point.

If elemental sulphur is present in a gas fuel, it is possible that deposition can occur anywhere in the system, from fuel supply to turbine blading, restricting the safe and efficient operation of the turbine. Elemental sulphur may not necessarily be in the gas at source, but may be formed by chemical reaction, as has been found with some Low Calorific Value Gases.

A1.1.8 Lithium Lithium forms salts which, at the temperatures experienced in gas turbines, can attack the grain boundaries and accelerate the oxidation rates of hot section alloys.

A1.1.9 Chlorine, Fluorine and other Halogens Chlorine and fluorine, as well as other halogens, can attack the protective coating on hot turbine components exposing the base material, this in turn accelerates the oxidation rate and results in hot section life reduction. Chlorine is also a pre-requisite for the formation of dioxins and furans.

A1.1.10 Silicon/Silica/Siloxanes All silicon compounds including silica (SiO2) and siloxanes must be controlled by including their silicon content in the contaminant level for silicon. See A1.1.13. Silica (SiO2) is a hard abrasive material which can cause erosion and/or fouling of hot section components. Silicon compounds such as siloxanes can produce silica, which although formed as a gas, may deposit on hot section components, particularly turbine blades and combustor walls.

A1.1.11 Ash Ash is made up of incombustible solid materials and/or water soluble metal based compounds present in a liquid fuel. The solid material can cause problems by wearing fuel system components or plugging the fuel injector passages or holes. Excess of metal oxides in ash can additionally deposit and possibly corrode the turbine components. Hot section erosion can also occur. The soluble ash can introduce harmful metals or materials that can form corrosive compounds and damage the turbine hot section.

A1.1.12 Other Trace Metals Deposition of oxides of other trace metals or their compounds may occur on blades and vanes to form extremely hard deposits. Their presence can also increase the oxidation rate of blade and vane alloys due to their attack on the protective oxide coating. Hence care must be taken to limit the intake of substances such as, cadmium, antimony and other trace metals.

A1.1.13 Contaminants not listed above Landfill, bio-fuel gases and similarly, other unconventional fuels, could contain contaminants not found in petroleum fuels. Severe operational problems can be experienced with contaminants such as tar, naphthalene, and amines. If a fuel contains a contaminant for which a limit has not been included in this document, then the fuel must not be used without prior written permission from the Company.



The omission of a given contaminant from the list in section 1 does not constitute the Company’s authorisation of an unlimited level of this contaminant or its acceptance. All contaminants and their level must be declared to the Company as well as any changes in contaminant levels as a result of changing the fuel quality.

A1.2 Contaminant Levels on a Customer Fuel Equivalent Basis

As mentioned in section 1.5, the Company limits the intake of various elements and compounds to protect the gas turbine and achieve each component’s design life. In order to achieve this objective, the Company have specified concentration limits on the Company’s reference fuel equivalent basis. This considers each contaminant and determines a maximum acceptable level.

The equation in A1.2.1 gives the fuel equivalent level for all sources based on the customer’s fuel. The calculation is performed as if this contaminant was contained only in the fuel. It is necessary to calculate the limit for each contaminant from all sources based on the customer’s fuel from the limits for the reference fuel which are given in the second column of Table 1.2, as in A1.2.2.

The value obtained from sections A1.2.1 must be equal to or lower than the value from A1.2.2 otherwise the customer’s fuel will be unsuitable.

A1.2.1 Calculation Method for Contaminant Levels on a Customer Fuel Equivalent Basis Total contaminant level on a fuel equivalent basis, CFE, is calculated by summing contamination from all sources per unit of fuel. The following equation gives the total contaminant level on a fuel equivalent basis, CFE. The value obtained must be within the limits given by the equation in A.1.2.2 or the values appropriate to the net calorific value of the customer’s fuel which are given in Table 1.2.

CFE = [(AFR* x Cair) + Cfuel + (IFFR* x Cinj) + (ECWFR* x CECW)]

where:

AFR* = Air-to-Fuel Ratio, mass based (for fuel used) IFFR* = Injection Fluid-to-Fuel Ratio, i.e. Steam or Water, mass based ECWFR* = Evaporative Cooling Water-to-Fuel Ratio, mass based Cair = Concentration of a given contaminant in site air, ppmm Cfuel = Concentration of a given contaminant in customer’s fuel, ppmm Cinj = Concentration of a given contaminant in customer’s injection water or steam, ppmm CECW = Concentration of a given contaminant in site evaporative cooling water, ppmm

* Based on the customer’s fuel

Engine Typical Full Load AFR** Gas Liquid

SGT-200 58 55 SGT-100 55 52 SGT-300 52 50 SGT-400 50 47

**when using The Company’s ’s Standard Natural Gas and Standard UK Liquid Fuel

Table A1.1 Full Load AFRs for The Company’s engines



As the limits for H2S are on a volume basis, if there is H2S in the air supply, the calculation in this section must be performed on a volume basis, which means that the AFR must also be on a volume basis. The AFR can be converted to volumes by multiplying by the ratio of the gas and air densities at standard conditions.

A1.2.2 Calculation of Contaminant Limit based on Customer’s Fuel CV The total contamination from all sources, allowed for the Company’s reference fuel, must be adjusted to allow for the different mass flow of the customer’s fuel. For instance if the net CV is lower than the Company’s reference natural gas more fuel must be burnt to obtain the same output, consequently the permissible concentration is lower.

Hence the limits allowed for the Company’s reference fuel must be multiplied by the ratio of net CVs to obtain the permissible concentration of contaminants:

CFE* = CVM*/CVMO x CFE

O where:

CVm0 = Net Calorific Value of reference fuel, the Company’s reference natural gas, 48160

kJ/kg CVm* = Net Calorific Value of customer’s fuel, in kJ/kg CFE

O = Contaminant limit on the Company’s fuel equivalent basis CFE* = Contaminant limit on Customer fuel equivalent basis



Appendix A2 Gas Fuels

A2.1 Calorific Value & Wobbe Index

The Company’s gas fuel systems are designed based on a UK pipeline natural gas. The value of the Wobbe Index for the Company’s reference natural gas is 45.3 MJ/m3 when supplied at a temperature of 15°C (59°F). Guidelines to the range of major constituents for acceptable fuel composition are shown in table A2.1. Pipeline quality natural gases which meet these requirements and have net CVs in the range 37 - 49 MJ/kg are likely to be acceptable. However, a detailed fuel specification needs to be supplied in order to ensure acceptable gas properties.

Constituent % volume

Carbon Dioxide 0 - 2.9 Methane 81.3 - 96.7 Ethane 1.0 - 9.1 Propane 0.3 - 5.4 Nitrogen 0 - 14.4

Table A2.1 Constituent range for Natural Gas

Natural gases with a Wobbe Index at the gas supply temperature ranging from 37 to 49 MJ/m3 can be used on the standard fuel gas system with minor changes in valve settings (software and pressure settings) being necessary. Certain fuel gases outside this range may be acceptable but the Company’s prior written approval must be obtained in respect of the gas fuel to be used. Normally Wobbe Index is defined as below :

)

)

bara 1.013K (288 conditions standardat are where

fuel =

conditions standardat Density Relative oRD

bara 1.013K (288 conditions standardat )3(MJ/m Value CalorificNet = oCVv Where,

oRD

oCVv = o WIIndex, Wobbe

o

o

airandfuel

air

ρρ

ρρ

=

However gases at temperatures other than standard conditions will have different temperature corrected Wobbe Indices from those at standard conditions due to 2 reasons:

I. Sensible Heat Change II. Density Variation



For premium quality gases the variation in sensible heat will be negligible compared to the CVv and can be ignored. Thus correction is only necessary for the density. From the Ideal Gas Law the correction for density due to temperature is 288/Tfuel. It should be noted that low calorific value gases such as, landfill and biogas may not follow this relation Hence the temperature corrected Wobbe Index WIT is given by

edge skid turbineat the fuel of eTemperaturfuel

T Where

fuelT288o WI=

fuelT288

oRD

oCVv=

fuelT288oRD

fuelT288oCVv

ofuelT

288o

fuelT288oCVv

T WI

=

××

×

×=

×

×=

air

fuel

ρ

ρ

Therefore WIT WI . 288Tfuel

O=

This must be calculated at 288°K or 20°C above the dewpoint or at the customers quoted supply temperature whichever is the greater. Any reference within this specification to Wobbe Index will imply temperature corrected Wobbe Index.



A2.2 H2S Limit for Customer’s Fuel on a Fuel Equivalent Basis

If the net CV of a gas fuel is lower than the Company’s reference natural gas, more fuel must be burnt to obtain the same power output, consequently the permissible concentration of H2S is lower.

The H2S level must be multiplied by the ratio of net CVs on a volume basis, to obtain the permissible concentration in a customer’s gas fuel.

i.e. CCFE = CVv*/CVv

O x CFE where:

CVv0 = Net Calorific Value of reference fuel, the Company standard natural gas, 34795

kJ/Nm3

CVv* = Net Calorific Value of customer’s fuel, in kJ/Nm3

CCFE = Permitted H2S level in customer’s fuel

CFE = Permitted H2S level in the Company’s standard natural gas

A2.3 Pressure

The nominal pressure required for a typical gas is dependent on the Wobbe Index of the gas. Two gases with the same Wobbe Index number will require the same gas fuel supply pressure to a given Company turbine. Pressure requirements at skid edge are specified in the appropriate fuel system piping and instrumentation diagrams. Factors that affect the gas pressure required are: - Wobbe Index - pressure increases as Wobbe Index decreases - gas temperature - pressure increases as gas temperature increases - ambient temperature - pressure increases as ambient temperature decreases - water or steam injection - pressure increases if water or steam injection required - auto fuel changeovers - pressure increases if auto-change from gas to liquid required - DLE hardware - pressure increases if DLE required due to higher burner and combustor ∆P Maximum acceptable gas fuel supply pressure fluctuations are specified in the PID and relevant IDM.



Appendix A3 Liquid Fuels

A3.1 Properties of Liquid Fuel and Significance of Parameters

A3.1.1 Viscosity The minimum requirement of this value is so that the fuel pump may operate satisfactorily and the maximum requirement is so that atomisation will be satisfactorily achieved in the burner. Under low ambient temperature conditions fuel heating may be necessary to comply with the burner nozzle requirement. Fuels with lower viscosity such as kerosene may be suitable but, a special fuel pump and/or booster pump may be necessary. In such cases as these the Company’s prior written approval must be obtained in respect of the liquid fuel to be used.

A3.1.2 Carbon Residue This value gives an indication of the capacity of the fuel to form carbon which can block burners and form deposits in combustion chambers. A fuel with high carbon residue may result in erosion of the turbine blades.

A3.1.3 Distillation Recovery Distillation results show the volatility of the fuel and the ease with which it can be vaporised. More volatile fuels have less tendency to form smoke or soot.

Distillation characteristics give:- - valuable data regarding the safety and performance of liquid fuel - the boiling range gives information on the composition, properties and behaviour of the fuel during storage and use. - information on the volatility of the fuel and the ease with which it can be vapourised.

A3.1.4 Flash Point This is an indication of the maximum temperature at which the fuel can be stored and handled without serious fire hazard. The minimum flash point is as limited by applicable laws and insurance regulations. However excessively high flash point may result in starting difficulties. For the use of fuels with a minimum flash point above 85°C the Company’s prior written approval must be obtained.

A3.1.5 Water Too much water and sediment in the fuel tend to cause fouling of the fuel handling facilities and can cause problems in the fuel system. Sediment can cause wear in the fuel system and plugging of fuel filters and nozzles. Water in the fuel promotes bacterial growth that blocks filters and affects burner spray patterns. Contamination by water shall be a maximum of 200mg/kg. Water may be present in the fuel as dissolved water or as free (undissolved) water, or both. The free water may be fresh or saline. If the fuel is contaminated by salt water then the maximum level is subject to the 0.6 ppmm Sodium and Potassium (Na + K) limit from all sources imposed in Table 1.2 as well as the limit in Table 4.1.



For information, typical non-coastal sea water contains 3.5% dissolved salts, comprising 2.7% Sodium Chloride (NaCl) plus 0.8% Magnesium (Mg) and Calcium (Ca) chlorides and sulphates (2.7% NaCl = 1% Na).

A3.1.6 Particulate Matter Solid particles may shorten the life of fuel system components. Life of fuel pumps and various close tolerance devices is a function of particulate levels and size distributions in the fuel. High levels of particulates can lead to short cycle times in the operation of filters.

A3.1.7 Total Ash Ash is the non combustible material, for limits from all sources see table 1.2.

A3.1.8 Metallic Ashes Ash comes in two forms; 1) solid particles and 2) oil or water soluble metallic compounds. The solid particles are for the most part the same as the sediment as mentioned in A3.1.6. The soluble metallic compounds have little effect on wear or plugging but they can contain elements that produce turbine corrosion and deposits.

It is recommended for coastal and marine applications, where sodium contamination due to sea water is a possibility, that coalescing filters are incorporated in the customer's fuel system.

A3.1.9 Sulphur Normally this oxidises to sulphur dioxide, but particularly in the presence of vanadium as a catalyst, it can also be oxidised to sulphur trioxide which can then combine with sodium and potassium compounds from the ash in the fuel to form sulphates, pyrosulphates and such compounds as sodium or potassium iron trisulphate. The pyrosulphates and the trisulphates have melting points in the operating range of the gas turbine. These compounds can cause severe corrosion of gas turbine components, e.g. transition ducts and blading. The maximum sulphur limit in Table 4.1 is required for the declared component life, it is possible that more stringent restrictions may be imposed by applicable laws and environmental legislation.

A3.1.10 Copper Strip corrosion This test is designed to assess the relative degree of corrosiveness of a fuel. It is a measure of the amount of sulphur remaining in the fuel after refining.

A3.1.11 Cold Filter Plugging Point The cold filter plugging point (CFPP) is an indication of the fuels ability to flow at low temperature. Its value should be at least 10°C below the fuel supply temperature under all conditions. Unless a winter grade fuel is used, with a CFPP low enough for all ambient temperatures to be encountered throughout the year, heating of the fuel and distribution lines is required. It is recommended that a winter grade is used throughout the year subject to it meeting the viscosity requirement. This will ensure that summer grade fuel does not remain in the storage tank for use in winter. Should attempts be made to run on summer grade fuel in winter, the chance of wax precipitation and fuel system blockage is increased.



A3.1.12 Cloud Point The cloud point is the temperature at which a cloud or haze begins to appear in a dry oil due to waxy components dissolved in the fuel beginning to precipitate. Clouding is an advance warning of the onset of “flow” problems. Whilst the preferred measure of flow capabilities is the Cold Filter Plugging Point the Cloud Point is acceptable. If the ambient temperature is not at least 5°C abov e the cloud point heating of fuel and distribution lines is required.

A3.1.13 Pour Point The pour point is the temperature below which the fuel will not flow adequately. Whilst the preferred measure of flow capabilities is the Cold Filter Plugging Point the Pour Point is acceptable. If the ambient temperature is not at least 10°C abo ve the pour point heating of fuel and distribution lines is required.

A3.1.14 Density Of value in weight volume relationships and in calculating the specific energy heating value.

A3.1.15 Oxidation Stability This is an indication of stability during field storage.

A3.1.16 Vapour Pressure A maximum vapour pressure of 0.14 bara is required while at supply conditions. Fuels with higher vapour pressures may have to be supplied to the Company’s connection point at pressures in excess of those defined by the appropriate Product Standard to avoid vapour-lock formation. In such cases, reference must be made to the Company for guidance as a special fuel supply system may be required.

A3.1.17 Supply Temperature The allowable temperature range (subject to meeting the liquid fuel properties in section 4) and reasoning for supply temperatures are as follows : Minimum 0°C, (32°F) Limit to avoid problems due t o ice formation. Maximum 60°C, (140°F) Personnel safety For temperatures outside the above limits, reference must be made to the Company for guidance.

A3.1.18 Fuel Handling Requirements Liquid fuel handling requirements are specified in Company document 65/0134.



A3.2 International Diesel Fuel Specifications The suitability of commercially available diesel fuels can be established by comparison of their properties with the Company’s liquid fuel specification given in Table 4.1. As an example, Table A3.1 compares the Company’s liquid fuel specification to the liquid fuel standards listed in the introduction to section 4. The inclusion of a fuel specification in Table A3.1 does not imply its suitability for use in the Company’s engines, as can be seen by the values in the table. The values given in Table A3.1 are correct at the time of writing; however the relevant standards should be checked to ensure these values have not changed.

The Company’s

BS EN 590 :

2004

BS 2869 : 2006

ASTM D2880 - 03

ASTM D975 - 08

ISO 4261-

1993 specification

Class A2 ind/agri engines

Class D burners

1-GT 2-GT 1D 2D DST.2/DMT.2

Petroleum dist. (gas oil)

Viscosity [mm2/s (cS)] @ 40oC winter

min

2

2

1.5

1.5

1.3

1.9

1.3

1.9

1.3

@ 40oC max 7.5 4.5 5.5 5.5 2.4 4.1 2.4 4.1 5.5 Cetane number min - 51 45 - - - 40 40 - Carbon residue [wt %] 10% distillation residue

max 0.3 0.3 0.3 0.3 0.15 0.35 0.15 0.35 0.15

Distillation recovery%v/v recovered at 250oC recovered at 350oC recovered at 370oC

max min min

< 65 85 95

< 65 85 95

65 85 -

65 85 -

90% at

max 288

90% at min 282 max 338

90% at

max 288

90% at min 282 max 338

90% at

max 365

Flash point oC min as applicable regs

55 56 56 38 38 - - 56/60 land/marine

Water [mg/kg] 1 max 200 200 200 200 588 570 588 588 568 [vol %] max - - - - 0.05 0.05 0.05 0.05 0.05 Particulates [mg/kg] 1 max 10 - - - - - - - -

Total contamination [mg/kg]

max

-

24

-

-

-

-

-

-

-

Total Ash [wt %]1 max 0.01 0.01 0.01 0.01 0.01 0.01 0.01 0.01 -

Metal ash [ppm wt] 1 V

Na+K Ca Pb Zn

max max max max max

1

0.6 1

0.5 1

- - - - -

- - - - -

- - - - -

0.5 0.5 0.5 0.5 -

0.5 0.5 0.5 0.5 -

- - - - -

- - - - -

0.5 0.5 0.5 0.5 -

Sulphur [wt %]1 max 0.5 0.005 0.2 0.2 - - 0.0015 0.05 0.5

0.0015 0.05 0.5

-

Cu strip corrosion (3h @ 50oC)

max class 1 class 1 1 1 - - No 3 No 3 1

Cold filter plugging point oC max -20 -15 -12 -12 - - - - - Density @ 15oC [kg/m3] min 820 820 820 - 850 876 - - 880

max 860 845 - - - - - - - Oxidation stability [g/m3] max 25max 25 - - - - - - -

Sediment [mg/l] max - - 24 24 included with water included with water -

1 Total contaminant levels from all sources based on the Company’s reference fuel calorific value; see table 1.2, section 1.0.

Table A3.1 Comparison of diesel Fuel Specifications



Appendix A4 LPG and Naphtha fuels

A4.1 General

A4.1.1 Liquid Petroleum Gas Fuel Liquid Petroleum Gas (LPG) is a by-product of natural gas treatment processes or an incidental gas recovered during the oil extraction process. LPG is generally composed of Propane and Butane, but it can also contain lighter and/or heavier hydrocarbons. Unsaturated forms and isomers may also be present. LPG fuel quality is closely controlled by recognised National and/or International specifications which impose strict limits on Vapour Pressure, Olefins, Acetylenes, Sulphur Content, Residues and Moisture Content. The LPG could also be contaminated during transportation and/or pumping.

A4.1.2 Naphtha Fuel Naphtha is a generic, loosely defined term that covers a wide variety of light distillates. Naphtha is processed from crude oil through distillation towers in petroleum refineries. Naphthas either join the pool of feedstocks in refineries or feed steam-crackers in petrochemical plants to produce the olefins (ethylene, propylene) that are the chemical feed stocks for the organic synthesis and polymer industries. Naphtha fuels are not covered by national and/or international specifications in the same way as other liquid fuels (i.e. petrol, diesel, kerosene, aviation fuels etc.) that are commonly used in gas turbines. As a consequence the composition of the fuel can vary widely depending on source or process by which it is produced. The Naphtha could also be contaminated during transportation and/or pumping.

A4.2 Significance of Parameters and Required Limits

The following section explains the significance of the required limits.

A4.2.1 Composition

A4.2.1.1 Summary LPG fuel composition is defined by quoting concentrations of hydrocarbons of specific carbon number (C2 C3 C4 and C5) as well as overall limits for Olefins, Acetylenes and Sulphur. Higher hydrocarbons are given in the form of contaminants. Naphtha composition is defined by quoting concentrations of the more general hydrocarbons classes (Paraffins, Naphthenes, Olefins, Aromatics, Sulphur and contaminants).

A4.2.1.2 C2 C3 C4 and C5. C2 concentration (%mol) is calculated by adding together individual concentrations of all C2 hydrocarbons namely Ethane (C2H6), Ethene (C2H4) and Acetylenes (C2H2). The same procedure is applied for C3 C4 and C5 hydrocarbons.



A4.2.1.3 Paraffins (Alkanes) - Cn H 2n+2 Paraffins are saturated straight chain hydrocarbons with the general formula Cn H 2n+2. In general, paraffins tend to have a higher hydrogen/carbon ratio, lower density and higher gravimetric calorific value than other types of hydrocarbon fuels. They possess high thermal stability, and their combustion is characterized by reduced coke deposition and reduced exhaust smoke. Consequently no restrictions are usually placed on the amount of Paraffins present in gas turbine LPG and Naphtha fuels provided that vapour pressure and distillation limits are met.

A4.2.1.4 Naphthenes (Cycloalkanes or Cyclanes) - Cn H2n Naphthenes are saturated hydrocarbons with the general formula Cn H2n in which the carbon atoms link to form cyclic structures instead of chains. Their names indicate the number of carbon atoms in the ring with the prefix cyclo added. They closely resemble the combustion characteristics of Paraffins. Consequently no restrictions are usually placed on the amount of Naphthenes present in gas turbine LPG and Naphtha fuels provided that vapour pressure and distillation limits are met.

A4.2.1.5 Olefins (Alkenes and Dienes) Olefins are unsaturated hydrocarbons which contain one or two carbon-carbon double bonds in their molecules. Mono-Olefins (Alkenes) contain one double bond and comply with the general formula Cn H2n. Di-Olefins (Dienes) contain two double bonds and share the same chemical series as Acetylenes Cn H2n-2.

Olefins do not normally exist in crude oil. They are produced by conversion processes in the refinery. These molecules because of their unsaturated nature are chemically reactive and readily react with minute quantities of inorganic elements contained within the fuel such as Sulphur, Nitrogen and Oxygen to form resinous gums and rubber like materials which can foul fuel lines and injectors. These reactions are stimulated by temperature, light and the catalytic effect of metal surfaces. Di-Olefins are more reactive than Mono-Olefins especially when Sulphur compounds are present. Consequently, gum formation is minimised by excluding Olefins, removing impurities (especially mercaptans and water) and avoiding exposure to atmospheric oxygen, catalytic metal and bright lights.

A4.2.1.6 Acetylenes (Alkynes) - Cn H2n-2 Acetylenes (Alkynes) are unsaturated hydrocarbons with the general formula Cn H2n-2 which contain one or more triple carbon-carbon bonds in their molecules. Like Olefins, Acetylenes also undergo additional reactions.

A4.2.1.7 Aromatics Cn H2n-6 Aromatics are Benzene ring compounds with the general formula Cn H2n-6. Examples are Benzene, Toluene and Naphthalene. Aromatic compounds are unsaturated compounds yet they do not easily partake in additional reactions. Combustion of highly aromatic fuels, however can result in increased smoke, carbon or soot deposition and increased combustor metal temperature via radiative heat transfer. Aromatics are also highly hygroscopic in nature thus leading to the precipitation of ice crystals when the fuel is exposed to low temperatures. Aromatics can also affect the integrity of rubber seals and therefore special consideration must be given to the design of the system.



A4.2.1.8 Mercaptan Sulphur Mercaptan Sulphur must be minimised as it has an adverse effect on fuel system elastomers, and is corrosive to fuel system components. Gum formation is also minimised by excluding mercaptans especially when Olefins are present in the fuel (see section A4.2.1.5).

A4.2.1.9 Vapour Pressure The vapour pressure of a liquid fuel is the pressure exerted by the vapour above its surface at a given temperature. The higher the vapour pressure the easier it is to vaporise the fuel. Conversely, the lower the vapour pressure, the easier it is to liquefy the fuel.

A4.2.10 Relative Density Although not a specific requirement, the relative density (based on water) must be determined for other purposes and must therefore be reported.

A4.2.11 Kinematic viscosity A typical kinematic viscosity for LPG or naphtha fuel is much lower than for diesel fuel. The Company uses non-standard fuel systems for LPG and naphtha fuels that use purpose made fuel pumps that can handle the low viscosity.

A4.2.12 Lubricity Lubricity has recently been introduced to characterise the lubrication behaviour displayed by liquid hydrocarbons in non-hydrodynamic regimes (boundary lubricated regimes) as opposed to hydrodynamic regimes. In hydrodynamic lubrication, viscosity, which decreases with increasing temperature, is the only key parameter. Boundary lubrication, is a condition in which the friction and wear between two surfaces in relative motion are determined by the properties of the surfaces and the properties of the contacting fluid other than viscosity. A typical lubricity for LPG and Naphtha fuels is much lower than for diesel fuels. The Company’s fuel systems use purpose made fuel pumps which can handle the low lubricities of liquid LPG and Naphtha fuels. .

A4.2.13 Oxidation stability All petroleum products come into contact with air and hence with oxygen. Prolonged oxidation of the fuel with air can cause certain types of liquid fuel to form gums and deposits which may block fuel filters and fuel injector passages. Hence it is usual to perform an oxidation stability test to measure the tendency of a fuel to form gum and deposits under accelerated aging conditions.

A4.2.14 Saybolt Colour Determination of the colour of petroleum products is used mainly for quality control purposes and is an important quality characteristic since colour is readily observed by the user of the product. In some cases the colour may serve as an indication of the degree of refinement of the fuel. When the colour range of the product is known, a variation outside the established range may indicate possible contamination with another product.



A4.2.15 Residue Control over residue content is of considerable importance in LPG and Naphtha fuel applications. Failure to limit the permissible concentration of residue materials may result in troublesome deposits in the fuel system and/or the combustion system.

A4.3 LPG and Naphtha - Supply Conditions

The conditions for supply of these fuels to the Company turbine package are defined by the appropriate fuel system piping and instrumentation diagram (P&ID).

A4.3.1 Gaseous LPG As stated in section 3.3.1, the minimum supply temperature for a gas fuel, must be at least 20ºC above dew point at the supply pressure. This margin is necessary to avoid formation of liquid droplets downstream of any restrictions in the fuel system. The recommended method for achieving this objective is the use of a vaporiser to heat the liquid LPG to approximately 98% dryness factor (the dryness factor must be defined for the fuel used) followed by a separator/demister to remove the liquid phase (which includes any contaminants in the fuel), then followed by a superheater to increase the temperature to the required level. This will improve the operability of the gas turbine and reduce the risk of liquid condensate reaching the turbine with consequent failure (particularly on load accept).

A4.3.2 LPG and Naphtha - Handling and Storage

LPG and Naphtha fuels have a lower flash point than distillate oil and are heavier than air when in gaseous form. Special procedures/precautions therefore have to be adopted in handling and storage of these fuels in order to prevent explosion by ensuring that spillage and leaks are properly dissipated. LPG installations must comply with the Codes of Practice of the UK LP Gas association. The Company will advise on Naphtha installation requirements. Electrostatic charge formation during handling, pumping and circulating of these fuels must be avoided. The use of an appropriate additive to dissipate electrostatic charge may also be required in addition to normal grounding procedure (in this case a specialist consultant is required).

A4.4 Fuel Supply Quality Control Procedure

LPG and Naphtha fuels are typically clean fuels but there are some areas where contamination can occur, for example during transportation, storage and pumping. Gas turbine problems in the past have resulted from contamination of the fuel. Hence the responsibility lies with the operator to ensure compliance with The Company’s specification before use in the gas turbine. Fuels found to be outside the specification must be treated and/or cleaned accordingly or the batch rejected. Examples of common sources of contamination and methods for removal are listed below: 1/ LPG and Naphtha fuels can be contaminated with heavy lubricating oils which may leak from LPG compressors or pumps. The use of self lubricating (oil free) compressors and pumps would remove this problem. 2/ Water and sulphur contamination of naphtha fuels is common. Salts and ash forming components are also carried with the water. The water (as well as solid contaminants) must be effectively removed



from the fuel by means of a centrifuge and/or settling tanks, at site, before using the fuel in the gas turbine. 3/ Both LPG and Naphtha fuels can be contaminated with residual fuels/oils, etc., as a result of using the same tankers for transportation. For gaseous LPG the recommended method for removing these contaminants is described in section A4.3.1. For liquid LPG and Naphtha appropriate methods for removing these contaminants must be implemented (e.g. for LPG this may include the use of a vaporiser followed by a condenser etc.).

Fluids Spec 65-0027 Issue6 07 01 13

Documents

Transcript of Fluids Spec 65-0027 Issue6 07 01 13