Specification for Fuel Gases for Combustion in Heavy-Duty Gas Turbines
This Document is Printed here just for your reference it is original Property of GE.
Note: These instructions do not purport to cover all details or variations in equipment nor to provide for every possible contingency to be met in connection with installation, operation or maintenance. Should further information be desired or should particular problems arise which are not covered sufficiently for the purchaser’s purposes the matter should be referred to the GE Company.
General Electric heavy-duty gas turbines have the ability to burn a wide classification of gaseous fuels as shown in Table 1. The properties of these gases can vary significantly due to the relative concentrations of the reactant and inert constituents. In order to protect the gas turbine and to burn these fuels in an efficient and trouble free manner, allowable ranges are defined in this specification for physical properties, constituents and contaminants.
Table 2a specif ies the allowable limits for the fuel properties and constituents and Table 2b lists the limitation on contaminants. These tables provide a screen for fuels that are acceptable for all frame sizes and combustor types. Fuels that fall outside of these limits may be acceptable for specific applications e.g. a high hydrogen fuel can be used with standard combustors in most cases. Contact GE for further evaluation of these fuels.
Table 3 identifies the acceptable test methods to be used for determining gas fuel properties shown in Tables 2a and 2b.
Fuel Property and Contaminant Notes:
- All fuel properties must meet the requirements from ignition to base load unless otherwise stated.
- Values and limits apply at the inlet of the gas fuel control module, typically the purchaser’s connection, FG1.
- Minimum and maximum gas fuel supply pressure requirements are furnished by GE as part of the unit proposal.
- The minimum fuel gas temperature must meet the required superheat as described in section III, C. Separate requirements are included for hydrocarbon and moisture superheat. The maximum allowable fuel temperature is defined in GER 4189(2).
- Heating value ranges shown are provided as guidelines. Specific fuel analysis must be furnished to GE for proper analysis. (see section III, A)
- See section III, B for definition of Modified Wobbe Index (MWI).
- The upper and lower limits for MWI shown are what can be accommodated within the standard dry low NOx fuel system designs. Fuels outside of this range may need additional design and development effort. Performance fuel heating may be restricted on fuel with high inert content to stay above the minimum MWI limit.
- Variations of MWI greater than + 5% or –5% may be acceptable for some applications, (i.e. on units that incorporate gas fuel heating). GE must analyze and approve all conditions where the 5% variation is to be exceeded. See also Section III, B for applications where the MWI varies between the +/- 5% limits.
- There is no defined maximum flammability ratio limit. Fuel with flammability ratio significantly larger than those of natural gas may require a start–up fuel.
- Candidate fuels, which do not meet these limits, should be referred to GE for further review. All fuels will be reviewed by GE on a case-by-case basis. (see section III, G)
- When fuel heating for thermal efficiency improvements is utilized (e.g. Tgas > 300°F) there is a possibility of gum formation if excess aromatics are present. Contact GE for further information.
- The quantity of sulfur in gas fuels is not limited by this specification. Experience has shown that fuel sulfur levels up to 1% by volume do not significantly affect oxidation/corrosion rates. Hot corrosion of hot gas path parts is controlled by the specified trace metal limits. Sulfur levels shall be considered when addressing HRSG Corrosion, Selective Catalytic Reduction (SCR) Deposition, Exhaust Emissions, System Material Requirements, Elemental Sulfur Deposition and Iron Sulfide. (see section IV, D)
- The contamination limits identified represent the total allowable limit at the inlet to the turbine section. These limits will be reduced if comparable contaminants are present in the compressor inlet air and combustion steam/water injection. Consult with GE for limits for specific applications.
- Sodium and potassium, from salt water, are the only corrosive trace metal contaminants normally found in natural gases. Na/K =28 is nominal sea salt ratio. Other trace metal contaminants may be found in Gasification and Process Gases. GE will review these on a case-by-case basis.
- The fuel gas delivery system shall be designed to prevent the generation or the admittance of solid particulate to the gas turbine gas fuel system. This shall include but not be limited to particulate filtration and non-corrosive (i.e. stainless steel) piping from the particulate filtration to the inlet of the gas turbine equipment. Fuel gas piping systems shall be properly cleaned/flushed and maintained prior to gas turbine operation. (see section IV, A)
- The fuel gas supply shall be 100% free of liquids. Admission of liquids can result in combustion and/or hot gas path component damage. (see section III, C) GE will require an input signal from the conditioning system liquid level indication closest to the GE Speed Ratio Valve or Gas Control Valve. This liquid level indication will be brought into the turbine controller and used as a signal to stop Gas Turbine operation when the liquid level reaches a fault level. It is highly recommended that this device have redundancy. The supplier of the gas conditioning system should provide this signal.
Test Method Notes
- Hydrocarbon and water dew points shall be determined by direct dew point measurement (chilled mirror device). If dew point cannot be measured, an extended gas analysis, which identifies hydrocarbon components from C1 through C14, shall be performed. This analysis must provide an accuracy of greater than 10 ppmv. A standard gas analysis to C6+ is normally not acceptable for dew point calculation unless it is known that heavier hydrocarbons are not present, as is most often the case with liquefied natural gases.
- This test method will not detect the presence of condensable sulfur vapor. Specialized filtration equipment is required to measure sulfur at concentrations present in vapor form. Contact GE for more information.
II. FUEL GAS CLASSIFICATION
A. Natural Gas, Liquefied Natural Gas (LNG) And Liquefied Petroleum Gas (LPG)
Natural gases are predominantly methane with much smaller quantities of the slightly heavier
hydrocarbons such as ethane, propane and butane. Liquefied petroleum gas is propane and/or butane with traces of heavier hydrocarbons.
- Natural Gas
Natural gases normally fall within the calorific heating value range of 800 to 1200 Btu per standard cubic foot. Actual calorific heating values are dependent on the percentages of hydrocarbons and inert gases contained in the gas. Natural gases are found in and extracted from underground reservoirs. These “raw gases” may contain varying degrees of nitrogen, carbon dioxide, hydrogen sulfide, and contain contaminants such as salt water, sand and dirt. Processingby the gas supplier normally reduces and/or removes these constituents and contaminants prior to distribution. A gas analysis must be performed to ensure that the fuel supply to the gas turbine meets the requirements of this specification.
- Liquefied Natural Gas (LNG)
Liquefied natural gas is produced by drying, compressing, cooling and expanding natural gas to approximately -260°F at 14.7 psia. The product is transported as a liquid and delivered as a gas after pressurizing and heating to ambient temperature. The composition is free of inerts and moisture and can be treated as a high quality natural gas. LNG can pick up moisture that is present in the pipeline but it is not a source of the moisture. The hydrocarbon dew point is typically less than -10°F at 500 psia but, depending on the processing steps and tank size, the dew point may increase if the boil-off is continuously extracted between deliveries. Cooling and recompression of the boil-off will avoid this potential problem. The expected range in component concentrations should be obtained from the gas supplier to determine the potential change in dew point.
- Liquefied Petroleum Gases
The heating values of Liquefied Petroleum Gases (LPGs) normally fall between 2300 and 3200 Btu/scft (LHV). Based on their high commercial value, these fuels are normally utilized as a back-up fuel to the primary gas fuel for gas turbines. Since LPGs are normally stored in a liquid state, it is critical that the vaporization process and gas supply system maintains the fuel at a temperature above the minimum required superheat value. Fuel heating and heat tracing are required to meet these requirements.
B. Gasification Fuels Gasification fuels are produced by either an oxygen blown or air blown gasification process and are formed using coal, petroleum coke or heavy liquids as a feedstock. In general, the heating values of gasification fuel are substantially lower than other fuel gases. The reduced heating value of gasification fuels result in the effective areas of the fuel nozzles being larger than those utilized for natural gas fuels.
- Oxygen Blown Gasification
The heating values of gases produced by oxygen blown gasification fall in the range of 200 to400 Btu/scft. The hydrogen (H2) content of these fuels are normally above 30% by volume and have H2/CO mole ratio between 0.5 to 0.8. Oxygen blown gasification fuels are often mixed with steam for thermal NOx control, cycle efficiency improvement and/or power augmentation. When utilized, the steam is injected into the combustor by an independent passage. Due to the high hydrogen con-tent of these fuels, oxygen blown gasification fuels are normally not suitable for Dry Low NOx (DLN) applications (see Table 2a). The high flame speeds resulting from high hydrogen fuels can result in flashback or primary zone re-ignition on DLN pre-mixed combustion systems. Utilization of these fuels requires evaluation by GE.
- Air Blown Gasification
Gases produced by air blown gasification normally have heating values between 100 and 150 Btu/ scft. The H2 content of these fuels can range from 8% to 20% by volume and have a H2/CO mole ratio 0.3 to 3:1. The use and treatment of these fuels is similar to that identified for oxygen blown gasification. Gasification fuels provide a significant fraction of the total turbine mass flow rate. With oxygen blown fuels the diluents addition (typically nitrogen) also assists with NOx control. Careful integration of the gas turbine with the gasification plant is required to assure an operable system. Due to the low volumetric heating value of both oxygen an air blown gases, a special fuel system and fuel nozzles are required.
C. Process Gases Many chemical processes generate surplus gases that may be utilized as fuel for gas turbines. (e.g. tail or refinery gases). These gases often consist of methane, hydrogen, carbon monoxide, and carbon dioxide that are normally byproducts of petrochemical processes. The hydrogen and carbon monoxide content, these fuels result in a high rich-to-lean flammability limit. These types of fuels often require inerting and purging of the gas turbine gas fuel system upon unit shutdown or a transfer to a more conventional fuel. When process gas fuels have extreme flammability limits such that the fuel will auto ignite at turbine exhaust conditions, a more “conventional” start-up fuel is required. Additional process gases that are utilized as gas turbine fuels are byproducts of steel production.
- Blast Furnace Gases
Blast Furnace Gases (BFGs), alone, have heating values below the minimal allowable limits. These gases must be blended with other fuels such as coke oven gas, natural gas or hydrocarbons such as propane or butane to raise the heating value above the required lower limit.
- Coke Oven Gases
Coke oven gases are high in hydrogen and methane and may be used as fuel for non-DLN
combustion systems. These fuels often contain trace amounts of heavy hydrocarbons, which may lead to carbon buildup on the fuel nozzles. The heavy hydrocarbons must be “scrubbed” or removed from the fuel prior to delivery to the gas turbine.
- COREX Gases
COREX gases are similar to oxygen blown gasified fuels, and may be treated as such. They are usually lower in H2 content and have heating values lower than oxygen blown gasified fuels. Further combustion related guidelines may be found in Bureau of Mines Circulars 503(5) and 622(6).
III. FUEL PROPERTIES
A. Heating Values
The heat of combustion, heating value or calorific value of a fuel is the amount of energy generated by the complete combustion of a unit mass of fuel. The US system of measurement uses British thermal units (Btu) per pound or Btu per standard cubic foot when expressed on a volume basis. The heating value of a gas fuel may be determined experimentally using a calorimeter in which fuel is burned in the presence of air at constant pressure. The products are allowed to cool to the initial temperature and a measurement is made of the energy released during complete combustion. All fuels that contain hydrogen release water vapor as a product of combustion, which is subsequently condensed in the calorimeter. The resulting measurement of the heat released is the higher heating value (HHV), also known as the gross heating value, and includes the heat of vaporization of water.
The lower heating value (LHV), also known as the net heating value, is calculated by subtracting the heat of vaporization of water from the measured HHV and assumes that all products of combustion including water remain in the gaseous phase. Both the HHV and LHV may also be calculated from the gas compositional analysis using the procedure described in ASTM D 3588. For most gas fuels, a standard gas analysis to C6+ is adequate for determination of heating value, but an extended C14 analysis(4) may also be used if available. Gas turbines do not operate with condensing exhaust systems and it is common gas turbine industry practice to utilize the LHV when calculating the overall cycle thermal efficiency.
B. Modified Wobbe Index (MWI)
Gas turbines can operate with fuel gases having a very wide range of heating values, but the amount of variation that a specific fuel system design can accommodate is limited. The fuel nozzles are designed to operate within a fixed range of pressure ratios and changes in heating value are accommodated for by increasing or decreasing the fuel nozzle area or gas temperature. A measure of the interchangeability of gas fuels for a given system design is the MWI(7). This term is used as a relative measure of the energy injected to the combustor at a fixed pressure ratio and is calculated using the fuel lower heating value, the specific gravity with respect to air and the fuel temperature.
The mathematical definition is as follows:
The allowable MWI range is established to ensure that required fuel nozzle pressure ratios are
maintained during all combustion/turbine modes of operation. When multiple gas fuels are supplied and/or if variable fuel temperatures result in a MWI that exceed the 5% limitation, independent fuel gas trains, which could include control valves, manifolds and fuel nozzles, may be required for standard combustion systems. For DLN systems, an alternate control method may be required to ensure that the required fuel nozzle pressure ratios are met. An accurate analysis of all gas fuels, along with fuel gas temperature- time profiles shall be submitted to GE for proper evaluation.
MWI Variability Within the +/-5% Range
This gas fuel specification is written to provide customers with the allowable limits of gas fuel
properties that can be tolerated with a specific set of hardware and permit the turbine to operate within the normal limits for emissions and combustor dynamics. It was not written with the intent of addressing fuel variability within the stated limits. The gas turbine can operate successfully within the stated limits without the need for outages or for combustion system hardware modification such as fuel nozzle changes. It is expected that as the fuel properties vary from one extreme limit to the next, some controls adjustments to change combustor operation may be required to operate the combustion system with optimum dynamics and emissions performance. Currently, these controls changes are performed manually, on-line and without the need for an outage. Accordingly, if the variability
described above is encountered on a frequent (daily, weekly) basis, then an automatic compensation system may be preferable to constant monitoring with manual intervention.
Exceptions to the fuel specif ication must be evaluated on a case-by-case basis.
C. Superheat Requirement
The superheat requirement is establish to ensure that the fuel gas supply to the gas turbine is 100% free of liquids. Superheat is the temperature difference between the gas temperature and the respective dew point. The requirement is independent of the hydrocarbon and moisture concentration. Depending on its constituents, gas entrained liquids could cause degradation of gas fuel nozzles, and for DLN applications, premixed flame flashbacks or re-ignitions.
Condensation of moisture must be avoided to prevent the formation of gas hydrates and collection of water in low points of the gas fuel system. The superheat requirement is specified to provide enough margin to compensate for the temperature reduction as the gas expands across the gas fuel control valves. The requirements are applicable at all operating conditions and apply to all units including those installed with either standard or DLN combustion systems. Exceptions are units burning coal derived low Btu fuels, the requirements for which must be determined on a case-by-case basis. The superheat requirements take into account the gas temperature drop and the relationship of the moisture and hydrocarbon dew point lines to the gas fuel pressure. Because of differences between the dew point line characteristics in the
region of interest (less than 700 psia), the opportunity for moisture condensation as the gas expands is less than that for hydrocarbons. Advantage has been taken of this physical property to provide users with two separate requirements in order to minimize the cost of superheating. In addition, the superheat requirements depend on the expansion ratio across the control valves and are therefore be expressed as a function of the incoming gas pressure at the inlet to the gas fuel control system.
The superheat requirements are shown graphically on Figure 1 for moisture and hydrocarbons. Both should be determined and added to the respective dew points (moisture and hydrocarbon) at the gas turbine fuel delivery pressure. The higher of the two values, superheat plus dew point, will determine the preliminary minimum gas fuel temperature that is required in order to meet the superheat requirements. In some cases, the hydrocarbon dew point may be low enough, that the requirement for meeting the moisture superheat will dominate. However, if the hydrocarbon dew point is close to the moisture dew point, and the hydrocarbon dew point varies sufficiently, the moisture and hydrocarbon superheat requirements may flip-flop on which one dominates. In order to avoid this situation, GE has developed a breakpoint strategy. The breakpoints that will be used are based on gas supply
pressure, as seen in the table below:
Maximum Hydrocarbon Dew Point less than Breakpoint
If the maximum hydrocarbon dew point, calculated during the Order to Requisition process, is below the breakpoint level, then GE will assume that the hydrocarbon superheat requirements are less than the moisture superheat requirements. Therefore, the minimum gas temperature will be determined by the moisture dew point plus the moisture superheat.
Maximum Hydrocarbon Dew Point greater than Breakpoint
However, if the maximum hydrocarbon dew point, calculated during the Order to Requisition
process, is above a breakpoint, then GE will assume the unconditioned gas is saturated. This will require the full hydrocarbon superheat to be applied to the unconditioned gas. The resulting gas temperature may be higher than just adding the hydrocarbon dew point and hydrocarbon superheat.
See Appendix 4 for a sample calculation.
Continuous Hydrocarbon Dew Point Measurement
An alternate approach, to the use of a breakpoint, is to provide instrumentation to measure the
hydrocarbon dew point continuously, and provide that signal to GE through the gas turbine
controller. The turbine controller will then use the hydrocarbon dew point, along with the moisture dew point, provided during the Order to Requisition process, to determine if sufficient superheat has been provided.
Non-superheated Gas Temperature Signal
GE will require an input signal, into the turbine controller, of the gas fuel temperature upstream of any performance or superheating system. The turbine controller will take action if sufficient superheat is not supplied.
D. Hydrocarbon Dew Point
The hydrocarbon dew point is the temperature at which the first droplet of hydrocarbon forms as the gas temperature is reduced at a given pressure and is analogous to the moisture dew point. The hydrocarbon dew point is very sensitive to small concentrations of heavy hydrocarbons (C6+) and contamination of the gas sample during sampling can be an issue. The use of a sample probe and following the sampling procedure described in GPA 2166(3), particularly with respect to sample cylinder purging, can avoid these problems. For this reason the recommended method for hydrocarbon dew point determination is by direct measurement using a chilled mirror instrument (ASTM D 1142). If a direct measurement cannot be performed, the dew point may be calculated from the extended C14 gas fuel analysis(4). Use of a C6+ analysis for dew point determination may result in an under-estimation of 30°F to 40°F or more. Exceptions are fuels that do not contain heavy hydrocarbons such as liquefied natural gas.
E. Moisture Dew Point
The gas fuel moisture dew point is dependent upon the moisture concentration and the gas fuel
pressure. When expressed in units of lbs/mmscft (pounds per million standard cubic feet), the
resulting dew point is practically independent of the gas fuel composition (other than moisture). Typically, many pipeline tariffs limit the maximum allowable moisture content to 7 lbs/mmscft while the actual value may be significantly less. It is the maximum allowable value, however, that determines the design requirements for superheat. Figure 2 is included to provide a guide for determining the expected moisture dew point from the moisture concentration and gas fuel pressure of a typical natural gas. The actual dew point will vary slightly with gas composition changes.
F. Flammability Ratio
Fuel gases containing hydrogen and/or carbon monoxide will have a ratio of rich-to-lean
flammability limits that is significantly greater than that of natural gas. Typically, gases with greater than 5% hydrogen by volume fall into this range and require a separate startup fuel. GE will evaluate the gas analysis to determine the requirement for a start-up fuel. Fuel gases with large percentages of an inert gas such as nitrogen or carbon dioxide will have a ratio of rich-to-lean flammability limits less than that of natural gas. Flammability ratios of less than 2.2 to 1 based on volume at ISO conditions (14.696 psia and 59°F), may experience problems maintaining stable combustion over the full operating range of the turbine.
G. Gas Constituent Limits
Gas constituent limits are specified to assure stable combustion through all gas turbine loads and modes of operation. A detailed gas analysis must be furnished to GE for proper evaluation. See reference (3) for the recommended sampling procedure and ASTM D1945 for a C6+analysis
H. Gas Fuel Supply Pressure
Gas fuel supply pressure requirements are dependent on the gas turbine model, the combustion system design, the fuel gas analysis and unit specific site conditions. As part of the unit proposal, GE will furnish minimum and maximum gas fuel supply pressure requirements.