GAS TURBINES
49. GAS TURBINES
49.1. GLOSSARY
Aircraft-derivative gas turbine
An aircraft jet engine modified for ground applications to produce shaft power instead of
thrust.
Base rating
The designed rating point of a gas turbine at which it is suitable for continuous operation.
Referenced to standard ISO conditions. (See “ISO rating.”)
Cogeneration
The sequential production of heat and power or recovery of low-level energy for power
production.
Combined cycle
A combined steam and gas turbine arrangement in which the gas turbine exhaust is
ducted to a heat-recovery steam generator which supplies steam to the steam turbine.
Compression ratio
The ratio of the compressor discharge pressure to the suction pressure.
Firing temperature
The mass-flow mean total temperature of the working fluid measured in a plane
immediately upstream of the first-stage turbine buckets.
Fuel consumption
The input fuel heating value per unit of time to a gas turbine, generally measured in Btu/h
(kJ/h), also called heat consumption. It is generally stated in terms of the lower heating
value (LHV) of the fuel by gas turbine manufacturers, but can also be in terms of pounds
per hour, where typical heating values are 18,500 Btu/lb (42,940 kj/kg) for liquid fuels
and 21,500 Btu/lb (49,902 kj/kg) LHV for natural gas. (Also see “Specific Fuel
Consumption.”)
Heat rate
The fuel consumption of a gas turbine divided by the output. For mechanical-drive gas
turbines this is the net output including the on-base auxiliary power losses. For generatordrive gas turbines this includes these auxiliaries plus the generator losses. It does not
include the power requirements for off-base lubrication oil cooling or heavy fuel
treatment, unless specified as in certain totally packaged designs. Expressed as British
thermal units or kilojoules per kilowatthour or horsepower hour. It is usually expressed in
terms of the LHV of the fuel.
Heavy-duty industrial gas turbine
A type of gas turbine designed specifically for ground applications using a design
philosophy similar to that of the steam-turbine industry. Casings are split on the
horizontal centerline, with on-site maintenance planned after long periods of operation.
Heavy fuel
Liquid petroleum fuels that are ash bearing and not true distillates. These can be crude oil
or residuals (No.5 or 6), or a blend of a distillate and residuals.
High heating value
The gross heating value of the fuel. This includes the latent heat required to vaporize the
water in the products of combustion, which is not truly available to a combustion device
having an exhaust temperature higher than 212°F (100°C).
Hot gas path
The path of the working fluid of a gas turbine during and after combustion. It includes the
fuel nozzles, combustion chamber and liner (if required), transition pieces to the turbine,
stationary and rotating airfoils (nozzles and buckets), and exhaust plenum and ducting.
ISO rating
The rated output of a gas turbine at standard site conditions as specified by the
International Standards Organization:sea-level altitude, standard atmospheric pressure of
14.7 psia (101.4 kPa) at the turbine inlet and exhaust, 59°F (15°C) ambient temperature,
and 60 percent relative humidity.
NO 2
Oxides of nitrogen include both NO and NO 2. Emission limits are generally based on
parts per million by volume (ppmv) of the total of NO and NO 2 emitted by combustion
devices.
Peak rating
The designed rating point for gas turbines for peak-load service generally operated at less
than 1000/yr. Not generally used for industrial applications which are base-loaded.
Regenerative cycle
A gas turbine that includes a gas-to-gas heat exchanger which transfers heat from the
exhaust to the compressor discharge air to reduce fuel consumption.
Simple cycle
A gas turbine that exhausts to the atmosphere without heat recovery.
Specific fuel consumption (SFC)
The gas turbine fuel consumption per unit of output. SFC is usually stated in terms of
pounds per kilowatt hour or pounds per horsepower hour using LHV.
Specific work
The output of a gas turbine per unit of air flow. It can be horsepower seconds per pound
or British thermal units per pound (kilojoules per kilogram).
Thermodynamic efficiency
The net output of a gas turbine divided by the input. It is the reciprocal of heat rate after
normalizing units. For example:
49.2. PRINCIPLES
49.2.1. Thermodynamic Fundamentals
A schematic diagram for a simple-cycle, single-shaft gas turbine is shown in Fig. 6.50. Air enters
the axial flow compressor at point 1 of the schematic at ambient conditions. Since these
conditions vary from day to day and from location to location, it is convenient to consider some
standard conditions for comparative purposes. The standard conditions used by the gas turbine
industry are 59°F (15°C), 14.7 psia (1.013 bar), and 60 percent relative humidity, which were
established by the International Organization for Standardization (ISO). These conditions are
frequently referred to as ISO conditions.
Figure 6.50. Simple-cycle, single-shaft gas turbine.
Air entering the compressor at point 1 is compressed to some higher pressure. No heat is added;
however, the temperature of the air rises due to compression, so that the air at the discharge of
the compressor is at a higher temperature and pressure.
Upon leaving the compressor, air enters the combustion system at point 2, where fuel is injected
and combustion takes place. The combustion process occurs at essentially constant pressure.
Although very high local temperatures are reached within the primary combustion zone
(approaching stoichiometric conditions), the combustion system is designed to provide mixing,
dilution, and cooling. Thus, by the time the combustion mixture leaves the combustion system
and enters the turbine at point 3, it is at a mixed average temperature.
In the turbine section of the gas turbine, the energy of the hot gases is converted into work. This
conversion actually takes place in two steps. In the nozzle section of the turbine, the hot gases
are expanded and a portion of the thermal energy is converted into kinetic energy. In the
subsequent bucket section of the turbine, a portion of the kinetic energy is transferred to the
rotating buckets and converted to work.
Some of the work developed by the turbine is used to drive the compressor, and the remainder is
available for useful work at the output flange of the gas turbine. Typically, more than 50 percent
of the work developed by the turbine sections is used to power the axial flow compressor.
The thermodynamic cycle upon which all gas turbines operate is called the Brayton cycle. Figure
6.51 shows the classical pressure-volume (PV) and temperature-entropy (TS) diagrams for this
cycle. The numbers on this diagram correspond to the numbers also used in Fig. 6.50. Every
Brayton cycle can be characterized by two significant parameters: pressure ratio and firing
temperature. The pressure ratio of the cycle is the pressure at point 2 (compressor discharge
pressure) divided by the pressure at point 1 (compressor inlet pressure). In an ideal cycle, this
pressure ratio is also equal to the pressure at point 3 divided by the pressure at point 4. However,
in an actual cycle, there is some slight pressure loss in the combustion system and, hence, the
pressure at point 3 is slightly less than at point 2. The other significant parameter is the firing
temperature, which is the highest temperature reached in the cycle. The most accepted definition
of firing temperature is the mass-flow mean total temperature at the first-stage nozzle trailing
edge plane. In a gas turbine without first-stage turbine nozzle cooling (in which air enters the hot
gas stream after cooling down the nozzle), the total temperature immediately downstream of the
nozzle is equal to the temperature immediately upstream of the nozzle. With turbine nozzle
cooling, this cooling air mixes with the hot gases expanding through the nozzle. This definition
utilizes a temperature that is indicative of the cycle temperature represented by point 3 of Fig.
6.51.
Figure 6.51. Brayton cycle.
An alternate method of determining firing temperature is defined in ISO document 2314, “Gas
Turbines-Acceptance Tests.” The firing temperature here is really a reference turbine inlet
temperature, and is not generally a temperature that exists in a gas turbine cycle. It is calculated
from a heat balance on the combustion system, using parameters obtained in a field test. This
ISO reference temperature will always be less than the true firing temperature, in many cases by
100°F (37°C) or more for machines using air extracted from the compressor for internal cooling.
Figure 6.52 shows how these various temperatures are defined.
Figure 6.52. Definition of firing temperature.
The thermal efficiency of the Brayton cycle can be calculated using classical thermodynamic
analysis. The compression ratio of the working fluid and the temperatures of heat addition and
heat rejection are very important parameters. The results of such an analysis are shown in Fig.
6.53. These calculations are based on an ambient temperature of 59°F (15°C), actual component
efficiencies, and real gas relationships. The results are plotted as thermal efficiency versus
specific work for two different firing temperatures.
The observations that can be made from these curves are:
o
o
o
Thermal efficiency increases as heat is added.
For a given firing temperature there is an optimum pressure ratio for achieving maximum
thermal efficiency.
For a given firing temperature there is an optimum pressure ratio for achieving the
maximum specific work which is different from the optimum thermal-efficiency pressure
ratio.
Figure 6.53. Efficiency vs.specific work of gas turbine cycles.
49.2.2. Design Features
There are many different design features among the gas turbines available for industrial plant
applications. Some of the more important characteristics are:
o
o
o
One or more shafts
Heavy-duty industrial type or aircraft derivative
Combustion-chamber design
As shown in Fig. 6.50, single-shaft gas turbines are configured in one continuous shaft and,
therefore, all stages operate at the same speed. These units are typically used for generator-drive
applications where significant speed variation is not required.
A schematic diagram for a simple-cycle, two-shaft gas turbine is shown in Fig. 6.54. The lowpressure or power turbine rotor is mechanically separate from the high-pressure turbine and
compressor rotor. This unique feature allows the power turbine to be operated at a wide range of
speeds, and makes two-shaft gas turbines ideally suited for variable-speed applications.
All of the work developed by the power turbine is available to drive the load equipment since the
work developed by the high-pressure turbine supplies all the necessary energy to drive the
compressor. Further, the starting requirements for the gas turbine load train are reduced since the
load equipment is mechanically separate from the high-pressure turbine.
Figure 6.54. Simple-cycle, two-shaft gas turbine.
The designs of gas turbines have evolved from two distinct philosophies. Industrial-type units
have been based on the technology developed in the steam-turbine industry for large central
stations. Of robust construction, with casings split along the horizontal centerline, these units are
designed for long periods of continuous operation, generally have the capability to burn a variety
of fuels, and are maintained on-site. Aircraft-derivative gas turbines are jet engines modified to
produce shaft power instead of thrust. Of lightweight construction, aircraft-derivative gas
turbines are generally derated from flight-takeoff firing temperatures to allow long periods of
continuous operation; they can usually be maintained on site, or are suitable for quick change-out
and replacement with a spare engine. Aircraft-derivative units generally do not have the fuel
flexibility of heavy-duty units.
Another distinguishing characteristic of gas turbine designs is the type of combustion section.
There are three general types: a series of small cylindrical chambers or cans, an annular chamber
surrounding the shaft, and large single off-base combustors. The series of small cylindrical
combustors is best suited to full-scale combustion development testing, a key factor in
successfully introducing a new model. New materials and designs can be developed without
going to the expense of prototype testing. Also, investigations of unusual fuels and methods of
reducing objectionable emissions such as NO x can be easily made. The annular combustion
chamber has minimum ducting, weight, and length and is therefore best suited to aircrafttypeunits.
Figures 6.55 and 6.56 illustrate many of the characteristics of the different gas turbine designs
mentioned previously. Figure 6.55 is the General Electric Model Series 7001FA single-shaft
heavy-duty gas turbine, and Fig. 6.56 is the General Electric LM6000 aircraft-derivative unit.
Figure 6.55. Cross section of an MS7001FA single-shaft gas turbine. (General Electric Co.)
Figure 6.56. Cross section of an LM6000 two-shaft gas turbine. (General Electric Co.)
The compressor for the MS7001FA is an axial-flow, 18-stage compressor with extraction
provisions at stages 9 and 13. Stages 0 and 1 have been designed for operation in transonic flow
using design practices applied by aircraft gas turbine designers for high-bypass-ratio aircraft
engines. Compressor surge control is accomplished through variable inlet guide vanes (VIGV)
and selective bleed. At 100 percent speed, the VIGV are fully open for simple-cycle applications.
For combined-cycle applications the VIGV are positioned at an intermediate setting and opened
as a function of load and exhaust temperature to maintain maximum thermal efficiency. The 9th
and 13th stage bleed valves close during start-up when the generator breaker closes.
The low stage loading has resulted in a very rugged compressor with a high level of compressor
efficiency.
The MS7001FA combustion system consists of 14 combustion chambers with 14-in (36-cm)
nominal-diameter combustion liners. Transition pieces conduct the combustion gases to the firststage nozzle.
The MS7001FA turbine is a three-stage design, with the first-stage blade unshrouded and the
second- and third-stage blades equipped with integral Z-form tip shrouds.
Each of the three rotor stages consists of 92 investment-cast blades. The first- and second-stage
blades and all three nozzle stages are air cooled. The first-stage blade is made of directionally
solidified construction and is convectively cooled via serpentine passages, with turbulence
promoters formed by coring techniques during the casting process (Fig. 6.57). The cooling air
leaves the blade through holes in the tip as well as in the trailing edge.
Figure 6.57. First-stage bucket cooling passages.
The second-stage blade is cooled by convective heat transfer using STEM (shaped tube electrode
machining)–drilled radial holes, with all cooling air exiting through the tip.
The first-stage nozzle contains a forward and aft cavity in the vane, and is cooled by a
combination of film, impingement, and convection techniques in both the vane and sidewall
regions. There are a total of 575 holes in each of the 24 segments.
The second-stage nozzle is cooled by a combination of impingement and convection techniques,
while the third-stage nozzle is cooled by convection only.
The efficient use of cooling air made possible by these advanced cooling methods is further
enhanced by the reduced vane-surface area of the first-stage nozzle, which is achieved by low
solidity.
The LM6000 is a dual-rotor “direct-drive” gas turbine. The LM6000 takes advantage of the fact
that the low-pressure rotor normal operating speed of its parent turbofan aircraft engine is
approximately 3600 rpm. The LM6000 gas turbine concept provides for direct coupling of the
gas turbine low-pressure system to the load and maintains an extraordinarily high degree of
commonality with the aircraft engine, as illustrated in Fig. 6.58. This is unlike the traditional
aeroderivative approach, also shown in Fig. 6.58, which maintains a high degree of commonality
with the aircraft engine in the gas generator only, and adds a unique power turbine. By
maintaining high commonality, the LM6000 offers reduced parts cost benefits and demonstrated
reliability.
Figure 6.58. LM6000 concept.
The LM6000 consists of a low-pressure rotor made up of a five-stage low-pressure compressor
(LPC) with variable-inlet guide vanes, driven by a five-stage low-pressure turbine via a
concentric shaft through the high-pressure rotor. This low-pressure rotor is also the driven
equipment driver, providing the option for either cold-end or hot-end drive arrangements. The
high-pressure rotor consists of a 14-stage high-pressure compressor with six stages of variable
guide vanes driven by a two-stage air-cooled high-pressure turbine. The overall compression
ratio is 29:1.
The LM6000 utilizes an annular combustor with 30 individually replaceable fuel nozzles, and is
equipped with an engine-mounted accessory drive gearbox for starting the unit and driving
critical accessories.
49.3. PERFORMANCE CHARACTERISTICS
49.3.1. Gas Turbine Ratings
Since the introduction of the first industrial gas turbines in the 1950s there has been a continuous
growth in performance. During this period there have been significant developments in the
metallurgy of hot-gas path parts and in coatings, cooling techniques, instruments, control
systems, and component efficiencies. Ratings for specific frame sizes have grown threefold.
Indications are that ratings and efficiency values will continue to increase as new techniques are
developed for increased air and water cooling of hot-gas parts.
Table 6.21. GE Gas Turbine Performance Characteristics: Generator-Drive Gas Turbine Ratings
Fuel gas/
Output,
Heat rate,
Exhaust flow, Exhaust temp., Freq.,
Model no.
distillate
kW
Btu/kWh (LHV)
lb/h
deg. F
Hz
PG5271(RA)
G
20,260
12,820
781,000
969 50 and
60
D
19,940
12,920
783,000
970
PG5371(PA)
G
26,300
11,990
985,000
PG6541(B)
D
G
25,800
38,340
12,070
10,860
988,000
1,104,000
D
G
D
G
D
G
D
G
D
G
D
G
D
G
D
G
D
37,520
83,500
82,100
125,000
122,410
159,000
144,800
123,400
121,300
212,200
208,000
226,500
222,000
39,970
39,920
39,170
39,120
10,970
10,480
10,560
10,030
10,130
9,500
9,580
10,100
10,170
9,995
10,080
9,570
9,650
8,790
8,850
8,960
9,030
1,107,000
2,351,000
2,358,000
3,309,000
3,318,000
3,387,000
3,397,000
3,256,000
3,265,000
4,860,000
4,875,000
4,877,000
4,892,000
982,300
982,100
982,300
982,100
PG7111(EA)
PG7171(E/F)
PG7221(FA)
PG9171(E)
PG9301(F)
PG9311(FA)
LM6000(PA)
LM6000(PA)
909 50 and
60
910
1,002 50 and
60
1,003
986 60
986
991 60
992
1,093 60
1,095
1,001 50
1,002
1,081 50
1,082
1,093 50
1,095
840 60
856
840 50
856
Therefore, any table of specifications for gas turbines can only represent a “snapshot” in time of
what is a dynamic, ever-changing picture. Nevertheless, Tables 6.21 and 6.22 are offered to
represent the state of the art of gas turbine technology in the early 1990s.
In Table 6.21 the models are heavy-duty gas turbine-generator sets. The PG7221(FA)
incorporates the MS7001FA gas turbine, the technological state of the art in the early 1990s.
Aircraft-derivative state of the art is embodied in the LM6000(PA) unit.
Table 6.22. Mechanical-Drive Gas Turbine Ratings
Model no.
Cycle (SCFuel (G- Output, Heat rate,
simple) (RC- gas) (Dhp
Btu/hph
regenerative)
dist.)
(LHV)
M3142(J)
SC
M3142R(J)
RC
M5261(RA)
SC
G
D
G
D
G
14,600
14,250
14,000
13,650
26,400
9,530
9,680
7,410
7,500
9,380
Output
shaft
speed,
rpm
6,500
6,500
6,500
6,500
4,860
Exhaust Exhaust
temp., F flow, lb/h
979
979
668
668
988
415.0
415.0
415.0
415.0
740.4
M5352(B)
M5382(C)
M5352R(C)
M6501(B)
M7111(EA)
LM6000(PA)
SC
SC
RC
SC
SC
SC
G
G
G
G
G
G
35,000
38,000
35,600
50,010
108,200
56,130
8,830
8,700
6,990
7,930
7,790
6,370
4,670
4,670
4,670
4,860
3,460
3,600
915
960
970/693
1,022
1,001
836
977.9
993.4
956.2
1,039.6
2,224.7
999.5
49.3.2. Factors Affecting Gas Turbine Performance
Since the gas turbine is an ambient-air-breathing engine, its performance will be changed by
anything affecting the mass flow of the air intake to the compressor, most obviously changes
from the reference conditions of 59°F (15°C) and 14.7 psia (101.4 kPa). Figure 6.59 shows how
ambient temperature affects output,heat rate, heat consumption and exhaust flow for a singleshaft MS7001EA. Each turbine model has its own temperature-effect curve, since it depends on
the cycle parameters and component efficiencies as well as air mass flow.
Figure 6.59. Effect of ambient temperature on MS7001EA.
Correction for altitude or barometric pressure is simpler. The less-dense air reduces the airflow
and output proportionately; heat rate and other cycle parameters are not affected. A standard
altitude correction curve is presented in Fig. 6.60.
Figure 6.60. Altitude correction curve.
Similarly, humid air, being less dense than dry air, will also have an effect on output and heat
rate as shown in Fig. 6.61. In the past, this effect was thought to be too small to be considered.
However, with the increasing size of gas turbines and the utilization of humidity to bias water
and steam injection for NO x control, this effect has greater significance.
Figure 6.61. Humidity effect curve.
Inserting air filtration, silencing, evaporative coolers, chillers, and exhaust heat recovery devices
in the inlet and exhaust systems causes pressure drops in the system. The effects of these
pressure drops are unique to each design. Shown in Fig. 6.62 are the effects on the MS7001EA.
Figure 6.62. MS7001EA pressure drop effects.
Fuel type will also impact performance. Tables 6.21 and 6.22 show that natural gas produces
nearly 2 percent more output than does distillate oil. This is due to the higher specific heat in the
combustion products of natural gas, resulting from the higher water vapor content produced by
the higher hydrogen/carbon ratio of methane.
49.4. OPERATION AND MAINTENANCE
49.4.1. Starting Procedures
In order to start up a gas turbine, another small prime mover is required to accelerate the unit to a
preselected speed until firing occurs and the unit becomes self-sustaining. The starting device is
then uncoupled from the gas turbine by a clutch. Starting devices can be:
o
o
o
o
o
Motors
Diesel engines
Expansion turbines
Steam turbines
Generators (via frequency conversion)
49.4.2. Normal Operation
Most gas turbine-generators normally operate at synchronous speed at full capability. Fuel flow
is governed to maintain the firing temperature at its design limit. Therefore, the output of the unit
will vary with ambient temperature. Units that are synchronized in a grid can also operate at part
load using a droop or speed/load control characteristic. This is illustrated in Fig. 6.63. Because
the unit is synchronized to the system, the speed is essentially constant. Therefore, varying the
speed set-point effectively varies the load. The family of diagonal lines represents different
settings of the speed/load control knob. Isolated gas turbine-generators can be furnished with an
isochronous control mode. Load changes result in transient speed excursions which are
instantaneously corrected by modulating fuel flow. Whether a gas turbine is on droop or
isochronous control, the maximum firing temperature control will always provide an upper limit
to prevent overfiring. Many other backup and protective controls and alarms are also provided.
Figure 6.63. Typical droop speed control characteristics.
Mechanical-drive gas turbines normally operate on speed/load control with the set-point
provided by the process control system. Figure 6.64 depicts a typical performance curve for a
two-shaft mechanical-drive gas turbine, with the load characteristic of a process compressor
system superimposed. A process controller might receive the suction or discharge pressure signal
of the driven compressor and generate the appropriate speed/load set-point of the gas turbine.
Again the fuel flow is still limited by the maximum-firing-temperature control.
Figure 6.64. Two-shaft mechanical-drive gas turbine performance curve with a process
compressor system load curve.
49.4.3. Gas Turbine Emissions
The gas turbine is one of many types of combustion devices that have been subject to strict
environmental codes in recent years. Limits have been placed on the following types of
objectionable emissions:
o
o
o
o
o
Oxides of nitrogen, NO x
Oxides of sulfur, SO x
Particulates
Unburned hydrocarbons
Carbon monoxide, CO
The development of combustion systems has progressed to the point where typical gas turbine
emissions of particulates, unburned hydrocarbons, and carbon monoxide fall well below the
environmental limits. Figure 6.65 shows the reverse-flow cannular combustion system that has
been the object of some of the most intensive development programs. Liquid fuels are atomized
by high-pressure air as they are injected through the fuel nozzle. This has been very effective in
reducing emissions of unburned hydrocarbons and particulates. Most of the compressor
discharge air flows through the combustion liner downstream of the reaction zone. This cools the
products of combustion and reduces the formation of NO x. Injection of water or steam into the
reaction zone further reduces NO x formation. In response to continuing reduction of allowable
NO x emissions, water or steam injection is being supplanted by dry low-NO x technology.
Figure 6.65. Reverse-flow combustion system.
There are two sources of NO x emissions in the exhaust of a gas turbine. Most of the NO x is
generated by the fixation of atmospheric nitrogen in the flame. This is called thermal NO x. NO x
is also generated by the conversion of a fraction of any nitrogen chemically bound in the fuel
[called fuel-bound nitrogen (FBN)]. Lower-quality distillates and low-Btu coal gases from
gasifiers with hot-gas cleanup carry varying amounts of bound nitrogen, which must be taken
into account when emissions calculations are made. The methods described below to control
thermal emissions are ineffective in controlling the conversion of FBN to NO x. In fact, these
methods result in the conversion of a greater fraction of FBN to NO x. If fuels with high bound
nitrogen levels become common, other control techniques will have to be used.
Thermal NO x is generally regarded as being generated by a chemical reaction sequence called
the Zeldovich mechanism. This set of well-verified chemical reactions postulates that the rate of
generation of thermal NO x is an exponential function of the temperature of the flame. It,
therefore, follows that the amount of NO x generated is a function not only of the temperature but
also of the time the hot gas mixture is at flame temperature. It turns out to be a linear function of
time. Thus, temperature and residence time determine NO x emission levels and are the principal
variables that a gas turbine designer can alter to control emission levels.
Since flame temperature of a given fuel is a unique function of the equivalence ratio, the rate of
NO x generation in a flame can be cast as a function of the equivalence ratio. This is illustrated in
Fig. 6.66, which shows that the highest rate of NO x production occurs at an equivalence ratio of
1 when the temperature is equal to the stoichiometric, adiabatic flame temperature.
To the left of the maximum temperature point, there is more oxygen available than there is fuel
and the flame temperature is lower. This is called fuel lean operation. In this case, the
equivalence ratio is less than unity.
Since the rate of NO x formation is a function of temperature and time, it follows that some
difference in NO x emissions can be expected when different fuels are burned in a given com
bustion system. Since distillate oil and natural gas have approximately a 100°F (37°C) flame
temperature difference, a significant difference in NO x emissions can be expected, all other
things (reaction zone equivalence ratio, water injection rate, etc.) being equal.
Figure 6.66. Rate of NO x production.
As can be seen from Fig. 6.66, the rate of NO x production falls drastically as temperature
decreases (i.e., the flame becomes fuel lean). This is because of the exponential effect of
temperature in the Zeldovich mechanism and is the reason why diluent injection (usually water
or steam) into a gas turbine combustor flame zone reduces NO x emissions. For the same reason,
very lean combustors can be used to control emissions. This is desirable for reaching the lower
NO x levels now being required in many applications. There are, however, two design challenges
with very lean combustors: First, care must be taken to ensure stability at the design operating
point; second, it is necessary to have turndown capability, as a gas turbine must ignite,
accelerate, and operate over the load range. At lower loads, the flame could be fuel lean and not
burn well or it could become unstable and blow out.
In response, designers use staged combustors so that only a portion of the flame-zone air is
brought into contact with the fuel at lower load or during start-up. Staged combustors can be of
two basic types: fuel staged or air staged. In the simplest and most common configuration, a
fuel-staged combustor has two flame zones, each receiving a constant fraction of the combustor
air flow. Fuel flow is divided between the two zones so that at each machine the amount of fuel
fed to a stage is matched to the amount of air available. An air-staged combustor has a
mechanism for diverting a fraction of the air flow from the flame zone to the dilution zone at low
load to increase turndown. These methods can be combined.
49.4.4. Maintenance
Periodic inspection, repair, and replacement of parts are required to maintain gas turbines. The
frequency of maintenance is heavily dependent on the type of fuel, the start-up frequency, and
the environment. Although control systems carefully sequence start-up, there is an inherent
thermal cycle which reduces parts life if frequently repeated. The parts life of peaking gas
turbines that run for 4 h/day is lower than that of continuous-duty units. However, most
industrial plants operate for many more than 100 fired hours per start and therefore do not have
this problem.
The general environment can also affect the parts life of gas turbines. Many plants are located in
areas with corrosive or abrasive matter in the atmosphere. Desert sandstorms, salt-water mist,
chemical fumes, and airborne fertilizers are examples. However, the effects of these types of
environments can be minimized by multistage high-efficiency inlet-air filters and mist
eliminators as well as the presence of correct materials and protective coatings in the compressor
and turbine.
The most important factor in gas turbine maintenance is the type of fuel burned. Natural gas is
the cleanest fuel and incurs minimum maintenance costs and downtime. It is common for gas
turbines in base-load industrial service to operate at full load on maximum-exhaust-temperature
control continuously for 3 yr. Not many industrial plants or processes can operate for such long
periods; hence,gas turbines are generally maintained at shorter intervals during process outages.
Normally, No.2 distillate oil contains very little contamination, but it does burn with greater
radiation, or luminosity, than natural gas. This decreases the life of hot-gas-path parts. The low
lubricity of distillate oil decreases the life of parts of fuel forwarding and metering systems as
well. Heavy fuel oils, both crude and residual, generally burn with additional radiation and have
contaminants which accelerate corrosion and deposition of the hot-gas-path parts. Sodium and
potassium must be removed from these fuels to prevent hot corrosion, and vanadium must be
inhibited by the use of magnesium additives.
Preventive maintenance practices generally consist of several different types of maintenance
procedures:
o
o
o
o
Running inspection
Combustion inspection
Hot-gas-path inspection
Major inspection
Table 6.23. Typical Achieved Crew Size and Skills—Combustion, Hot-Gas-Path, and Major
Inspection Baseload duty (gas fuel) MS7001E gas turbine
Worker-hours
Trade skill
Combustion
Hot-gas-path
Major
Millwright
136
2340
4730
Crane operator
3
68
112
Instr/elec/NDT tech
Carpenter
Welder
Pickup/driver
Elapsed times
13
36
78
0
48
60
0
4
12
0
200
300
152
2696
5292
(3 ×10 h shifts) 17 days (2 ×10 h shift/day) 22 days (2 ×10 h shift/day)
Running inspections include load versus exhaust temperature measurements, vibration
monitoring, and fuel-flow and fuel-pressure measurements. Sophisticated electronic equipment is
planned to enhance trend monitoring and on-line diagnostics.
In a combustion inspection the unit is shut down and some disassembly is required to repair or
replace combustion parts such as fuel nozzles and liners. Visual or boroscope inspections can
also be made of turbine nozzles and buckets during these inspections.
A hot-gas-path inspection includes disassembly of the turbine casing. A major inspection
includes a disassembly of the compressor casing as well as the turbine casing. A major
inspection essentially returns the gas turbine to its new, or zero time, condition. For an MS7000
operating on natural gas or distillate, combustion, hot-gas-path, and major inspections occur at
8,000-, 24,000-, and 48,000-fired-hour intervals, respectively.
Many gas turbine parts are fabricated from expensive superalloys. Minimum maintenance costs
can be achieved by repairing these parts during an inspection to extend their life. Spare sets of
parts can be used as replacements to minimize downtime. In some critical continuous-process
plants, it is more economical to maintain production without outages rather than extend parts life
by repairs.
Typical crew sizes and trade skills needed to perform combustion, hot-gas-path, and major
inspections on an MS7001E unit are shown in Table 6.23. Furthermore, as an indication of
typical maintenance worker-hour requirements which may be used in initial planning phases,
Table 6.23 also presents average worker-hours per downtime (calendar) hour for some of the
more prevalent types of inspection activity that occur during the life of a gas turbine.
49.5. APPLICATIONS IN PLANTS
49.5.1. General Discussion
There are several different application categories for stationary gas turbines. These include:
o
o
o
Pipeline pumping stations
Offshore platforms
Electric utility stations, including:
Base-load
Midrange (1500 to 3000 h/yr)
Peaking duty
o
Industrial plants
Pipeline pumping stations are generally base-loaded around the year, or through all except the
summer months. There are many applications of simple-cycle gas turbines in remote areas.
Table 6.24. Typical Performance of a Combined Cycle, Based on 59°F (15°C) Sea-Level Site,
with Natural Gas Fuel
*Registered trademark of General Electric Co.
Plant designation Output, kW Heat rate (LHV), Btu/kWh (kJ/kWh) Gas turbine configuration
STAG* 107EA
124,100
7055 (7440)
One MS7001EA
STAG* 207EA
249,400
7020 (7410)
Two MS7001EA
There have also been a very small number of combined steam and gas turbine cycles in this
category.
Most offshore-platform applications have been simple cycles due to weight and “foot-print”
constraints, with wide application of aeroderivative units.
In electric utility service, thousands of gas turbines around the world have been applied to serve
peak loads (up to 1500 h/yr) in the simple-cycle mode. Because of limited operation, fuel
consumption is not as significant a factor as are capital costs, operating labor, and maintenance.
Most gas turbines that are applied in midrange or base-load electric utility service combine steam
and gas turbine cycles, but a small number also have used regenerative cycles.
Many of the gas turbines applied in electric utility combined-cycle service are supplied as part of
a complete package by the gas turbine manufacturer. The manufacturer supplies or specifies all
the major equipment, such as heat-recovery steam generators (HRSGs), steam turbines, and plant
controls, to optimize plant performance through an integrated approach. Table 6.24 lists typical
performance specifications for three versions of combined cycles based on the MS7001E gas
turbine.
Most gas turbines applied in industrial plants are in base-load service. There are many simplecycle gas turbines applied throughout the world in industrial plants where fuel supplies are
abundant. However, generally all gas turbines applied in industrial plants are equipped with
some type of heat recovery to improve overall energy efficiency. Figure 6.67 illustrates some of
the ways in which the high-temperature exhaust of gas turbines has been recovered in industrial
plants. In Fig. 6.67 the exhaust gases are used to generate low-pressure process steam. The
HRSGs can be unfired or have supplementary firing to increase steam output. In Fig. 6.67
higher-pressure steam is generated for a steam turbine. Typical upper limits for steam conditions
of unfired HRSGs are 850 psig, 825°F (5964 kPa,441°C). Fired HRSGs have been applied with
steam conditions as high as 1450 psig, 950°F (10,100 kPa, 510°C). In Fig. 6.67 a two-pressure
HRSG is shown. When high-pressure turbine inlet steam is generated in an unfired HRSG,
typical stack temperatures are a relatively high 400 to 450°F (204 to 232°C). Additional heat can
be recovered when a 25- to 150-psig (276- to 1138-kPa) saturated steam-generation section is
included.
In Fig. 6.67 a regenerative-cycle gas turbine is followed by a low-pressure process steam
generator. One of the consequences of the low fuel consumption of the regenerative-cycle gas
turbine is a reduction of the regenerator exhaust gas temperature to approximately 600°F
(316°C). This arrangement should be selected when only a relatively small amount of process
steam is required.
Finally, in Fig. 6.67, the heat in the exhaust gas is used directly in the process or as preheated
combustion air for a fired process heater.
In all these cycles the process is known as cogeneration, and the fuel utilization effectiveness is
improved by recovering heat from the gas turbine exhaust. A parameter used to define the
thermal performance of a cogeneration system is fuel chargeable to power (FCP). The FCP is the
incremental fuel-power ratio for the cogeneration system relative to the case with which it is
being compared (usually a noncogeneration alternative). For a plant generating electric power
only (an industrial or a utility), the fuel chargeable to power and net plant heat rate are
interchangeable terms. Net plant heat rate in Btu/kWh is the more commonly used term for
plants generating electric power only.
The FCP concept is illustrated in Fig. 6.68. Stated in simple terms, the FCP is the total fuel
burned in the cogeneration system minus the fuel which would have been required if all power
were purchased (process fuel credit) divided by the gross power generated minus the difference
in powerhouse auxiliaries.
Figure 6.67. Industrial gas turbine heat-recovery cycles.
The heat recovery capability and fuel chargeable-to-power for typical gas turbines is shown in
Table 6.25.
Steam turbines are often used in cogeneration systems that produce heat for industrial processes
as well as power. A typical application is shown in Fig. 6.69. In this case an automatic-extraction
noncondensing unit supplies steam at two different pressure levels to the process. A typical value
of fuel chargeable to power for noncondensing steam turbine cycles is 4200 Btu/kWh (4431
kJ/kWh) HHV. This is an equivalent thermal efficiency of 80 percent, which is far higher than
that of most other types of prime movers. The high efficiency of the noncondensing steam
turbine cycle is due to the fact that heat losses to the surroundings are minimized. The only
losses are the boiler inefficiency (stack losses), generator, seals, bearing friction, radiation, and
additional auxiliary power requirements.
Figure 6.68. Fuel chargeable to power.
Table 6.25. Steam Generation and Fuel Chargeable-to-Power with Gas Turbine and Exhaust
Heat Boilers
*Gas turbines and boilers fueled with natural gas and all fuel data based on higher heating
value (HHV).
Unfired single-pressure boilers 92% effectiveness for SH and evaporator; supplementary
fired to 1600°F, 86.8% to 90.5% effectiveness; fully fired to 10% excess air with 300°F
stack temperature.
For two-pressure boilers, criterion of minimum 300°F stack temperature may require less
than 92% low-pressure boiler effectiveness.
Assumes 0% exhaust bypass stack damper leakage, 3% blowdown, 1 1/2% radiation and
unaccounted losses, and 228°F feedwater for all cases.
Standard gas turbine inlet losses; exhaust 10°H 2O for unfired, 14°H 2O for supplementary
fired,and 20°H 2O for fully fired.
LM2500, LM5000, and LM6000 values based on guarantee, not average engine
performance.
Fuel chargeable to gas turbine power assumes GT credit with PH auxiliaries and
equivalent 84% boiler fuel required to generate steam.
Lower heating value (LHV)—21,515 Btu/lb; HHV =LHV×1.11.
Generator drives—natural gas fuel
Gas
MS5001
MS6001
MS7001
MS7001 LM2500- LM5000- LM6000turbine
(PA)
(B)
(EA)
(F)
PE
PC
PA
type
Gas
PG5371
PG6541
PG7111 PG7221 (F) PGLM250 PGLM500 PGLM600
turbine
(PA)
(B)
(EA)
0-PE
0-PC
0-PA
model
ISO
26,300
38,340
83,500
159,000
21,790
33,630
39,970
base
rating,
kW
Perform
ance at
59°F,
sea
level,
natural
gas fuel
output,
kW
Unfired
25,890
38,000
82,680
156,500
21,540
33,190
39,700
Supp
25,710
37,820
82,330
155,700
21,400
32,970
39,550
fired
Fully
25,430
37,530
81,780
154,400
21,220
32,620
39,320
fired
Speed,
5,100
5,100
3,600
3,600
3,600
3,600
3,600
rpm
Fuel,
344.6
462.3
967.8
1,678.1
236.5
355.4
390.0
MBtu/h
(HHV)
Exhaust
971,400 1,083,000 2,343,000 3,387,000
535,000
950,800
982,300
flow,
lb/h
Exhaust
temp.,
°F
Unfired
906
1,007
968
1,103
993
823
844
Supp
fired
Fully
fired
HRSG
perform
ance
fuel,
MBtu/h
(HHV)
Supp
fired
Fully
fired
Steam
conditio
ns,
psig/°F
HR
SG
Stea
mK
lb/h
Unfired
160/371 143.
4
420/655 114.
4
630/755 104.
4
895/830 96.2
895/830 96.2
909
1,010
990
1,106
996
826
846
913
1,014
993
1,111
1,001
830
849
221.5
214.2
475.7
564.5
107.9
242.1
244.4
878.7
904.4
1,989.6
2,592.3
438.4
845.5
850.0
FCP
GT
Btu/k
Wh
HR
SG
Stea
mK
lb/h
6650 193.
2
7240 159.
0
7560 148.
0
7870 139.
4
6360 139.
4
— 27.6
— 130.
8
— 34.3
— 125.
8
— 37.8
FCP HRS FCP HRS
GT
G GT
G
Btu/k Stea Btu/k Stea
Wh m K Wh m K
lb/h
lb/h
6060 403.
5
6420 331.
5
6610 307.
0
6800 288.
5
5920 288.
5
— 63.0
5920 269.
5
— 78.7
5920 258.
5
— 86.9
5840 704.
0
6200 592.
9
6410 559.
2
6600 533.
0
5680 533.
0
— 61.4
5680 510.
0
— 74.9
5870 495.
0
— 82.0
FCP
GT
Btu/k
Wh
HR
SG
Stea
mK
lb/h
FCP
GT
Btu/k
Wh
HR
SG
Stea
mK
lb/h
FCP
GT
Btu/k
Wh
HR
SG
Stea
mK
lb/h
FCP
GT
Btu/k
Wh
5320 93.4 5770 117. 6440 127. 5960
8
8
5530 76.5 6110 90.9 6950 99.8 6370
5630 71.0 6280 81.0 7230 89.5 6610
5740 66.8 6440
—
—
—
—
5270 66.8 5640
—
—
—
—
160/371 32.3
— 14.3
— —
— —
—
1315/90 —
5270 —
— —
— —
—
5
160/371 —
— —
— —
— —
—
1525/95 —
5270 —
— —
— —
—
5
160/371 —
— —
— —
— —
—
Supp
fired
420/655 301. 5960 338. 5630 730. 5380 105 5080 167. 5380 297. 5750 307. 5380
0
0
0
9.0
2
5
5
630/755 289. 5980 324. 5670 701. 5410 101 5100 160. 5410 285. 5790 295. 5400
5
5
895/830 281. 6030 315. 5710
0
0
1315/90 273. 6100 306. 5770
5
5
5
1525/95 269. 6080 301. 5740
5
0
5
Fully
fired
630/755 777. 4610 836. 4710
0
0
895/830 757. 4610 815. 4690
0
0
1315/90 740. 4610 796. 4710
5
0
0
1525/95 726. 4650 782. 4700
5
0
0
0
7.0
6
5
5
681. 5440 988. 5130 156. 5380 277. 5810 287. 5430
0
0
8
5
0
663. 5490 962. 5170 151. 5490 270. 5870 279. 5470
0
0
8
0
5
652. 5470 946. 5150 149. 5460 265. 5860 274. 5470
0
0
4
5
5
182
6.0
177
9.0
173
9.0
170
8.0
4390 252
6.0
4390 246
0.0
4390 240
5.0
4380 236
2.0
4370 406.
5
4380 396.
0
4380 387.
0
4380 380.
0
4540 734.
0
4540 715.
0
4550 699.
0
4550 686.
0
4780 745.
0
4790 726.
0
4780 710.
0
4800 697.
0
4570
4560
4550
4560
Figure 6.69. Typical noncondensing steam turbine application.
One method of displaying the many options available by using a gas turbine in a cogeneration
application is shown in Fig. 6.70. This diagram has been developed for the GE MS7001EA gas
turbine-generator.
Figure 6.70. Performance envelope for gas turbine cogeneration system.
Point A represents the MS7001EA gas turbine-generator exhausting into an unfired low-pressure
HRSG. Point C is a combined-cycle configuration based on use of a two-pressure-level unfired
HRSG. The steam turbine in the C cycle is a noncondensing unit expanding the HP HRSG steam
to the 150-psig (1034 kPa) process steam header.
Points B and D in Fig. 6.70 represent operation of the HRSG with supplementary firing to a
1600°F (878°C) average exhaust-gas temperature entering the heat-transfer surface. The
temperature used for the HRSG firing in Fig. 6.70 has been arbitrarily limited to 1600°F (878°C)
even though higher firing temperatures (and thus steam production rates) are possible in the
exhaust of this unit.
Figure 6.71. Gas turbine cogeneration systems MS options, 60 Hz.
The envelope defined by A, B, C, and D in Fig. 6.70 represents the most thermally optimized use
of a gas turbine in a cogeneration application (i.e., provides the lowest FCP). Operation along the
line CE, DF, or any intermediate point to the left of line CD represents the use of condensing
steam turbine power generation with the E and F points applicable for combined-cycle operation
without any heat supplied to process. Thus, the cycles along line EF are combined cycles
providing power alone.
Performance envelopes for many of the gas turbines included in Table 6.25 are presented in Figs.
6.71 and 6.72. These data are on the same basis as Fig. 6.70 except for point C. Point C for all
units except the various MS7001 models is based on 850 psig (5464 kPa), 825°F (441°C) initial
steam temperature to the noncondensing steam turbine. Furthermore, the only condensing power
illustrated is based on unfired, two-pressure-level HRSG designs.
Figure 6.72. Gas turbine cogeneration systems LM options, 60 Hz.
49.6. ACKNOWLEDGMENT
The author acknowledges the support and contribution provided by the Engineering Staff of
GE’s Power Generation Business.
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