Gas Turbine Engineering Handbook 2 Episode 10 docx

G:/GTE/FINAL (26-10-01)/CHAPTER 11.3D ± 435 ± [409±435/27] 1.11.2001 3:51PM Another area of research is the development of techniques to ensure that the application of the coatings are extremely even. The external deposition source can be electron beam vapor deposition, sputtering, plasma spray, cladding, or any number of other techniques. The technique for application of overlay coatings which appears to have the most promise is high-velocity plasma. For this technique, powder particles of the desired coating composi- tion are accelerated through a plasma field to velocities as high as three times the speed of sound. The impact of the powder onto the workpiece results in a much stronger bond between the coating and workpiece than can be achieved by using conventional subsonic plasma spray deposition. In addition, much higher coating densities can be achieved using the high-velocity plasma. One company has developed and patented a ``detonation gun'' to use for coating application. Basically, the gun detonates a metered mixture of oxygen, acetylene, and particles of the desired coating material and throws them at supersonic velocities at the workpiece surface. The workpiece itself remains at quite low temperatures, so its metallurgical properties are not modified. Bibliography Bernstein, H.L., ``High Temperature Coatings for Industrial Gas Turbine Users,'' Proceedings of the 28th Turbomachinery Symposium, Texas A&M University; p. 179; 1999. Bernstien H.L., ``Materials Issues for Users of Gas Turbines,'' Proceedings of the 27th Texas A&M Turbomachinery Symposium, (1998). Lavoie, R., and McMordie, B.G., ``Measuring Surface Finish of Compressor Airfoils Protected by Environmentally Resistant Coatings,'' 30th Annual Aerospace/Airline Plating and Metal Finishing Forum, April 1994. McMordie, B.G., ``Impact of Smooth Coatings on the Efficiency of Modern Turbomachinery,'' 2000 Aerospace/Airline Plating & Metal Finishing Forum Cincinnati, Ohio, March 2000. Schilke, P.W., ``Advanced Gas Turbine Materials and Coatings,'' 39th GE Turbine State-of the-Art Technology Seminar, August 1996. Warnes B.M., and Hampson L.M., ``Extending the Service Life of Gas Turbine Hardware,'' ASME 2000-GT-559. Wood, M.I., ``Developments in Blade Coatings: Extending the Life of Blades? Reducing Lifetime Costs?,'' CCGT Generation, March 1999, IIR Ltd. Materials 435 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 436 ± [436±466/31] 1.11.2001 3:52PM 12 Fuels The gas turbine's major advantage has been its inherent fuel flexibility. Fuel candidates encompass the entire spectrum from gases to solids. Gas- eous fuels traditionally include natural gas, process gas, low-Btu coal gas, and vaporized fuel oil gas. ``Process gas'' is a broad term used to describe gas formed by some industrial process. Process gases include refinery gas, pro- ducer gas, coke oven gas, and blast furnace gas among others. Natural gas is the fuel of choice and is usually the basis on which performance for a gas turbine is compared, since it is a clean fuel fostering longer machine life. Vaporized fuel oil gas behaves very closely to natural gas because it provides high performance with a minimum reduction of component life. About 40% of the turbine power installed operates on liquid fuels. Liquid fuels can vary from light volatile naphtha through kerosene to the heavy viscous residuals. The classes of liquid fuels and their requirements are shown in Table 12-1. The light distillates are equal to natural gas as a fuel, and between light distillates and natural gas fuels, 90% of installed units can be counted. Care must be taken in handling liquid fuels to avoid contamination, and the very light distillates like naphtha require special concern in the design of fuel systems because of their high volatility. Generally, a fuel tank of the floating head type with no area for vaporization is employed. The heavy true dis- tillates like 52 distillate oil can be considered the standard fuel. The true distillate fuel is a good turbine fuel; however, because trace elements of vanadium, sodium, potassium, lead, and calcium are found in the fuel, the fuel has to be treated. The corrosive effect of sodium and vanadium is very detrimental to the life of a turbine. Vanadium originates as a metallic compound in crude oil and is concen- trated by the distillation process into heavy oil fractions. Sodium compounds 436 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 437 ± [436±466/31] 1.11.2001 3:52PM Table 12-1 Comparison of Liquid Fuels for Gas Turbines General Fuel Type True Distillate & Naphthas Blended Heavy Distillates & Low-Ash Crudes Residuals & High-Ash Crude Fuel pre-heat No Yes Yes Fuel atomization Mech/LP air HP/LP air HP air Desalting No Some Yes Fuel inhibitation Usually none Limited Always Turbine washing No Yes, except distillate Yes Start-up fuel With naphtha Some fuels Always Base fuel cost Highest Intermediate Lowest Description High-quality distillate essentially ash-free Low-ash, limited contaminant levels Low-volatility High-ash Types of fuels included True distillates (naphtha, kerosene, no. 2 diesel, no. 2 fuel oil, JP-4, JP-5) High-quality crudes, slightly contaminated distillates Navy distillate Residuals and low-grade crude (No. 5 fuel, No. 6 fuel, Bunker C) ASTM designation 1-GT, 2-GT, 3-GT 3-GT 4-GT Turbine inlet temperature Highest Intermediate Lowest Fuels 437 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 438 ± [436±466/31] 1.11.2001 3:52PM are most often present in the form of salt water, which results from salty wells, transport over seawater, or mist ingestion in an ocean environment. Fuel treatments are costly and do not remove all traces of these metals. As long as the fuel oil properties fall within specific limits, no special treatment is required. Blends are residuals that have been mixed with lighter distillates to improve properties. The specific gravity and viscosity can be reduced by blending. About 1% of total installed machines can operate on blends. A final fuels group contains high-ash crudes and residuals. These account for 5% of installed units. Residual fuel is the high-ash by-product of dis- tillation. Low cost makes them attractive; however, special equipment must always be added to a fuel system before they can be utilized. Crude is attractive as a fuel, since in pumping applications it is burned straight from the pipeline. Table 12-2 shows data obtained from a number of users that Table 12-2 Operation and Maintenance Life of an Industrial Turbine Type of Application and Fuel Firing Temperature below 1700 °F (927 °C) Firing Temperature above 1700 °F (927 °C) Comb. Liners 1st Stage Nozzle 1st Stage Blades Comb. Liners 1st Stage Nozzle 1st Stage Blades BASE LOAD Starts/hr   Nat. gas 1/1000 30,000 60,000 100,000 15,000 25,000 35,000 Nat. gas 1/10 7,500 42,000 72,000 3,750 20,000 25,000 Distillate oil 1/1000 22,000 45,000 72,000 11,250 22,000 30,000 Distillate oil 1/10 6,000 35,000 48,000 3,000 13,500 18,000 Residual 1/1000 3,500 20,000 28,000 2,500 10,000 15,000 Residual 1/10 SYSTEM PEAKING Normal Max. Load of short duration and daily starts Nat. gas 1/10 7,500 34,000 60,000 5,000 15,000 24,000 Nat. gas 1/5 3,800 28,000 40,000 3,000 12,500 18,000 Distillate 1/10 6,000 27,200 53,500 4,000 12,500 19,000 Distillate 1/5 3,000 22,400 32,000 2,500 10,000 16,000 TURBINE PEAKING Operating Above 50  F  ± 100  F (28  ±56  C) Firing Temperature Nat. gas 1/5 2,000 12,000 20,000 2,000 12,500 18,000 Nat. gas 1/1 400 9,000 15,000 400 10,000 15,000 Distillate 1/5 1,600 10,000 16,000 1,700 11,000 15,000 Distillate 1/1 400 7,300 12,000 400 8,500 12,000 438 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 439 ± [436±466/31] 1.11.2001 3:52PM indicates a considerable reduction in downtime, depending on the type of service and fuel used. This table also shows that natural gas is by far the best fuel. The effect of various fuels on the output work of the turbine can be seen in Figure 12-1. This figure shows that vaporized fuel oil gives a higher output. This high output results when steam is mixed with the hot fuel gas, which enters the combustor at (371  C). Corrosion effects have not been detected with this fuel, since the steam is not allowed to condense in the turbine. Assuming that natural gas is the base line fuel to obtain the same power using diesel fuel the gas turbine would have to be fired at a higher tempera- ture, and for low Btu (400 Btu/cu ft, 14911 KJ/m 3 ) gases at the same firing temperature the turbine would produce more power due to the fact that the amount of fuel could be increased by threefold, thus increasing the overall mass flow through the turbine. The limitation in using low Btu gases is that it takes about 30% of the air for combustion as compared to 10% of the air for natural gas leaving much less air for cooling the combustor liners. Because of this for low Btu gases it is easier to modify annular combustor turbines, which have less of a combustor liner surface area than can-annular combustors. Another problem is that in some cases the extra flow can choke the turbine nozzles. For turbines used in combined cycle Figure 12-1. Effect of various fuels on turbine inlet temperature. Fuels 439 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 440 ± [436±466/31] 1.11.2001 3:52PM application there is a tendency to keep the same firing temperature at off- load conditions but with the use of the inlet guide vanes vary the airflow rate. Fuel Specifications To decide which fuel to use, a host of factors must be considered. The object is to obtain high efficiency, minimum downtime, and the total economic picture. The following are some fuel requirements that are important in designing a combustion system and any necessary fuel treatment equipment: 1. Heating value 2. Cleanliness 3. Corrosivity 4. Deposition and fouling tendencies 5. Availability The heating of a fuel affects the overall size of the fuel system. Generally, fuel heating is a more important concern in connection with gaseous fuels, since liquid fuels all come from petroleum crude and show narrow heating-value variations. Gaseous fuels, on the other hand, can vary from 1100 Btu/ft 3 (41,000 KJ/m 3 ) for natural gas to (11,184 KJ/m 3 ) or below for process gas. The fuel system will of necessity have to be larger for the process gas, since more is required for the same temperature rise. Cleanliness of the fuel must be monitored if the fuel is naturally ``dirty'' or can pick up contaminants during transportation. The nature of the con- taminants depends on the particular fuel. The definition of cleanliness here concerns particulates that can be strained out and is not concerned with soluble contaminants. These contaminants can cause damage or fouling in the fuel system and result in poor combustion. Corrosion by the fuel usually occurs in the hot section of the engine, either in the combustor or the turbine blading. Corrosion is related to the amounts of certain heavy metals in the fuel. Fuel corrosivity can be greatly reduced by specific treatments discussed later in this chapter. Deposition and fouling can occur in the fuel system and in the hot section of the turbine. Deposition rates depend on the amounts of certain com- pounds contained in the fuel. Some compounds that cause deposits can be removed by fuel treating. Finally, fuel availability must be considered. If future reserves are unknown, or seasonal variations are expected, dual fuel capability must be considered. 440 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 441 ± [436±466/31] 1.11.2001 3:52PM Fuel requirements are defined by various fuel properties. By coincidence, the heating-value requirement is also a property and needs no further mention. Cleanliness is a measure of the water and sediment and the particulate content. Water and sediment are found primarily in liquid fuels, while particulates are found in gaseous fuels. Particulates and sediments cause clogging of fuel filters. Water leads to oxidation in the fuel system and poor combustion. A fuel can be cleaned by filtration. Carbon residue, pour point, and viscosity are important properties in relation to deposition and fouling. Carbon residue is found by burning a fuel sample and weighing the amount of carbon left. The carbon residue property shows the tendency of a fuel to deposit carbon on the fuel nozzles and combustion liner. Pour point is the lowest temperature at which a fuel can be poured by gravitational action. Viscosity is related to the pressure loss in pipe flow. Both pour point and viscosity measure the tendency of a fuel to foul the fuel system. Sometimes, heating of the fuel system and piping is necessary to assure a proper flow. The ash content of liquid fuels is important in connection with cleanliness, corrosion, and deposition characteristics of the fuel. Ash is the material remaining after combustion. Ash is present in two forms: (1) as solid particles corresponding to that material called sediment, and (2) as oil or water soluble traces of metallic elements. As mentioned earlier, sediment is a measure of cleanliness. The corrosivity of a fuel is related to the amount of various trace elements in the fuel ash. Certain high-ash fuels tend to be very corrosive. Finally, since ash is the fuel element remaining after combustion, the deposition rate is directly related to the ash content of the fuel. Table 12-3 is a summary of gaseous fuel specifications. The two major areas of concern are heating value with its possible variation and contam- inants. Fuels outside a specification can be utilized if some modification is made. Gas fuels with heating values between 300  ±1100 Btu/ft 3 (11,184  ±41,000 KJ/m 3 ) are in use today; however, future systems may use gas with heating values Table 12-3 Gaseous Fuel Specifications Heating value 300  ±1100 Btu/ft 3 (11,184  ±41,000 KJ/m 3 ) Solid contaminants < 30ppm Flammability limits 2.2:1 CompositionÐS, Na, K, Li < 5ppm Sulfur  sodium  potassium  lithium (When formed into alkali metasulfate) H 2 O (by weight) < 257 Fuels 441 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 442 ± [436±466/31] 1.11.2001 3:52PM below 100 Btu/ft 3 (3728 KJ/m 3 ). Although wide ranges of heating values can be accommodated with different fuel systems, the maximum variation that can be used in a given fuel system is Æ10%. Sulfur content must be controlled in units with exhaust recovery systems. If sulfur condenses in the exhaust stack, corrosion can result. In units with- out exhaust recovery there is no problem, since stack temperatures are considerably higher than the dew point. Sulfur can, however, promote hot- section corrosion in combustion with certain alkali metals such as sodium or potasium. This type of corrosion is sulfidation or hot corrosion and is controlled by limiting the intake of sulfur and alkali metals. Contaminants found in a gas depend on the particular gas. Common contaminants include tar, lamp black, coke, sand, and lube oil. Table 12-4 is a summary of liquid fuel specifications set by manufacturers for efficient machine operations. The water and sediment limit is set at 1% by maximum volume to prevent fouling of the fuel system and obstruction of the fuel filters. Viscosity is limited to 20 centistokes at the fuel nozzles to prevent clogging of the fuel lines. Also, it is advisable that the pour point be 20  F (11  C) below the minimum ambient temperature. Failure to meet this specification can be corrected by heating the fuel lines. Carbon residue should be less than 1% by weight based on 100% of the sample. The hydrogen content is related to the smoking tendency of a fuel. Lower Table 12-4 Liquid Fuel Specifications Water and sediment 1.0% (V%) Max. Viscosity 20 centistokes at fuel nozzle Pour point About 20  below min. ambient Carbon residue 1.0% (wt) based on 100% of sample Hydrogen 11.% (wt) minimum Sulfur 1% (wt) maximum Typical Ash Analysis and Specifications Metal Lead Calcium Sodium & Potassium Vanadium Spec. max. (ppm) 1 10 1 0.5 untreated Naphtha 0  ±1 0  ±1 0  ±1 500 treated Kerosene 0  ±1 0  ±1 0  ±1 0  ±.1 Light distill. 0  ±1 0  ±1 0  ±1 0  ±.1 Heavy distill. (true) 0  ±1 0  ±1 0  ±1 0  ±.1 Heavy distill. (blend) 0  ±1 0  ±5 0  ±20 .1/80 Residual 0  ±1 0  ±20 0  ±100 5/400 Crude 0  ±1 0  ±20 0  ±122 .1/80 442 Gas Turbine Engineering Handbook G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 443 ± [436±466/31] 1.11.2001 3:52PM hydrogen-content fuels emit more smoke than the higher-hydrogen fuels. The sulfur standard is to protect from corrosion those systems with exhaust heat recovery. The ash analysis receives special attention because of certain trace metals in the ash that cause corrosion. Elements of prime concern are vanadium, sodium, potassium, lead, and calcium. The first four are restricted because of their contribution to corrosion at elevated temperatures; however, all these elements may leave deposits on the blading. Sodium and potassium are restricted because they react with sulfur at elevated temperatures to corrode metals by hot corrosion or sulfurization. The hot-corrision mechanism is not fully understood; however, it can be discussed in general terms. It is believed that the deposition of alkali sulfates (Na 2 SO 4 ) on the blade reduces the protective oxide layer. Corrosion results from the continual forming and removing of the oxide layer. Also, oxidation of the blades occurs when liquid vanadium is deposited on the blade. Fortunately, lead is not encountered very often. Its presence is primarily from contamination by leaded fuel or as a result of some refinery practice. Presently, there is no fuel treatment to counteract the presence of lead. Fuel Properties Natural gas has a Btu content of about 1000  ±1100 Btu/ft 3 (37,272  ± 41,000 KJ/m 3 ). By definition, low-Btu gases can vary between 100  ±350 Btu/ft 3 (3728  ±13,048 KJ/m 3 ). Presently, little success has been achieved in burn- ing gases with a heating value lower than 200 Btu/ft 3 (7456 KJ/m 3 ). To provide the same energy as natural gas, a 150 Btu/ft 3 (5592 KJ/m 3 ) low-Btu gas must be utilized at the rate of seven times that of natural gas on a volumetric basis. Therefore, the mass flow rate to provide the same energy must be about 8  ±10 times that of natural gas. The flammability of low-Btu gases is very much dependent on the mixture of CH 4 and other inert gases. Figure 12-2 shows this effect by illustrating that a mixture of CH 4 -CO 2 of less than 240 Btu/ft 3 (8947 KJ/m 3 ) is inflammable, and a CH 4 -N 2 mixture of less than about 150 Btu/ft 3 is less inflammable. Low-Btu gases near these values have greatly restricted flammability limits when compared to CH 4 in the air. Vaporized fuel oil gas is produced by mixing superheated steam with oil and then vaporizing the oil to provide a gas whose properties and heating value are close to natural gas. Important liquid fuel properties for a gas turbine are shown in Table 12-5. The flash point is the temperature at which vapors begin combustion. The flash point is the maximum temperature at which a fuel can be handled safely. Fuels 443 G:/GTE/FINAL (26-10-01)/CHAPTER 12.3D ± 444 ± [436±466/31] 1.11.2001 3:52PM The pour point is an indication of the lowest temperature at which a fuel oil can be stored and still be capable of flowing under gravitational forces. Fuels with higher pour points are permissible where the piping has been heated. Water and sediment in the fuel lead to fouling of the fuel system and obstruction in fuel filters. The carbon residue is a measure of the carbon compounds left in a fuel after the volatile components have vaporized. Two different carbon residue tests are used, one for light distillates, and one for heavier fuels. For the light fuels, 90% of the fuel is vaporized, and the carbon residue is found in the remaining 10%. For heavier fuels, since the carbon residue is large, 100% of the sample can be used. These tests give a rough approximation of the tendency to form carbon deposits in the combustion system. The metallic compounds present in the ash are related to the corrosion properties of the fuel. Viscosity is a measure of the resistance to flow and is important in the design of fuel pumping systems. Specific gravity is the weight of the fuel in relation to water. This property is important in the design of centrifugal fuel washing systems. Sulfur content is important in connection with emission concerns and in connection with the alkali metals present in the ash. Sulfur reacting with alkali metals forms compounds that corrode by a process labeled sulfidation. Luminosity is the amount of chemical energy in the fuel that is released as thermal radiation. Figure 12-2. Flammable fuel mixtures of CH 4 -N 2 and CH 4 -CO 2 at one atm showing various energy levels. 444 Gas Turbine Engineering Handbook [...]... 12. 83 104 001 0 /2 79 1/.8 047 35.0 53 .2  82 .88 7543@60  F 0 19,000/19,600 18,700/ 18, 820 12/ 13 .2 14.75 03/.3 0 /20 0/1 0/.1 0/1 0 /2 175 /26 5 15/95 100 /1,800 68 7.3 5/4 15 92/ 1.05 84 1%wt 18 ,25 0 18,300/18,900 10/ 12. 5 100 /1,000 1/350 5/400 0 /25 0/50 2/ 10 36ppm 2. 2/4.5 0/1 186  F 10  F 6.11 45.9 1.01 30.5 874 198 Low-Ash Crude 6 .20 50 /20 0 15/ 110 2/ 100 1.075 1 /2. 7 8786 80/. 92 18 ,23 9 19,000/19,400 12. 40...G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 445 ± [436±466/31] 1.11 .20 01 3:52PM Table 12- 5 Fuel Properties Diesel Fuel Burner Fuel Kerosene Flash point  F Pour point  F Visc CS @ 100  F SSU Sulfur % API gr Sp gr @ 100  F Water & ded Btu Heating value lb Oil #2 JP-4 130/160 À50 1.4 /2. 2  118 22 0 À55 to 10 2. 48 /2. 67 34.4 169/ .24 3 38.1 85 150 /20 0 10= 30 2. 0/4.0 < RT 01/.1 78/.83 19,300/ 19,700 12. 8/14.5 01/.1... Cost x 2x 4x 8x dollars dollars dollars dollars Figure 12- 11 Gas turbine fuel treatment plant investment costs (Courtesy of General Electric Company.) G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 458 ± [436±466/31] 1.11 .20 01 3:52PM 458 Gas Turbine Engineering Handbook Table 12- 8 Average Total Maintenance and Cost Factor for a Gas Turbine Expected Actual Maintenance Cost (mils/kWh) Fuel Natural gas No 2 distillate... over a 20 -year period is approximately $0.50 MMBtu G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 4 52 ± [436±466/31] 1.11 .20 01 3:52PM 4 52 Gas Turbine Engineering Handbook output This cost includes the initial capital investment, maintenance, and operating costs The initial cost of a VFO unit with an output of 800 MMBtu/hr (required for a 60 MW gas turbine) is approximately $1150/MMBtu/hr output ($ 920 ,000... 2/ 100 1.075 1 /2. 7 8786 80/. 92 18 ,23 9 19,000/19,400 12. 40 12/ 13 .2 3/3 20 /20 0 0/50 0/15 Fuels Hydrogen % Carbon residue 10% bottoms Ash ppm Na ‡ K ppm V Pb Ca #2 High-Ash Typical Navy Heavy Crude Heavy Libyan Residual Crude Distillate Distillate 445 G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 446 ± [436±466/31] 1.11 .20 01 3:52PM 446 Gas Turbine Engineering Handbook Finally, the weight of a fuel, light or heavy,... combustion turbine plant designed for today's energy needs,'' Pub No 4875BIO-7 610 Combustors for Large Aircraft Turbine Engines, AIAA Paper Number 69-493 G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 466 ± [436±466/31] 1.11 .20 01 3:52PM G:/GTE/FINAL (26 -10- 01)/CHAPTER 13.3D ± 467 ± [467± 520 /54] 1.11 .20 01 3:56PM Part IV Auxiliary Components and Accessories G:/GTE/FINAL (26 -10- 01)/CHAPTER 13.3D ± 468 ± [467± 520 /54]... to install a steam boiler G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 4 62 ± [436±466/31] 1.11 .20 01 3:52PM 4 62 Gas Turbine Engineering Handbook To Other Tracers Condensate Return Pressure Reduction (If required) Steam Main Condensate Return Main e d Pip e Trac Steam Trap Assembly Steam tracer length limited Low pressure Small diameter Elevation changes Figure 12- 12 Steam tracing system just for tracing... turbine has been fueled by cheap natural gas at $3.50/mmBTU ($3. 32/ mmkJ) The cost of natural gas in late 20 01 is heading to $9.0/mmBTU ($8.53/mmkJ), this will make alternative fuels interesting once again Table 12- 10 is an estimate of the world population of gas turbines, and it reflects the growth of natural gas driven gas turbines in the late 1990s and early 20 00s Heat Tracing of Piping Systems As... abandoned due to warpage G:/GTE/FINAL (26 -10- 01)/CHAPTER 12. 3D ± 454 ± [436±466/31] 1.11 .20 01 3:52PM 454 Gas Turbine Engineering Handbook Cleaning of Turbine Components A fuel treatment system will effectively eliminate corrosion as a major problem, but the ash in the fuel plus the added magnesium does cause deposits in the turbine Intermittent operation of 100 hours or less offers no problem, since... availability of natural gas The 1990s have seen a tremendous growth in gas turbine usage with the  advent of the high-efficiency gas turbines (40±45%), being used in Combined  Cycle Power Plants, which have plant efficiencies between 55±60% Most of  20 01, gas turbines are these turbines were all driven by natural gas In 20 00 backordered for the next three to five years All this growth in the turbine has been . 118  22 0 150 /20 0 < RT 175 /26 5 186  F 198 50 /20 0 Pour point  F À50 À55 to 10 10= 30 15/95 68 10  F 15/ 110 Visc. CS @ 100  F 1.4 /2. 2 2. 48 /2. 67 2. 0/4.0 .79 100 /1,800 7.3 6.11 6 .20 2/ 100 SSU. 18,700/ 18, 820 18,300/18,900 18 ,25 0 18 ,23 9 19,000/19,400 Hydrogen % 12. 8/14.5 12. 83 12/ 13 .2 14.75 10/ 12. 5 12. 40 12/ 13 .2 Carbon residue 10% bottoms .01/.1 .104 .03/.3 2/ 10 .3/3 Ash ppm 1/5 .001 0 /20 100 /1,000. 1 /10 7,500 42, 000 72, 000 3,750 20 ,000 25 ,000 Distillate oil 1 /100 0 22 ,000 45,000 72, 000 11 ,25 0 22 ,000 30,000 Distillate oil 1 /10 6,000 35,000 48,000 3,000 13,500 18,000 Residual 1 /100 0 3,500 20 ,000