GE Power Generation

Considerations When BurningAsh-Bearing Fuels in Heavy-DutyGas Turbines

Eric KaufmanGE Power SystemsSchenectady, NY

GER-3764A

GE Power Generation

Considerations When BurningAsh-Bearing Fuels in Heavy-Duty

Gas Turbines

Eric KaufmanGE Power Systems

Schenectady, NY

GER-3764A

Eric KaufmanMr. Kaufman is a Lead Application Engineer in the Production

Systems Engineering Department. He is principally responsible for thedesign and application of gas turbines in electrical generation andmechanical drive projects. He has spent six years rotating throughControl Engineering, CM&U Engineering, Generator ApplicationEngineering and Gas Turbine Application Engineering. Mr. Kaufman isa member of ASME.

A list of figures and tables appears at the end of this paper

INTRODUCTIONGE is the world’s leading manufacturer of gas

turbines utilizing ash-bearing fuel oil. GEmachines have accumulated more operatinghours than those of any other manufacturer. Thispaper highlights GE’s experience with burningcrude, residual, and other ash-bearing fuels in thevarious GE gas turbine product lines. The paperalso presents discussion regarding the combustionsystem design; hot section design and materials;fuel treatment and handling; and turbine accesso-ry systems. In addition, this paper goes into depthon laboratory testing of hardware and ash depositmechanisms, effects of increased firing tempera-ture, the relative merits of various fuel additivescurrently used, and inspection intervals.

HEAVY FUELS OPERATINGEXPERIENCE

IntroductionGE’s experience burning heavy ash-bearing

fuels dates to the infancy of the gas turbine busi-ness in the 1940s and 1950s. More than 300 GE-designed machines have accumulated in excessof 7.8 million fired hours using crudes, residu-als, or blends of crudes and distillates as the pri-mary fuel.

A large number of machines were installed inthe decade 1950 to 1960. Interest then wanedthrough the 1960s as low cost natural gasbecame more plentiful, and the gas turbine mar-ket began to shift to electric utility peakingapplications where gas or distillate were the pre-ferred fuels. In the late 1960s when natural gasreserves began to decline, heavy fuel applica-tions again increased. Many machines were soldwith dual fuel capability, using ash-bearing typesas secondary fuels, or provisions were requiredfor possible conversion to heavy fuel. This inter-est lapsed again after a few years as natural gasonce more became plentiful. Only very recentlyhas interest in heavy fuel, particularly in the FarEast, become a factor once again.

Table 1 shows GE’s overall heavy fuel experi-ence. Early operating experience provided the tech-nological base that made possible the success of thelarge number of more sophisticated heavy-fuel-firedmachines installed in more recent history.

GE experience burning heavy ash-bearing fuelsat various firing temperatures is shown in Figure 1.

Initial Experience — 1950 Through 1960

Early use of ash-bearing fuels in the 1950s and1960s was in units ranging from 5,000 kW to15,000 kW, with firing temperatures around 1450F(788C), which were typical of that stage of gas tur-bine development. Installations included electricutilities, oil pipelines, railroad locomotives, andship propulsion, and nearly three million operat-ing hours were accumulated. Many of these unitsremain in service today, although several havebeen converted to natural gas fuel. The first “test-beds” where fuel washing and treatment systemswere developed were residual oil burningmachines operating with Central Vermont andBangor Hydroelectric utilities. The fuels wereheavy residuals with gravities ranging from 0.90 to1.0, vanadium from 50 to 360 ppm, and sodiumfrom 20 to 100 ppm before washing. Successfuloperation was demonstrated at a nominal firingtemperature of 1500F (816C), with more than19,000 hours on the longest running unit.

The most heavy-fuel operating hours (1.9 mil-lion) were achieved on 57 Union Pacific Railroadlocomotives. The residual fuel contained less than5 ppm sodium, and vanadium levels averagedabout 10 ppm, requiring a magnesium additive.Each unit accumulated some 35,000 fired hours at1450F (788C) firing temperature.

Nine machines in crude oil pipeline service inSaudi Arabia logged a further total of 700,000hours on crude which did not require desaltingsince the sodium levels were below the specifiedlimit of 5 ppm. However, a magnesium additivewas injected to inhibit the 12 ppm vanadium. Theunits were remotely operated and started and shutdown on crude fuel. Finally, the GTS JohnSargent, a Liberty ship converted to gas turbine

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CONSIDERATIONS WHEN BURNING ASH-BEARINGFUELS IN HEAVY-DUTY GAS TURBINES

E. KaufmanGE Power Systems

Schenectady, NY

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Table 1GE-DESIGNED GAS TURBINE WORLDWIDE EXPERIENCE (AS OF FEBRUARY 1994)

WITH HEAVY ASH-BEARING FUELS

GT24235A

Figure 1. Firing temperature operating experience

drive, logged 10,000 hours of service, nearly 8,000of which were achieved on a variety of residual oilswhich were desalted and treated on board. Duringthis period of operation the hot gas path was com-pletely free of corrosion.

Continuing Experience — Late 1960s On

In the decade of the late 1960s to the late1970s, over 150 GE machines were installed withheavy fuel capability. The majority of these wereused for power generation, both utility and indus-trial, with others operating as mechanical drivemachines and for ship propulsion. Within thistime frame, more than one million hours wereaccumulated, and several units achieved in excessof 30,000 hours each. Unit ratings ranged from 10MW to 65 MW, with firing temperatures of 1450Fto 1850F (788 - 1010C).

Nine Frame 5 machines in Indonesia (Caltex),were used for power generation to pump crudeoil. The fuel was a waxy crude with low vanadium(0.5 ppm) that was water washed to reduce sodi-um concentration from 10 ppm to less than 1ppm. The units were baseloaded at a firing tem-perature of 1650F (898C). Although no currentoperating data is available, the machines hadaccumulated well over 200,000 hours in 1984, withmore than 50,000 hours on some individual units.Hot gas path inspections were performed every10,000 hours, major inspections every 20,000hours, and the U700 turbine buckets providedexcellent service to beyond 28,000 hours. Tenmachines in France (Rhone-Poulenc), havelogged well over one half million hours of serviceat firing temperatures of 1650F (898C). The units’high-viscosity fuel requires heating to 140F (60C),and air atomization for combustion. Some individ-ual units have delivered in excess of 50,000 hoursof service.

Additional machines in North Africa and Italyhave also run at 1650F (898C) firing temperatureon residual fuel containing high levels of vanadi-um and sodium before washing. Electrostatic pre-cipitators provided desalting, and the fuel wasinhibited with an organic oil-soluble magnesiumadditive.

A comprehensive test program was run on aFrame 5 unit at the GE facility in Lynn,Massachusetts to demonstrate the capability ofburning oils at high firing temperatures. Bothelectrostatic and centrifugal desalting systemswere installed for evaluation, and the unit has runon a variety of residual fuels up to firing tempera-

tures of 1850F (1010C). No corrosion on uncoat-ed turbine buckets has been experienced. Threetypes of magnesium additives, water soluble, oilsoluble, and suspendible solids, were evaluated,and it was shown that magnesium oxide slurriescan be added to heavy fuels without any adverseeffects on fuel pumps and flow dividers.

In addition to the numerous Frame 5machines, many larger Frame 7 units were alsoinstalled in this time period using heavy oil as theprimary fuel.

Ten units (MS7001B) were operated by FloridaPower Corp. at its Bartow and DeBarry stations. AtBartow, the fuel was a high wax Libyan crudewhich was electrostatically desalted and inhibitedwith an oil soluble magnesium additive; it was alsoheated to 100/110F (38/43C) to avoid fuel filterplugging. These machines operated successfully at1840F (1004C) firing temperature in peak loadmode between 1972 and 1976, when the crudefuel became unavailable. Turbine washing toremove combustion ash deposits was performedevery three months. Residual oil with up to 33ppm sodium and 40 ppm vanadium was used atDeBarry and washed to reduce sodium to lessthan 1.0 ppm by a three stage electrostaticdesalter; vanadium was inhibited by an oil solublemagnesium additive.

Another example of Frame 7 experience is theAlcoa Aluminum Bauxite plant in Paramaribo,Surinam. The unit went operational in 1976 usingTrinidadian residual oil. The raw fuel had sodiumlevels from 80 to 125 ppm and vanadium varyingfrom 65 to 85 ppm. Fuel treatment is achievedwith a De Laval centrifugal washing system andinjection of oil and water soluble magnesium inthe ratio of three magnesium to one vanadium.Initial operation indicated some minor problemswith the fuel pump, flow divider and fuel nozzleplugging when using water-soluble additive. Astainless steel screw-type positive displacement fuelpump and the addition of corrosion resistantmaterials to the flow divider eliminated two of theproblems. Fuel nozzle plugging was eliminated bymore thorough mixing of the magnesium andfuel with a centrifugal pump which allows the useof the less expensive water-soluble additive; oil-sol-uble additive is retained as a backup.

Unit operation through July 1987 occurred at afiring temperature of 1750F (954C), and 25,000hours were accumulated. Since a major overhaulin 1987, the unit had been exercised monthlyuntil November 1992, when it was placed backinto continuous ser vice at reduced load.

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Inspection results indicated little to no corrosionproblems on the turbine nozzles or buckets, andnozzle corrosion life (FSX-414 material) far inexcess of 25,000 hours.

Saudi Arabian ExperienceMost recent operating experience with heavy

ash-bearing fuels (in excess of two million hours)has occurred on numerous GE-designedmachines in Saudi Arabia. Riyadh Power Plant #7(PP7) is an outstanding example, where sixteenFrame 7E machines have run continuously oncrude at a firing temperature of 1740F (949C) forthe past fourteen years. The fuel, light Arabiancrude, is supplied directly from the Riyadh refin-ery and has 10 to 30 ppm vanadium; it is washedon site and a magnesium additive is introduced inthe ratio of 3:1 Mg:Va. Turbine base heating isnormal, and the units start and stop on the crudefuel. After more than one million hours at PP7,there have been no significant problems in thehot gas path. Most of the units still have their orig-inal turbine buckets. Turbine water washing isperformed on each unit at monthly intervals.Currently at PP7, GE is installing 4 additionalFrame 7EA machines. These machines utilize thesame crude oil as the existing 16 units. Theseunits have a firing temperature of 2000F (1093C)and are expected to have a water wash interval ofapproximately 1000 hours.

In addition to PP7, there are twenty-eight otherGE-designed machines operating in the Kingdomeither on similar crude or blends of distillate andcrude. These units include Frame 5s, 6s and 7sinstalled in Saudi Consolidated ElectricCompany’s (SCECO) Central, Western, Southernand Eastern regions at sites such as Jeddah,Tihama and Quaisumah. They have accumulatedmore than one million operating hours.

GE-designed machines in Saudi Arabia haveoperated satisfactorily on various crudes andcrude/distillate blends for over two million hours.Since the majority of the machines are used inbaseload or mid-range applications, operatinghours continue to accumulate rapidly.

Competitive ExperienceHeavy duty machines installed by our three

major competitors have about half the total oper-ating hours of GE units using heavy ash-bearingfuels. Most current experience has been in SaudiArabia, where several competitor units operateside-by-side with GE machines and use the same

fuel. It appears that in the Central, Western andSouthern regions of SCECO, turbine bucket fail-ures due to corrosion have been common oncompetitors machines using light Arabian crudeand blends of crude/distillate. The problemsseem to occur on the first and second turbinestages after relatively few hours (10 - 15,000), andmany machines have had both stages replaced atleast once in the past ten years. In addition, out-put degradations of as much as 30% have beenreported.

A further comparison can be made with unitssituated in Taiwan, where GE Frame 7Es and com-petitor units operate at the same site and on thesame no. 6 residual fuel. Again, the competitorunits have suffered turbine bucket corrosionrequiring premature bucket replacement, whilethe GE units have been free of these problems.Overall, the GE machines have been utilizedalmost twice as much as the other manufacturers’equipment, with each GE unit accumulatingapproximately 1,600 hours per year as opposed toabout 900 hours on the competitors’ units.

Significance of Field ExperienceExtensive field operating experience accumu-

lated on GE gas turbines burning heavy oils pro-vides a time-tested evaluation of the ability ofthese machines to operate economically and reli-ably over extended periods. Early experience ofunits operating at lower firing temperatures ishighly relevant to the heavy fuel operation oftoday’s gas turbines with higher firing tempera-tures. The extensive heavy-fuel technology devel-oped during this early period includes:

• Determination of effects of trace metal con-taminants (vanadium, sodium and potassi-um) on high temperature materialsemployed in the turbine.

• Development of appropriate fuel treatmentsystems to remove or inhibit the corrosivetrace metal contaminants.

• Determination of the relationship of fuelquality and trace metal contamination limitsto reliable operation.

• Evaluation of ash deposit rates, includingmethods of cleaning and their effect on per-formance.

• Development and design of combustion sys-tems and fuel handling and control systems.

This technology base has now been extendedto the higher temperature MS7001EA andMS9001E machines. The total GE experience onash-bearing fuels is unparalleled in the industry.

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TURBINE GAS PATH DESIGN

IntroductionGE gas turbine designs are based on both a

firm analytical foundation and field experience.Evolution of proven designs has resulted fromimproved components and materials which havebeen prudently applied to increase power andthermal efficiency. While designs are carefully test-ed in development facilities, field performancecontinues to provide the best proof of designeffectiveness.

Turbine Gas PathIncreasing firing temperature has been a major

developmental thrust for turbines over the past 30years, since increased firing temperatures increasethe output and efficiency. Higher turbine firingtemperatures are achieved by improved nozzleand bucket materials and by air cooling.Concurrent developments in alloy corrosion resis-tance and bucket surface protection systems haveprovided fuel-flexible, corrosion-resistant compo-nents. Base load firing temperatures haveincreased approximately 25F (14C) per year, from1500F (816C) in 1961 to 2000F (1093C) today.This corresponds to an annual increase in attain-able output of approximately three percent andan annual increase in efficiency of approximatelyone percent. Thus, machine development findssignificant rewards in reduced first-cost per unitoutput and reduced costs of operation.

GE turbines use high-energy stages with lowreaction. The most important advantage of thisdesign is the higher firing temperatures achiev-able at constant first-stage bucket metal tempera-ture, as illustrated by Figure 2. This designapproach also minimizes the required number ofturbine stages, providing fewer operating compo-nents, less exposure to corrosion, less mainte-nance and, consequently, lower overhaul costs. Toenhance the capability to burn heavy fuels, otherfeatures are also included, such as thick wall sec-tions, thick trailing edges, and wide throats.

Since the early 1960s, air extracted from thecompressor has been used to cool the nozzles andbuckets. Nozzle metal temperatures were main-tained at about 1550F (843C) as firing tempera-tures were raised. By the late 1960s, turbine baseload firing temperatures were approximately1700F (927C). Significant firing temperatureincreases depended on first-stage bucket coolingand deposit washability.

The cooling air circuit of the first-stage nozzlefor the crude oil burning MS7001EA or MS9001Estarts with air impinging on the nozzle internalcavity surface. The air is then exhausted into thegas path through trailing-edge rectangular slotsand through large pressure-side film holes whichare not subject to plugging by ash deposits.

Bucket air cooling circuits are entirely internalto the rotor, starting with a radially inward extrac-tion from the inner diameter of the compressorgas path. Since the compressor acts as a naturalcentrifuge, this extraction point prevents foreignmatter from entering the cooling circuits andplugging the bucket cooling passages. The inter-nal circuit also eliminates the need for seals orpackings between the rotor and stator to containthe cooling air. Metering of the air is accom-plished by the buckets, because the cooling circuithas a much greater flow area than the bucketcooling holes. This feature provides high velocityfor efficient heat transfer in the bucket. Anotheradvantage of this design is that cooling air exitsfrom radial holes at the bucket tip, permittingburning of ash-bearing fuels without plugging ofthe bucket cooling system.

Cooled buckets and advanced air-cooled first-stage nozzles were incorporated in MS7001B tur-bines in 1972. A base load firing temperature of1840F (1004C) was established. The success of thisdevelopment has resulted in satisfactory operationin over 230 MS7001B units.

In the more recent MS7001EA and MS9001E,the nozzle and bucket cooling have been furtherimproved to provide base load firing temperaturesin the 2000F (1093C) range. The second-stage

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GT24523

Figure 2. Bucket metal temperature

nozzles and buckets are also internally cooled,similar to the first stage.

Buckets are subjected to gas forces which cancause bucket vibration. Resonance between forcesand bucket natural vibration modes are avoided atfull operating speed. However, resonance cannotbe avoided during startup and shutdown. All GE-designed turbines incorporate features to sup-press resonant vibration. These include the long-shank bucket with a friction type connection atthe bucket platform and a tip shroud (Figure 3).

In the long-shank bucket design, damping isintroduced near the midspan by placing axial pinsunderneath the platform between adjacent buck-ets. In the first stage, the damping provided bythese pins virtually eliminates all vibration involv-ing tangential motion and controls vibration inthe other modes. The shank also provides thermalisolation between the gas path and the turbinewheel dovetail. Since the shank is a uniform unre-strained section, stress concentrations in the dove-tail are minimized.

The integral tip shroud is the second majorvibration control feature. These are used on thelong second and third stages. The individualbucket shrouds are interlocked to form a continu-ous band during operation. The natural tendencyfor the buckets to untwist under centrifugal loadis used to force the mating faces of adjacentshrouds together, providing friction damping.The tip restraint provided by the continuousshroud band eliminates the first flexural mode ofvibration, which is the most sensitive.

Turbine deposits from heavy fuels cause ran-dom aerodynamic vibration stimuli in the gas

path. The vibration-resistant design has enabledGE gas turbines to operate reliably while subject-ed to these stimuli.

Several test techniques are used to assure ade-quate vibration margin. Stationary bench testingis used to drive a bucket through a range of fre-quencies to identify its natural modes. Wheelboxtesting is performed in a large, evacuated cham-ber in which full turbine stages are run through-out the operating speed range to determine buck-et vibration response. Gas force excitation isgenerated by an array of nozzles which direct highvelocity air at the buckets. Vibration data fromstrain gauges mounted on the buckets is fedthrough slip rings into a processing facility, whereboth tape recording and on-line analyses are pos-sible. Thorough testing, combined with extensiveservice experience, provides a sound design basis.Since 1958, when these concepts were introduced,no bucket of this design has experienced a vibra-tion failure in the shank or dovetail.

Combustion DesignAll modern GE heavy-duty gas turbines use

multiple reverse-flow combustors similar to thatillustrated in Figure 4. Each combustor is com-posed of a liner, transition piece, and fuel nozzle,chosen for its fuel flexibility, maintainability, andease of testing at full pressure, temperature, andflow conditions in the laboratory. The designobjectives for a combustor are listed in Table 2.

Air atomizing fuel nozzles (Figure 5) are uti-lized for liquid fuel applications. Air pressureatomizes the fuel to assure complete combustionand a smoke-free stack over the operating rangeof the gas turbine.

Figure 4 shows that compressor discharge airflows around the transition pieces while coolingthem. It enters the combustion liner through vari-ous air passages in the liner. Fuel injected into the

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GT19690A

Figure 3. MS7001 gas turbine construction features of second- and third-stageprecision cast buckets

GT?

Figure 4. Multiple reverse-flow combustor

combustion reaction zone burns with a portion ofthe available air entering the head end of thecombustor. Recirculating flow patterns of air andburning gases provide flame stability. The hotcombustion gases are then mixed with secondaryair entering through downstream holes to dilutethe gas and lower its temperature before it entersthe turbine. The temperature profile of hot gasesentering the turbine section is controlled to maxi-mize the life of the turbine parts.

Heat transfers from the flame and hot gases tothe liner walls and is removed by air sweepingover the inside and outside of the liner. The flowsleeves enhance liner cooling by increasing thecooling air velocity near the liner.

These combustors can burn a wide variety offuels ranging from natural gas to the various pro-cess gases, and from naphtha to heavy residualoils. Dual fuel nozzles are often used to allowtransfer between fuels without shutdown.

Neither mathematical nor geometric modelinghas been adequate for combustion developmentbecause a scale model does not reproduce thechemical reactions, heat release rates, and aerody-namic mixing of the full-size design. Aerodynamic

mixing, which is achieved by air jet penetrationfrom the walls of the combustor, becomes moredifficult as the liner diameter increases.Consequently, full-size combustor testing at fullflow and pressure is necessary to assure the ade-quacy of new designs. Additionally, the ability toeconomically perform extensive full-scale labora-tory testing is a major advantage of the multiple-combustor approach. Almost all of the develop-ment work can be done on a single-burner teststand at full operating conditions.

The combustor ignition system includes sparkplugs, crossfire tubes, and flame detectors. Forreliability, two spark plugs and two flame detectorsare used. Ignition in one of the chambers pro-duces a pressure rise which forces hot gasesthrough the crossfire tubes, thereby propagatingrapid ignition to all other chambers. Flame detec-tors, located diametrically opposite the sparkplugs, signal the control system when the ignitionprocess has been completed. Because of the sim-plicity and reliability of this technique, it is used inall GE-designed heavy-duty gas turbines.

Combustion LinerThe combustion system has evolved from the

original application of heavy-duty machines burn-ing residual oil. Engineering development workon this system has continued, and the slot-cooledliner (Figure 6) is standard in the MS7001EA andMS9001E gas turbines.

The slot-cooled liner, originally developed byGE for aircraft gas turbines, has been modified forapplication to the heavy-duty gas turbine. It pro-vides more uniform, more effective cooling thanpossible with a louvered liner. The slot-cooledliner operates with 250F (139C) lower metal tem-

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Table 2COMBUSTION DESIGN OBJECTIVES

GT24242

Figure 5. Air atomizing fuel nozzle

peratures than an equivalent louver system(Figure 7). It also operates with lower tempera-ture gradients, which increases the comparativelife of the parts. The slot-cooled liner is superiorto the louver type for the more radiant flamesfrom heavy fuels, and it eliminates the cornerstress concentration points of louvers.

Another important innovation in liner designhas been decrease in length. This “short” linerprovides increased stiffness as well as reducing theamount of cooling air required, since the surfacearea to be cooled is reduced.

The major impacts of the heavy fuel propertieson combustor design are the liner metal tempera-ture and carbon formation. The degree to whichthe fuel has been atomized is an important influ-ence on both. By using a finely atomized spraysuch as that produced by the prefiring airblastnozzle, flame radiation can be reduced by as

much as 75 percent in the intermediate zone ofthe combustor. All liquid fuels for the MS9001Eand MS7001EA are, therefore, air atomized at thefuel nozzle. Typical atomizing air pressure ratios(fuel nozzle air pressure/compressor dischargepressure) are in the range of 1.2 to 1.4 for lightdistillate fuels, with higher ratios required forheavy fuels. Fuels with kinematic viscosities of upto 20 x 10-6m2/s can be successfully burned usingatomizing air. The required pressure ratio is deter-mined largely by experiment and consideration ofseveral design factors including emissions, com-bustor metal temperatures, temperature profiles,and carbon build up.

Transition PieceOn the multiple combustor arrangement of the

MS7001EA and MS9001E, the transition piece,which channels the high temperature gas fromthe combustion liner to the first-stage nozzle, isvery short and easily cooled by air flowing fromthe compressor. The attachment point of the sup-port bracket is jet film cooled as shown in Figure8.

The original MS7001 transition pieces had cer-tain difficulties which have been corrected byincreasing the metal thickness and eliminatingthe flat panels which were prone to vibration. Thisdesign is shown in Figure 8. The positive curva-ture (bulge) stiffens the body and eliminates thevibration failures.

The MS9001E gas turbine uses canted combus-tors as opposed to the in-line configuration of theMS7001EA. As a consequence, the MS9001E tran-sition pieces are a shorter, simpler design which isinherently less susceptible to vibration and wear.An exploded view of the MS9001E transitionpiece is shown in Figure 9.

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GT24241

Figure 6. Slot-cooled liner, cutaway view

GT24524

Figure 7. Liner cooling profiles

GT12785

Figure 8. MS7001EA transition piece

TURBINE GAS PATH MATERIALS AND CORROSION

IntroductionThere are a number of constraints involved in

the development and choice of materials for thehot gas path components of a gas turbine. Hightemperature strength, manufacturability, and costare some examples. When operating with ash-bearing oils, one of the most important considera-tions is corrosion resistance.

For more than 35 years, GE has maintained acontinuing program to improve the tolerance ofmachines to the corrosive contaminants sodium(Na), potassium (K), vanadium (V), and lead(Pb) from air and fuel. The results of this pro-gram include the use of large, heavy-walled parts,corrosion-resistant materials, protective coatings,and component cooling.

Mechanism of CorrosionHot corrosion will take place if metallic com-

pounds containing Na, K, Pb, or V are depositedor condensed on the surface of hot-section com-ponents. The rate of corrosion attack depends onthe concentration and composition of the con-taminants, the material properties, and the tem-perature and pressure at the surface.

Two competing mechanisms are involved:• Condensation of corrosive deposits is

increased by lower temperature and higherpressure.

• Chemical reaction rates are increased athigher temperature.

An example of this is the observation that cor-

rosion can be more severe at lower temperaturesthan at higher temperatures (e.g., bucket fillets,latter stage buckets, intermittent operation at verylow firing temperatures). Figure 10 shows anexample of condensation taking place on surfacesover the radial cooling holes in buckets. Similarly,the first-stage nozzle has patches of white depositswhere the materials have condensed oppositeimpingement holes in the nozzle insert used todirect cooling air against the inside surface of theairfoil.

Figure 11 shows the relationship between cor-rosion life and contaminant level at two tempera-tures. This chart shows that at higher tempera-tures, more contaminants can be tolerated for agiven corrosion life. The decrease in life as a func-tion of contaminant level is the result of increas-ing condensation of corrosive deposits, until thesurface is saturated. At this point, the corrosionlife is limited primarily by the kinetics of the cor-rosion reaction.

Superalloys in high temperature service oxidizeuniformly due to the formation and retention ofprotective oxides. Hot corrosion, however, is initi-ated by the destruction of protective oxides byreactions with molten compounds of Na, K, Pband V, resulting in an accelerated attack. Thesequence of the hot-corrosion phenomena can besummarized as follows:

• Hot corrosion is usually associated with thepresence of both Na and sulfur (S). Thesecombine in the hot gas atmosphere to formNa2SO4, which condenses on componentsurfaces. The Na2SO4 reacts with the sur-face, destroying the protective oxide. Sulfurthen penetrates into the metal, formingchromium (Cr) sulfides.

• Depletion of Cr retards the reformation ofthe oxide film.

• Continuing dissolution of the protectiveoxide scale allows the hot corrosion processto accelerate.

Pb and V in hot gas streams cause a similar typeof attack in which protective oxides are fluxed andtheir protective effect is destroyed.

Small Burner Test FacilitiesThe initial concept of small burner test facilities

dates back to the middle 1950s at GE. More than30 million specimen hours of testing have beenaccumulated with materials at high temperaturein both clean and contaminated combustionproduct environments. Specimens of candidate

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GT24525

Figure 9. MS9001E transition piece

nozzle and bucket materials are exposed to tem-peratures ranging from 1400F (760C) to 2000F(1093C) and to controlled contaminant levels.

GE’s data bank accumulated over the years isthe largest in the world and is used to predict theintegrity of nozzles and buckets under a verybroad spectrum of fuel and airborne contami-nants. The tests serve three purposes:

• To evaluate new and more corrosion resis-tant materials for nozzles and buckets.

• To evaluate the behavior of materials in com-bustion products containing the contami-nants Na, K, V, Pb singly and in combina-tion.

• To develop a prediction of corrosion partslife as a function of levels of these contami-nants and metal temperature.

Oxidation tests are run from 1000 to 30,000hours at firing temperatures up to 2000F (1093C).The maximum penetrations observed at each testtemperature are plotted vs. time on log paper(Figure 12). A line is curve fitted through each setof points. The expression for this line is:

P = (Kt)where P = the maximum penetration (mils)

t = time of exposure (hours)K = constant which is dependent

on temperature - T (F)= exponent or slope of P vs. t line

and is dependent on T.Subsequently, a third order polynomial is fit-

ted to the plots of K and vs. 1/T.Hot corrosion tests are conducted with No. 2

λ

λ

λ

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GT24521

Figure 10. Deposits of sea salt on MS7001 first-stage nozzle partitions and buckets. Note condensatesin locally cooled surfaces

GT24526Figure 11. Life vs. alkali concentration for

heavy duty gas turbine (schematic)

fuel to which detertiary butyl disulfide is added toadjust the sulfur level to 1 percent by weight. Adispersing agent is added to keep the simulatedsea water in suspension (sodium equal to 125 ppm).

Tests are most frequently conducted at 1600F(871C) and 1800F (982C), which are theextremes for hot corrosion with respect to theamount of condensible contaminants on the spec-imen surface at one atmosphere. The specimensat 1600F (871C) are “wet” with condensed salts,while at 1800F (982C) specimens are “dry”, andcondensation takes place only during daily tem-perature cycling.

An example of the comparative corrosionbehavior of two alloys is shown in Figure 13. Thelaboratory data for penetration vs. time is shownfor U700 and IN-738.

Gas Path MaterialsGE’s design approach through the past 40 years

has been to maintain as high a turbine firing tem-perature as possible consistent with materialsproperties and cooling concepts. The result hasbeen a steady, continued growth in firing temper-atures, as shown by the upper curve in Figure 14.The lower curve is the creep/rupture strength of

the materials used in the first-stage bucket, themost critical component to support this firingtemperature. The introduction of new materialshas contributed to the steady improvements inturbine output and efficiency.

GE currently utilizes GTD-111, IN-738, andU500 as bucket materials. All three are precipita-tion-strengthened nickel-base superalloys withdemonstrated corrosion resistance. GTD-111 hasthe added benefits of a 35F (19 C) increase inrupture strength and greater low-cycle fatiguestrength over IN-738. IN-738 is significantlystronger than U500, and is used where greaterhigh temperature strength is required.

First stage nozzles (GE terminology for the sta-tor vanes of the turbine) are subjected to thehottest gas temperatures but to lower mechanicalstresses than the buckets. Their function is todirect the hot gases toward the buckets, and theymust be able to withstand high temperatures andprovide minimal gas turning losses. The nozzlesare required to have excellent oxidation and hotcorrosion resistance (particularly in sulfurousenvironments), high resistance to thermal fatigue,relatively good weldability for ease of manufactureand repair, and good castability. The current alloyused for all first stage nozzles is a GE patented

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Figure 12. Small burner oxidation test result, FSX414

cobalt base alloy, FSX-414.

Bucket CoatingsThe primary purpose of bucket coatings (Ref.

1) is to protect the bucket from corrosion, oxida-tion, and mechanical property degradation. Assuperalloys have become more complex, it hasbeen increasingly difficult to obtain both requiredhigher strength levels and satisfactory levels ofcorrosion and oxidation resistance without theuse of coatings. Thus, the trend toward higher fir-ing temperatures increases the need for coatings.The function of all coatings is to provide a surfacereservoir of elements that will form very protec-tive and adherent oxide layers, thus protecting the

underlying base material from oxidation and cor-rosion attack and degradation.

Bucket coatings were first used in aircraft gasturbines in the early 1960s. The first of these werediffused aluminum types of coatings. They wereevaluated in heavy-duty gas turbines and found tobe inadequate because of the longer service timesand the higher levels of contaminants in thesemachines. The presence of increased levels ofcontaminants gives rise to an accelerated form ofattack called hot corrosion. Experience has shownthat the lives of both uncoated and coated bucketsdepend to a large degree on the amount of fueland air contamination, as well as the operatingtemperature of the bucket. This effect is shown inFigure 15, which illustrates the effect on bucketlife of sodium, a common contaminant.

In addition to hot corrosion, high temperatureoxidation is also a concern in the higher firing gasturbines. In today’s advanced machines, it is ofconcern not only for external buckets surfaces butalso for internal passages such as cooling holes.

Hot CorrosionHot corrosion is a rapid form of attack which is

generally associated with alkali metal contami-nants such as sodium and potassium reacting withsulfur in the fuel to form molten sulfates. The

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GT03480B

Figure 13. Comparision of U700 and U500/IN738 corrosion resistance

GT01650N

Figure 14. Firing temperature trend and bucket material capability

presence of only a few parts per million (ppm) ofsuch contaminants in the fuel, or equivalent inthe air, is sufficient to cause this corrosion.Sodium can be introduced in a number of wayssuch as salt water in liquid fuel, through the tur-bine air inlet at sites near salt water or other con-taminated areas, or as contaminants inwater/steam injections.

There are now two distinct forms of hot corro-sion recognized by the industry, although the endresult is the same. These two types are high tem-perature (Type 1) and low temperature (Type 2)hot corrosion.

High temperature hot corrosion has beenknown since the 1950s. It is an extremely rapidform of oxidation which takes place at tempera-tures between 1500F (816C) and 1700F (927C) inthe presence of sodium sulfate (Na2SO4).Sodium sulfate is generated in the combustionprocess due to the reaction between sodium, sul-fur and oxygen. Sulfur is present as a natural con-taminant in the fuel.

Low temperature hot corrosion was recognizedas a separate mechanism of corrosion attack inthe mid-1970s. This attack can also be very aggres-sive if the conditions are right. It takes place attemperatures in the 1100F (593C) to 1400F(760C) range and requires a significant partialpressure of SO2. It is caused by low melting eutec-tic compounds resulting from the combination ofsodium sulfate and some of the alloy constituentssuch as nickel and cobalt. It is somewhat analo-gous to the type of corrosion called “fireside cor-rosion” in coal-fired boilers.

The two types of hot corrosion cause differenttypes of attack, as shown in Figures 16 and 17.These are metallographic cross sections of corrod-ed material. High temperature corrosion featuresintergranular attack, sulfide particles, and adenuded zone of base metal. Low temperature

corrosion characteristically shows no denudedzone, no intergranular attack, and a layered typeof corrosion scale.

Besides the alkali metals such as sodium andpotassium, other chemical elements can influenceor cause corrosion on bucketing. Most notable arevanadium, primarily found in crude and residualoils, and lead, most frequently resulting fromautomobile exhaust emissions or as a transporta-tion contamination from leaded gasolines.

The lines of defense against both types of cor-rosion are similar. First, reduce the contaminants.Second, use materials that are as corrosion resis-tant as possible. Third, apply coatings to improvethe corrosion resistance of the bucket alloy.

High-Temperature OxidationMetal oxidations occurs when oxygen atoms

combine with metal atoms to form oxide scales.The higher the temperature, the more rapidly thisprocess takes place, creating the potential for fail-

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GT8909E

Figure 15. Effect of sodium on bucketcorrosion life

GT11638A

Figure 16. Hot corrosion (high-temperaturetype)

GT11639

Figure 17. Hot corrosion (low-temperaturetype)

ure of the substrate material if too much of it isconsumed in the formation of these nil strengthoxides. Figure 18a shows the microstructure of acoated bucket after about 30,000 hours of service.At the temperatures in this region of the airfoil,no significant oxidation attack of the coating canbe seen. By contrast, Figure 18b shows themicrostructure of the same coating which hasbeen severely attacked after about the samelength of service. At the higher temperatureswhich must have been present in the Figure 18bcase, insufficient aluminum was available in thecoating to maintain a protective oxide at the sur-face, and oxygen was able to diffuse into the inte-rior of the coating structure where it formed dis-crete, discontinuous aluminum oxide particles.This phenomenon is known as internal oxidation.Such a situation quickly depletes the coating of itsavailable aluminum, rendering it non-protective.

At the higher temperatures (>1650F (899C)),relatively rapid oxidation attack of some materialscan occur unless there is a barrier to oxygen diffu-sion on the metal surface. Aluminum oxide(Al203) provides such a barrier. Aluminum oxidewill form on the surface of a superalloy at hightemperatures if the superalloy aluminum contentis sufficiently high. Thus, the alloy forms its ownprotective barrier in the early stages of oxidationby the creation of a dense, adherent aluminumoxide scale. However, many high strength superal-loys in use today cannot form sufficiently protec-tive scales because the compositional require-ments for achieving other properties, such as highstrength and metallurgical stability, do not allowfor the optimization of oxidation/corrosion resis-tance in the superalloy itself. Therefore, most oftoday’s superalloys must receive their oxidationprotection from specially engineered coatings.

High-Temperature CoatingsThese are the types of coatings that are used on

the first stages of all machines, and also might findsome application in selective downstream stages.Considerable development has occurred duringthe past 20 years in the field of high temperaturecoatings. The result has been a marked increasein the capability of these coatings to resist not onlyhot corrosion attack over long periods of time,but high temperature oxidation as well. GE heavyduty coatings available today have lives which are10 to 20 times longer than first generation coat-ings under a wider diversity of corrosion and oxi-dizing conditions.

We have used two basic classes of coatings dur-

ing the past 25 years. The first class used was a dif-fusion coating called platinum aluminide (PtAl).The second class is an overlay coating, PLASMA-GUARD™GT-29 IN-PLUS™.

The development of each of these coating sys-tems was in response to field needs. The platinumaluminide was the original heavy duty coating and

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GT21640

Figure 18a. Photomicrograph showing soundmiscrostructure of a coated bucketwhich has been in service

GT21639

Figure 18b. Photomicrograph of a coating on bucket material showing internaloxidation of coating (dark particles)

addressed corrosion problems seen by a large seg-ment of the fleet in the 1960s. It doubled the cor-rosion life of the uncoated IN-78 buckets of thattime. The PLASMAGUARD™ GT-29™ coatingimproved that corrosion resistance by an addition-al 50%. That same high level of hot corrosionresistance is kept in the more recent PLASMA-GUARD™ GT-29 PLUS™, which also has substan-tially more oxidation resistance, as required by themore advanced machines. PLASMAGUARD™GT-29 IN-PLUS™ is a two layer coating, with thetop layer only applied to the internal surface ofthe bucket.

A comparison of these first stage bucket coat-ings is shown in Figure 19, while a more detaileddescription of each is in the following sections.

Platinum-Aluminide CoatingsAll first stage buckets have been coated since

the late seventies. Up until mid-1983, the coatingused by GE on most first stage buckets was a plat-inum-aluminum (PtAl) diffusion coating. Thiscoating was selected over the straight aluminidecoatings because it provided superior corrosionresistance both in burner test rigs and in field tri-als. The platinum-aluminum coating is applied byelectroplating a thin (0.00025 in. (0.06635mm))layer of platinum uniformly onto the bucket air-foil surface, followed by a pack diffusion step todeposit aluminum. This results in a nickel-alu-minide coating with platinum in solid solution orpresent as a PtAl2 phase near the surface. Theplatinum in the coating increases the activity ofthe aluminum in the coating, enabling a very pro-tective and adherent Al2O3 scale to form on thesurface.

A Rainbow example of comparative corrosionon PtAl coated and uncoated IN-738 buckets, run

side-by-side in the same machine under corrosiveconditions, is shown in Figure 20. The two bucketswere removed for interim evaluation after 25,000hours of service. This Aramco unit burned sournatural gas containing about 3.5% sulfur, and waslocated in a region where the soil surrounding thesite contained up to 3% sodium.

The uncoated IN-738 bucket has penetrationextending 0.010 to 0.015 inches (0.251 - 0.381mm), into the base metal over most of the bucketsurface. The coated bucket generally shows no evi-dence of base metal hot corrosion attack,although some of the bucket areas showed coat-ing thinning. Only at some very small locations onthe leading edge of the coated bucket was thecoating breached, and then to only a depth of0.001 to 0.002 inches (0.025 to 0.051 mm).

PLASMAGUARD™ CoatingsThe new, GE-developed and patented

PLASMAGUARD™ coatings are now our stan-dard first stage bucket coatings - GT-29 PLUS™for solid buckets, GT-29 IN-PLUS™ for cooled orhollow vaned buckets.

PLASMAGUARD™ coatings are examples ofoverlay coatings and differ from diffusion coatingssuch as the platinum-aluminum coatings in onemajor respect. At least one of the major con-stituents (generally nickel) in a diffusion coatingis supplied by the base metal. An overlay coatinghas all the constituents supplied by the coatingitself. The advantage of overlay coatings is thatmore varied corrosion resistant compositions canbe applied, since the composition is not limited bythe base metal composition, nor is thickness limit-ed by process considerations.

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GT24541

Figure 19. Types of coatings

GT01504A

Figure 20. First-stage turbine buckets: coatedand uncoated IN-738; 25,000 service hours

PLASMAGUARD™ coatings are applied by theVacuum Plasma Spray (VPS) process in equip-ment especially designed to apply this coating in auniform and controlled manner. In this process,powder particles of the desired composition areaccelerated through a plasma jet to velocitieshigher than those achievable through atmospher-ic plasma spray methods. The solidification of thepowder onto the airfoil results in a much strongercoating bond than can be achieved by using con-ventional atmospheric plasma spray depositionbecause of the higher particle speeds and thecleaner, hotter substrate. In addition, much high-er coating densities and soundness are achievableusing the VPS approach.

The first production VPS facility was installed inSchenectady, N.Y., during the early 1980s. Thisfacility is currently being augmented by a newer,higher capacity and more automated VPS facilityin the gas turbine manufacturing plant inGreenville, South Carolina. This facility has thecapability to coat the latter stage buckets withPLASMAGUARDTM coatings, as well as providerefurbishment capability for used buckets.

Extensive laboratory corrosion testing was per-formed on candidate PLASMAGUARD™ coatingcompositions in the late 1960s to the early 1970s.This led to the selection of GT-29™ as the originalPLASMAGUARD™ coating that satisfied the fieldneed for superior hot corrosion resistance com-pared to the original PtAl coating. This laboratorytesting was confirmed by field experience inRainbow rotors that were installed in the mid-1970s. Nearly 35,000 hours of satisfactory turbineoperation have now been accumulated on thiscoating, as shown in Figure 21.

In the mid-1980s, GE found that more oxida-tion resistance was required for the higher firingtemperature gas turbines (generally above 1950F(1065C) in air cooled machines and above 1750F(954C) in uncooled machines). This led to theintroduction of the patented coating called PLAS-MAGUARD™ GT-29 PLUS ™ that combines thedemonstrated hot corrosion protection of GT-29™ with a substantial increase in oxidation pro-tection. The enhanced oxidation protectionoffered by GT-29 PLUS™ is gained from anincreased aluminum content in the outer regionof the coating matrix. In service, the higher alu-minum content of the GT-29 PLUS™ forms amore oxidation-protective aluminum oxide layerthat greatly improves the high temperature oxida-tion resistance. Recently, PLASMAGUARD™ GT-29 IN-PLUS™ has been introduced for advanced

cooled and hollow vaned buckets. This coatingapplies a diffused, aluminum rich layer on thoseinner passages, cooling holes, and surfaces to pro-tect against oxidation which would otherwiseoccur.

Buckets and Nozzles For Heavy-OilApplication

The cooling circuitry for the nozzles and buck-ets has been designed to avoid plugging by fuelash deposits. The first and second stage bucketsuse internal convective cooling to maintain lowmetal temperature. This cooling system isdesigned to provide an exit for cooling air at thebucket tips (Figure 22), where these exits are pro-tected from ash impingement. Figure 10 alsoshows that the air exit holes in the bucket tipremain open and unplugged after long-termoperation.

The MS7001EA and MS9001E first-stage nozzlecooling circuits and cooling air exit passages havebeen modified to further minimize the occur-rence of plugging by ash deposits (Figure 23).Should the suction side film holes experienceplugging by ash deposits, the forward cavity cham-ber cooling flow would then pass through the ribbypass holes into the aft cavity chamber. The cool-ing air entering the aft cavity chamber exits fromthe trailing edge region of the nozzle vane

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GT07066B

Figure 21. VPS coating after 34,943 hours ofturbine exposure – pressure face

VPSCoating

through trailing-edge rectangular slots andthrough large pressure-side film holes which arenot subject to plugging by ash deposits.

Borescope Inspection TechniquesGE gas turbines have provision for borescope

inspections of internal conditions, thereby mini-mizing disassembly and outage time.

The borescope access is provided at strategiclocations in the turbine for inspection of the com-pressor and turbine (Figure 24). Evaluation of theresults of borescope inspections, in conjunctionwith the practice of periodically monitoring per-

formance, will determine the most economicaltime for a scheduled outage. The timing of thedisassembly outage thus becomes a judgmentbased on known machine condition, rather thanthe historical approach based upon generalizedoperating factors and usage.

TURBINE DEPOSITS

Nature of DepositsAsh-bearing fuel oils generally require the use

of suitable additives to inhibit corrosion. A discus-sion of additives is presented in the “FuelAdditives” section. Deposits of ash from thesefuels can adhere to the hot gas path parts andrestrict the flow of gas, thereby reducing the out-put and efficiency of the turbine. The rate atwhich these deposits accumulate, and the abilityto remove them, will depend upon a number offactors including fuel composition, treatmenteffectiveness, turbine design, and firing tempera-tures.

The nature of the deposits changes with tem-perature. Figure 25 shows an example of depositsformed at 1750F (954C) on a cooled turbine noz-zle partition. The deposit next to the metal iswater soluble MgSO4. The deposits on top of thislayer are insoluble MgO. These deposits, becausethey are insulated from the nozzle surface, wereformed at higher temperature than those next tothe metal. The relationship between temperatureand sulfur content, both of which determine theequilibrium between MgO and MgSO4, is alsogiven in this figure.

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GT16233B

Figure 22. MS7001 first-stage turbine buckets,radial view

GT24218B

Figure 23. MS7001EA first-stage nozzle forheavy fuels

GT5419B

Figure 24. MS7001EA simple-cycle, single-shaft,heavy-duty gas turbine borescopeinspection locations

Four distinct processes may result in ash parti-cle deposits on the nozzle airfoils:

• Vapor particles migrate through the bound-ary layer toward the cool wall. If the bound-ary layer temperature is below the dewpoint, condensation takes place at the wall(Figure 26).

• If the temperature of the boundary layer isbelow the melting point of the species, andthe particle has a long enough residencetime in the boundary layer, then the vaporparticle condenses and solidifies before itreaches the surface. If the liquid particle is ata temperature well below its sintering tem-perature by the time it gets to the surface,

the probability of sticking to the surface isreduced (Figure 27).

• Liquid and solid particle impaction occurswhen ash particles form nuclei for the con-densation of low-melting point species eitherinside or outside of the boundary layer. Thecondensate which the solid particle may pickup forms the binder which causes the parti-cle to stick to the wall Figure 28).

• A liquid droplet deviates from the streamlineand impacts the wall due to its own inertia(Figure 29).

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GT00103BFigure 25. Layered ash deposit on first-stage nozzle

GT24219A

Figure 26. Vapor diffusionGT24220A

Figure 27. Vapor diffusion/condensation/solidification

Turbine Simulator TestsIn the early 1960s, a test facility to simulate the

combustion system and turbine first-stage nozzlewas constructed at the GE Research andDevelopment Center to study deposit formingcharacteristics of various fuels. This “TurbineSimulator” has been extremely valuable for study-ing, under actual machine conditions of pressureand temperature, the nature of turbine depositsand the rate of deposit formation, as well as devel-opment of techniques for deposit removal.Heated, non-vitiated air is delivered to the testapparatus (Figures 30 and 31) at flows up to 8

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GT24221A

Figure 28. Solid particle impaction

GT24222

Figure 29. Liquid particle impaction

GT8915

Figure 30. Turbine simulator, high-pressuretest facility

lbs/sec (3.6 kg/sec) at a pressure ratio up to 6 to1. The combustor is scaled from the MS5000 gasturbine. The turbine nozzle is part of an MS3002air-cooled nozzle sector, and the transition sectionis matched to these parts.

Sixty-two tests of 100 hours each have been con-ducted in this facility at firing temperatures rang-ing from 1000F (538C) to 2100F (1150C).Residual fuel and No. 2 distillate doped with Na,V, Mg, Si, etc., to simulate various grades of heavyoils have been burned, and the deposit character-

istics have been studied. Methods of removingthese deposits during and after operation havebeen developed. In one test, deposits formed at1500F (816C) on the first-stage nozzle partitionswere hydrated, causing them to swell. On subse-quent refire, the deposits spalled off. Nutshellsinjected into the combustors at full speed underload remove much of the ash.

At firing temperatures above 1700F (927C),(depending on the sulfur content of the fuel),MgO deposits are more likely to form thenMgSO4, as indicated in Figure 25. Generally,MgSO4 can be completely and quickly removedby water or wet steam. MgO deposits, however, areinsoluble and more difficult to remove.

Since high turbine firing temperatures aredesirable for high output and high efficiency, itwas necessary to find effective methods to removedeposits formed at high temperatures. A largenumber of tests were devoted to this need. Awash/soak/refire procedure was developed forremoving ash deposits during a series of tests con-ducted in the turbine simulator.

In these tests, removal of the deposits formed at1950F (1066C) firing temperature (Figure 32) wasaccomplished by the following sequences:

1. Warm water was injected into the combus-

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GT24529Figure 31. Turbine simulator test section

GT23875

Figure 32. Nozzles before washing

tors for 30 minutes. This removed 60-70 per-cent of the deposits. Additional washing hadno noticeable effect. The appearance of thedeposit after this sequence is shown inFigure 33. About 30-40 percent of the origi-nal deposit remained.

2. The rig was refired to 1950F (1066C) for onehour. Inspection after shutdown showed thatthe nozzle was essentially 100 percent clean(Figure 34). It was surmised that water pene-trated through the porous deposit duringthe water wash and when the rig was refired,the water flashed into steam creating suffi-cient pressure to fracture the deposits.

This wash, soak, refire procedure was repeatedin several tests and has been proven in the field inremoving deposits formed at 1850F (1010C) fir-ing temperature. Refiring to full speed at no loadafter the water soak removes the deposits.

Field ExperienceTwo examples of residual fuels experience on

the MS7001 gas turbines are of interest withrespect to nozzle deposition rates and depositremoval (Table 3).

The difference in deposit rates is attributed todifferent amounts of vanadium and sodium in the

fuel and the differing hours of operation. The tur-bine in Case II was run continuously for 185hours, and showed a low deposit rate of 1.5 per-cent per 100 hours. Each combustion chamberwas washed with 25 gpm (1.6 lps) water flow for 10minutes. In both cases, turbine cleaning (wash,soak and refire), completely restored the turbineperformance. Figure 35 is a picture of the com-bustion liner from the same turbine showing noblockage of the cooling passages.

FUEL ADDITIVES

BackgroundThe successful burning of heavy fuels in gas tur-

bines depends on the use of additives to preventhot corrosion of hot gas path components. Thecause and nature of this type of corrosion is dis-cussed in the “Turbine Gas Path Materials andCorrosion” section. Briefly, it is due to vanadiumor to vanadium plus sodium trace contaminants inheavy fuels - crude oils, residual oils and blendedresidual oils - which destroy protective oxide filmson hot gas path parts. Certain selected crude oilscontain less than the 0.5 ppm threshold limit forvanadium inhibition, but most heavy fuels have

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GT23876Figure 33. Nozzles after water washing

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Before After

Figure 35. Combustion liner before and after wash, soak and refire

GT23877

Figure 34. Nozzles after water washing and refiring

over 0.5 ppm of vanadium and require an inhibit-ing additive.

Additives for hot corrosion inhibition are basedon magnesium, although some commercial addi-tives also contain other elements including silicon,chromium, and aluminum for special applica-tions. The basic requirements for an inhibitor arethat it form a high melting point, non-corrosiveash with the harmful trace metal contaminants inthe fuel, and that the hot gas path deposits fromthis ash do not cause excessive maintenance ofthe turbine.

Other additives are occasionally used in gas tur-bine fuels for fuel storability improvement orcombustion improvement (smoke reduction).These additives are not included in this discus-sion, due to their specialized and less frequentapplications.

Magnesium-Based AdditivesCommercial magnesium-based vanadium

inhibitors used in gas turbines include severalchemical types. Operating experience and labora-tory data indicate that they are equally effective inpreventing vanadium hot corrosion at the samemagnesium level in the treated fuel. They do dif-fer, however, in cost and application considera-tions, which can affect the additive selection for aspecific turbine installation.

There are three generic types of magnesium-based additives: water-soluble, oil-soluble, and oil-dispersible. Magnesium sulfate (Epsom salt) is thewater-soluble additive. It is used as a 10 to 20 per-cent water solution of magnesium sulfate whichmust be emulsified into the fuel. Since it does notform a stable emulsion in the fuel, the solutionmust be injected into the fuel just prior to use.Oil-soluble inhibitors are proprietary productswhich blend readily and uniformly in the fuel toform stable mixtures. Oil dispersible inhibitors arestable suspensions of very finely divided solid mag-nesium compounds either in an oil vehicle or awater vehicle. They are outgrowths of “fireside”additives used in boilers for corrosion and ashdeposit control. Oil-dispersible inhibitors formstable mixtures in the fuel if some mixing is pro-vided.

The properties of these three generic types ofmagnesium-based additives are outlined and com-pared in Tables 4 and 5. The final selection willdepend on economic and operating considera-tions, which in turn depend on the vanadium levelin the specific fuel, the size of the turbine installa-tion, and the operating duty cycle of the turbine.

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Table 3.RESIDUAL FUEL EXPERIENCE

Table 4.COMPARISON OF MAGNESIUM-TYPE VANADIUM INHIBITORS

Water-soluble (magnesium sulfate): Magnesium sul-fate usually has the lowest cost per unit of magne-sium, an important consideration when the vana-dium level in the fuel is high and/or the rate offuel consumption is high. On the negative side,magnesium sulfate is the most difficult to handleand to mix with the fuel. Only low sodium levelmagnesium sulfate should be used, and the waterused to dissolve it should also be low in sodium.

Oil-soluble (magnesium sulfonate): These commer-cial proprietary additives are similar to certainadditives used in automotive crankcase lubricatingoils. Due to their ease of application and han-dling, they have been widely used in recent years.The cost for use with high-vanadium fuels and/orhigh fuel usage is a negative factor for this type ofadditive.

Oil dispersible: These are concentrated stable sus-pensions of very finely divided magnesium oxideor magnesium hydroxide in distillate oil or lessfrequently water. These concentrated suspensionsdisperse readily in the liquid fuel to form uniformmixtures which may be stored for a limited time ifsome mixing is provided. These additives are themost concentrated, with the least shipping andstorage problems. This may be a significant factorwhere large quantities of additive are required.The presence of fine solids presents a risk of abra-sive wear of fuel pumps and flow dividers unlessthe particles are kept extremely small. Additives ofthis type intended for boiler use may have toohigh concentrations of trace contaminants (sodi-um, potassium and calcium) and too large sizeparticles for gas turbine application. Only addi-tives approved and verified for gas turbine appli-cation should be used.

Magnesium Additive Dosage RateTo prevent vanadium hot corrosion in the tur-

bine hot gas path, a minimum ratio of magne-sium-to-vanadium is required. Higher rates thannecessary should be avoided to avoid excessiveadditive cost, to minimize stack particulate emis-sions, and to avoid higher rates of combustion ashbuild-up in the hot gas path.

For normal applications, a minimum 3 to 1weight ratio of magnesium-to-vanadium (Mg/V),is recommended, with a maximum of 3.5 to 1. Forresidual fuels and blended residual fuels withmoderate to high vanadium levels and sodiumplus potassium levels of 1 ppm or less after wash-ing, the 3 to1 Mg/V ratio is adequate. This ratiowill have to be increased in those special cases ofhigh sodium-to-vanadium ratio in treated fuel,usually crudes with low vanadium levels (0.5-10ppm). If the sodium-to-vanadium ratio is high,these two elements may interact and cause hotcorrosion. This is especially critical when sodiumremoval to less than 1 ppm is not practical.Increasing the magnesium-to-vanadium ratioabove 3-to-1 is recommended in such cases. Themagnesium-to-vanadium ratio may have to beincreased to about 5 to 1 for sodium-to-vanadiumratios of 1/15, and to about 10 to 1 for sodium-to-vanadium ratios of 1/5. Although the magnesium-to-vanadium ratios are high, the total level of mag-nesium required is not significant since this onlyoccurs with low vanadium level fuels. A conve-nient and economical means of accommodatingthis requirement would be to maintain a mini-mum dosage rate for these low vanadium levelfuels.

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Table 5APPLICATION OF MAGNESIUM ADDITIVES

Silicon AdditivesSilicon additives have been used to modify gas

turbine combustion ash to make it drier, lessdense and more friable. Usually silicon has beenused in combination with a magnesium additive.The operating advantage sought by modifying theash is a low ash deposition rate in the hot gas pathand/or and ash which is more readily removed byavailable turbine cleaning techniques.

The effect of silicon additives on the combus-tion ash deposition rate appears to depend oncomplex inter-relationship of fuel chemistry,deposit chemistry, and turbine firing temperature.Most of the reported successful use in the past hasbeen at firing temperatures below 1550F (843C).At the state-of-the-art higher firing temperatures,the effect of silicon is complex and is still beingstudied closely for better understanding.

GE’s laboratory experience in the turbine simu-lator indicates that there is only a limited range offuel chemistries within which silicon reduced theash deposit rates in the first-stage nozzle at firingtemperatures of 1750F (954C) and 1950F(1066C). Specifically, when the Na/V ratio in thefuel is between 0.01 and 0.5, deposit rates arereduced by a factor of between 5 and 10 fold andare washable by standard water wash-refire proce-dures. At lower Na/V, ratios field experience hasshown no benefit rates. In applications involvingwaste heat boilers, excessive fouling of fin tubeshas been observed.

At higher Na/V ratios (> 0.05), and at firingtemperatures between 1750F (954C) and 1950F(1066C), deposit rates are sometimes higher usingsilicon and are sometimes not removable by wash-ing. One interesting characteristic, however, isthat the silicon does render deposits formed at1950F (1066C) partially removable by nutshellinjection during operation. Deposits formedwhen using magnesium alone at this firing tem-perature have not been found to be removable bynutshells.

Silicon is usually added with magnesium suchthat the weight ratio of silicon-to-magnesium-to-vanadium is typically 7:3:1. The silicon-magnesiumadditive costs about four times more than the oil-soluble magnesium. For typical heavy fuel applica-tions, GE has not recommended the silicon-mag-nesium additives because of their higher cost anduncertainties in ash deposit rates and removal.However, it is recognized that in special situations,there may be operational and/or economic bene-fits for use of the silicon-magnesium additives.

TURBINE ACCESSORY SYSTEMS

Heavy Oil Fuel System The fuel system is installed on the gas turbine

accessory base and performs the following func-tions: pumping to the pressure required by thefuel nozzles; metering the fuel required by the tur-bine; and metering fuel to each combustor.

Figure 36 presents a schematic of the fuel sys-tem. Fuel is received from the forwarding systemat the point marked “supply”. It flows through thelow-pressure filter, stop valve, main fuel pump,and the free wheeling flow divider. The flowdivider meters essentially equal fuel to each com-bustor. The total fuel flow is controlled by a by-pass valve around the main fuel pump which ismodulated by the gas turbine SPEEDTRONIC™control system.

Fuel PumpThe fuel pump employed on the MS7001EA

and MS9001E burning crude or residual fuels is ascrew-type positive-displacement pump. A cut-away view is presented on Figure 37. Design fea-tures which suit it for heavy fuel pumping serviceare:

• The pump has separately lubricated bear-ings, with oil supplied from the turbine lubeoil system. This eliminates corrosion of thefuel pump bearings by contaminants con-tained in the fuel being pumped.

• The pump is water cooled, to reduce metaltemperatures since residual fuel oil tempera-ture can approach 275F (135C).

• The screws are driven by herringbone gearslocated at the end of the pump. The matingsurfaces of the pumping screws are not inphysical contact. Clearances are provided, somechanical interferences are eliminated.

• The pump elements are corrosion-resistantstainless steel.

Flow DividerThe flow divider consists of multiple mechani-

cally connected pumps having identical capacitywhich meter fuel to each combustor. The gearwhich mechanically connects the individual gearpumps is illustrated in Figure 38, and one of theindividual gear pumps is shown in Figure 39. Thegear pumps are matched, positive-displacementpumps which are forced to run at equal speed.

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GT24539

Figure 37. Warren pump

GT243530

Figure 36. Fuel system for heavy fuel applications

Consequently, equal fuel flows to each combustoreven though the back-pressure from the fuel noz-zles varies.

The bearings in the pump elements are lubri-cated with the pumped fluid, and some haveexperienced corrosion. The radial tip clearancebetween the pump rotors and housings is small, asillustrated by Figure 39. The corrosion caused lossof material from the needle bearings, whichallowed the rotors to move into the casing wallscausing interference. These deficiencies have

been corrected by the application of corrosion-resistant materials and improved clearance con-trol. Equipment service life on heavy oil fuels isnow consistent with the reliability requirement forbase-load power generation.

Atomizing Air SystemAtomizing air is delivered to each fuel nozzle to

finely atomize the fuel for complete, smoke-freecombustion. The atomizing air system supplies airat a pressure higher than that in the combustor.The pressure drop across the fuel nozzle sweepsthe fuel into the air stream in a finely atomizedspray pattern. The major equipment are the com-pressor and precooler. A typical system is shown inFigure 40.

Atomizing Air CompressorThe atomizing air compressor boosts the pres-

sure of air received from the gas turbine compres-sor discharge. It is a shaft driven centrifugal com-pressor mounted on the accessory gear box. Thecompressor is available with either low- or high-pressure-ratio impellers and diffusers. The pres-sure ratio of the low-pressure system is 1.4 and isused with distillate fuels. The high-pressure systempressure ratio is 1.7 and is employed with residualsand heavy crudes.

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GT01939

Figure 38. Circular flow divider (disassembled)

GT24540

Figure 39. Flow divider gear pump

PrecoolerThe precooler reduces the temperature of the

air upstream of the atomizing air compressorinlet. The air is cooled to reduce compressorpower and to cool the fuel nozzle to preventdeposits in the nozzles.

Starting Air CompressorThe main, shaft-driven atomizing air compres-

sor flow is supplemented during turbine start-upby a motor driven air compressor. This compres-sor is a fixed-displacement lobe-type. It suppliesatomizing air at a pressure ratio of 1.3 for ignitionand smoke-free operation to approximately 60percent turbine speed.

Deposit Removal SystemsTurbine cleaning systems are included with

heavy fuel fired gas turbines to remove ashdeposits from the combustors and turbine gaspath parts. Water washing systems removedeposits from the turbine and combustors by thespray-soak-refire method. Water is sprayed intothe combustors and turbine through the atomiz-ing air manifold and nozzles while the unit isoperated on the starting motor, and allowed tosoak into the deposits. The unit is refired and thewater absorbed by the deposits forms steam withsufficient pressure to remove deposits.Compressor discharge can be monitored to deter-mine that the turbine is clean. The unit can alsobe inspected with a borescope to assure that is iscleaned.

The turbine can be partially cleaned duringoperation under load by the injection of an abra-sive compound such as nutshells into the combus-tion system. Abrasive cleaning removes sufficientdeposits to restore 10 to 50 percent of perfor-mance loss. This procedure can significantlyincrease the operating time between shutdowns

for water washing. This improves the economicsof burning heavy oils with high deposit rates.

The gas turbine air compressor should bemaintained in a clean condition for sustainedoptimum performance. Therefore, washing thecompressor is conducted when the turbine iswashed.

Turbine and Compressor Washing SystemThe turbine and compressor washing system

consists of a water-wash skid, on-base pipingincluding water-wash manifold and drains, andskid-to-turbine base interconnecting piping. A5,500 gallon (21,000 liter) tank holds sufficientwater to clean both the compressor and the tur-bine, and a 50 gallon (190 liter) detergent tank isused for compressor washing. A 250 gpm (16 lps)pump on the skid delivers water to the turbineatomizing air manifold for turbine cleaning. Theskid mounted pump is also used to deliver thewater/detergent solution and rinse water to thecompressor cleaning nozzles located in the airintake. The compressor is washed simultaneouslywith the turbine.

Turbine Abrasive CleaningThe abrasive injection system consists of skid-

mounted hopper, injection nozzle in each com-bustor, and interconnecting piping between theskid and unit. Air from the atomizing air systemcarries the nut shells from the skid mounted hop-per to the combustor. Cleaning is performed byconnecting the system to the unit, filling and clos-ing the hopper, and opening the valves in theatomizing air line.

Fuel Treatment SystemHeavy fuels are frequently contaminated with

trace metals and usually require both treatment toremove sodium and potassium and injection ofadditives to inhibit corrosion. Residuals and heavycrudes require washing to remove the sodium andpotassium salts. Some light crudes can be desaltedto satisfactory contaminant levels by dehydratingwith a centrifuge system.

Residual and Heavy Crude SystemThe heavy fuel treatment system is typically

composed of raw fuel storage tanks, fuel washunit, effluent water treatment unit, inhibitionunit, wash fuel storage tanks, heavy fuel forward-ing skid, distillate storage tanks, distillate forward-ing skid, and a fuel filter/selection skid. Thesecomponents are schematically shown in Figure 41.

The fuel may be contaminated with water, dirt

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GT24532

Figure 40. Atomizing air system schematic

and rust. Tank design should enhance settling.Floating suctions help to avoid the pumping offuel from the tank bottoms which may containconcentrated contaminants. To reduce contami-nant entrainment, the operator should fill tanksand allow time for contaminants to settle beforeusing the stored fuel. Water should be periodicallydrained to prevent buildup of microorganisms atthe fuel/water interface.

Fuel treatment is accomplished in three stages:• Washing the fuel to remove the water-soluble

trace metals such as sodium, potassium, andcertain calcium compounds. Washing alsoremoves much of the particulate materialprior to forwarding to the filtering systems.

• Inhibiting the vanadium in the fuel with suit-able additives.

• Filtration to remove particle contaminants.

Fuel WashingThe primary function of the fuel washing

equipment is to remove the water-soluble tracemetals and a significant amount of the solid mate-rial contained in the fuel. Fuel washing is accom-plished by mixing 2 to 10 percent of potable waterto absorb the salts, followed by a one- or two-stagewater extraction system. A typical system is illus-trated in Figure 42. Each stage includes a mixerprior to the centrifuge or electrostatic precipita-tor. This equipment extracts the salt water fromthe fuel. The number of water extraction stagesdepends on the sodium concentration in the fueland certain fuel properties such as specific gravityand viscosity. Washing systems with one or twostages can consistently reduce sodium and potassi-um contamination to 1 ppm or less if properlymatched for the fuel properties.

• Centrifuge Desalting SystemA centrifuge desalting system is normallycomposed of a centrifuge, water skid, anddemulsification skid. The centrifuge systemis illustrated in Figure 43. Performance ofcentrifuge systems is excellent. A typical two-stage system can reduce sodium from 150ppm to less than 1 ppm for heavy salts.Centrifuges also have excellent capability forremoving solids.

• Electrostatic Desalting SystemThe electrostatic process is similar to cen-trifuging. The primary feature of the electro-static system is that the water is coalesced tolarge droplets to enhance settling. For exam-ple, a 100 to 1 diameter increase in waterdroplet diameter in turn increases the set-tling rate by 10,000 to 1 according to StokesLaw. Electrostatic systems require longerstart-ups and more filtration than centrifugalsystems. They are also less adaptable to fuelsof varying quality.

Light Crude Oil Dehydration/ClarificationSystem

The relatively low viscosity and specific gravityof some light crude oils enables removal of smallamounts of water by direct centrifuging. In thecase of light crude oils, it is possible to reduce thesodium plus potassium to less than 3 ppm by sim-ple centrifuge dehydration. This method also pro-vides the desirable benefit of dirt removal,referred to as clarification. This process is attrac-tive for the Middle East crude oil burning applica-tions where the availability of water is low. A smallamount of water, less than 0.1 percent of the oilflow, is used for sealing.

InhibitionHeavy oils usually contain organic vanadium

compounds which cannot be mechanically sepa-rated from the fuel. Additives are injected to

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GT10235B

Figure 41. Heavy-fuel treatment system–withbatch-type inhibition

GT24534

Figure 42. Elements of a two-stage fuel washsystem

inhibit corrosion induced by this contaminant.Inhibitors may also be used to counteract sodiumand to modify ash deposits. Two systems areapplied for inhibition injection. These are the on-line system and batch processing systems.

The on-line system is illustrated by Figure 44.This system injects the additive in the fuel as it isdelivered to the gas turbine. Most heavy fuel firedinstallations use this system. It allows the use ofeither oil soluble or less costly water soluble addi-tives.

The batch-type system, sometimes called thetotal certification system, inhibits fuel as it is deliv-ered to the treated fuel storage tanks. This system

requires the use of oil soluble additives thatremain in solution during storage and subsequenthandling. The advantage of this system is the abili-ty to check the fuel for proper treatment prior todelivery to the gas turbine. Figure 41 incorporatesa batch-type system for inhibition.

Fuel Forwarding, Heating andFiltration

The fuel forwarding, heating and filtration sys-tem delivers fuel from the storage tank to the gasturbine at the required pressure, temperature,and cleanliness.

Residual and Heavy Crude SystemThe systems for heavy fuels accommodate the

high viscosity and wax content of these fuels. Theunits start and stop on distillate, and a forwardingsystem is included for the residual and distillatefuels. A fuel management system includes replace-able-cartridge-type filters and fuel selection valves.This system is illustrated on the residual fuel sys-tem schematics, Figure 41.

The residuals and heavy crude oils requireheating to approximately 200-275F (93-135C) tomaintain the viscosity in a range for proper atom-ization and to maintain the wax in solution.Heating is usually performed by steam.

Light Crude Oil SystemGas turbines can start and stop on light crude

oils, simplifying the forwarding system. When this

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GT02040Figure 43. Typical centrifuge installation

GT24535

Figure 44. On-line inhibition schematic

fuel is used, heating is usually not required forpumping, but is required to maintain wax in solu-tion.

OPERATION ANDMAINTENANCE

REQUIREMENTS

Startup and ShutdownIn order to ensure that the entire turbine liquid

fuel system will remain free from any waxy fuelbuildups or plugging, startup and shutdown ofthe gas turbine must occur while burning distillate#2 fuel oil. On startup, the lower viscosity distillateensures proper light off fuel atomization, andheats up the onbase piping to normal operatingtemperatures. Fuel transfer to the ash bearing fuelcan occur after unit has been synchronized to thegrid. The fuel transfer typically requires a gradual5 minute transfer time. This transfer time allowsfor the onbase piping and hardware to slowly heatup to the supply temperature of the ash bearingfuel, (which in some instances can approach 275F(135C)), thus ensuring that no frozen blocks ofash bearing fuel form.

On shutdown signal, the unit will automaticallyunload itself and then transfer to distillate #2 fueloil. The shutdown must occur on distillate topurge the onbase hardware and make sure thatthere is no solidification of the ash bearing fuelthroughout the fuel system.

Normal Running OperationDuring normal operation it will be it will be

necessary to periodically remove the ash depositswhich form on the first stage nozzle. The rate ofdeposit buildup on the first stage turbine nozzle isprimarily dependent upon the firing temperatureof the gas turbine and the amount of vanadiumcontained in the fuel, (Figure 45). This plot illus-trates the effect of firing temperature and vanadi-um content on the deposition rate. This plot illus-trates that the higher the level of vanadium in thefuel, the more pronounced the effect that increas-ing the firing temperature will have on the rate ofdeposition. The faster the rate of deposition, theshorter the interval between deposit removal shut-downs. Because of this relationship, the selectionof turbine firing temperature should be tailoredfor each specific site and customer. The benefitsof increased output and efficiency must be com-

pared with the costs incurred for deposit removalshutdowns.

The allowable amount of deposit on the first stagenozzle is dependent upon the ambient temperatureof the site. The lower the ambient temperature, thehigher the mass flow will be through the turbine. Forthis reason, the amount of first stage nozzle pluggingat low ambients will range from 5 - 7 %. At tempera-tures above 59 F, (15 C), the allowable plugging ofthe first stage nozzle will be 10 %. Referring back toFigure 45, one can estimate what the turbine waterwash interval will be for various levels of vanadiumcontent versus unit firing temperature.

One method used for extending the periodbetween turbine washing is to incorporate a tur-bine abrasive cleaning system. This type of clean-ing can be done online, and restores 10 to 50% ofthe lost performance through injecting nutshellsat the first stage turbine nozzles which removessome of the ash deposits. The effectiveness of theabrasive cleaning cycle on the turbine is dramati-cally affected by the nature of the deposits. Theharder the deposit, the less effective the abrasivecleaning. Since the hardness of the deposit is adirect result of the firing temperature of the gasturbine, a relationship between the two exists suchthat whenever the rated firing temperature of theunit exceeds 1900F, the effectiveness of abrasivecleaning becomes negligible. But, at lower firingtemperatures, a softer deposit forms and abrasivecleaning becomes more effective.

Even when utilizing abrasive cleaning, eventual-ly an offline turbine water wash will be required inorder to remove the accumulated deposit. Theturbine water washing system for ash bearing fuelswill consist of a turbine water wash skid, onbaseturbine wash piping, and controls. The procedurefor offline turbine water wash, as contained in GEinstruction books, is detailed in Table 6.

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GT24237A

Figure 45. The effect of firing temperature and vanadium content on deposition rate

Based on this procedure, a typical water washinterval for shutdown to start up should beapproximately 10 - 12 hours, recognizing that theoverall cycle should be adjusted based on theexperience of cleaning effectiveness.

To assist the customer in selecting the optimumoperating rating for the gas turbine, a plot illus-trating the recoverable performance degradationversus time will be developed for each uniqueapplication, (Figure 46). This plot illustrates theoperating hours for a unit which has nutshellingcapability versus a unit which does not. Theamount of running hours gained is depicted in“X” hours. In order to better quantify the poten-tial performance degradation due to fouling ofthe hot gas path, GE estimates an output loss of

approximately 3 % for every 1 % of blockage ofthe first stage nozzle.

A typical combined cycle performance varia-tion is illustrated in Figure 47. This particularexample illustrates the “saw tooth” performanceloss that is associated with ash-bearing fuels andwater wash/nutshell intervals.

Inspection IntervalsInspection intervals for optimum turbine ser-

vice are not fixed for every installation, but ratherdeveloped through an interactive process by eachuser, based on past experience and trends indicat-ed by key turbine factors. The condition of thehot gas path parts provides a good basis for cus-tomizing a program of inspections and mainte-nance. Expected maintenance interval ranges forash-bearing fuels are identified in Table 7.

The intervals are, in part, based on hydrogencontent of the fuels, because heavier hydrocarbonfuels frequently contain corrosive elements andgenerally release a higher amount of radiant ther-mal energy. This results in higher combustion sys-tem hardware temperatures, which reducesinspection intervals (Figure 48).

GE utilizes a fired hours and/or a fired startsphilosophy for determining inspection intervals.This criteria recommends an inspection whenever

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Table 6PROCEDURE FOR OFFLINE

TURBINE WASH

Gas turbine will be shut down and put oncrank speed, (540 rpm), to allow wheel-space temperatures to cool to 300 F.

With turbine at crank speed, a detergent/water solution for compressor water washwill be injected into the compressor.

Unit will be shut down and allowed timeto soak.

With turbine at crank speed, compressorwill be rinsed. At this time copious amounts of water will be injected in thehot gas path via the atomizing air piping,(all combustors at the same time).

9hours

5min.

20min.

20min.

Procedure Time

GT24236A

Figure 46. Recoverable performance degrada-tion vs. time

GT07410B

Figure 47. Typical combined cycle performancevariation with time – residual oilfuel

Table 7EXPECTED MAINTENANCE

INTERVAL RANGES

Inspection Hours Starts

Combustion 3,000 400

Hot Gas Path 6,000 - 12,000 1,200

Major 18,000 - 24,000 2,400

the fired hours or starts limit is reached. The lim-its are based on two different criteria. The firedhour limits are based on corrosion, oxidation, andcreep, while the start limits are based on low cyclefatigue of components resulting from thermalcycling of the unit.

Inspection ScopeThe shutdown maintenance inspections

include the “combustion”, “hot gas path”, and“major” inspections. These inspections requiredisassembly of the turbine in varying degrees.Figure 49 illustrates the turbine sections involvedduring each of these inspections.

Combustion InspectionThe combustion inspection is a relatively short

disassembly inspection which concentrates on thecombustion liners, transition pieces, and fuel noz-zles, components recognized as being the first torequire repair and/or replacement in a goodmaintenance program.

Hot Gas Path InspectionThe purpose of the hot gas path inspection is

to examine those parts exposed to high tempera-ture from the hot gases discharged from the com-bustion process. The hot gas path inspectionincludes the full scope of the combustion inspec-tion, and, in addition, a detailed inspection of theclearances of the turbine nozzles, stationary statorshrouds, and turbine buckets. The hot gas pathinspection interval is based on initial recommen-dation and experience. In addition, the visualborescope evaluation made at the time of thecombustion inspection may influence the intervaltime.

Major InspectionThe purpose of the major inspection is to

examine all of the internal rotating and stationarycomponents from the inlet of the machinethrough the exhaust section of the machine. Thisinspection includes the elements of the combus-tion and hot gas path inspections, in addition tolaying open the complete flange-to-flange turbineto the horizontal joints (Figure 49). Propermachine centerline support using mechanicaljacks and jacking sequence are necessary to assureproper alignment of rotor to stator, obtain accu-rate half shell clearances, and prevent twisting ofthe casings while on the half shell.

Inspection DurationIt is difficult to estimate the number of man-

hours required for each type of shutdown inspec-tion, primarily because of the wide range of expe-rience, productivity, and working conditions thatexist around the world. Based upon the mainte-nance inspection man-hour assumptions in Figure50 however, an estimate can be made, as shown inTable 8.

The shutdown inspection man-hours will varydepending upon preplanning, availability of parts,

33

GER-3764A

GT16662AFigure 48. Fuel hydrogen content and

combustion hardware temperatures

GT07094B

Figure 49. Major inspection work scopeGT10238C

Figure 50. Maintenance inspection assumptions

site location, productivity, tooling, weather condi-tions, union regulations, and supervision. LocalGE field service personnel are available to helpplan the maintenance work that will ultimatelyreduce downtime and labor costs.

SUMMARYGE is the world’s leading manufacturer of gas

turbines utilizing ash-bearing fuels. This paper haspresented an overview of unparalleled turbineexperience in utility, industrial, and transporta-tion applications. The evolution of gas turbinedesign, including incorporation of new alloys andcoatings, thorough product testing, and monitor-ing of field experience, has produced durable andreliable machines capable of operating on a widevariety of fuels and at ever-increasing firing tem-peratures. Internal cooling for hot gas path com-ponents has been designed to minimize theeffects of ash-bearing fuel deposits. Applicationsand site specific fuel treatment systems and tur-bine cleaning regimens allow the gas turbine usermaximum fuel flexibility and minimum perfor-mance interruption.

REFERENCES1. A.M. Beltran, A.D. Foster, J.J. Pepe, P.W.

Shilke, “Advanced Gas Turbine Materials andCoatings,” 36th General Electric TurbineState-Of-The-Art Technology Seminar, August,1992.

2. “Heavy-Duty Gas Turbine Operating &Maintenance Considerations.” EJ. Walsh, MAFreeman, GER 3620A, 1991.

3. “Progress in Heavy Fuels.” MJ. Hefner, FD.Lordi, GER 3110A, 1979.

4. “Fuels Flexibility in Heavy-Duty Gas Turbines.”AD. Foster, ME. Von Doering, MB. Hilt, GER3428A, 1984.

5. “Gas Turbine Support Systems.” EH. Gault,GER 3452, 1984.

6. “Liquid Fuel Treatment Systems.” RT. Henke,SS. Dreymann, JW. Hickey, 1981.

7. “Heavy Fuel Treatment Systems.” AA. Pyrong,A. Renko, SS. Dreymann, JW. Hickey, GER2484A, 1974.

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Table 8TYPICAL ACHIEVED CREW SIZE AND SKILLS COMBUSTION,

HOT-GAS-PATH AND MAJOR INSPECTION

© 1996 GE Company

LIST OF FIGURES

Figure 1. Firing temperature operating experienceFigure 2. Bucket metal temperatureFigure 3. MS7001 gas turbine construction features of second- and third-stage precision cast bucketsFigure 4. Multiple reverse-flow combustorFigure 5. Air atomizing fuel nozzleFigure 6. Slot-cooled liner, cutaway viewFigure 7. Liner cooling profilesFigure 8. MS7001EA transition pieceFigure 9. MS9001E transition pieceFigure 10. Deposits of sea salt on MS7001 first-stage nozzle partitions and buckets. Note condensates in

locally cooled surfaces.Figure 11. Life vs. alkali concentration for heavy duty gas turbine (schematic)Figure 12. Small burner oxidation test result, FSX414Figure 13. Comparision of U700 and U500/IN738 corrosion resistanceFigure 14. Firing temperature trend and bucket material capabilityFigure 15. Effect of sodium on bucket corrosion lifeFigure 16. Hot corrosion (high-temperature type)Figure 17. Hot corrosion (low-temperature type)Figure 18a. Photomicrograph showing sound miscrostructure of a coated bucket which has been in

serviceFigure 18b. Photomicrograph of a coating on bucket material showing internal oxidation of coating

(dark particles)Figure 19. Types of coatingsFigure 20. First-stage turbine buckets: coated and uncoated IN-738; 25,000 service hoursFigure 21. VPS coating after 34,943 hours of turbine exposure – pressure faceFigure 22. MS7001 first-stage turbine buckets, radial viewFigure 23. MS7001EA first-stage nozzle for heavy fuelsFigure 24. MS7001EA simple-cycle, single-shaft, heavy-duty gas turbine borescope inspection locationsFigure 25. Layered ash deposit on first-stage nozzleFigure 26. Vapor diffusionFigure 27. Vapor diffusion/condensation/solidificationFigure 28. Solid particle impactionFigure 29. Liquid particle impactionFigure 30. Turbine simulator, high-pressure test facilityFigure 31. Turbine simulator test sectionFigure 32. Nozzles before washingFigure 33. Nozzles after water washingFigure 34. Nozzles after water washing and refiringFigure 35. Combustion liner before and after wash, soak and refireFigure 36. Fuel system for heavy fuel applicationsFigure 37. Warren pumpFigure 38. Circular flow divider (disassembled)Figure 39. Flow divider gear pumpFigure 40. Atomizing air system schematicFigure 41. Heavy-fuel treatment system–with batch-type inhibitionFigure 42. Elements of a two-stage fuel wash systemFigure 43. Typical centrifuge installationFigure 44. On-line inhibition schematicFigure 45. The effect of firing temperature and vanadium content on deposition rateFigure 46. Recoverable performance degradation vs. timeFigure 47. Typical combined cycle performance variation with time – residual oil fuelFigure 48. Fuel hydrogen content and combustion hardware temperaturesFigure 49. Major inspection work scopeFigure 50. Maintenance inspection assumptions

GER-3764A

LIST OF TABLES

Table 1 GE-designed gas turbine worldwide experience (as of February 1994) with heavy ash-bearing fuels

Table 2 Combustion design objectivesTable 3 Residual fuel experienceTable 4 Comparison of magnesium-type vanadium inhibitorsTable 5 Application of magnesium additivesTable 6 Procedures for offline turbine washTable 7 Expected maintenance interval rangesTable 8 Typical achieved crew size and skills combustion, hot-gas-path and major inspection

GER-3764A

For further information, contact your GE Field SalesRepresentative or write to GE Power Systems Marketing

GE Power Systems

General Electric CompanyBuilding 2, Room 115BOne River RoadSchenectady, NY 12345

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