IEEE TRANSACTIONS ON POWER APPARA'I'US AND SYSTEMS VOL. PAS-84, NO. 12 DECEMBER 1965

The World's First Large Combined Cycle (SteamTurbine-Gas Turbine) Generating Unit: How

Is It Doing?T. H. GEORGE

Abstract-A year's operation of the first large combined cycle flange; 880°F normal exhaust temperature; 940°F peak-unit, using a modem reheat steam turbine with a two-shaft gas tur- ing exhaust temperature; designed for natural gas or dieselbine, shows that expected economy and capability have been realized. oil or combination.Reliability is expected to improve as a result of modifications. 4) Gas turbine generator, GE: 32 000 kVA at 30 psig

H2 pressure; 0.85 PF.INTRODUCTION 5) Steam generator (boiler), B&W: 1 339 000 lb/hr;

I557JITHIN THE LAST few years, a significant number 2200 psi design; 1005°/1005°F; natural circulation; 20IV of papers have been published on the subject of the Laredo spud burners; normal fuel: natural gas; standby

combined cycle uinit that went into operation at the fuel: heavy oil.Horseshoe Lake Station of the Oklahoma Gas and Electric Particular mention is made of the Laredo spud burners asCompany in the spring of 1963. As might be expected, the their stability over the wide range of burner pressures andfirst papers [1 ]- [4] dealt primarily with the design charac- excess air inherent in a combined cycle contributes muchteristics of the unit and the economic advantages this to the operator's peace of mind.cycle was expected to produce. They also emnpahsized the One distinguishing characteristic of the steam genera-rather uniique arrangement between the manufacturer, the tor is the huge primary economizer (145 158 ft2) whichconsultanit, anid the purchaser for the design and construc- effectively replaces the conventional air preheater.tion of the unit. Operation of the unit has been covered in With a back pressure on the steam unit of 2.0 inches Hg,other papers [5], [6]. this combination of equipment was guaranteed by GeneralEvents during the last three years have corroborated the Electric to produce 200 783 net kW at a heat rate of 9530

prediction that the uInit could be designed and built, and Btu/kWh.could be operated. Now the questions the industry is ask- This, incidentally, is referred to as the "most economicaling are point"; that is, all the air for combustion is being supplied

1) Is it dependable? by the gas turbine exhaust.2) Does it come up to expectations on capacity and heat Early in the planning of this unit, it was decided that

rate? start up would be by separate components. Also, because3) What special problems has it posed? of the gas turbine being the first of the manufacturer's large

two-shaft design, it was evident that it would be the lastSome have even asked the question, "Would you do it component ready for field operation. This necessitated theagain?" The answers to these questions will constitute this addition of two forced draft fans capable of handling the

boiler and steam unit up to full load. Parenthetically, itDESIGN should be stated that the initial plans had called for a small

forced draft fan merely for supplementing the gas turbinePerhaips the major components of ths cycle should be exhaust flow at peak loads.

With the gas turbine on peaking temperature and its]) Steam turbinie, GE: 193 600 kW at 3.5 iniches Hg exhaust supplemented by a forced draft fan; and with the

abs; TC2F-26 iinches 3600 r/min; 1800 psig 1000°/ steam turbine operating at 5 percent overpressure, its top1000°F. heater cut out, and with a back pressure of 3.5 Hg abs,

2) Steam turbine generator, GE: 258 500 kVA at 45 the unrit was expected to produce 237 874 kW net, with anpsig H2 pressure; 0.85 PF with liqu1id cooled stator. expected heat rate of 9798 Btu/kWh net.

3) Gas turbine, GE: 25 000 kW, 2 shaft, frame 8;800F inlet, 14.17 psia compressor inlet anld turbine exhaust OPERATING EXPERIENCE

Paper 64-362, recommended and approved by the Power Genera- Now for the answers to somle questions.tiOnI Committee of the IEEE Power Group for presentation at the Table I shows the operating hours on the various com-IEEE-ASME National Power Conference, Tulsa, Okla., September27-October 1, 1964. Manuscript submitted July 15, 1964; made ponlents. This indicates that the comnbined cycle doesavailable for printinlg January 15, 1965.wokTalIIsostersnsfrocdougsfrthThe author is with Oklahoma Gas and Electric Company, ok al Isosteraosfrfre uae o h

Oklahoma City, Okla. same period.1182

1965 GEORGE: STEAM TURBINE-GAS TURBINE UNIT PROGRESS 1183

TABLE I HRS. SERVICE HRS. SERVICEHOURS SERVICE ON UNIT 7, HORSESHOE LAKE, JUNE 12, 1963* TO COMB CYCLE STEAM TURBJUNE 12, 1964

Hours in period 8784 62O O0Hours service on steam unit 6970Hours service on gas unit 4789Hours service in combined cycle 4339Forced outages from combined cycle attributable I

to gas turbine 6Forced outages fromn combinied cycle attributable

to other than gas turbine 0

* Date of commercial operation.

TABLE II 0FORCED OUTAGES FROM COMBINED CYCLE CAUSED BY GAS TURBINE,

JUNE 12, 1963 TO JUNE 12, 1964

6/25/63 Consultant control oil spline stripped ( i)t10/2/63 Oil leak in overspeed trip line )10/12/63 Oil leak in overspeed trip line 8i12/20/63 Gasket under access door on outer shell ofgas-turbine compressor blew out

1/15/64 High gas turbine exhaust trip1/16/64 Fuel controller shut off variable control oil

Figure 1 shows some of the same data in graphic formkeyed to the following legend: ©

* hours operatedo reason for outage

1) Joint leak in hot duct2) Consultant control oil (CCO) pump spline failure3) Holeburnedinneopreneexpansionsleeve4) Conlverting to combined cycle5) Inspect and adjust dampers6) Gas turbine operated independently; did not elect

to risk a trip out on whole unit7) Converting to combined cycle8) Units off to go to steam turbine only operation9) Converting to combined cycle

10) Oil leak in gas turbine overspeed trip line11) MIodification of gas turbine fuel oil nozzles12) Converting to combined cycle13) Oil leak in gas turbine overspeed trip line14) Converting to combined cycle15) Gas turbine anniual overhaul; add auxiliary stack

and damper 6-12-6416) Correct boiler reheat Fig. 1. Hours service by days of Horseshoe Lake 7, June 12, 1963 to17) Gasket trouble on gas-turbinie compressor June 12, 1964.18) Gas-turbine high-exhaust trip; installed additional

vapor extractor combined cycle unit was no exceptionl. In the fall of 1963,19) Steam turbine overhaul the gas turbine was completely overhauled, with the20) Repair damage to steam turbine steam turbine getting similar treatment in the spring of21) Gas turbine off for test; restart trouble 1964. These operations proved the desirability of providing22) :Replace nozzle shear pin; work on start up controls full capacity forced draft fans as the steam turbine was23) Work on temperature controls. available for rated capacity all during the time the gas

turbine was out, and vice versa. By far the more importantIt is company policy to make a complete inspection of was having the steam turbine, as even without the gas

each new Unlit within the first year of its operation. This turbine it is prime generating capability on our system.

1184 IEEE TRANSACTIONS ON POWER APPARATUS AND SYSTEMS DECEMBER

TABLE III TABLE IVCOMPARATIVE HEAT RATES AT MOST ECONOMICAL POINT COMPARATIVE HEAT RATES AT MAXIMUM LOAD*

Guaranteed Performance Expected PerformanceGross steam-turbine output 185576 kW Gross steam-turbine output 221078 kWGross gas-turbine output 23351 kW Gross gas-turbine output 26456 kW

Total terminal output 208927 kW Total terminal output 247 534 kWStation power 8144 kW Station power 9660 kW

Net station output 200783 kW Net station output 237874 kWNet heat rate 9530 Btu/kWh Net heat rate 9798 Btu/kWh

Performance by Test Performance by TesttGross steam-turbine output 187 069 kW Gross steam-turbine output 235310 kWGross gas-turbine output 24721 kW Gross gas-turbine output 24992 kW

Total terminal output 211790 kW Total termiinal output 260302 kWStation power 6439 kW Station power 7744 kW

Net station output 205 351 kW Net station output 252558 kWtNet heat rate 9434 Btu/kWh Net heat rate 9668 Btu/kWh

* Five percent overpressure, top heater out and gas turbine onpeaking temperature.

Otherboniuses from having the flexibility of being able t This test was made after second-stage damage was repaired.Other borluses from havlng the flexlblllty OI nelng able The slight drop in net capability from that established in summerto overhaul the components separately are the reduced of 1963 (254 000 kW) is attributed to restriction in the second stagecongestion in the laydown space and the reduced crew that could not be corrected by the method of repair used.

necessary to complete the work.Incidentally, the 13 days outage in April on the steam know how to what they would have been if contract condi-

unit was the result of a grub screw working out of the tions had prevailed during the test. At this writing, a com-nozzle block bolt shielding and getting into the inlet of the prehensive set of correction curves, tables, etc., is unavail-second-stage diaphragm nozzles. In trying to get out the able. This appears to be an area which needs more work.downstream side of the nozzles, it very effectively closedup the second-stage buckets, as well as the stationary SPECIAL PROBLEMSnozzles, which necessitated the reopening of the high- As would be expected with the initial operation of suchpressure turbine for repairs. a pioneering unit, the past year has not been without itsKeeping in mind the fact that the guarantee point was problems. Some of the more important troubles, and their

200 783 net kW with a heat rate of 9530 Btu/kWh net, corrections, are listed in the following.Table III, which gives the results of the acceptance test runin April and May, should now be examined. This shows that Burning Oil in Gas Turbineat the most economical point (no supplemental forced While the only oil burned in the gas turbine has been fordraft fans) the net load was 205 351 kW at a heat rate of test purposes, difficulties in burning oil became readily ap-9434 Btu/kWh net, or, roughly, a 2-percent inlcrease in load parent. A great deal of the trouble proved to be in theand a 1-percent decrease in heat rate. Although it is granted filtering process. All oil lines were acid cleaned and anthat these are modest improvements, they are both in the additional 10-micron filter was installed. The Bendix oilright direction; and the run chosen was one of the more con- burners then became clogged with carbon caused by oilservative ones. Many of our tests under less rigorous condi- leakage under the caps. This leakage was corrected by in-tions have shown a considerably greater improvement in ternal seal welding on the Bendix nozzles.heat rate at this point, up to 2 percent.The performance under wide open conditions will now be Oil Fire

described. The expected capability was 237 874 net kW at A hole was burned in the neoprene expansion sleeve onan expected, not guaranteed, heat rate of 9798 Btu/kWh the 10-inch return oil line under bearing 4. This was cor-net. Table IV shows the net capability to be 252 558 kW rected by installing a metal expansion joint in place of theat 3.5 inches Hg back pressure with a heat rate of 9668 neopreine sleeve.Btu/kWh net. This is an increase of better than 6 percentin capability and an improvement of about 1.5 perce'lt Crack in Oil Linein heat rate. Actually, prior to the second-stage damage, the The small oil line to the overspeed trip at bearing 4 twiceunit had demonstrated asummer capability of 254 000 kW developed cracks, with leaks, resulting from resonance.net and a winter capability of 263 000 kW net. Because of The oil trip line was redesigned and installed inside a largerthe somewhat less than perfect job of straightening out and guard line with stainless-steel flexible sections inl both innerpolishing up the second-stage damage, limits to a few mega- and outer pipes.watts less than these ratings are currently imposed.

Perhaps a word of explanation is due here on these Excessive Temperature in Vicinity of Bearing 4tables. The kSilowatt figures shown are the actual metered This condition has been partially alleviated by morefigures. The heat rates given are corrected as nearly as we insulation and increased air circulation.

1965 GEORGE: STEAM TURBINE-GAS TURBINE UNI'T PROGRESS 1185

Insufficient Vapor Extractor Capacity on Gas-Turbine Oil One of the more important onles was the addition of anCompartmnent auxiliary stack and butterfly damper on the gas-turbinie

This condition prevented the holdinlg of the niecessary exhaust. The original stack only can he put into service byvacuum to prevent oil-laden vapors to escape and first shutting the gas turbine down and unbolting and removinigbecame evident when ambient temperature dropped below some bulk heads; this originally meant shutting down the

40'F. The addition of a second vapor extractor has taken steam unit also. The auxiliary stack and damper allowcare of this problem. Studies are continuing, however, to starting up the gas turbine any time. A modification ofdetermine if there is something basically wrong which damper controls allows combiiing and separating the

causes this excessive air. units at will.Along this same line, it should be pointed out that the

Gas-Turbine Exhaust Pressure Trip Set Too Low combustion control system originally was such that loss

As a result of a momentary fluctuation of the exhaust of the gas turbine automatically tripped the boiler. Not

pressure, the unit tripped off while carryinig 263 000 kW. wishing to jeopardize 250 M\IW of capability by the lossSince this is the largest unit, it now has the dubious honlor of only 25 MW, a scheme was devised whereby now if theof having dropped the largest single block of load in our gas turbine is lost, the steam turbine holds on to 100 MWhistory. The tripping pressure was raised to 40 iliches of of load. This scheme is only called on to functioni wheen awater from the previous setting of 35 inches. forced draft fan is in operation.

As a practical measure, instrumentation has been addedDifficulty of Making Hot Starts on the Gas Turbine to limit the automatic drop in gas-turbine load (fronm the

Prior to modifying the controls so that the componienits steam-flow signal) to a point where the unit stays oni ex-could be combined and separated at will, the stanidard haust temperature control. This means approximately 82-practice on loss of the gas turbine was to briiig the steam percent speed on the high-pressure turbine and approxi-unit back on with the forced draft fans and thein put the mately 15-M1W load on the low-pressure turbine. Other-gas turbine back on, only after investigation had revealed wise, large load surges on the steanm turbine would tend to

what caused it to trip. As a consequence, there had been drop the gas-turbine speed to a point where the gas-turbinefew, if any, hot restarts. When testing of the niew controls generator would trip or, worse, to where the boiler fuelmade it necessary to make hot restarts, it became evidet might trip because of low-windbox pressure.that the exhaust temperature control was trying to do the Early in the operation of the unit it became questionableimpossible of trying to hold the unit at say 300°F when as to whether the steam generator would maintain reheatit was already 400°F. This caused the fuel valve to close over the specified range. After several months of seasoning,and the unit to flame out. The manufacturer has chalged the reheat temperature was still low at the lower loads sohis program and this is now believed to be corrected. advantage was taken of the overhaul outage on the gas

It should be emphasized that the difficulties listed pre- turbine to rectify this condition. The measure taken wasviously occurred subsequent to the date designated as to remove 32 tubes from the front section of the divisionthat of "Commercial Operation." Prior to this time, wall. Subsequeint tests have proved this to be effective.there were a number of interesting events, some of which Another major modification to the original design of thefollow: boiler controls has been the point of measurement of the

air flow to the boiler. With the original layout of pneu-1) The 800-hp starting motor on the gas turbine failed. matically adding the gas-turbine exhaust flow to the forced-

It was replaced with a 1200-hp motor. draft fan flow (using air foils in the ducts as prinmary2) The gas-turbine exhaust duct expansion joint shroud elements), a major combustion upset occurred every time a

collapsed. This shroud or heat shield was installed back- forced draft fan was called on to start. The principal causewards so that the flow of the hot gases tended to turn it of this upset seemed to be that the cold air meters werewrong side out. pegged at zero prior to the starting of the fan and, as loiig

3) As might be expected with a newly designed damper, as the gas turbine was on, the cold air meters operated ina number of breakages on the sealing strips on the dampers their lower range. Therefore, when a fan was called onl toin the exhaust duct system were experienced. start, before the air flow meters could get off zero and start

4) Tears occurred in the windboxes on the boiler be- responding properly, an excess of cold air had alreadycause of tremendous expansion forces in the hot ducts. been added. This caused the furnace to overfire just toThese were repaired by welding. compensate for the cold air. By moving the air flow con-

5) On the actual date of "tCommercial Operationl," the nections from across a section of the air ducts to across theunit was downl to correct an installationl error onl the hot secondary economizer, this operation has been materiallyduct. The flanged joint adjacent to the recirculating improved.damper opened up as a result of improper welding pro- Two features, neither of which has been called Onl tocedure. operate, but both of which were installed to protect unit

capability, are 1) the loss of boiler feed pump runback1\IODIFIcATIONS and 2) the loss of stator oil runback.

A few major changes have been effected as a direct With two 50-percent boiler feed pumps, loss of one at acause of operating experience, high-load rating would probably cause loss of the boiler

1186 IEEE TRANSACTIONS ON POWER APPARATUS AND SYSTEMS DECEMBER

caused by low-drum level. This scheme involves dropping year overhauls and is not, in itself, a reflection on the avail-load automatically down to a one-pump load, or until the ability of the gas turbine. It is confidently expected thatproper feedwater-steam flow relationship is restored. This an availability factor on the combined cycle comparable todrop is initiated by the feedwater flow being a certain per- that of any of our other prime units will result. There havecentage below steam flow. been some problems, but these, on the whole, have beenAs to the loss of stator oil feature, the steam-turbine worked out.

generator will trip within a specified time after loss of stator As to the final question, "Would we do it again?", it isoil unless its stator amperes are down to about 35 percent believed to be only fair to give this unit a chance to proverating. The actual load, of course, will depend on the power itself over a reasonable period of time before coming to afactor at the t,me. On loss of stator oil, the load is automati- definite conclusion. Right now it can be said that incally dropped to where the stator amperes are satisfied. planning the installation of the next generating unit, if theThose familiar with the design of this unit may remem- engineering and economic aspects of the combined cycle

ber that temperinig dampers were originally installed to then available prove attractive, consideration to such abypass some gas-turbine exhaust to the upper part of the unit will certainly be given.furnace. These dampers were to perform the dual function ofprovidiiig an extra outlet for the exhaust gases in the event REFERENCESof high-duct pressures and to be part of the steam tem- [1] J. B. Stout, J. J. Walsh, and A. G. Mellor, "A large combinedperature control system. Operating experience has shown gas turbine-steam turbine generating unit," Proc. Am. Power

Conf., vol. XXIV, pp. 404-411, 1962.that these dampers are not needed for either function; they [2] J. B. Stout, J. J. Walsh, T. D. McKone, and A. G. Mellor,actually limit the load on the boiler by robbing the burners "OG & E combined cycle unit offers 4% gain in efficiency,"

E16ct. World, August 14, 1961.of combustion air. These dampers are now locked shut. [31 J. B. Stout, J. J. Walsh, and A. G. Mellor, "First large combined-

cycle uniit justified by increased efficiency," Elect. Light andCONCLUSION Power, vol. 41, pp. 32-35, May 1963.

[41 D. C. McClintock and R. E. Dale, "Control of a steam turbine-It is the author's belief that the foregoiing has indicated gas turbine combined cycle generating unit," presented at the

1964 Power Instr. Symp. of Instr. Soc. of Am., Denver, Colo.that the combined cycle uInit has definitely come up to ex- [5] C. D. Reid and K. A. Ketchersid, "A look at the world's largestpectations both as to capability and economy. While the combined cycle unit after one year's operation," presented at

the 1964 Missouri Valley Elect. Assoc. Engng. Conf., Kansascombined cycle service factor only comes to approxi- City, Mo.mately 50 percent for its first year, this may be attributed [61 J. W. Blake, "Operating experience with world's first large

combined cycle generating unit," presented at the 1963 South-largely to the unusual amount of time spenlt on the first- east. Elect. Exch. Meeting, Tampa, Fla.