gek41745 - cleaning of main steam piping for combined cycle plant

GEK 41745BRevised August 2004

GE Energy

Cleaning of Main Steam Piping for Combined Cycle Plant

These instructions do not purport to cover all details or variations in equipment nor to provide forevery possible contingency to be met in connec tion with installation, operation or maintenance. Shouldfurther information be desired or should particular problems arise which are not covered sufficiently forthe purchaser's purposes the m atter should be re ferr ed to the GE Company.

GEK 41745B Cleaning of Main Steam Piping for Combined Cycle Plant

TABLE OF CONTENTS

I. LIMITATION OF LIABILITY .................................................................................................... 3

II. INLET STEAM PIPING (INTRODUCTION) ........................................................................... 3

III. CHEMICAL CLEANING............................................................................................................. 4

IV. PRECAUTIONS IN THE USE OF THE CONDENSER HOT WELL AS A RESERVOIR

FOR CHEMICAL CLEANING SOLUTIONS ........................................................................... 5

V. CONSIDERATIONS FOR A STEAM BLOWDOWN............................................................... 7

VI. STEAM BLOWDOWN PRELIMINARY PREPARATION ..................................................... 10

VII. STEAM BLOWDOWNOF THE HEAT RECOVERY STEAMGENERATORS AND THE

MAIN STEAM LINES .................................................................................................................. 13

VIII. TURBINE OPERATION WITH A FINE MESH STRAINER ................................................ 14

IX. AUXILIARY STEAM PIPING .................................................................................................... 15A. Auxiliary Oil Pump Steam Supply Piping (If Applicable) ...................................................... 15B. Steam Seal Piping .................................................................................................................... 15

APPENDIX A – POOR STEAM QUALITY DAMAGE ........................................................... 17

LIST OF FIGURES

Figure 1. Typical Stop Valve Cross Section with Typical Blanking Fixture Installed for Chemical

Cleaning ................................................................................................................................... 6Figure 2. Suggested Arrangement for Blowing Down Steam Piping...................................................... 7Figure 3. Bracket Support for Polished Target ........................................................................................ 8Figure 4. Blowdown Discharge Velocity (VD) and Flow Function (F30) for 30 psia Discharge Pressure

vs. Steam Enthalpy ................................................................................................................. 11Figure 5. Pressure Distribution Near the End of a Pipe Discharging Steam at Sonic Velocity.............. 12Figure 6. Stage 12 Nozzle Area Reduction ............................................................................................. 17Figure 7. Stage 12 Bucket Damage ......................................................................................................... 18Figure 8. Stage 12 Nozzle Damage ......................................................................................................... 18

Figure 9. Stage 1 Bucket Damage ........................................................................................................... 19

Figure 10. Stage 1 Nozzle Damage........................................................................................................... 19

LIST OF TABLES

Table 1. Efficiency Appraisal Evaluation Summary.............................................................................. 18Table 2. Summary of Performance Parameters and Related Changes ................................................ 19

APPENDIX B – FOREIGN OBJECT DAMAGE ....................................................................... 19

Cleaning of Main Steam Piping for Combined Cycle Plant GEK 41745B

I. LIMITATION OF LIABILITY

The Purchaser should recognize that the choice of conditions and methods to be used as well as precautionsto be followed for the cleaning of the internal main steam system are the responsibilities of the Purchaser,the choice over which General Electric has no knowledge or control. For this reason, although this articlecontains suggestions on various conditions and methods for cleaning, the final decision is up to the Purchaser,and General Electric can assume no liability whatsoever for the final result.

II. INLET STEAM PIPING (INTRODUCTION)

Techniques for cleaning steam piping for a variety of turbines furnished with com-bined cycle plants are covered in this article. The purchaser should apply onlythose guidelines and procedures which are applicable to the specific equipmentpurchased.

Operators of a combined cycle plant(s) using heat recovery steam generators should observe the criteria tofollow here for the cleaning of the main steam piping.

To attain steam turbine high reliability, minimum plant maintenance and long term cycle efficiency, a clean,particle-free condition of the steam piping and steam passages in the steam equipment is essential. The guide-lines to follow will outline the practical steps necessary for the Purchaser to undertake early in plant construc-tion and prior to any system steam tests that will best assure trouble free operation of the combined cycleplant. Proper cleaning of the station steam piping and the heat recovery boiler should be accomplished at thesite in order to assure the availability of clean steam for the reliable operation of the steam turbine, steamturbine seal system and the steam turbine bypass desuperheating valve. Failure to effectively clean the stationsteam piping and the heat recovery boiler can result in damage to the diaphragm nozzles and rotor buckets.An example of the damage resulting from poor steam quality and the costs associated with the damage arehighlighted in Appendix A.

Experience has demonstrated the extreme importance of blowing down the main steam lines and admissionsteam piping upstream of the steam turbine. Blowing down minimizes the possibility of damage to the tur-bine by removing weld bead deposits, pipe slag and other foreign material which might otherwise be carriedover into the turbine. An example of the damage that can result from this foreign material and the efficiencycosts associated with it are highlighted in Appendix B. Also blowing down will minimize the likelihood ofparticles jamming working mechanisms exposed to steam and the clogging of narrow steam passages.

Although, for startup, steam turbines are equipped with a fine-mesh screen in the main stop valves, thisscreen is not to be considered a substitute for blowing down the steam lines. The screen, assembled over thepermanent coarse screen in the strainer casing, helps to trap foreign material during the initial full-load opera-tion of the unit. It is only a temporary extra precautionary measure, however, and must be removed after ini-tial full-load operation because the fine screen is not designed to stand up in continuous service without risk-ing fatigue failure of the screen wire. It would not be desirable to leave the fine screen in permanent servicebecause the increased pressure drop in the fine screen may result in a reduction of turbine efficiency.

The most satisfactory method of cleaning the steam piping is by means of a heating cooling and steam blow-ing cycle. Pressure is built up in the boiler and main steam header and then released through the temporarypiping. The lines cool while the steam pressure is being built up again. The cycle-heating, cooling, blowingis repeated until the steam emerging from the blowdown piping is observed to be clean. Limiting the cleaningoperation to a specific number of blowing cycles, or until the blowdown appears clean, may not always result

in adequately clean piping. It has been found that the effectiveness of cleaning can more positively be deter-mined by use of a polished target at the outlet of blowdown piping. Details on the construction and applica-tion of such a target are given later in this article.

The characteristics of heat recovery steam generators necessitates some change in cleaning methods as op-posed to acceptable methods used on conventional power boilers. Usually it is not possible for one heat re-covery unit on a typical multi-shaft application to furnish sufficient steam during blowdown to obtain theforce ratio of one for cleaning of the main steam header piping. This prevents utilizing the conventional pow-er boiler sequence of: fire to steam blow pressure, open blowdown valve and allow the pressure to decay toa minimum pressure level, close blowdown valve and repeat process. In addition, the volume of water storedin the evaporator section and the drum is less than the volume stored in the conventional power boiler of thesame generating capacity. Allowing for these differences some combination of the following design andcleaning methods should be given consideration by the Purchaser:

A. Joint design of field welds should use first pass TIG consumable inserts.

B. Chemical cleaning of the heat recovery steam generators, the main steam header piping including steam tur-bine bypass piping prior to cleaning either by mechanical means, steam blowdown or by a gas blowdown.

C. Provisions included in the main steam header piping to utilize mechanical cleaning methods.

D. Steam blowdown – generate steam in the HRSG(s) in the unfired mode utilizing the storage capacity asnecessary from the deaerator and condenser hotwell to replenish boiler water spent in steam blowdown.

E. Gas blowdown – combined gas blowdown of the main steam header piping only.

F. After the completion of any combination of the above, steam turbine operation with a fine mesh screeninstalled for a prescribed period of time beginning with turbine testing and ending sometime after steamturbine goes into commercial operation.

III. CHEMICAL CLEANING

Special blanking fixtures will be required to protect the turbine and internal parts. Certain materials common-ly used in these turbine assemblies are attacked by the acids or caustics used and must be protected duringthis chemical cleaning. Because these blanking fixtures sometimes leak, GE recommends that caustic notbe used as a constituent of the chemical cleaning process. The installation of blanking fixtures is accom-plished by removal of the valve top cover and protecting the seat bore with a special blanking fixture duringthe cleaning and flushing cycle. Occasionally, a blanking fixture is required to replace the upper head portionof the valve to provide temporary acid cleaning pipe connections through the upper head. General Electricwill supply fixtures for chemical cleaning. Instructions and drawings will be furnished for the chemicalcleaning fixture(s). Hydrostatic tests should be completed prior to the installation of the chemical cleaningfixture. The chemical fixture may collapse if installed during the hydrostatic tests. The fixture should be in-stalled during the blowdown in order to prevent foreign matter from depositing adjacent to the seat and plug.

General Electric requests that the Purchaser furnish early in the plant design phase, answers to the followingquestions:

A. Maximum pressure and temperature at valve during acid wash?

B. What chemicals will be in contact with the valve internals in the cleaning process?

C. What temporary pipe connections are required, if any? Purchaser should review General Electric draw-ings to assure that temporary pipe flange bolting matches bolt hole size and bolt circle furnished in thefixture.

D. Will temporary sealing fixtures be subject to blowdown (steam or gas) pressures?

Figure 1 shows a sketch of a typical stop valve cross-section with typical blanking fixtures installed for chem-ical cleaning with a blowdown flange.

IV. PRECAUTIONS IN THE USE OF THE CONDENSER HOT WELLAS A RESERVOIR FOR CHEMICAL CLEANING SOLUTIONS

GE recommends that the condenser hotwell not be used as a reservoir for chemical cleaning solvent. GE alsorecommends that any chemical mixing not be performed in the condenser hotwell. If it is desired to use thecondenser hotwell as a reservoir for boiler cleaning solutions, the possible corrosion of turbine componentsby these solutions must be a prime consideration. Conditions conducive to attack on these components couldresult either through direct contact with the liquid solution or through contact with a volatile component ofthe solution.

Generally speaking, chemical cleaning solutions may be classified as acidic or basic, according to theirchemical composition. Each class may contain subdivisions such as, organic or inorganic, inhibited or unin-hibited, and so on. The two main classes will be discussed separately with examples and typical considerationbeing given.

The first general type of chemical cleaning solution is the acidic type. The acidic type cleaning solutions maybe inorganic (hydrochloric, sulfuric) or organic (hydroxyacetic, formic, citric, etc).

Acidic cleaning solutions usually contain an inhibitor to limit attack on steel surfaces in contact with the solu-tion. The use of solutions containing low molecular weight, volatile organic acids (such as, but not limitedto, formic and hydroxyacetic acids) should be avoided since there is the possibility of acidic vapors reachingthe turbine and causing corrosion and perhaps hydrogen embrittlement of buckets, tie wires and other ferrousmaterials. Inhibited citric acid solutions are much less volatile than the above and are preferable from thestandpoint of turbine corrosion. Ammoniated citric acid might be used when the condenser tubes and otherfittings which might come in contact with the ammonia vapors evolved from this solution, are not brass.Since brass is susceptible to stress corrosion cracking in the presence of ammonia and air, the use of citricacid solution inhibited with Rodine 115 or an equivalent inhibitor is preferred.

The use of hydrochloric acid or other chlorides containing cleaning solutions is not desirable, since manyferrous alloy materials show susceptibility to stress corrosion cracking and intergranular attack in the pres-ence of chloride ions.

The second general type of chemical cleaning solutions is the basic or alkaline type.

These solutions usually contain caustic soda and/or sodium phosphates, and possibly wetting agents and oth-er additives. Again, because of the serious contamination consequences if the chemical cleaning solvent con-taining caustic were accidentally flushed into the steam turbines, GE recommends that caustic not be usedin the process. Other basic solutions are usually less corrosive and less volatile than acidic cleaning solutions.Although normally one would not expect significant quantities of solution to volatilize into the turbine, suchan occurrence would present the possibility of caustic stress corrosion cracking of buckets and other turbinecomponents.

1. Parts shown in heavy solid lines and as noted are acid wash fixtures.

2. The valve head cover is to be removed for acid washing.

3. The temporary upper head covers may be used for both blowdown and acid washif specified by the Purchaser when ordering. The blowdown cover shown on thestop valve has a large blowdown connection and is of this type.

4. In some types of valve designs it is possible to use the permanent head for acidwashing, but it is not possible for the permanent head to be used for blowdown.

ACID CIRCULATIONCONNECTION

TYPICALMAIN STOP VALVE

BLOWDOWNFLANGE

CHEMICAL CLEANINGFIXTURE

(INCLUDES BOLTING,COVER AND GASKET)

ACID CIRCULATIONCOVER

Figure 1. Typical Stop Valve Cross Section with Typical Blanking FixtureInstalled for Chemical Cleaning

Obviously, it is not possible to cover all possible cleaning solution compositions and conditions which mightbe encountered. The purpose of this discussion is to bring to the users attention a few of the many possiblesituations that could occur as a result of using the condenser hotwell for storing an improper chemical clean-ing solution for boiler use.

V. CONSIDERATIONS FOR A STEAM BLOWDOWN

Primarily, this article will cover a steam blowdown of the heat recovery units and the main steam header pip-ing and certain recommendations may be applicable if the Purchaser chooses a gas blowdown.

For steam blowdown the heat recovery steam generators will be operated in the unfired boiler mode. Theauxiliary firing capabilities on fired heat recovery boiler applications will not be utilized during blowdown.The Purchaser shall determine from the plant arrangement what order to select for the steam blowdown ofthe heat recovery steam generators and the main steam lines. Generally, the heat recovery boilers are blowndown separately followed by the combined boiler steam blow of the main steam header through the steamturbine bypass piping and, finally, a combined boiler steam blow of the main steam header through the tur-bine stop valve(s). If there are two main stop valves, the Purchaser can select to blow down both valves simul-taneously, one valve at one time whichever is most economical, convenient and practical. The Purchasershould make up or order from General Electric temporary cover plates, one for each main stop valve, to re-place the normal stop valve covers. These temporary plates must be designed heavy enough and machinedadequately to maintain the desired blowdown steam pressure without leakage. Pertinent dimensions of thepermanent covers will be sent to the Purchaser as a reference for making up temporary plates. If the Purchaserwishes to blow down one valve at a time, he may then use the same plate and pipe for the second stop valve.In this case, the stop valve not being blown through should be covered with its permanent cover. The chemi-cal cleaning fixture should be installed in the turbine stop valve during blowdown to prevent particles fromdepositing adjacent to the valve seat and plug. See Figure 2 for the suggested arrangement for blowing thesteam header piping through the main stop valve.

Pressure readings during blowdown should be taken upstream of the boiler stop valves and as close as possi-ble to the blowdown pipe discharge. The latter connection should be made at a convenient location not less

PURCHASER’S 8″ TO 14″[203 TO 356 MM]

TEMPORARY BLOW PIPETO SAFE AREA

TEMPORARYBLOWDOWNGATE VALVE

BOILER SHUTOFFVALVE

TEMPORARYHEAD BY

PURCHASERSTOP VALVE

CLOSED

MAIN STEAM

Figure 2. Suggested Arrangement for Blowing Down Steam Piping

than twenty diameters from the discharge end of the blowpipe in order to obtain a stable pressure reading.These readings will help substantiate the calculated boiler pressure and pipe sizes selected for the blowdownoperation.

The number of polished targets required to ascertain that the steam piping is adequately clean will vary de-pendent on the interpretation of the targets taken from the previous blows.

Following the initial three or four blowing cycles for each particular pipe run, when the steam appears to beclean by visual observation, a polished target should then be inserted in the blowpipe discharge for each sub-sequent blow. The targets can be made of steel, aluminum or copper strips, polished on both sides to obtaindouble use from each. Figure 3 shows one suitable method for fastening the target to the open discharge endof the blowdown piping. The arrangement shown permits easy replacement of the target.

Adequate communication must be established and maintained between the gas turbine operation center,HRSG operation and the temporary blowdown valve operation. This might also be backed up by a systemof visual communication, such as indicating lights, since phone communication may become difficult dueto high noise level at the blowdown valve. An arrangement should also be made to record pressure readingsat various stations simultaneously through proper communications.

Sufficient reserve feedwater should be available in the deaerator storage tank, condenser hotwell, and reservefeedwater tanks for blowdown. The Purchaser should provide sufficient time in the blowdown schedule toperform a satisfactory steam blow.

The following equipment and steam piping should be chemically cleaned and steam blown prior to undertak-ing plant startup testing.

A. Each heat recovery steam generator and its steam lines.

B. The main steam lines and header from each heat recovery steam generator through to the turbine bypasspiping just upstream of the turbine bypass desuperheater valve. The turbine bypass desuperheater valve

11/2″x11/2″x1/4″[38 x 38 x 6 mm]

ANGLE BRACKET

POLISHED STEEL STRIP1/8″ TO 1/4″ [3 TO 6 mm] THICK

SAME LENGTH ASBACKING BAR

POLISHED TARGET STRIPBOLTED TO BACKING BAR

TO PREVENT FLUTTER

BACKING BAR1″ X 1″ [25 X 25 mm]

6″[152 mm]

2″[51 mm]

Figure 3. Bracket Support for Polished Target

must not be in the steam path during blowdown. The Purchaser shall supply temporary piping includinga blowdown valve to be connected at a point just upstream of the turbine bypass desuperheater valve.

C. The main steam lines and header through to the turbine stop valve(s).

D. The steam seal piping. No acid cleaning of seal steam piping recommended.

The Purchaser shall furnish the temporary piping and the blowdown valve(s). The Purchaser shall determinethe arrangement and sizing of the temporary blowdown pipe as well as the type and number of blowdownvalve(s) to be used. The blowdown pressure will be built up in the steam piping and released by the operationof the blowdown valve(s). The blowdown valve(s) shall have valve position jogging capabilities.

Several steam generator factors should be considered in blowing down combined cycle steam generators.These include feedwater quality, drum thermal stresses, and steam generator design application.

Since the blowdown takes place during the initial operation of the plant, design deaeration levels of the feed-water may not be possible. The Purchaser should recognize that there is a risk of corrosion, especially in theeconomizer tubes, if normal feedwater oxygen levels are not maintained. To correct this situation, catalyzedhydrazines or other oxygen scavenging chemicals may be used during steam blowdown. This is essential,especially if the blowdown is to take place on a semi-continuous basis.

Steam drum thermal stress is potentially highest during the period water is flashing to steam during steamblowdown. A measure of this stress is the time rate of change of drum pressure which can be converted backthrough saturation temperatures to temperature rate. General Electric will furnish on request, a curve of al-lowable pressure change in the drum versus drum pressure for the specific application. This curve will takeinto consideration parameters such as drum diameter, wall thickness, steady state stress, and relate this topressure rise rate. Due to the rapid decrease in saturation temperature relative to pressure below approximate-ly 250 psig [1.72 MPa (gauge)] [17.6 kg/cm2 (gauge)], it is usual to terminate blowdown sequence beforethis pressure is reached.

The relative volume of evaporator and drum water space is considerably smaller in a heat recovery steamgenerator relative to that of a modern power boiler of the same steaming capacity. This difference usuallynecessitates a change in blowdown procedure than that associated with power boilers in order to obtainequivalent blowing times. Due to the inability of obtaining a significant blow time and remain within thedrum stress limits, a semi-continuous process is described. Here steam is generated on a continuous basisat lower than rated pressure but slightly greater than rated flow with only a limited amount of flashing takingplace. The chief consideration in this method is makeup capability. Usually the hotwell and/or deaerator stor-age will allow for a 5 to 7 minute blow.

In a heat recovery boiler blow, it must be recognized that the blown steam will have significant superheat.Any temporary piping installed for the blow should be designed for the expected temperature and pressure.Also, the superheater tube velocity should be limited to approximately double the design operating velocity.

When calculating the cleaning force ratios on heat recovery steam generators, it should be remembered thatambient temperature will have a significant affect on steam generation due to the gas turbine exhaust gas flowcharacteristic. Highest flows occur at the lowest ambient temperature. The aspect of variable pressure opera-tion may indicate that the best cleaning forces for a steam generator occur under different conditions thanthose optimum for a steam turbine, i.e.; steam generator steam flow peaks while operating in the low pressureregion (part load mode) and steam turbine peaks at its maximum load point.

For combined cycle units with multiple steam generators supplying steam to a single turbine, it is unlikelythat a single steam generator will be able to produce enough steam to reach a force ratio of one for the main

steam header. In such cases blowdown of the header with simultaneous operation of steam generators, gasblow of the main header, or mechanical cleaning of the header, after individual steam generator blows shouldbe given serious consideration.

VI. STEAM BLOWDOWN PRELIMINARY PREPARATION

The Purchaser should size and provide the temporary piping required for the blowdown. This blow piping mustbe large enough to develop a mass-velocity head in the permanent piping at least equal to that developed duringfull-load operation. The size of the temporary piping is usually 8 to 14″ [203–356 mm] in nominal diameterwhen blowing with a boiler pressure of 600 psig [4.14 MPa (gauge)][42.2 kg/cm2 (gauge)] superheated steam.

Since the force on a particle is proportional to the mass-velocity head of the fluid, it appears reasonable thatthe mass-velocity head developed during the blowing cycle must be equal to that developed during full-loadoperation. This should take care of most loose pieces, although the time factor is involved and no one canbe sure how long it takes pipe scale to loosen up, or such things as pieces of welding rod to work their waythrough the pipe lines, superheater and main steam lines.

Calculations can be made to show how much flow and what drum pressure is necessary for an assumed tem-porary pipe size to get a mass-velocity head during cleaning equal to that attained during full-load operation,based on the following.

A. As a first attempt, assume that the velocity at the pipe exit to atmosphere during blowdown is sonic, andthat the pressure, Pp, just inside the pipe at the exit is 30 psia [207 kPa][2.11 kg/cm2]. To make this as-sumption, it is necessary that all flow areas in the system be equal to or larger than the discharge area.

B. Estimate the steam conditions (pressure, enthalpy) at the boiler outlet expected during steam blowdown.From the curves on Figure 4 read the mass flow function, F30. Calculate the mass flow, Qc, as follows:

Qc = F30 × Apwhere Ap = area of pipe at discharge (in.2)

C. It is necessary to calculate the pressure drop through the temporary and permanent piping to arrive ata boiler pressure. Refer to Figure 5. This curve should be used in determining the pressure drop near thedischarge end of the temporary piping since the velocity is near sonic and ordinary calculation of pres-sure drop due to friction does not apply. In applying Figure 5, assume as a first trial that L is the totalequivalent length of the temporary piping including the equivalent length of elbows, tees, etc. in the tem-porary system. Calculate the fL/D and enter the curve in Figure 5 and thus calculate P, the pressure atthe distance L from the exit. Note that if fL/D of the temporary pipe is more than 5, use a shorter L whichwill make fL/D equal 5 and use corresponding P/Pp to calculate P at the shorter L. Where fL/D is greaterthan 5, the pressure drop is a straight line function of L and can be calculated by conventional method.Then calculate by conventional straight line methods the pressure drop due to friction in the piping fromthe point L from the exit to the boiler outlet, thus arriving at the boiler outlet pressure Pc.

D. Then calculate the cleaning force ratio at the boiler outlet using calculated Pc and expected enthalpy. Thisratio compares the mass velocity head during cleaning with that developed during normal full-load oper-ation. The cleaning force ratio is expressed by:

× ×( )2

NOTES:

1. IF STEAM IS SUPERHEATED ENTER CURVE 1AT ESTIMATED ENTHALPY AT SUPERHEATEDOUTLET AND READ FLOW FUNCTION F30.

2. IF STEAM IS SATURATED ENTER CURVE 2 ATDRUM PRESSURE AND READ ENTHALPY. USEENTHALPY TO ENTER CURVE 1 FOR OBTAIN-ING FLOW FUNCTION F30.

3. CURVE 3 IS FOR REFERENCE IN OBTAININGDISCHARGE VELOCITY.

Figure 4. Blowdown Discharge Velocity (VD) and Flow Function (F30) for30 psia Discharge Pressure vs. Steam Enthalpy

where:

Qc = calculated flow during cleaning (lb/h)Qmax = max load flow (lb/h)(Pv)c = pressure-specific volume product during cleaning at boiler outlet (ft3/in2)(Pmax) = pressure at max load flow at boiler outlet (psia)(Pc) = pressure during cleaning at boiler outlet (psia)(Pv)max = pressure-specific volume product at max load flow at boiler outlet (ft3/in2)

NOTES: L = EQUIVALENT LENGTH OF PIPE FROM DISCHARGE (ft)D = INSIDE DIAMETER OF PIPE (ft)f = FRICTION FACTOR DEFINED AS hL

( )WHERE hL = HEAD LOSS (ft)

V = VELOCITY ft/sP = PRESSURE AT POINT L FROM DISCHARGE (psia)Pp = PRESSURE ASSUMED AT PIPE DISCHARGE (psia)

f ( )L

10 1 2 3 4 5

Figure 5. Pressure Distribution Near the End of a Pipe Discharging Steam at Sonic Velocity

E. If this ratio R is less than one and the steam velocity in the superheater tubes is less than twice the allow-able, divide the pressure assumed inside pipe exit (Pp) by this ratio and repeat the above process; thus,the required flow and pressures for equivalent cleaning forces can be determined, establishing the re-quired sizes for the temporary blowpipes. Note that for a discharge pressure different than 30 psia[207 kPa] [2.11 kg/cm2], the flow function is

Fp = F30 x (Pp/30)

The size of the temporary pipe is a most important factor. The use of a larger pipe will result in lesserflows and lesser pressure levels required for the same cleaning force. The size effect is proportional tothe ratio of diameters to the fourth power. In no case, however, should the temporary pipe have greaterflow area than the permanent piping.

F. If the ratio R cannot be adjusted to meet a ratio of unity without exceeding twice the allowable steamvelocity in the superheater tubes, then the boiler pressure to be used during blowdown can be selectedas follows:

Determine the boiler pressure equivalent to the point where the steam velocity in the superheater tubesis equivalent to twice the allowable, subtract a nominal pressure of 50 psi [345 kPa] [3.52 kg/cm2] andround off to the next lower practical boiler pressure setting.

For example, if the boiler pressure calculates to be 683 psi [4.71 MPa] [48.0 kg/cm2] for the point wherethe steam velocity reaches 600 ft/s [183 m/s] then:

683 psi – 50 psi = 633 psi [4.36 MPa] [44.5 kg/cm2]

The next lower practical boiler pressure can be selected either as 600 psi [4.14 MPa] [42.2 kg/cm2] or625 psi [4.31 MPa] [43.9 kg/cm2] and be used as the blowdown release pressure.

VII. STEAM BLOWDOWN OF THE HEAT RECOVERY STEAM GENERATORS AND THEMAIN STEAM LINES

A. Suggested preparations to be made prior to undertaking a steam blowdown are given as guidance infor-mation and the assumption that the turbine unit has one main turbine stop valve:

1. Check to ensure the turbine main stop valve is closed tightly.

2. Remove the permanent head and the steam strainer from the main stop valve. It is necessary to plugthe pilot passages of the valve during blowdown to keep foreign material out of the assembly. Theseprotective devices should be installed for blowdown and must be removed before starting the turbine.

3. Install a temporary blowdown cover on the main stop valve. A new gasket is not required. Installthe temporary piping to the top of this plate and run blowpipe out of building to a safe area. A blow-down valve should be installed at some convenient place in the temporary piping.

4. Anchor all permanent and temporary piping properly with sufficient flexibility for thermal expan-sion. Make provisions for taking pressure readings and for adequate communication between plantcontrol.

5. Remove the attemperator nozzle, if applicable, and install a blind flange.

6. Close isolation valves on steam header instrumentation such as pressure transmitters, gauge linesetc. This will eliminate pockets for foreign matter to collect. Sensing lines necessary for controlsused during blowdown must be left open.

7. Hotwell and deaerator level controls as well as boiler feedpump-recirculation controls should bechecked out and operational.

8. Steam generator level controls should be checked out and operational.

9. Steam generator pressure and temperature instrumentation as well as damper and motor operatedvalve controls should be checked out and operational.

10. Steam generator circulating system should be checked out and operational.

11. The temporary blowdown valve should be power actuated and be able to operate as a control valvewith valve position jogging capabilities.

B. The procedure for blowing down one heat recovery steam generator is suggested as follows:

1. Fill condenser hotwell and deaerator storage tank to maximum level with feedwater quality water.

2. Start gas turbine and bring to load point (probably low load for first blow, base load for subsequentblows).

3. Warm up steam generator by admitting small quantities of exhaust gas through isolation damper.Vents, drains and circulating system are to be operated per instruction book.

4. When pressure is adequate to close steam generator vents, start admitting small quantities of steamto main header to start its warmup.

5. Bring gas turbine to base load and continue warming main header until it is above saturation temper-ature for the blowdown pressure. Steam generator isolation damper can be adjusted for flow control,vent, drain, and blowdown valve(s) can be adjusted to bring drum pressure to the desired level.

6. When the required warmup pressure is reached in drum and the header is determined, final buildupto blow can start by fully opening the isolation damper and then closing the bypass damper. Pressureshould be held near the calculated blow pressure by adjusting the blowdown control valve. Drumwater level should be maintained near its high alarm point.

7. After reaching steady state, continue opening the blowdown control valve to allow drum pressuredecrease at the allowable rate.

8. To terminate a blowing cycle, first the bypass damper should be opened and then the isolation damp-er closed. Pressure should be held approximately constant by adjusting the blowdown control valve.

9. The operator should be aware of water levels in the hotwell and deaerator during the blow and re-member that some feedwater will be needed during the idle period between blows.

10. When a blow cycle is terminated, a small flow of steam will keep the header warm until hotwell anddeaerator levels are brought back to starting water levels. The gas turbine could remain at base loador be adjusted to suit system requirements. The blowdown valve can be throttled to hold the desiredboiler hold pressure during this period.

11. The above steps should be repeated for each heat recovery steam generator until each unit accom-plishes a successful steam blow. Then a combined steam blow should be undertaken to clean themain steam header piping including the turbine bypass steam piping up to but not through the desup-erheating-reducing valve.

VIII. TURBINE OPERATION WITH A FINE MESH STRAINER

After the completion of blowdown tests and prior to turbine roll tests, a fine mesh screen will be furnishedon a loan basis by General Electric for installation into the turbine strainer basket. General Electric’s experi-ence indicates that cleaning by chemical means and steam blows may not remove all the grit, dirt, scale, etc.from all the steam passages and turbine operation with a fine mesh screen is a necessary requirement.

During steam turbine tests, the fine mesh screen may have to be removed and cleaned once or twice depend-ing on the accumulation of foreign matter in the first change-out.

After the combined cycle plant goes commercial on the steam turbine, the following is recommended basedon daily continuous service hours on the turbine assuming the plant is shutdown on the weekends.

If the unit is operated 8 to 10 hours per day on a full load basis, the stop valve should be opened and the finemesh screen inspected between 3 days but no more than 8 days of operation.

If the unit is operated 12 to 24 hours per day on a full load basis, the stop valve should be opened and finemesh screen inspected between 2 days but no more than 6 days of operation.

During inspection, the fine mesh screen should be replaced and no dirt removed until after photographs havebeen taken of the fine mesh screen and of the valve body internals. The photographs will be used as a basisfor comparison at the next opening of the stop valve.

Depending on the amount of dirt found during the first inspection, the unit should then be operated one ortwo weeks before again opening the stop valve for the second inspection.

If dirt is still evident, photographs of the dirt in the valve body and in the screen should be taken again andan assessment made as to whether or not the quantity of dirt was less, more or the same as that found duringthe first inspection. The screen should again be cleaned (if no mechanical damage is evident) or replaced andthe cover reassembled to the valve body. If the dirt accumulated during the second run is a small quantity,the unit should be run 2 to 3 weeks before the next inspection is made. If the quantity of dirt was the sameor more than that found at the first inspection, the unit should only be operated 1 or 2 weeks before openingthe stop valve again for an inspection.

IX. AUXILIARY STEAM PIPING

A. AUXILIARY OIL PUMP STEAM SUPPLY PIPING (if applicable)

To protect the drive of the auxiliary oil pump and the regulator from damage from weld spatter and weldbeads, the supply piping should be considered in the blowdown operation.

Disconnect the supply line from the auxiliary pump regulator and pipe to a point outside the building,taking care to provide supports, and taking precautions to protect plant equipment and personnel.

The blowing through of this piping can then be accomplished when steam pressure is available on themain steam line. In the event this pump has a supply other than throttle conditions, blowing through canbe accomplished independently of main steam line cleaning.

The temporary blowpiping may be removed and the permanent connection to the pump regulator maybe made after the Purchaser is satisfied that steam emerging from blowpipe is clean.

B. STEAM SEAL PIPING

Weld spatter and other foreign material that may be contained within the steam seal piping can do appre-ciable damage to both steam seal packing and the turbine shaft. It is prudent, therefore, to direct as muchattention to the cleaning of this piping as has been stated for the main steam piping.

Factory prefabrication and pickling procedures, of course, tend to minimize the amount of foreign matterin this piping. However, because field welding is required for shipping and field assembly reasons, theremay be scaling and possible weld spatter conditions existing even after the field welds have been careful-ly made.

In order to do a thorough job of cleaning, it is recommended this piping be blown out with steam beforeunit startup. For this purpose, the steam seal piping will have removable sections in each major field run.

The following procedure for conducting the blowdown is suggested for a turbine with two high pressurepackings and two packings in the exhaust:

1. The removable sections near all four packings should be removed and the header side of the open-ings blanked on all but the No. 1 (front standard) packing. If necessary, to prevent blown materialfrom entering the turbine, temporary blow piping should be installed.

2. Steam pressure should be built up and the bypass valve around the steam seal regulator opened. Agood blow for 20 seconds followed by a waiting period of 10 minutes repeated once should be suffi-cient. Steam supply pressure should be 200 to 300 psig [1.38–2.07 MPa (gauge)] [14.1–21.1 kg/cm2

(gauge)]. The steam seal regulator inlet valve should be closed during this blow.

3. The header side of the removable section at the No. 1 packing should be blanked and the blank re-moved at the No. 2 packing. Again, temporary piping may be necessary at the No. 2 packings toprevent blown steam from entering the turbine.

4. Repeat the blowing procedure of Step 2.

5. On some turbines with close coupling between the high and low pressure sections, it is not possibleto install a removable section at the No. 2 packing. In this case, a flange is provided in the piping tothis packing. During the blowdown period, a blanking plate can be installed at this flange to preventsteam entering the turbine. The blowing procedure should eliminate Steps 3 and 4 if this is the case.

6. The blank should be replaced at the No. 2 packing and removed at the No. 3 packing (turbine endof exhaust). With some piping arrangements it is necessary to blank the short run of pipe betweenthe removable section and the packing casing to prevent blown steam entering the packing area.

8. Replace the blank at the No. 3 packing and remove the blank at the No. 4 packing.

10. Make one final 30 second blow through the steam seal regulator inlet valve.

11. Remove all temporary blanks and replace the removable sections in preparation for starting theturbine.

Experience has shown that blowing more than one packing at a time is ineffective. This blowing procedureshould be conducted after completion of the main steam supply blowdown to minimize the possibility ofexternal material being lodged in the steam seal system.

Cleaning of Main Steam Piping for Combined Cycle Plant GEK41745B

Appendix A – Poor Steam Quality Damage

A new 256 MW, 33.5” LSB, 3600-RPM Combined Cycle D-11 code type unit experienced a significant reduction in efficiency during commissioning. Because of the significant loss of efficiency in the reheat section, the unit was opened and a steam path audit was initiated.

The audit revealed reductions in nozzle flow areas of the IP diaphragms due to solid particle damage. The reductions were estimated as follows, and the extent of the reduction can be seen in the photo of the stage 12 nozzles (Figure 6).

12th – 10% reduction13th – 8% reduction14th – 7% reduction15th – 6% reduction16th – 5% reduction

Figure 6. Stage 12 Nozzle Area Reduction

The major cause of the damage to the steam path was determined to be poor steam quality. A large quantity of solid particles entered the IP steam path, producing Solid Particle Erosion and Small Particle Impingement damage to internal components as evident in the photos of the stage 12 buckets and nozzles (Figures 7 and 8). In addition, heavy rubbing of packing, tip spill strips and root radials increased the internal clearances within the turbine. The HP buckets and

GEK41745B Cleaning of Main Steam Piping for Combined Cycle Plant

diaphragms were not inspected as part of the audit, and are considered in the calculations to not have any performance losses. However, the HP diaphragm packing, root radial, and tip spill strips were inspected as part of this audit and the associated performance losses were calculated. The summary of the efficiency appraisal evaluation is included in Table 1.

SectionEfficiency

Loss(% pts)

UnitKilowatt

Loss(kWs)

Unit HeatRate Loss(BTU/kWh)

TurbineCycle HR

Loss(BTU/kWh)

Excess Costof Fuel

(Annum) ($)Section High PressureRecovered Losses 1.732 366.1 12.9 18.7 83,733Unrecovered Losses 0.000 0.0 0.0 0.0 0Section Total Losses 1.732 366.1 12.9 18.7 83,733

Section Intermediate Pressure Recovered Losses 5.448 4,108.5 145.0 210.4 939,747Unrecovered Losses 0.358 242.9 8.6 12.4 55,561Section Total Losses 5.806 4,351.4 153.6 222.8 995,308

Other Recovered LossesN Packings 275.2 9.0 13.1 40,280Other Recovered Losses Total 275.2 9.0 13.1 40,280

SummaryRecovered Losses 4,749.7 166.9 242.2 1,063,760Unrecovered Losses 242.9 8.6 12.4 55,561Inspected Total Losses 4,992.6 175.5 254.6 1,119,321

Table 1. Efficiency Appraisal Evaluation Summary

Figure 7. Stage 12 Bucket Damage Figure 8. Stage 12 Nozzle Damage

Cleaning of Main Steam Piping for Combined Cycle Plant GEK41745B

Appendix B – Foreign Object Damage

A 186 MW, 33.5” LSB, 3600-RPM Combined Cycle D-11 code type unit experienced a significantreduction in HP efficiency. An analysis of the performance parameters revealed a decrease of 11.2% in the HP flow capacity and a decrease of 2.4% in HP efficiency as shown in Table 2. The change in efficiency resulted in the unit being opened up, and, as can be seen in Figures 9 and 10, the turbine had experienced serious foreign object damage.

Parameter Units Initial Data (A) Data Collected 20 Days Later (B)

Change from (A) to (B)

HP section flow capacity lb/hr 820831 728509 -11.2%IP section flow capacity lb/hr 908371 897614 -1.2%HP section efficiency % 82.6 80.5 -2.4%Corrected CRH pressure psia 386.26 349.57 -9.5%Corrected HRH pressure psia 369.86 333.83 -9.7%Test Throttle pressure psia 1795.9 1948.0 8.5%

Table 2. Summary of Performance Parameters and Related Changes

Figure 9. Stage 1 Bucket Damage Figure 10. Stage 1 Nozzle Damage

General Electric CompanyOne River Road, Schenectady, NY 12345518 • 385 •2211 TX: 145354

GE Power Systems

gek41745 - cleaning of main steam piping for combined cycle plant

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