Air cooled condenser and non performance

March 13, 2012

REPORT ON INSPECTION AND PERFORMANCE OF AIR COOLED CONDENSER OF 35 MW UNIT AT JAI BALAJI, DURGAPUR

By K.K.Parthiban, Venus Energy Audit System

The visit was made to study the Air cooled condenser unit of 35 MW. The thermograph study was done by our engineer Mr.Muthukumar on 5th March 2012. The temperatures readings were taken at drain pipes and at the surface of ACC outer tube bundles. The data are presented in annexure 3. The velocity measurement was done for all fans at 25 MW and 35 MW unit. The report on air flow calculated is enclosed in annexure 2. The observations and suggestions are furnished in annexure 1. The plant was stopped on 8th March 2012 to check the air cooled condenser inside. The inspection was made inside and the findings are covered in annexure 1. An action plan was given during the visit, which is necessary to improve the ACC performance.

AGENDA

The ACC of 35 MW unit was experiencing cold often. This was found out by plant staff. The ACC was supplied by Paharpur cooling tower. The problem was pending since long. The problem is to be resolved to make all the modules hot.

ACTION PLAN

There were many observations made by us during operation and shut down, which could drastically affect the overall performance of the ACC. A list was given immediately to plant engineers. These are time taking actions. It is learnt that some works are still to be completed in the ensuing shut down in May 2012 end.

A. Free air & proper air circulation

1. ACC air inlet area to be cleared by 15 metres all around. 2. ACC bottom area to be cleared of all materials so that the air suction is available. 3. ACC bottom water sump is required for ensuring minimum dust infiltration in to the ACC. It also

helps to drop the air temperature. It shall be preferable with flow of water. RO reject water can be used here before taking to sponge iron plant. A sump and pump system shall be arranged so that there is continuous flow of water so that there is no mud formation.

4. Floor grill at motor access area can be kept minimum so that air intake area is increased. An approach ladder can be readily fitted when required. This would help in allowing more air in to ACC.

5. Floor to ACC ribbed plate sealing is required. Ribbed plate to plate joint shall be fitted asbestoes felt sealing as done in roofing sheets.

6. Casing to ribbed sheet openings shall be filled with insulation wool and be plastered to ensure no air comes out from ACC inside.

7. Casing to casing joint shall be 100% seal welded. If required flats / filler rods can be added. 8. ACC bundles to supporting structure shall be sealed from inside using asbestoes felt. Shellac

shall be liberally used to ensure the asbestoes felt stays inside. 9. The slot holes in the bundle frame are not used at the moment. They shall be plugged with a

small plate. The ACC bundle shall not be welded to support as there will be relative thermal

expansion. 10. The side gap between the end casing and the end ACC blocks shall be fully closed using plate

and asbestoes felt. 11. ACC block to block gap shall be closed with a plate at top ends where there is no support frame.

Light could be seen at the top. See photograph in annexure 1. 12. All doors shall be made leak proof so that ACC fan air would not leak out. 13. The door shall be repaired where the hinge got broken. 14. Floor grills above the ACC fan shall be stacked above the hub area in each ACC section. This

will enable free air flow in ACC.

Cleaning of ACC tubes

1. Bottom headers of ACC blocks shall be provided with 40 nb drains with plugs at both ends. Each header shall be provided such plugs. This is required for flushing.

2. Water cleaning is suggested to remove loose iron oxide scales from inside of each ACC tube. The plugged tubes shall be made free. For inspection the drain header end shall be cut for inspection.

Condensate pH maintenance

1. The condensate pH shall be maintained at 9.5 to 9.6 pH. This is to avoid inside corrosion of ACC bundles.

Collecting header modification

1. The present collecting header is 150 nb per side of the ACC bundle. This has to be increased as the velocity works out to be 0.437 m/s. It is advised to split the present header in to two sections. The rear section shall be connected by another 150 nb pipe to the main pipe to condensate tank.

Ejector line equalizer valve operation

1. It is seen that that the ejector lines are connected to CST through a common header. Valves are available for isolation. During plant start up these valves can be opened as the vacuum is created b y using hogger ejector which is connected to CST tank. When the hogger ejector is closed, these valves are to be closed to avoid problem in air removal in inner section of each bundle.

DETAILED REPORT About the aircooled condenser The air cooled condenser of 35 MW unit and 25 MW unit are compared below. There is a design discrepancy on the air temperature and exhaust steam temperature. Parameter Unit 25 MW unit 35 MW unit Ambient air temperature Deg C 30 36 Condenser vacuum ata 0.13 0.22 Corresponding turbine steam exhaust Deg C 51 62

temperature Site elevation Metres above MSL 30 26.4 The ACC sizing is based on the air & steam temperatures. Hence there will be undersizing of surface area if lower ambient temperature is specfied. Higher the ambient air temperature, more will be the surface area required. It is learnt that the plant was under performing due to vapor locks inside the ACC. The supplier had suggested to increase the fan capacity. It was learnt that some of the drain hoses were replaced earlier. The 35 MW unit was stabilised in April 2010. So far the unit had barely touched 25 MW. pH for ACC The air cooled condenser tubes are made of carbon steel tubes. The condensate pH is maintained by dosing ammonia / morpholine / cyclohexylamine. These chemicals are volatile in nature. The travel with the steam and combine with condensate. That is how, the pH of the return condensate is close to that of feed water. Each chemical has a volatility ratio. When the condensation begins at top, the first condensate has low pH since the amount of chemical would be less due its volatility. As the condensation process is complete at bottom, the condensate pH would be 8.5 or more as per the chemical dosage practice. Since the pH is less in the upper part of ACC, corrosion products are generated. These can plug the drain plugs. This can be reason for poor heat transfer as well. We need to raise the pH and wait for the inside of ACC to become normal. This can take a month too. In annexure 4, an article is enclosed on the pH requirement at ACC. In annexure 1 the debris removed from ACC bottom header can be seen. In addition, the choking occuring at CEP confirms that the condition of ACC is not good. Preservation of ACC during off-line period The ACC duct at top was found to have corroded and generated flakes of rust. This happens due to presence of water in CST when the ACC is off line. The rust flakes are large enough to block the ACC tubes during the operation. These flakes could block the small bore condensate drain pipes provided at the bottom headers. The square headers can also accumulate the rust inside. There is no way it can be cleaned well. Drains plugs are required, so that water flushing can be attempted. During off line period, the CST tank must be left dry with trays of limestone for absorbing moisture. Rightly a dehumdification system is required for preserving ACC tubes. Compressed air can be used for filling the ACC and keep it pressurised at pressure, say, 50 mmWC. Design parameters of ACC The design parameters selected for ACC is very conservative. The vacuum selected is only 0.78 kg/cm2 (a) as against 0.80 kg/cm2 (a). The steam temperature is chosen as 62.4 deg C and ambient temperature is chosen as 36 deg C. Lesser the difference between the steam temperature and the air temperature, more will be the heating surface requirement. Ideally the selection should have been made for a condensate temperature of 56 deg C & ambient temperature of 40 deg C. Table 2 gives a comparison of a successfully operating 7.5 MW & 20 ACC with 35 MW ACC. We can see the sizing

impact. Also the 25 MW and 35 MW are compared and found to have an undersized HTA. Hence vaccum will be a problem at full load. Bundle arrangement In this unit it is seen that the four bundles have been packed one over other. The first bundle has high T over the outer bundle. The effectiveness of the HTA in a upper bundle, comes down as the air gets heated in the previous bundle. The fourth bundle effectiveness will be the least. This can affect the draining of condensate as the driving force - T will not be efficient. In most of the units, three bundles are used. Four bundles was a wrong choice. This must have been doen to avoid two additional cells. Draining arrangement In other installations the collecting header to common condensate header is thorugh a large drain. Here it is seen that the drain pipes are smaller. It is necessary to add two more collecting hoses, preferable at the ends. In addition the common condensate header pipe has to be made in two sections to reduce the water side velocity. Small cross sections are prone to vapor locks. Additional drain would be of use on this aspect. Ejector piping arrangement In other installations the air removal pipe size is larger. Larger diameter pipes will have less pressure drop. The velocity and pressure drop are calculated and presented in annexure 5. It is worth drawing the air from both front and rear side of ACC. At present each bundle in each module is having two tubes devoted to air removal. In other designs one section in the middle is is devoted for air removal. The pressure drop in these units are lesser. While using smaller pipes, we would have blockages due to offline corrosion. The material of construction for air handling pipe must be SS 304. This is due to oxygen & wet steam handled in this pipe. It is not clear what is the material used. Air lock / dirt lock in ACC bundles Thermograpy camera was used by us to find out stagnation of water in bundles. It was clear that the drains were getting choked up. It was not like some tubes in the bundle were cold and some were hot. Since the drain was choked up, the entire bundle were found cold. There was no case that the drain was clear and part of the bundle was cold. It is not a vapor lock in some bundles. It is a flow lock for all the tubes of the bundle. Ejector inter connection to common hogger The design of ACC is with separate ejectors for inner bundle, bundle 2, bundle 3 and bundle 4. All inner bundles would condense more steam due higher T. Thus more non condesible gases would be handled by the 65 nb ejector than the remaining 3 x 50 nb ejectors. The valves connecting to common hogger should be in closed condition so that the vacuum is better. This is an operational

modification. Leakage of ACC casing The air from the ACC fan leaks directly at the casing around the fan. There are several locations of leakages. Many leakages were attended in our engineers presence. The locations of air leakages are brought out in the annexure 1.

Free air & proper air circulation

The space below ACC was to be cleared first to ensure the air circulation is available. The status has to be checked now. ACTIONS RECOMMENDED / TAKEN AND THE RESULTS The common collecting header end plate was cut to inspect the presence of choking material. The

photograph in annexure 1 shows what was seen. The corrosion products were seen right below the drain connectiion at the common collecting header.

ACC tubes were inspected by going inside the inspection door at the top header. Bottom headers are too small such an internal inspection. Hence its condition is not known. The ACC tubes were undergoing corrosion. The tubes and ducts are compared with another installation in annexure 1. Looking at the blockage and loose material inside the ACC tubes, water flushing was taken up immediately. The water connection was made from the CEP and used for cleaning the inside tube of each bundle.

When the ACC was restarted after the shut down, the drains were getting choked again. Hence it was advised to use hogger ejector as often as required, to carryout dechoking on line. This had helped lot. It was learnt that the dechoking was almost complete after a month of this operation. CEP choking was indicating the corrosion product present in ACC.

CONCLUSION 1. The cause for cold ACC sections was identfied to be partly due to wrong pH regime. 2. The number of drains have to be increased at the drain header. As the drain header is small in

size, only increasing the number of drains is possible. 3. The ACC design basis was not correct. The high condensate temperature and low ambient

temperature has resulted in undersizing of the ACC. 4. The air circulation was checked with many materials inside the ACC space. Now it is learnt that

the ACC base is cleaned up. A revised study is required to find out improvement in airflow. Or else the air flow can be increased as proposed by supplier.

5. It is necessary to add cells for the shortfall. There are units where additional cells have been added. This is to be done after the completion of revised study after incorporation of additional drains and after modification of air ejector piping.

K.K.Parthiban

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ANNEXURE 1: PHOTOGRAPHS & COMMENTS

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Photo 01 & 02: These are the photographs showing the space below ACC. These obstructions for free air circulation should be removed immediately. There should be 15 m free spacing all around for free air circulation.

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Photo 03: These are the photos taken under the ACC fans. Due to this obstructions, the fan flow will not be uniform. This should be removed immediately.

Photo 04: There should have been 15 m free space all around. The ACC to TG building space is only 10 meters.

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Photo 05: At present there is no water sump under the ACC fans. Dust ingress to ACC can be reduced if a water sump is added. We can see the dust pick marks in the floor.

Photo 06: The water trap arrangement provided elsewhere under ACC. Garden water / cooling water to kiln can be routed through the water trough here. 200 mm height of water is recommended.

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Photo 07: The photograph showing the ribbed casing joint in ACC. Here the joint is not closed. Due to this air is leaking from this joint. This should be arrested by asbestos sealing as shown in the following photo. Also cement mortar sealing is required for ACC floor to ribbed sheet.

Photo 08: Hand sketch showing ribbed plate to plate joint by asbestoes felt with shellac.

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Photo 09: The photograph showing the gap found between the ribbed sheet and the casing. Due to this gap air is leaking from inside. This shall be arrested to in order to reduce the passing of air outside.

Photo 10: Hand sketch showing the casing to ribbed sheet gap filling detail. After the insulation is filled, plastering should be done above to ensure no air leakages.

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Photo 11: The photograph shows the incomplete sealing in the ACC casing. These shall be sealed as illustrated below.

Photo 12: Hand sketch showing casing to casing closing detail for ACC. Stitch welding is OK to arrest the leakage.

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Photo 13: The photograph the air leakage mechanism at ACC at ribbed casing.

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Photo 14: The ACC Inspection doors in between the ACC cells & outside should be in closed condition always. The leaky doors would over reduce the cooling capacity of ACC.

Photo 15: There is air leakage at the side casings to front & rear casing. These must be arrested.

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Photo 16 & 17: Light seen between the ACC modules. These must be plugged. The bundle casing to casing can be closed from inside only with an overlap plate.

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Photo 18 & 19: Photographs showing the debris generated by the ACC on wrong condensate chemistry. An article is enclosed informing the condensate pH monitoring.

Photo 20: Sealing required between the bundles. 75 mm wide x 4 mm thick overlapping plate shall be welded from inside. The light is visible from these joints when see from inside ACC.

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Photo 21: ACC duct showing the corrosion products generated during offline storage. Dehumidified air is to be circulated during offline storage. Even compressed air is adequate as it is moisture free. Large amount of lime can be kept inside the ACC duct and at CST.

Photo 22 & 23: The Photograph on left showing the general pH corrosion. Photograph on right shows the oxygen corrosion.

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Photo 24 & 25: The photographs show the corrosion of ACC tube. One tube is seen in plugged condition.

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Photo 26: Photograph shows the four rows of condenser tubes. This is not good. As the air becomes hotter from one stage to another, the heat transfer reduces. Thus the effectiveness of last row will be less due to high inlet air temperature. Generally only three tubes are arranged by many manufacturers.

Photo 27: Photograph showing the best ACC internals with very grey surface at inlet of the ACC tubes. In this plant the pH was raised to 9.6 -9.8 as per our recommendations and the iron in condensate was the same as that of the feed water.

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Photo 28: The Inside of ACC duct seen here. The rust flakes would travel to ACC tubes and end up plugging the 40 nb drain hoses provided.

Photo 29: Corrosion products collected at ACC duct. This is due to poor offline storage of ACC.

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Photo 30: The photograph shows the low pH corrosion of ACC duct. The surface is being continually etched.

Photo 31: The surface of ACC duct is seen with grey surface at another plant after the pH was raised to 9.6 to 9.8. This plant uses all volatile treatment, in which the filming amines do this job. About 30% of pH booster is admitted at turbine exhaust duct..

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Photo 33: The photograph showing awful condition of ACC tubes. The oxide scales reduce the heat transfer drastically. After adjusting the pH and on continuous running, we have to pull it out of the system. Water washing would help to a great extent. But high pressure water jetting is a must.

Photo 34: Debris collected at condensate pipe at ACC bottom. With this kind of continuous corrosion the life of the ACC would come down drastically.

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Photo 35: The drain size in other ACC units. Any scale will drop in to the condensate piping below.

Photo 36: The hoses are too small for the long header. There would not be proper draining of water from the headers. Each header shall be provided with two more drains at the ends.

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Photo 38: Air removal piping from bundles of modules. The air piping is now connected to front side. In order to gain some head the air piping can be taken from rear side also to the ejectors. It would reduce the pressure drop.

Photo 39: The photograph shows the additional valves added from each non condensable air piping. These valve should be in closed condition on regular operation.

ANNEXURE 2: AIR VELOCITY MEASUREMENT AT ACC FANS 35 MW & 25 MW

GENERAL METHOD

Air Velocity Measurement at 35MW & 25MW:

Notes:1.Thevelocityismeasuredfromthefanoutercasingring.2.Thedistancefromwhichvelocityismeasuredis200,600,2.Thedistancefromwhichvelocityismeasuredis200,600,1000&1400mm.3.Fourareawillbecalculatedwithrespecttofourvelocitynotedforeachquadrantoftotalfanarea.4.Flowratewillbecalculatedforeachareainthequadrant

depending upon the velocity obtained at the area Summingdependinguponthevelocityobtainedatthearea.Summingofflowinallfourquadrantsgivesthetotalflowofthefan.

Input: CurrentconsumptionofFans: Fanspeed:Area 35MW 25MW FanNo 35MW 25MW FanNo 35MW 25MW

Area1,m2 4.48 4.36 Fan#1,Amps 135 110 Fan#1 1480 1485 RpmArea2,m2 2.68 2.59 Fan#2,Amps 132 100 Fan#2 1490 1485 RpmArea3,m2 2.42 2.34 Fan#3,Amps 145 Fan#3 1430 1485 RpmArea4,m2 9.34 6 Fan#4,Amps 136 95 Fan#4 1490 1485 Rpm

Fan#5,Amps 130 100 Fan#5 1485 1485 RpmFan#6,Amps 135 100 Fan#6 1485 1485 RpmFan#6,Amps 135 100 Fan#6 1485 1485 Rpm

MEASUREMENT AT 35 MW

200 4 4.48 17.92600 4.5 2.68 12.061000 8.2 2.42 19.8441400 9.2 9.34 85.928

200 5.5 4.48 24.64600 6.4 2.68 17.1521000 7.2 2.42 17.4241400 8.1 9.34 75.654

200 4.5 4.48 20.16600 6.5 2.68 17.421000 8.2 2.42 19.8441400 8.5 9.34 79.39

200 5.5 4.48 24.64600 8.2 2.68 21.9761000 9.3 2.42 22.5061400 9.5 9.34 88.73

m3/s

200 4 4.48 17.92600 4 2.68 10.721000 7 2.42 16.941400 8 9.34 74.72

200 2.5 4.48 11.2600 4.8 2.68 12.8641000 7.5 2.42 18.151400 9.8 9.34 91.532

200 6.5 4.48 29.12600 6.8 2.68 18.2241000 8.1 2.42 19.6021400 9.5 9.34 88.73

200 7.5 4.48 33.6600 10 2.68 26.81000 11.1 2.42 26.8621400 10.8 9.34 100.872

m3/s

FanNo Quadrant Distanceatvelocitymeasured,mm

Velocity,m/s

Areaatvelocitymeasured,m2

Discharge,m3/s

DischargeofflowateachQuadrant

m3/s

m3/s

m3/s

m3/s

Total air flow from the Fan is 565.288

IV 157.852

Fan # 1

I 135.752

II 134.87

`III 136.814


Discharge,m3/s


155.676


m3/s

IV 188.134 m3/s

Fan # 2

I 120.3 m3/s

II 133.746 m3/s

`III


Velocity,m/s

AirvelocitymeasurementsinACCfans35MW

200 5 4.48 22.4600 7.8 2.68 20.9041000 8.5 2.42 20.571400 9.2 9.34 85.928

200 5 4.48 22.4600 6.1 2.68 16.3481000 7.3 2.42 17.6661400 8.5 9.34 79.39

200 5.5 4.48 24.64600 6.8 2.68 18.2241000 8 2.42 19.361400 9 9.34 84.06

200 5.8 4.48 25.984600 6.8 2.68 18.2241000 7.8 2.42 18.8761400 9.5 9.34 88.73

m3/s

200 3.4 4.48 15.232600 4.5 2.68 12.061000 8.2 2.42 19.8441400 9.5 9.34 88.73

200 2.5 4.48 11.2600 4.8 2.68 12.8641000 7.6 2.42 18.3921400 8.2 9.34 76.588

200 3.6 4.48 16.128600 3.4 2.68 9.1121000 6 2.42 14.521400 8.8 9.34 82.192

200 7.2 4.48 32.256600 8.5 2.68 22.781000 10.5 2.42 25.411400 10.6 9.34 99.004

m3/s


Velocity,m/s


Discharge,m3/s


Fan # 3

I 149.802 m3/s

IV 151.814 m3/s


II 135.804 m3/s

`III 146.284 m3/s


Velocity,m/s


Discharge,m3/s


121.952 m3/s

IV 179.45 m3/s

Fan # 4

I 135.866 m3/s

II 119.044 m3/s

`III


200 2.4 4.48 10.752600 4.2 2.68 11.2561000 7.5 2.42 18.151400 10.1 9.34 94.334

200 6.1 4.48 27.328600 9.3 2.68 24.9241000 8.3 2.42 20.0861400 8.6 9.34 80.324

200 6.5 4.48 29.12600 7.3 2.68 19.5641000 8.5 2.42 20.571400 9 9.34 84.06

200 4.2 4.48 18.816600 6.5 2.68 17.421000 8.5 2.42 20.571400 9.5 9.34 88.73

m3/s

200 2.5 4.48 11.2600 3.5 2.68 9.381000 7.8 2.42 18.8761400 9.5 9.34 88.73

200 3.8 4.48 17.024600 6.8 2.68 18.2241000 7.8 2.42 18.8761400 8.5 9.34 79.39

200 4.5 4.48 20.16600 6.4 2.68 17.1521000 8.5 2.42 20.571400 9.8 9.34 91.532

200 6.5 4.48 29.12600 10 2.68 26.81000 10.5 2.42 25.411400 10.6 9.34 99.004

m3/s

m3/s

m3/s

m3/s


Velocity,m/s


Discharge,m3/s


153.314 m3/s

IV 145.536 m3/s

Fan # 5

I 134.492 m3/s

II 152.662 m3/s

`III



Velocity,m/s


Discharge,m3/s


Fan # 6

I 128.186 m3/s

II 133.514 m3/s

Total air flow from all the ACC Fans at actual is 3480.612

Total air flow from all the ACC Fans as per Design is 3614

Shortage of air in the ACC fans is 133.388


`III 149.414 m3/s

IV 180.334 m3/s

MEASUREMENT AT 25 MW

200 9 4.36 39.24600 9.2 2.59 23.8281000 8.8 2.34 20.5921400 8.5 6 51

200 5 4.36 21.8600 5.3 2.59 13.7271000 6 2.34 14.041400 6.8 6 40.8

200 1.3 4.36 5.668600 2.5 2.59 6.4751000 6.2 2.34 14.5081400 7.8 6 46.8

200 6.2 4.36 27.032600 7.4 2.59 19.1661000 8.5 2.34 19.891400 9.8 6 58.8

m3/s

200 6.2 4.36 27.032600 7.5 2.59 19.4251000 7.6 2.34 17.7841400 7.6 6 45.6

200 2.5 4.36 10.9600 4.2 2.59 10.8781000 6.4 2.34 14.9761400 6.8 6 40.8

200 5.5 4.36 23.98600 6.2 2.59 16.0581000 7.5 2.34 17.551400 7.6 6 45.6

200 7.5 4.36 32.7600 7.6 2.59 19.6841000 8 2.34 18.721400 8.4 6 50.4

m3/s

AirvelocitymeasurementsinACCfans25MW


Velocity,m/s


Discharge,m3/s


73.451 m3/s

IV 124.888 m3/s

Fan # 1

I 134.66 m3/s

II 90.367 m3/s

`III



Velocity,m/s


Discharge,m3/s


Fan # 2

I 109.841 m3/s

II 77.554 m3/s


`III 103.188 m3/s

IV 121.504 m3/s

200 7.2 4.36 31.392600 7.8 2.59 20.2021000 8.2 2.34 19.1881400 8.6 6 51.6

200 6.5 4.36 28.34600 7.8 2.59 20.2021000 7.8 2.34 18.2521400 9 6 54

200 7.5 4.36 32.7600 8.4 2.59 21.7561000 9.3 2.34 21.7621400 9.2 6 55.2

200 5.4 4.36 23.544600 6.5 2.59 16.8351000 7.5 2.34 17.551400 8.5 6 51

m3/s

200 3.8 4.36 16.568600 5.5 2.59 14.2451000 7.6 2.34 17.7841400 8.2 6 49.2

200 5.5 4.36 23.98600 6.3 2.59 16.3171000 7.4 2.34 17.3161400 7.6 6 45.6

200 4.5 4.36 19.62600 6.5 2.59 16.8351000 8 2.34 18.721400 8.2 6 49.2

200 6.5 4.36 28.34600 7.2 2.59 18.6481000 8.5 2.34 19.891400 7.9 6 47.4

m3/s


Velocity,m/s


Discharge,m3/s


131.418 m3/s

IV 108.929 m3/s

Fan # 3

I 122.382 m3/s

II 120.794 m3/s

`III

Fan # 4

I 97.797 m3/s

II 103.213 m3/s



Velocity,m/s


`III 104.375 m3/s

IV 114.278 m3/s

Discharge,m3/s



200 4.5 4.36 19.62600 6.5 2.59 16.8351000 8.5 2.34 19.891400 7.6 6 45.6

200 7 4.36 30.52600 8.5 2.59 22.0151000 9 2.34 21.061400 9.2 6 55.2

200 3.3 4.36 14.388600 6.2 2.59 16.0581000 7.8 2.34 18.2521400 8 6 48

200 4.2 4.36 18.312600 6 2.59 15.541000 7.2 2.34 16.8481400 8.5 6 51

m3/s

200 2 4.36 8.72600 2.5 2.59 6.4751000 4.8 2.34 11.2321400 7.6 6 45.6

200 7.5 4.36 32.7600 8.2 2.59 21.2381000 8 2.34 18.721400 8.5 6 51

200 7.2 4.36 31.392600 8.5 2.59 22.0151000 8.6 2.34 20.1241400 8.3 6 49.8

200 5.5 4.36 23.98600 4.4 2.59 11.3961000 6.4 2.34 14.9761400 7.2 6 43.2

m3/s

m3/s

m3/s

m3/s


Velocity,m/s


Discharge,m3/s


96.698 m3/s

IV 101.7 m3/s

Fan # 5

I 101.945 m3/s

II 128.795 m3/s

`III



Velocity,m/s


Discharge,m3/s

`III 123.331 m3/s

IV 93.552 m3/s


Fan # 6

I 72.027 m3/s

II 123.658 m3/s

Total air flow from all the ACC Fans at actual is 2580.345

Shortage of air in the ACC fans is 237.655


Total air flow from all the ACC Fans as per Design is 2818

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ANNEXURE 3: THERMOGRAPH STUDY ON AIR COOLED CONDENSER OUTER BUNDLE. Date of test: 5th March 2012

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Photo 01: The hand sketch shows the arrangement of ACC of 35 MW as viewed from TG side. View AA shows at how many locations the thermograph reading is taken. Totally there are 9 bundles. In those 9 bundles 7 rows were divided equally and the temperature was measured. Therefore totally 63 locations the readings were taken and presented in other photographs.

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Photo 02: This hand sketch shows the view-BB. There are 4 sections for each bundle. Here individual drain pipe / pipes are given from the drain box to connect drain header. Here also the temperature is measured. At some places it was cold proving there was no condensate flow. Like this for 9 bundles (column wise) the temperatures were checked. Therefore totally 36 readings were noted. The inner sections are supposed to condense more. But there was no flow of condensate.

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Photo 03: This is the continuation of temperature values measured at individual drain hoses from drain boxes to common drain header. (Refer comment in photo: 02). From the readings we can observe that the ACC bundles on WHRB side alone are working completely. This may be due to better air availability for the 2-left side bundle.

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Photo 04: These were the surface temperature readings at 1-Right side wall of ACC. Refer photo: 01 for legend.

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Photo 05: These were the surface temperature readings at 1-Left side wall of ACC. Refer photo: 01 for sketch.

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Photo 06: These were the surface temperature readings at 2-Right side wall of ACC. Refer photo: 01 for sketch.

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Photo 07: These were the surface temperature readings at 2-Left side wall of ACC. Refer photo: 01 for sketch.

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Photo 08: The hand sketch showing the plan view of fan with its orientation as view from TG building front. At the time of test, the wind direction was from south-west.

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Photo 09: These were the photographs from IR camera. At some bottom rows of bundle it was cold in condition. The last two photos show the drain pipe stub to drain header. This means there is no flow of condensate downwards.

`

Photo 10 & 11: It was learnt that some of the pipes were changed due to air leakage. As the ACC is bottom supported, there is no need for flexible piping. We can add flexibility. The hose temperatures were measured by camera at the locations shown. As per the report, there was no flow in many drains. It is doubted that the stubs are choked due to ACC corrosion products. Had the line size was bigger as in other ACC units elsewhere, there would not be any choking. The inner most section of the bundle would collect more condensate. The outer most would collect less condensate due to hotter air.

ANNEXURE 4: ARTICLE ON AIR COOLED CONDENSER pH REQUIREMENT

264 PowerPlant Chemistry 2009, 11(5)

PPChem Assessing and Controlling Corrosion in Air-Cooled Condensers

2009 by PowerPlantChemistry GmbH. All rights reserved.

Assessing and Controlling Corrosion in Air-Cooled Condensers

ABSTRACT

An increasing number of air-cooled condensers (ACC) are being installed and operated on conventional and combinedcycle plants worldwide. Unless understood and corrected, the corrosion associated with the ACC ducts and tubeentries can become a major problem for operators of plant. Up to just a few years ago very little was known about thecorrosion/ flow-accelerated corrosion (FAC) process. This paper starts to rectify the situation with a description of thecorrosion/FAC process, a corrosion index and a relationship between the operating pH and the level of iron at the con-densate pump discharge.

R. Barry Dooley, J. Denis Aspden, Andrew G. Howell, and Francois du Preez

INTRODUCTION

Since the installation of the first small 1 MW dry coolingsystem in 1939, many hundreds of air-cooled condensers(ACC) have been erected worldwide. Corrosion of the car-bon steel components in these large systems has been aconcern because of the impact of high iron levels and airin-leakage [1]. The maximum corrosion has been observedat the entries to the A-frame ACC tubes. The mechanism ofthis corrosion is not fully understood and little work hasbeen expended in trying to rectify this. As far as theauthors know, only two ACC tubes have been removed formetallurgical examination. Based on these two analysesthe actual corrosion appears to be a flow-accelerated cor-rosion (FAC) derivative where local indigenous magnetite isremoved from the surface of the ACC tube leaving a veryintergranular surface appearance. Adjacent to these areaswhere the local turbulence of the two-phase media is notas great, the magnetite deposits on the surface. There areclear boundaries between the regions where corrosion/FAC takes place (white bare metal) and regions wheredeposition (black areas) occurs.

Figure 1 shows one of the two ACC tubes which have beensubjected to a metallurgical analysis. The low magnifica-tion photograph of the surface of the ACC tube near to thetube entry clearly shows the adjacent black and whiteareas. The other two parts of the figure show details of theblack areas, which are essentially deposited magnetite(upper part, left), and the white bare metal area, which hasan intergranular appearance (upper part, right).

These metallurgical analyses have provided the firstdetailed investigations of the interfacial science takingplace between the fluid and the ACC duct and tube sur-faces. It is anticipated that more tubes will become avail-able to assist in the development of a fuller understandingof the corrosion and deposition mechanisms. However, inthe interim operators of ACC need guidance in operationso that the corrosion/FAC can be minimized. This paper

describes two major steps which have been taken over thelast few years to quantify ACC damage: a) an index toassess the severity of the corrosion/FAC process through-out the ACC system from the steam turbine exhaust to thecollected condensate, and b) a relationship between thecycle chemistry (pH) and the level of corrosion/FAC.

A parallel paper [2] outlines an interim cycle chemistryguidance for ACCs developed for EPRI.

ACC CORROSION INDEX

After inspecting a number of ACCs around the world, twoof the authors developed an index for quantitatively defin-ing the internal corrosion status of an ACC. This is knownby the acronym DHACI (Dooley Howell ACC CorrosionIndex) [3,4]. The index separately describes the lower andupper sections of the ACC, according to the following:

Upper Section (upper duct/header, ACC A-frame tubeentries). Index: 1, 2, 3, 4 or 5. Examples are shown inFigure 2.

1. Tube entries in relatively good shape; possibly someareas with dark deposits in first few inches of tube inte-rior. No corrosion or FAC.

2. Various black/grey deposits on tube entries as well asflash rust areas, but no white bare metal areas. Minimalcorrosion/FAC.

3. Few white bare metal areas on a number of tube entries.Some black areas of deposit. Mild corrosion/FAC.

4. Serious white (bare metal) areas on/at numerous tubeentries. Extensive areas of black deposition adjacent towhite areas within tubes. Serious corrosion/FAC.

5. Most serious. Holes in the tubing or welding. Obviouscorrosion on many tube entries.

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265PowerPlant Chemistry 2009, 11(5)

PPChemAssessing and Controlling Corrosion in Air-Cooled Condensers

Lower Section (turbine exhaust, lower distribution duct,risers); rate A, B or C. Examples are shown in Figure 3.

A. Ducts have no indication of damage and are grey incolor.

B. Minor white (bare metal) areas on generally grey ducts.Some 'tiger striping' appearance with darker grey/black areas demonstrating two-phase flow-acceler-ated damage. Overall assessment is 'mild damage'.

C. Multiple, widespread areas of bare metal in the turbineexhaust and at abrupt changes in flow direction (e.g.where steam flow enters vertical riser from lower distri-bution duct). White (bare metal) areas are evident indi-cators of metal loss. Severe local damage exists.

The index provides a number (from 1 to 5) and a letter (fromA to C) to describe/rank an ACC following an inspection.For example, an Index of 3C would indicate mild corrosionat the tube entries, but extensive corrosion in the lowerducts.

The DHACI can be used to describe the status of a par-ticular ACC in terms of its corrosion history. A poor rating(e.g. 4B) indicates the need to consider options to reducethe corrosion rate, especially in the tube entry areas.

Additionally, the index provides a convenient tool for com-parison between different units. This can aid in determiningwhether some factor in effect at one station, e.g. use of anamine rather than ammonia, is yielding better results.

Finally, the DHACI is a very useful means of trackingchanges that occur as a result of making changes in steamcycle chemistry. A plant that has a relatively poor rating forcorrosion at a steam cycle pH of 8.58.8 (e.g. 4C) mayincrease the pH to 9.49.6 and determine whether thischange improves its rating (e.g. 3B). Similar tracking maybe done in association with mechanical or materialchanges, or with major shifts in operating pattern (cyclingvs. baseload operation).

DEVELOPMENT OF RELATIONSHIP BETWEEN pHAND CORROSION IN ACC AND THE RAMIFICA-TIONS FOR CONDENSATE POLISHING SYSTEMSAND THE USE OF AMINES

The current understanding of the mechanism associatedwith the corrosion of ACCs has been outlined in the introduction. Regardless of the mechanism itself bothchemistry data and visual evidence suggest that the pH

Figure 1:

Details from the examination of an ACC tube section withinabout 38 cm (15 in) from the tube entry in the upper duct. Thelower photograph shows the adjacent white and black areas onthe tube surface. The two upper parts of the figure show surfacemetallographs of the black area after cleaning of the surface (left)and white bare metal (right).

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environment plays a significant role in the corrosionprocess. Currently data is only available from organizationswhich employ ammonia as the feedwater conditioningchemical for pH control. It has also been discussed thatthe two-phase conditions present in the upper ducting ofthe ACC are likely to contribute to the corrosion process atthe tube entries.

In two-phase conditions ammonia much prefers thevapour phase over the liquid phase. Therefore in the liquiddroplets, associated with the first condensate, that comeinto contact with the ducts and condensing tube inletsthere is far less ammonia present than that originallyinjected into the condensate/feedwater of the plant. Notealso that some of the ammonia vapour will be removed inthe dephlegmator of the ACC. As a result, where these

Figure 2:

Montage illustrating DHACI indices 15 for the upper ducts andtube entries.

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liquid droplets come into contact with the ducts, in particu-lar the tube entries, the solution pH can be as much as1 pH unit lower than the condensate/feedwater pH at25 C (77 F). This has been confirmed by measurement[5]. More importantly the differential between the solutionpH and the neutral pH (at temperature) is significantlyreduced. With this reduction in alkalinity and under theinfluence of locally increased turbulence, iron oxide (mag-netite) dissolution is increased.

Increasing the ammonia concentration in the condensate/feedwater of the plant will increase the first condensate pHof the droplets and thus reduce the oxide solubility.However, because of the effect of the reducing basicity ofammonia with increasing temperature and the preferentialvapour phase distribution of ammonia, a great deal moreammonia has to be added.

Data gathered from several organizations around the worldhas resulted in the development of the Dooley/Aspdenrelationship for Fe in the condensate at the condensatepump and pH associated with units having ACC [3]. This isillustrated in Figure 4, which also shows the correspondingcurve for magnetite solubility extracted from Sturla's mag-

netite solubility data [6] at 50 C (120 F). The steam/con-densate temperature throughout the ACC is for all practicalpurposes constant since the ACC only rejects the latentheat in the exhaust steam. The steam temperaturedepends on the ambient temperature and the design of theACC. The minimum and maximum design steam tempera-tures, and thus the steam temperature at the tube entries,are usually between 45 and 80 C. So the 50 C used inFigure 4 is near the lower end of the scale, but the solubil-ity of magnetite varies very little up to 80 C.

The band in Figure 4 is about 5 g kg1 wide to allow foruncertainty associated with the data from many organiza-tions, but does have a strong track record around the worldfor units with ACCs using only ammonia conditioning forpH control. The relationship shows that these plantsrequire a condensate/feedwater pH of at least 9.8 toachieve acceptably low iron levels at the condensate pumpdischarge. Alternatively, operating at the normal pH rangeassociated with normal oxygenated treatment of between8.0 to 9.0 would be absolutely disastrous for the ACC ashas been illustrated [7,8]; high levels of corrosion will ensueat the tube entries and failures in the ACC can beexpected. The high levels of iron will also completely over-

Figure 3:

Montage illustrating DHACI indices AC for the lower ducts fromthe steam turbine to the vertical risers to the upper duct.

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whelm the filtration capability of condensatepolishers (where fitted) resulting in short resinruns due to differential pressure limits and sig-nificant deposition in boiler or HRSG tubes.

Figure 4 also shows the solubility of magnetiteextracted from Sturla [6] at the approximatetemperature of the tube entries of an ACC(50 C (120 F)). The practical corrosion curvein the figure is elevated above this normallyaccepted magnetite solubility relationship bysome considerable amount and shows forinstance that at pH of 8.8 the ACC relationshipis higher by 4050 g kg1 and at pH of 9.2 itis higher by about 30 g kg1. Only at pH of9.8 and above do the curves become conver-gent. This suggests that the corrosion processat the lower pH range is faster or more aggres-sive than a normal classical two-phase FACprocess [9] which may relate to the severe tur-bulence created by the tube entries.

From the parallel field of nuclear plant two-phase FAC, Table 1 illustrates the calculatedeffect of the different regimes on the liquid filmpH under conditions approximating those ofthe condensate droplets in the ACC ducting.

What is evident from the table is that when a plant is usingconventional oxygenated treatment (OT) at pH 8.5 thedelta pH, the pH at solution temperature neutral pH (lastcolumn), is only 0.26. It has been established by workers inthe nuclear industry that a minimum delta pH of 1 unit (atsolution temperature) is required to mitigate two-phaseFAC. The table shows that to achieve this, the conden-sate/feedwater pH needs to be close to 9.8, which sup-ports the Dooley/Aspden relationship shown in Figure 4.

CONDENSATE POLISHING

Where condensate polishing is fitted, these high levels ofammonia that are required to protect the ACC present asignificant challenge. Where polishers are employed they

are usually of the deep mixed-bed variety, which aredesigned for hydrogen form operation. This means thatunder these high pH conditions the operating cycles willbe 2 to 3 days due to ammonium loading. The regenera-tion turnaround and effluent production make this mode ofoperation extremely difficult and costly.

Ammonium form operation of mixed beds is an option [11]but presents significant challenges regarding polishedwater quality at these high pH values.

At least one utility has approached this problem by equip-ping the ACC units with deep bed polishers using separatecation and anion vessels. This makes ammonium formoperation quite simple and the required water quality isreadily achieved. Capital costs are higher but the opera-

Figure 4:

Iron levels measured at condensate pump discharge on units with ACC andonly using ammonia for pH control. The iron solubility data which is extractedfrom Sturla [6] at 50 C is shown only as an example as actual operatingtemperatures at the ACC tube entries may be higher, as discussed in the text.

Ammonia concentration

Treatment regime Condensate Condensate Condensing steam Liquid phase

Liquid phase Vapour phase

pH (25 C) pH* g L1 Molal g L1 Molal g L1 Molal pH (c) pH**

OT 8.5 1.5 64 3.765 106 0.31 1.804 108 63.7 3.747 106 6.18 0.26

High pH OT 9.8 2.8 5 018 2.952 104 7.02 4.129 107 5 012 2.948 104 7.05 1.13

Table 1:

Calculations showing ammonia concentrations and delta pH for early condensate [10].

pH (25 C) = pH measured at the reference temperature of 25 C

pH* = difference between pH (25 C) and the neutral pH (25 C)pH** = difference between pH at temperature and neutral pH at temperature

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tional costs are very attractive with cycles of 60 days ormore being the norm.

Powdered resin filtration systems also offer some benefitsbut the limited ion exchange capacity may deter someusers, particularly if operation at high pH (ammonium form)is desired.

The use of an amine injected into the crossover steampipes (superheated steam) between the intermediate pres-sure (IP) and low pressure (LP) turbines is another avenuewhich could be considered. A relatively low concentrationof an amine such as ethanolamine (ETA) or dimethylamine(DMA) would be required to achieve the required delta pHof > 1 unit (64 g kg1 ammonia for feedwater pH 8.5 and100 g kg1 ETA). This would allow for reasonable andacceptable polishing cycles to be achieved with hydrogenform polishing. The injection of ammonia downstream ofthe polishers to achieve a feedwater pH of 8.5 would sat-isfy OT requirements. The removal of all the amine on thepolishers would therefore retain the cation conductivity asa core measurement parameter. The authors are not awareof any organization using this technique and it would needto be evaluated to ensure that the correct mixing in super-heated steam can be achieved and that the amine will notdegrade in the short residence time at IP turbine outlettemperatures around 380 C (716 F). Also, although anumber of combined cycle units with ACC are usingamines and blends of amines including ETA, there is insuf-ficient data at this time to superimpose another curve onthe Dooley/Aspden relationship (Figure 4).

PRACTICAL CASE STUDY OF CORROSION IN ANACC

Numerous internal inspections have been performed onthe ACC ducts at Eskom's Matimba Power Station in

South Africa. The station (Figure 5) consists of 6 coal-firedunits with a gross generating capacity of 665 MW each.The first unit at Matimba was commissioned in 1987 andthe last unit went into commercial operation in 1991.

The station was commissioned using an all-volatile treat-ment chemistry, AVT(R). The condensate pH ranged from9.29.4 during the first few years of operation. A decisionwas made in the late 1990s to increase the steam/watercycle pH to 9.7 to help reduce the severe corrosion thatwas seen in the ACC ducts. Due to problems experiencedin early 2000 with condensate polishing plant (CPP) resincross contamination and early chloride leakages when thepolisher resins were at the end of life, the steam cycle pHwas controlled between 9.49.6 to help minimize the chlo-ride leakage from the CPP [5].

The Matimba ACC exhaust ducts consist of rather com-plex arrangements of vertical and horizontal duct sectionsconnected by a series of 90 bends, which in most casesare fitted with guide vanes to minimize the steam sidepressure drop. Figures 6 and 7 illustrate the side and frontviews of the ACC duct arrangement to convey the exhauststeam from the LP turbine exhaust to the condensing ele-ments.

The two LP turbine exhausts are downward facing and thefirst vertical duct section (only one V1 is shown in Figure 6)is designed as a transition piece from a rectangular to a5 m (16.4 ft) diameter round steam duct. The first guidevane bend connected to the transition piece diverts thesteam in the horizontal direction (H1). After penetrating theturbine house wall another guide vane bend turns thesteam direction in the vertical direction. Two vertical risers(only one V2 is shown in Figures 6 and 7) convey the steamupwards to an elevation of 30 m (98.4 ft) above the zerometer level, where the flow is distributed by two horizontaldistribution pipes (only one H2 is shown in Figure 7) to 8risers (4 risers per side) (V3) of 2.5 m (8.2 ft) diameter each,

Figure 5:

Aerial view of the MatimbaPower Plant showing theACC at the front of thepower plant.

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PPChem

which convey the steam to the inlet of the condensing ele-ments (H3) at an elevation of 56 m (184 ft) above the localzero level.

Depending on the ambient temperature, the design LP tur-bine exhaust pressure (absolute) varies from a minimumvalue of 11.5 kPa (1.66 psia) at minimum ambient tempera-ture to a maximum value of 46.5 kPa (6.7 psia) in summer.Due to the corresponding variation in the specific volumeof the exhaust steam, the average steam velocity in theducts varies approximately between 35 m s1 and120 m s1 (114 and 393 ft s1) at the maximum and mini-mum exhaust pressure respectively. At the weightedannual average exhaust pressure of 19.8 kPa (absolute)(2.87 psia), the average steam velocity is 76 m s1

(249 ft s1) with a moisture content of 5.4 %.

Condensation of the exhaust steam occurs in bundles offinned heat exchanger tubes. The latter is characterized byrectangular fins fitted mechanically on an elliptical tubecore as shown in Figure 8. A corrosion resistant bondbetween the fin root and tube is achieved by hot dippedgalvanizing of the fin/tube. Heat exchanger bundles areconstructed by arranging two tube rows in the air flowdirection (A-frame). 48 axial flow fans per turbine unit of9.1 m (29.8 ft) diameter each driven by a 270 kW electricmotor force ambient air through the finned tubes as cool-ing medium.

Internal inspections of the Matimba exhaust ducts andsteam headers during outages revealed areas with corro-

sion/FAC and a corresponding loss of material. The exactdamage mechanism was not fully understood initially. Atthe time when the corrosion was first observed, a numberof actions were identified to obtain more information for a


Figure 6:

Side view of the Matimba ACC ducts. Duct V1 takes the two-phase steam mixture from the steam turbine. V1, V2, V3, and H1 are con-sidered to be the lower ducting of the ACC in the DHACI nomenclature. H3 and the ACC tube entries are considered to be the uppersections of the ACC.

Figure 7:

Front view of the Matimba ACC ducts. H2, V2 and V3 are con-sidered to be the lower ducting of the ACC in the DHACI nomen-clature. H3 (above the A-frames) and the ACC tube entries areconsidered to be the upper sections of the ACC.

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PPChem

better understanding and to help mitigate the corrosion/FAC mechanism. Among these options, cycle chemistrychanges were made as discussed above as well as apply-ing wear resistant protective coatings.

Based on the various internal duct inspections conductedon the different Matimba units, it was evident that the liquidphase in the turbine exhaust steam had a significant effecton the corrosion pattern in the ducts. In areas were liquidaccumulates significantly more corrosion was observedcompared to areas exposed to dry saturated steam. As aresult of the relatively high average steam velocity and thecentrifugal forces exerted on the two-phase flow by theguided bends, the free water droplets in the exhaust steamaccumulate and become separated from the steam [5].

The DHACI was used as a quantitative measure to definethe internal corrosion status of the steam ducts and head-ers of the ACC. In the following examples the application ofthe Index is illustrated and used to quantify the benefit thatthe cycle chemistry changes had on the corrosion status.

Of immediate concern during the initial Matimba inspec-tions was the perforation of the relatively thin wall, 1.5 mm(0.059 in), of the elliptical fin tube at the tube entry. Anyperforations would result in an air leak into the vacuumspace with an adverse effect on condenser performance.Figure 9 shows a perforation in a tube entry surrounded bya large white corroded area. This white area is the same asthe "bare metal areas" described in the introduction and isshown in more detail in Figure 1.

Figure 10 shows patches of white corroded areas in anumber of tube entries in a location of high liquid concen-tration caused by the two drain holes in the channel imme-diately above the tube entries. These white areas have

been described in the introduction and are shown inFigure 1. The surrounding dark grey areas are the same asthe black deposited areas also described in relation toFigure 1.

Whilst the desired pH for operation at Matimba PowerStation was 9.8 for the protection of the ACC, there was aperiod of operation when the pH had to be reduced to 9.4because of problems related to the ability of the conden-sate polishing plant to operate in the ammonium form. Thislasted for approximately two years and the resulting dam-age to the ACC is evident in Figures 9 and 10. Tube entries,rated at DHACI 1, with no visible white bare metal areas(FAC) are shown in Figure 11, which illustrates the improve-ment when a plant is operated at a pH of 9.8. Such signifi-cant improvements can occur in approximately two years.

Corrosion of the exhaust (lower) ducts should generally notcompromise the overall integrity of the ducts or vacuum


Figure 8:

Matimba ACC heat exchanger tube. The tubes are 9.5 m (31.7 ft)long. The rectangular fin dimensions are 120 and 50 mm (4.7 and1.96 in).

Figure 9:

Through-wall penetration of the tube wall immediately below theseal weld at the tube entry. Also note the loss in material of theseal weld. This is recorded as DHACI 5.

Figure 10:

White bare metal areas at a number of tube entries which are im-mediately below a drain hole in a channel on the duct surface.This is recorded as DHACI 3.

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boundary of the ACC but will contribute to the iron trans-port in the condensate. However, in localized areas signifi-cant material loss can be experienced, generally in areas ofhighly disturbed flow or high liquid phase concentration.An example of such an area in the lower ducting, immedi-ately downstream of the trailing edge of a guide vane in abend, is shown in Figure 12. The figure shows a corrodedarea where material loss of about 3 mm (0.117 in) is experi-enced after a total exposure of 146 000 operating hours.

The corrosion in Figure 12 is an exception, and generallyminor wall loss is associated with the corroded areas. Suchan example is given in Figure 13, which shows some 'tigerstriping' appearance with darker grey/black areas demon-strating two-phase flow-accelerated damage.

A detailed internal ACC duct inspection was performed onMatimba Unit 5 in September 2008. A definite improve-ment in duct appearance was observed in the steam flowdirection, i.e. fewer white bare metal areas were observedwith increasing distance from the LP turbine exhaustflange. In Table 2, a qualitative comparison is shown

between the appearances of the different duct sections asidentified in Figures 6 and 7. The improvement (lower cor-rosion/FAC areas) was due to the return to pH 9.8 and theassociated "self repair" which took place.

Figure 11:

Well-protected tube entries with no white bare metal areas and awell passivated red duct surface in an ACC operating with a pHbetween 9.6 and 10. This is recorded as DHACI 1.

Figure 12:

Localized area of significant wall loss in the lower exhaust duct.DHACI C.

Figure 13:

Minor bare metal (white) areas on black background as observedin the duct section H1 (see Figure 6). DHACI B.

Duct section (Figures 6 and 7) % red area % black area % bare metal (white)

V1 0 95 5

H1 40 50 10*

V2 60 40 < 1

H2 70 30 < 1

V3 75 25 < 1

H3 85 15 < 1

Table 2:

Duct appearance of Unit 5.

* The majority of the bare metal areas are caused by the LP bypass dump diffusers which are located inside duct section H1.

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The effect of the moisture content in the exhaust steam iswell illustrated in Figure 14, which shows the branch H2-V3. On the downstream side of the branch a large baremetal area is visible with patches of flash rust, while therest of the branch circumference is well protected with astable oxide layer. Due to centrifugal action the free mois-ture in the exhaust steam impinges on the downstreamside of the branch, resulting in the corrosion pattern shownin the figure.

CONCLUDING REMARKS

By examination of only two tubes worldwide the authorshave started to understand the corrosion processes inACCs. Based on this it has been possible to develop twotools for operators to use in assessing the condition ofACCs. The first, a corrosion index, DHACI, allows the op-erators to assess corrosion/FAC on a common basis andto monitor changes in corrosion as a result of chemistry orcoating changes. The second, the Dooley/Aspden relation-ship between corrosion/FAC and pH in the cycle, clearlyshows the importance of pH adjustment in optimizing theiron levels in the cycle.

REFERENCES

[1] Howell, A. G., Pritekel, R. J., Dooley, R. B.,PowerPlant Chemistry 2007, 9(5), 270.

[2] Dooley, R. B., Shields, K. J., Shulder, S. J, Aspden, D.A., DuPreez, F., Howell, A. G., Mathews, J., EPRI'sGuideline on ACC, To be presented at the EPRIInternational Conference on Cycle Chemistry, Bos-ton, MA, U.S.A., June 2009.

[3] Dooley, R. B., Aspden, D. A., Proc., Air-Cooled Con-denser Workshop, 2008 (Sunshine Coast, Queens-land, Australia).

[4] ACC Interest Group of the Power Plant and Environ-mental Chemistry Research (PPEC) Group of ASME,Interim Guidelines for Off-Line Inspection of Air-Cooled Condensers, To be published April 2009.

[5] Phala, S., Aspden, D., DuPreez, F., Goldschagg, H.,Northcott, K., Proc., API Power Chemistry Con-ference, 2008 (Sunshine Coast, Queensland, Aus-tralia).

[6] Sturla, P., Proc., Fifth National Feedwater Con-ference, 1973 (Prague, Czech Rebublic).

[7] Prust, A., PowerPlant Chemistry 2008, 10(6), 393.

[8] Richardson, I., PowerPlant Chemistry 2008, 10(7),393.

[9] Dooley, R. B., PowerPlant Chemistry 2008, 10(2).

[10] Galt, K. J., Private communication to D. Aspden,2009.

[11] Sadler, M. A., PowerPlant Chemistry 2001, 3(10), 559.

Figure 14:

Corrosion pattern in branch H2-V3 (Figure 7). DHACI C.

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THE AUTHORS

R. Barry Dooley (B.S. with first class honors, Metallurgy,Ph.D., Metallurgy, both from University of Liverpool, UK,D.Sc., Moscow Power Institute, Moscow, Russia) is aSenior Associate with Structural Integrity Associates.Before joining Structural Integrity Associates he was aTechnical Executive, Materials and Chemistry, at theElectric Power Research Institute (EPRI) in Charlotte, NorthCarolina, where he managed the Cycle Chemistry, HRSG,and Materials Programs, as well as the Boiler Tube FailureReduction/Cycle Chemistry Improvement and FAC Pro-grams. Before joining EPRI in 1984, Barry Dooley spentnine years with Ontario Hydro in Toronto, Canada. From1972 to 1975, he was a research officer in the MaterialsDivision of the Central Electricity Research Laboratories(CERL) of the former Central Electricity Generating Board(CEGB) at Leatherhead, Surrey, England.

Barry Dooley is the author or coauthor of over 260 papersand the editor of 14 international conference proceedings,primarily in the areas of metallurgy, power generation,boiler tube failures, HRSG tube failures, cycle chemistry,and life extension and assessment of fossil plants. He is thecoauthor of a three-volume book on boiler tube failures, atwo-volume book on steam turbine damage mechanisms,and a book on flow-accelerated corrosion in power plants.Barry Dooley is the executive secretary of the InternationalAssociation for the Properties of Water and Steam(IAPWS). He was awarded an Honorary D.Sc. from theMoscow Power Institute in 2002.

Denis Aspden (National Diploma, Chemistry, M.S., Engi-neering Management, University of Pretoria, South Africa)has more than 40 years of experience in power plantchemistry and is now an independent consultant.

Andrew G. Howell (M.S., Chemistry, University of Mis-souri, Columbia, MO, U.S.A.) has worked for Xcel Energyand its predecessors since 1982. He has worked in theanalytical laboratory, including laboratory and field investi-gation of power system component failures due to corro-sion, and currently provides support for Xcel Energy'spower stations as a 'hands-on' consultant.

Abraham Francois du Preez (Ph.D., Mechanical Engi-neering, University of Stellenbosch, South Africa) joinedEskom, the electric power utility in South Africa, in 1994,where he has gained maintenance and operational experi-ence on dry cooling systems, including air-cooled con-densers. As the responsible engineer he provides design,operational and maintenance technical advisory and sup-port service to power stations for condensers and coolingsystems. His recent work includes the specification for theair-cooled condensers for the 6x800 MW Medupi powerstation, which is currently under construction.

CONTACT

Barry Dooley PhD., DSc.Senior AssociateStructural Integrity Associates, Inc.2616 Chelsea DriveCharlotte, NC 28209USA

E-mail: [email protected]

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ANNEXURE 5: PRESSURE DROP IN EJECTOR AIR PIPING

Specificvolumeofsteam m3/kg 6.913Densityofairatcondenserpressure&temp kg/m3 0.2273Specificvolumeofairatcondenserpressure m3/kg 4.399

Suckedsteamflow kg/h 20.4Expectedairflow kg/h 9.2

PRESSUREDROPCALCULATIONFOREJECTORPIPING

p g/Air+Steamflow' kg/h 29.6Specificvolumeofmixture m3/kg 6.132

Mixtureflowrate m3/s 0.050Steamairflowrateinonetubeofabundle m3/s 0.0007003Steamairflowrateinonetubeofabundle kg/h 0.4111111Tubediameter mm 32Tubethickness mm 2Tubeflowarea m2 0.0006158Velocityinthetube m/s 1.1372285Tubelength m 10.5

Lossnode12 mmWC 0.14Lossnode23 mmWC 0.001Loss node 3 4 mmWC 0 004Lossnode34 mmWC 0.004Lossnode45 mmWC 0.005Lossnode56 mmWC 0.015Lossnode67 mmWC 0.013Lossnode78 mmWC 0.013Lossnode89 mmWC 0.026Lossnode910 mmWC 0.058Lossnode1011 mmWC 0.043Lossnode1112 mmWC 0.091Lossnode1213 mmWC 0.064Lossnode1314 mmWC 0.131Lossnode1415 mmWC 0.089Lossnode1516 mmWC 0.178Loss node 16 17 mmWC 0.118Lossnode16 17 mmWC 0.118Lossnode1718 mmWC 0.233Lossnode1819 mmWC 0.152Lossnode1920 mmWC 0.525Lossnode2021 mmWC 2.818Lossnode2122 mmWC 21.809

T t l d i j t i i WC 26 526Totalpressuredropinejectorpiping mmWC 26.526

ANNEXURE 6 DESIGN COMPARISON OF ACC WITH FEW OTHER PLANTS

Birlawhite Jaibalaji Jaibalaji Commentreqd Design

7.5MW 35MW 35MWSteamflow kg/h 31000 115000 115000Condenser pressure kg/cm2 a 0 18 0 18 0 22

TABLE2:COMPARISONOFACCDESIGNDATA&HEATINGSURFACEDESIGNCOMPARISONBETWEENBIRLAWHITE7.5MW&JAIBALAJI35MW

Condenserpressure kg/cm2a 0.18 0.18 0.22Condensatetemperature degC 57.4 57.4 62.4Designambienttemperature degC 40 40 36

Heatduty kcal/h 16649100 77695800 58346000Finnedheatingsurfacearea m2 76622.3 357571 134629 HTAislessby62.35%Fandiameter ft 28 32.8Fan rpm rpm 118 114Fanrpm rpm 118 114Nooffans no 3 6Fanairflow kg/h 5463370 25495727 14600000 flowislessby42.74%

Jaibalaji Jaibalaji Jaibalaji CommentDesign reqd Design25MW 35Mw 35MW

DESIGNCOMPARISIONBETWEENTHEJAIBALAJI25MW&JAIBALAJI35MWUNIT

Steamflow kg/h 77010 115000 115000Condenserpressure kg/cm2a 0.22 0.22 0.22Condensatetemperature degC 62 62 62.4Designambienttemperature degC 40 40 36

Heatduty kcal/h 39361120 58346000 58346000Finnedheatingsurfacearea m2 113473 158862 134629 HTAislessby15.25%Fandiameter ft 32.0 32 32.8Fanrpm rpm 114 114 114Nooffans no 6 6 6Fanairflow kg/h 11222566 15711592 14600000 flowislessby7.07%

SSIL Jaibalaji Jaibalaji CommentDESIGNCOMPARISIONBETWEENSSIL20MW&JAIBALAJI35MWUNIT

j jDesign reqd Design20MW 35Mw 35MW

Steamflow kg/h 115000 115000Condenserpressure kg/cm2a 0.2 0.22 0.22Condensatetemperature degC 62 62.4Designambienttemperature degC 42 40 36

Heatduty kcal/h 39738000 58346000 58346000Finnedheatingsurfacearea m2 151446 265031 134629 HTAislessby49.2%

Fandiameter ft 30.0 32 32.8Fanrpm rpm 0 114 114Nooffans no 6 6 6F i fl k /h 13280865 18593211 14600000 fl i l b 21 48%Fanairflow kg/h 13280865 18593211 14600000 flowislessby21.48%

ANNEXURE 7 CONDENSATE CHEMISTRY CHANGE

17/3/2012Conduct Silica Iron Turbiditys/cm ppm ppb NTU

Unit#1 8.9 9.5 0.014 30 0.26Unit#2 9.2 9.4 0.015 30 0.29Unit#3 9.1 9.4 0.019 80 0.8816/3/2012

Conduct Silica Iron Turbiditys/cm ppm ppb NTU

Unit#3 8.89 9.4 0.018 180 2.1115/3/2012

Conduct Silica Iron Turbiditys/cm ppm ppb NTU

Unit#1 10.27 9.6 0.016 30 0.21Unit#2 9.87 9.5 0.015 30 0.24Unit#3 10.39 9.6 0.016 320 4.1

Condensatewater

AftertheriseofpHatatACCcondensate,theironcontentrisedatcondensate.Chokingofstrainerswasexperiencedinitially.LaterittaperedoffindicatingthecleaningoftheACC.

UnitNo Description PH


Table1:Condensatechemistryreport


Condensatewater

ANNEXURE 8 EFFECT OF VACUUM ON ACC CONDENSATE CHEMISTRY CHANGE

main report.pdfAnnexure 1- Photographs and commentsAnnexure 2- Air flow measurement report of ACC 35 MW & 25 MWAir flow at ACC.pdfAir velocity study of ACC fans 2.pdfAir velocity study of ACC fans 3.pdfAir velocity study of ACC fans 4.pdf

Annexure 3 - Thermography study before modificationAnnexure 4- Article on pH requirement for ACC unitsAnnexure 4- Article on air cooled condenser pH requirement.pdfassessing and controlling ACC corrosion.pdf

Annexure 5- Pressure drop in ejector steam air pipingDocument1.pdfEjector pressure drop.pdfAnnexure 5- Pressure drop in ejector air piping.pdf

Annexure 6- Comparion of heat duty and heating surface of ACC with other unitsDocumenE1.pdfAnnexure 6.pdf

Annexure 7- condensate chemistry changeDocument1.pdfTable 1 -Condensate chemsitry change.pdf

Annexure 8- Effect of condensate chemsitry on vacuumDocument1.pdfFull page photo.pdf

Documents

Air cooled condenser and non performance