WO1998028231A1 - FEEDWATER pH CONTROL FOR STEAM GENERATORS - Google Patents

FEEDWATER pH CONTROL FOR STEAM GENERATORS Download PDF

Info

Publication number
WO1998028231A1
WO1998028231A1 PCT/US1997/021877 US9721877W WO9828231A1 WO 1998028231 A1 WO1998028231 A1 WO 1998028231A1 US 9721877 W US9721877 W US 9721877W WO 9828231 A1 WO9828231 A1 WO 9828231A1
Authority
WO
WIPO (PCT)
Prior art keywords
feedwater
steam
steam generator
phosphate
drum
Prior art date
Application number
PCT/US1997/021877
Other languages
French (fr)
Inventor
Frank Gabrielli
Original Assignee
Combustion Engineering, Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Combustion Engineering, Inc. filed Critical Combustion Engineering, Inc.
Priority to AU78725/98A priority Critical patent/AU7872598A/en
Publication of WO1998028231A1 publication Critical patent/WO1998028231A1/en

Links

Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22D—PREHEATING, OR ACCUMULATING PREHEATED, FEED-WATER FOR STEAM GENERATION; FEED-WATER SUPPLY FOR STEAM GENERATION; CONTROLLING WATER LEVEL FOR STEAM GENERATION; AUXILIARY DEVICES FOR PROMOTING WATER CIRCULATION WITHIN STEAM BOILERS
    • F22D11/00—Feed-water supply not provided for in other main groups
    • F22D11/006—Arrangements of feedwater cleaning with a boiler
    • C—CHEMISTRY; METALLURGY
    • C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
    • C02F1/00—Treatment of water, waste water, or sewage
    • C02F1/66—Treatment of water, waste water, or sewage by neutralisation; pH adjustment

Definitions

  • the present invention relates to the control of the water composition in a steam generator and most particularly to the control of the feedwater pH in a heat recovery steam generator or similar cycles by the addition and maintenance of a strong alkali concentration of trisodium phosphate, sodium hydroxide or similar treatment chemicals.
  • the failure of tubes in steam generator components, especially economizers, may be caused by a variety of factors.
  • One factor is the erosion and corrosion of the internal surfaces of the tubes.
  • the mechanism of this type of attack involves a cyclic phenomenon of dissolution and reformation of the protective magnetite layer on the tubes. This is greatly influenced by pH, temperature, local velocity and turbulence as well as oxygen levels. A pH of 8 or below has been found to promote the highest dissolution of the carbon steel material.
  • the common method for pH control of the feedwater is by the use of volatile amines such as ammonia.
  • Volatile amines are used since they volatilize with the steam as a vapor, thus offering several advantages. They do not affect the dissolved solids inventory in the boiler water and thus pose no demands for blowdown to reduce solids. They recirculate with the steam and condensate thus minimizing chemical usage and cost. Also, they do not restrict the use of feedwater for attemperation purposes. However, in some situations, the inclusion of amines or other volatiles are restricted or prohibited by the particular end use of the steam.
  • the present invention involves the injection of a non-volatile chemical such as trisodium phosphate to the feedwater of a steam generator system at a level to maintain a desired pH.
  • a non-volatile chemical such as trisodium phosphate
  • the use of the non-volatile is possible because the steam generator system is equipped to include the recycle of blowdown from the steam drums to the feedwater line downstream from where feedwater is extracted for the attemperation of superheated steam.
  • the invention is particularly applicable to heat recovery steam generators where blowdown from a higher pressure steam drum can be recycled to the lower pressure feedwater at a point downstream of the feedwater or condensate pump.
  • Figure 1 is a graph showing the effect of pH on the thinning of tube walls due to erosion corrosion.
  • FIG. 2 is a flow diagram of a heat recovery steam generator system incorporating the present invention.
  • the present invention relates to the reduction of the effect of feedwater pH on the erosion/corrosion of the tubes in a steam generator and particularly the economizer tubes.
  • Figure 1 is an example of the effect that pH can have on tube thinning for a particular set of conditions. This same general effect is also applicable at other conditions. As can be seen, the tube wall thinning is most evident at a pH range below about 8. Above a pH of 8, the rate of wall thinning drops off dramatically.
  • An object of the present invention is to maintain the feedwater in the higher pH range to minimize the erosion/corrosion with the same non-volatile treatment chemicals used for boilerwater pH control. Since the present invention is particularly applicable to heat recovery steam generators, the detailed description will be directed to such a steam generator.
  • gas turbines are widely used to provide standby or peaking electric power.
  • the thermal efficiency is low because of the high exit gas temperature.
  • the thermal energy remaining in the exhaust gas can be recovered in a heat recovery steam generator to produce steam such as for the production of additional electricity using a steam turbine.
  • the combined output of electricity from the gas turbine and the steam turbine may be 30 to 50 percent greater than that obtained from the gas turbine alone with no additional fuel input.
  • heat recovery steam generators with gas turbines is only one example of where heat recovery steam generators may be used.
  • FIG. 2 a simplified fiow diagram of a horizontal gas flow heat recovery steam generator 1 0 is illustrated. At the left end is the inlet 1 2 which would be connected to the exhaust of the gas turbine (not shown) or other hot gas source. The hot gases flow through the heat recovery steam generator 1 0 contacting the heat exchange surface as will be explained and exits at 1 4 into the flue gas stack 1 6.
  • the heat recovery steam generator 1 0 contains a series of banks of heat exchange surfaces.
  • the feedwater or condensate 1 8 from the condensate pump 20 flows into the low pressure economizer section 22 and then into the low pressure boiler section 24.
  • the steam or steam/water mixture flows from the low pressure boiler section 24 through line 26 into the low pressure steam drum 28.
  • the steam from the drum 28 is fed at 30 to the deaerator 32 for feedwater heating.
  • the recycle condensate from the steam turbine is also fed to the deaerator 32 as will be explained hereinafter.
  • the deaerated condensate 34 from the deaerator 32 is ' then recycled through the system by the condensate pump 20.
  • the steam from the low pressure drum 28 can also be used for other plant processes.
  • the liquid 36 from the low pressure drum 28 is fed by pump 38 into the intermediate pressure economizer 40 and by the pump 42 into the high pressure economizer 44.
  • the effluent from the intermediate pressure economizer 40 flows to the intermediate pressure boiler bank 46 and then to the intermediate pressure steam drum 48.
  • the separated intermediate pressure steam 50 from the steam drum 48 may be used for a variety of purposes such as process steam or injection into the gas turbine combustor to reduce NO x emissions. It could also be used for additional power recovery in the lower pressure stages of the steam turbine.
  • the effluent from the high pressure economizer 44 flows to the high pressure boiler bank 52 and then to the high pressure steam drum 54.
  • the separated high pressure steam 56 from the drum 54 then flows through the superheater 58 and the superheated steam 60 goes to the steam turbine 62.
  • the superheated steam may be attemperated or desuperheated at 64 as required. The attemperation spray will be further explained hereinafter.
  • the expended steam 66 from the turbine 62 goes to the condenser 68 and through pump 70 to the deaerator 32.
  • phosphate chemistry is utilized for pH control. Initially, trisodium phosphate is injected at 72 into the feedwater at the condensate pump discharge. Sufficient phosphate is injected to raise the pH above 8.5. This normally requires about 1 ppm of trisodium phosphate in the feedwater. It is even preferable to raise the pH higher than 8.5 but this depends on a number of factors such as the boiler pressure for a specific plant.
  • the use of the dissolved solids such as trisodium phosphate for feedwater pH control in the present invention is made possible because of the blowdown cascade and recycle feature from one or more higher pressure drums to the lower pressure feedwater line downstream of the condensate pump discharge. This results in very little phosphate content in the stream effluents and conserves the phosphate, i.e., the phosphate is continuously recycled with only small amounts being required for makeup of any lost such as through whatever minor blowdowns to waste may be required.
  • the blowdown scheme of the present invention is shown in Figure 2 where the blowdown 74 from the high pressure steam drum 54 is fed into the intermediate pressure steam drum 48 and the blowdown 76 is recycled at 78 to the low pressure feedwater line 1 8. Any small amount of blowdown to waste that may be required to reduce accumulations of other solids is through line 80.
  • the following table lists one specific example of the flow rates, pressures and amounts of trisodium phosphate at various key points in the process:
  • blowdown rates given in the example in the table are based on maintaining 1 00 ppm and 200 ppm of trisodium phosphate in the high and intermediate pressure drums 54 and 48, respectively. This will result in about 1 3 ppb sodium in the intermediate pressure steam 50 and about 80 ppb in the high pressure steam 60. These steam sodium values can be altered by changing the blowdown rates.
  • Another significant feature of the present invention comes into play when there is a need for attemperation or desuperheating of the superheated steam 60. In most steam generator systems, feedwater is used for this purpose.
  • the attemperation water 64 is derived from some selected source with a low solids content external to the circulating steam generator water.
  • the pH can be automatically controlled if desired.
  • a pH monitor 82 is connected into the feedwater line 1 8 and the output is used to control the trisodium phosphate feed at 84 as needed to replace any loses or otherwise correct the pH.

Landscapes

  • Engineering & Computer Science (AREA)
  • Water Supply & Treatment (AREA)
  • Physics & Mathematics (AREA)
  • Thermal Sciences (AREA)
  • Mechanical Engineering (AREA)
  • General Engineering & Computer Science (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Hydrology & Water Resources (AREA)
  • Environmental & Geological Engineering (AREA)
  • Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Preventing Corrosion Or Incrustation Of Metals (AREA)

Abstract

The feedwater of a steam generator (10) and particularly the feedwater to a heat recovery steam generator (10) is injected with non-volatile chemicals such as trisodium phosphate to maintain a desired pH. The use of the non-volatile chemicals is possible because the system includes the recycle of blowdown from the steam drums (28, 48, 54) to the feedwater line at a point downstream from the condensate pump (20) and downstream from where feedwater (18) is extracted for attemperation.

Description

Feedwater pH Control for Steam Generators
Background of the Invention
The present invention relates to the control of the water composition in a steam generator and most particularly to the control of the feedwater pH in a heat recovery steam generator or similar cycles by the addition and maintenance of a strong alkali concentration of trisodium phosphate, sodium hydroxide or similar treatment chemicals. The failure of tubes in steam generator components, especially economizers, may be caused by a variety of factors. One factor is the erosion and corrosion of the internal surfaces of the tubes. The mechanism of this type of attack involves a cyclic phenomenon of dissolution and reformation of the protective magnetite layer on the tubes. This is greatly influenced by pH, temperature, local velocity and turbulence as well as oxygen levels. A pH of 8 or below has been found to promote the highest dissolution of the carbon steel material.
The common method for pH control of the feedwater is by the use of volatile amines such as ammonia. Volatile amines are used since they volatilize with the steam as a vapor, thus offering several advantages. They do not affect the dissolved solids inventory in the boiler water and thus pose no demands for blowdown to reduce solids. They recirculate with the steam and condensate thus minimizing chemical usage and cost. Also, they do not restrict the use of feedwater for attemperation purposes. However, in some situations, the inclusion of amines or other volatiles are restricted or prohibited by the particular end use of the steam.
Summary of the Invention
The present invention involves the injection of a non-volatile chemical such as trisodium phosphate to the feedwater of a steam generator system at a level to maintain a desired pH. The use of the non-volatile is possible because the steam generator system is equipped to include the recycle of blowdown from the steam drums to the feedwater line downstream from where feedwater is extracted for the attemperation of superheated steam. The invention is particularly applicable to heat recovery steam generators where blowdown from a higher pressure steam drum can be recycled to the lower pressure feedwater at a point downstream of the feedwater or condensate pump.
Brief Description of the Drawings
Figure 1 is a graph showing the effect of pH on the thinning of tube walls due to erosion corrosion.
Figure 2 is a flow diagram of a heat recovery steam generator system incorporating the present invention.
Description of the Preferred Embodiment
The present invention relates to the reduction of the effect of feedwater pH on the erosion/corrosion of the tubes in a steam generator and particularly the economizer tubes. Figure 1 is an example of the effect that pH can have on tube thinning for a particular set of conditions. This same general effect is also applicable at other conditions. As can be seen, the tube wall thinning is most evident at a pH range below about 8. Above a pH of 8, the rate of wall thinning drops off dramatically. An object of the present invention is to maintain the feedwater in the higher pH range to minimize the erosion/corrosion with the same non-volatile treatment chemicals used for boilerwater pH control. Since the present invention is particularly applicable to heat recovery steam generators, the detailed description will be directed to such a steam generator. As an example, gas turbines are widely used to provide standby or peaking electric power. However, the thermal efficiency is low because of the high exit gas temperature. The thermal energy remaining in the exhaust gas can be recovered in a heat recovery steam generator to produce steam such as for the production of additional electricity using a steam turbine. The combined output of electricity from the gas turbine and the steam turbine may be 30 to 50 percent greater than that obtained from the gas turbine alone with no additional fuel input. Of course, the use of heat recovery steam generators with gas turbines is only one example of where heat recovery steam generators may be used.
Referring to Figure 2, a simplified fiow diagram of a horizontal gas flow heat recovery steam generator 1 0 is illustrated. At the left end is the inlet 1 2 which would be connected to the exhaust of the gas turbine (not shown) or other hot gas source. The hot gases flow through the heat recovery steam generator 1 0 contacting the heat exchange surface as will be explained and exits at 1 4 into the flue gas stack 1 6.
As indicated, the heat recovery steam generator 1 0 contains a series of banks of heat exchange surfaces. Starting from the cold end, the feedwater or condensate 1 8 from the condensate pump 20 flows into the low pressure economizer section 22 and then into the low pressure boiler section 24. The steam or steam/water mixture flows from the low pressure boiler section 24 through line 26 into the low pressure steam drum 28. In the particular arrangement shown, the steam from the drum 28 is fed at 30 to the deaerator 32 for feedwater heating. The recycle condensate from the steam turbine is also fed to the deaerator 32 as will be explained hereinafter. The deaerated condensate 34 from the deaerator 32 is ' then recycled through the system by the condensate pump 20. The steam from the low pressure drum 28 can also be used for other plant processes.
The liquid 36 from the low pressure drum 28 is fed by pump 38 into the intermediate pressure economizer 40 and by the pump 42 into the high pressure economizer 44. The effluent from the intermediate pressure economizer 40 flows to the intermediate pressure boiler bank 46 and then to the intermediate pressure steam drum 48. The separated intermediate pressure steam 50 from the steam drum 48 may be used for a variety of purposes such as process steam or injection into the gas turbine combustor to reduce NOx emissions. It could also be used for additional power recovery in the lower pressure stages of the steam turbine.
The effluent from the high pressure economizer 44 flows to the high pressure boiler bank 52 and then to the high pressure steam drum 54. The separated high pressure steam 56 from the drum 54 then flows through the superheater 58 and the superheated steam 60 goes to the steam turbine 62. The superheated steam may be attemperated or desuperheated at 64 as required. The attemperation spray will be further explained hereinafter. The expended steam 66 from the turbine 62 goes to the condenser 68 and through pump 70 to the deaerator 32.
In the present invention, phosphate chemistry is utilized for pH control. Initially, trisodium phosphate is injected at 72 into the feedwater at the condensate pump discharge. Sufficient phosphate is injected to raise the pH above 8.5. This normally requires about 1 ppm of trisodium phosphate in the feedwater. It is even preferable to raise the pH higher than 8.5 but this depends on a number of factors such as the boiler pressure for a specific plant.
The use of the dissolved solids such as trisodium phosphate for feedwater pH control in the present invention is made possible because of the blowdown cascade and recycle feature from one or more higher pressure drums to the lower pressure feedwater line downstream of the condensate pump discharge. This results in very little phosphate content in the stream effluents and conserves the phosphate, i.e., the phosphate is continuously recycled with only small amounts being required for makeup of any lost such as through whatever minor blowdowns to waste may be required. The blowdown scheme of the present invention is shown in Figure 2 where the blowdown 74 from the high pressure steam drum 54 is fed into the intermediate pressure steam drum 48 and the blowdown 76 is recycled at 78 to the low pressure feedwater line 1 8. Any small amount of blowdown to waste that may be required to reduce accumulations of other solids is through line 80. The following table lists one specific example of the flow rates, pressures and amounts of trisodium phosphate at various key points in the process:
Figure imgf000007_0001
The indicated blowdown rates given in the example in the table (streams 74 and 78) are based on maintaining 1 00 ppm and 200 ppm of trisodium phosphate in the high and intermediate pressure drums 54 and 48, respectively. This will result in about 1 3 ppb sodium in the intermediate pressure steam 50 and about 80 ppb in the high pressure steam 60. These steam sodium values can be altered by changing the blowdown rates. Another significant feature of the present invention comes into play when there is a need for attemperation or desuperheating of the superheated steam 60. In most steam generator systems, feedwater is used for this purpose. However, in the present invention where the feedwater contains dissolved solids in the form of the trisodium phosphate and where it is important to maintain low levels of solids in the steam, feedwater cannot be used for this purpose. Therefore, the attemperation water 64 is derived from some selected source with a low solids content external to the circulating steam generator water. In the present invention, the pH can be automatically controlled if desired. A pH monitor 82 is connected into the feedwater line 1 8 and the output is used to control the trisodium phosphate feed at 84 as needed to replace any loses or otherwise correct the pH.

Claims

Claims:
1 . A method of operating a steam generator system including a high pressure steam drum and a lower pressure feedwater supply comprising the steps of: (a) adding a phosphate pH control material as a dissolved solid to said feedwater to obtain a desired pH;
(b) recycling water containing said dissolved solid from said high pressure steam drum to said lower pressure feedwater supply thereby recycling said dissolved solid through said steam generator system.
2. A method as recited in claim 1 wherein said phosphate pH control material is trisodium phosphate.
3. A method as recited in claim 1 wherein said steam generator system further includes an intermediate pressure steam drum and wherein said step of recycling said water from said high pressure steam drum includes recycling through said intermediate pressure steam drum.
PCT/US1997/021877 1996-12-23 1997-12-01 FEEDWATER pH CONTROL FOR STEAM GENERATORS WO1998028231A1 (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
AU78725/98A AU7872598A (en) 1996-12-23 1997-12-01 Feedwater pH control for steam generators

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
US77240496A 1996-12-23 1996-12-23
US08/772,404 1996-12-23

Publications (1)

Publication Number Publication Date
WO1998028231A1 true WO1998028231A1 (en) 1998-07-02

Family

ID=25094957

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US1997/021877 WO1998028231A1 (en) 1996-12-23 1997-12-01 FEEDWATER pH CONTROL FOR STEAM GENERATORS

Country Status (2)

Country Link
AU (1) AU7872598A (en)
WO (1) WO1998028231A1 (en)

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0018083A1 (en) * 1979-04-02 1980-10-29 Betz Europe, Inc. Corrosion inhibitor method for the treatment for boiler water
US4709664A (en) * 1986-11-03 1987-12-01 Combustion Engineering, Inc. Method for determining the existence of phosphate hideout
EP0398070A2 (en) * 1989-05-15 1990-11-22 Westinghouse Electric Corporation A combined cycle power plant
EP0615061A1 (en) * 1993-03-11 1994-09-14 Hitachi, Ltd. Combined cycle power plant and method of operating it
EP0640747A1 (en) * 1993-08-20 1995-03-01 Nalco Chemical Company Boiler system pH/phosphate program control method

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP0018083A1 (en) * 1979-04-02 1980-10-29 Betz Europe, Inc. Corrosion inhibitor method for the treatment for boiler water
US4709664A (en) * 1986-11-03 1987-12-01 Combustion Engineering, Inc. Method for determining the existence of phosphate hideout
EP0398070A2 (en) * 1989-05-15 1990-11-22 Westinghouse Electric Corporation A combined cycle power plant
EP0615061A1 (en) * 1993-03-11 1994-09-14 Hitachi, Ltd. Combined cycle power plant and method of operating it
EP0640747A1 (en) * 1993-08-20 1995-03-01 Nalco Chemical Company Boiler system pH/phosphate program control method

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
MARTYNOVA: "The Water Chemistry of Power Stations with Drum-Type Boilers", THERMAL ENGINEERING, vol. 42, no. 10, October 1995 (1995-10-01), pages 854 - 859, XP002059172 *

Also Published As

Publication number Publication date
AU7872598A (en) 1998-07-17

Similar Documents

Publication Publication Date Title
US5754613A (en) Power plant
US6041588A (en) Gas and steam turbine system and operating method
KR100323398B1 (en) Combined Cycle Power Unit
US3769795A (en) Multipressure steam system for unfired combined cycle powerplant
JP2001514368A (en) Boiler, especially waste heat boiler and its operation method
KR100439464B1 (en) A multi-pressure waste-heat boiler and a method of operating the same
US4745757A (en) Combined heat recovery and make-up water heating system
KR100615732B1 (en) Gas and Steam Turbine Devices
US10760453B2 (en) Feedwater system of combined cycle power plant
US20070227154A1 (en) System and method for producing injection-quality steam for combustion turbine power augmentation
US6089013A (en) Configuration for deaerating a condensate
CA2054799C (en) Method and arrangement for treating black liquor
US5906178A (en) Degree of separation of steam impurities in a steam/water separator
US6109020A (en) Combined cycle power plant with a once through steam generator
US6155054A (en) Steam power plant and method of and cleaning its steam/water cycle
US7146795B2 (en) System and method for producing injection-quality steam for combustion turbine power augmentation
US5904039A (en) Method and configuration for deaerating a condensate
RU2067668C1 (en) Combined-cycle plant operation process
WO1998028231A1 (en) FEEDWATER pH CONTROL FOR STEAM GENERATORS
JPH11236689A (en) Water treating apparatus for power generating plant and water treatment
US4236968A (en) Device for removing heat of decomposition in a steam power plant heated by nuclear energy
Putman et al. The economic effects of condenser backpressure on heat rate, condensate subcooling and feedwater dissolved oxygen
SU1638360A1 (en) Power plant for geothermal power station
RU2067667C1 (en) Combined-cycle plant operation method
JPS6017210A (en) combined cycle power plant

Legal Events

Date Code Title Description
AK Designated states

Kind code of ref document: A1

Designated state(s): AL AM AU AZ BA BB BG BR BY CA CN CZ EE GE GH HU ID IL IS JP KG KR KZ LC LK LR LT LV MD MG MK MN MW MX NO NZ PL RO RU SD SG SI SK SL TJ TM TR TT UA UZ VN YU ZW AM AZ BY KG KZ MD RU TJ TM

AL Designated countries for regional patents

Kind code of ref document: A1

Designated state(s): GH KE LS MW SD SZ UG ZW AT BE CH DE DK ES FI FR GB GR IE IT LU MC NL PT SE

121 Ep: the epo has been informed by wipo that ep was designated in this application
122 Ep: pct application non-entry in european phase