FIELD OF INVENTION

This invention relates generally to corrosion protection of metal vessels containing liquid water and water vapors and more specifically to corrosion protection of internal surfaces of steam and water cycle equipment of both nuclear and conventional fossil fuel fired power generating plants.

BACKGROUND OF THE INVENTION

Power generating plants, using either nuclear or conventional fuel, heat water in boilers to generate steam. Steam then powers turbines and electric generators producing electricity. Steam exiting from turbines is condensed in the main steam condenser from which it is pumped back into boilers. The main construction materials of a power generation cycle plant are iron and copper based alloys. Its internal volume may be up to several hundred cubic meters while internal surfaces needing protection against corrosion may be of the order of several tens of thousands m².

FIG. 1 is the schematic of a typical steam and water cycle in a fossil fuel fired power generation plant, which burns fuel such as coal, gas or oil in boiler 24 to produce electric power. Steam condensate formed in the main steam condenser 12 is pumped with condensate extraction pump 41 through low pressure heaters 14,15,16 and 17 into de-aerating heater 18 (de-aerator). Boiler feed pump 42 then pumps water from de-aerator 18 through high pressure heaters 19 and 21 and the economizer 22 into the steam drum 23, which is located at the top of the boiler 24. The boiler is typically a large vessel with walls made of carbon steel tubes, which are filled with water, where fossil fuel is burned inside and heated water in the tubes is turned into steam. Steam in the tubes rises up to the steam drum where it is separated from liquid phase and proceeds through the super heater 34 into high pressure turbine, re-heater 34, intermediate pressure turbine 37 and low pressure turbine 38 into the condenser 12 to complete the cycle of working fluid. Turbines are vessels with rotors in them, which convert heat energy in the passing steam into mechanical work, which is then converted into electrical energy in electric generators, which are not shown.

Schematic drawing in FIG. 1 also shows piping from the turbines to low pressure heaters, de-aerator and high pressure heaters, which allows flow of extraction steam from specific points in the turbines to pre-heat condensate in different heat exchangers. Steam to high pressure heater 21 is extracted from high pressure turbine 36; the intermediate pressure turbine 37 provides steam to high pressure heater 19 and the de-aerator 18; the low pressure turbine provides heating steam to the low pressure heaters 14, 15, 16 and 17. FIG. 1 also shows make-up water (condensate) storage 11 and two sets of drain lines for the condensing extraction steam. The first set indicates piping for draining of condensate from high pressure heater 21 through 19 into de-aerator; the second one is a cascade from low pressure heater 17 through 16,15 and 14 into the main unit condenser 12. The primary purpose for the installation of the heaters, the extraction steam system and the two sets of drain lines is to improve overall energy efficiency of the power plant cycle. In service, the internal space of the power generating cycle equipment is filled with either water or steam.

FIG. 2 is the schematic of a typical steam and water cycle in a typical nuclear power plant. Nuclear power generation cycle differs from the conventional one in that instead of boilers it contains primary circuit consisting of a pump 44, nuclear reactor 61, pressurizer 62 and steam generator 63. The rest of the cycle is similar in both the fossil and the nuclear power plants. Nuclear fuel heats water in the nuclear reactor 61, which is than transferred by pump 44 into steam generator 63 where it releases its heat into water in the secondary circuit and turning it into steam which runs turbines and electric generators (not shown). Operating steam temperature is the main difference between the conventional and nuclear power plants. Whereas the temperature of the former is up to 1000° F., maximum temperature of steam in the nuclear units is approximately 590° F.

It is known that the chemistry of water used as the working fluid in steam and water cycles of power generating plants has to be controlled to minimize internal corrosion. For example, the content of acidic components of dissolved solids (measured by cation conductivity) in such water is reduced by de-ionization process to less than 0.2 uS/cm. Its alkalinity, measured by pH, is elevated to above 9.0, depending on the specific part of the cycle, with ammonia, organic amines or solid alkali or different combinations of these chemicals. Gaseous oxygen content of the cycle is controlled mechanically with de-gassifiers and by injecting chemicals like hydrazine to maintain dissolved oxygen concentration levels in system condensate below 200 ug/L. Under such conditions the internal equipment surfaces are coated with relatively thin (several microns thick), but dense adherent layers of oxides, which effectively protect underlying base metal. It is also known that internal water quality in most of the power generating cycles is well within the recommended chemistry control ranges during power generating periods. In service, the power plant equipment is therefore well protected against corrosion.

During power plant shutdown periods, some or all parts of the power generating cycle are opened to atmosphere and the quality of water in contact with internal cycle surfaces is typically well outside the recommended control range proportionately increasing system corrosion. One reason is intentional contamination of the cycle with ambient air during stand-by periods for either operational or plant maintenance reasons. The second reason for elevated corrosion is injection into the cycle of make-up water contaminated with air, which includes oxygen and acidic gases, namely carbon dioxide and oxides of nitrogen and sulfur. As a result of this contamination, concentration of oxygen dissolved in cycle water may reach several mg/L while its pH may drop well below 8.5. Further, the concentration of corrosion causing dissolved solids, measured by cation conductivity, may increase to up to 2 uS/cm and perhaps even higher.

Impact of lowered pH and higher oxygen content in cycle water on copper alloys is indicated by data in FIG. 3, which were published by P. H. Effertz et al in Vom Wasser, 43. Band in 1974. One of the key conclusions of this work is that pH is the main corrosion factor for copper alloys. Contamination with dissolved oxygen is also important, but only when pH of de-ionized water drops below approximately 8.5. Impact of dissolved oxygen on copper corrosion is apparently minimal at higher alkalinity levels.

Test data of F. J. Pocock et al (Proceedings American Power Conference, Chicago, Ill., April 1964) in FIG. 4 indicate impact of different pH levels on corrosion rate of carbon steel. Test data of P. H. Effertz et al. in FIG. 5, which were published in Der Maschinenschaden 48 in 1975, show impact of varying carbonic acid concentrations, expressed by corresponding cation conductivities, on the rate of carbon steel corrosion. Very relevant is also study of G. McIntire et al in Journal Corrosion—NACE, Vol. 46, No 2, February 1990, who concluded that carbon steel corrodes in water but only if both dissolved oxygen and carbon dioxide are present. Absence of either one of these two contaminants in water apparently reduces corrosion risks to a minimum. In summary, data in the above references indicate that internal surfaces of both the carbon steel and copper alloys' components will be protected against corrosion, regardless oxygen concentration levels, providing water does not contain carbon dioxide and its alkalinity is maintained within the preferred pH range of between 9.0 and 9.5.

Corrosion products are known to be transported around the cycle depositing on surfaces of various heat exchangers, including boilers and turbines. In heat exchangers, they reduce heat transfer rate and hence plant thermal efficiency. In boilers, reduction of heat transfer due to deposits may lead to overheating tube failures or, if corrosive anions are also present, to under deposit corrosion attack, such as hydrogen damage. Deposits in turbines may lead both to corrosion failures due to under-deposit corrosion attack and/or plant capacity reduction.

It is also known that low pH water during plant start-ups and shut downs causes initiation and/or propagation of corrosion fatigue cracks on internal surfaces of thermally stressed carbon steel plant components. Corrosion fatigue failures in boilers are known to be the main cause of plant unreliability but similar type failures in de-aerators and turbines are also important since they may be catastrophic, causing long periods of plant unavailability (EPRI, Palo Alto, Calif., TR-106696, November 1997). Deposition of corrosion products in nuclear power plant cycles is also known to aggravate health and safety problems due to increased radioactive radiation exposure of station staff. Further, the necessary periodic removal of excessive levels of corrosion products with chemical solvents generates large quantities of toxic wastes in both the conventional and nuclear power stations.

Field studies indicate that corrosion rate of cycle materials during unprotected shutdown periods does correspond to the inferior quality of water in power cycles. J. A. Sawicki et al, showed at the 1995 Candu Maintenance Conference that shutdown corrosion is up to orders of magnitude above that during normal operation when system chemistry is within recommended control limits. In summary, it is the corrosion during shutdowns and early start-ups and not the one during closely controlled operating periods, which is the root cause of the majority of reliability and availability problems in power plants.

Prior art of plant corrosion protection during out off service time periods is to take no chemistry control countermeasures while displacing steam and water in the power generation cycle equipment with untreated air. This technique is the most damaging one to plant equipment integrity yet it is practiced by up to 80% utilities. A modification of this art is storage of certain cycle components, such as boilers, with a solution of 10 mg/L ammonia and 200 mg/L hydrazine to preserve oxides formed on internal surfaces of selected components during operating periods (The ASME Handbook on Water technology for Thermal Power Systems, Chapter 22). Disadvantage of this method is that the protective solutions cannot reach majority of other surfaces around the cycle and its value to the plant equipment protection is thus rather limited. Another disadvantage is that hydrazine is a known carcinogen and its solutions, which have to be drained from the cycle prior to each plant re-start, pose a serious risk to the environment.

Another art for equipment shut down corrosion protection is to drain water and steam condensate from the power generation cycle as hot as possible after plant shutdown and subsequently quickly reduce moisture content in the internal atmosphere (relative humidity) to below approximately 45% with de-humidifiers. Disadvantage of this art is that draining of system components is ineffective and de-humidification process is time consuming and labor intensive. Preparation of the plant for storage and subsequent return to service is typically so long as to make it practical only for equipment storage with an indefinite time for return to service (The ASME Handbook on Water Technology for Thermal Power Systems, Chapter 22).

Yet another art for equipment shut down corrosion protection is to fill internal cavities of power generation cycle equipment not with untreated air but with inert nitrogen gas. Disadvantage of this art is its logistics constraints, technical problems with its comprehensive application and potential safety hazard of asphyxiation to plant personnel (The ASME Handbook on Water Technology for Thermal Power Systems, Chapter 22).

OBJECTS OF THE INVENTION

The object of this invention is a reduction of corrosion inside power generation cycle equipment during plant shutdown and start-up periods by substantially reducing or totally eliminating internal contamination with corrosion causing acidic gases such as carbon dioxide and oxides of sulfur and nitrogen. Acidic gases are removed at their potential points of entry into the cycle either from ingressing ambient air or dissolved in make-up water in two different kinds of filters.

BRIEF DESCRIPTION OF THE DRAWINGS

The apparatus of the invention will now be described with reference to the accompanying drawings, in which:

FIG. 1 is a schematic diagram of a typical conventional fossil fuel fired power generation cycle;

FIG. 2 is a schematic diagram of a typical nuclear power generation cycle;

FIG. 3 is a graph of the corrosion rates of copper alloys in condensate of different pH and oxygen concentration;

FIG. 4 is a graph of the corrosion rates of carbon steel in condensate at different pH;

FIG. 5 is a graph of carbon steel corrosion rates in condensate of different cation conductivities.

FIGS. 1 and 2 show the typical location for the filter 51 on the discharge line from the water storage tank 11 into the main steam condenser 12. The same figures also show the main terminal points 12, 18 and 23 and lines for distribution of air treated in the externally located filter 52. Since the active media used in the filters have limited capacity for acidic gases, they will either have to be periodically replaced or reactivated by the proper regeneration step. Inherent part of some of the proposed systems may therefore be regeneration equipment and associated piping network.

DETAILED DESCRIPTION OF THE INVENTION

In order to more clearly understand the present invention part numbers as assigned in the following parts list will be used:

Part Number

Description

11

make-up water (condensate) storage

12

main steam condenser

13

vacuum breaker

14

low pressure heater

15

low pressure heater

16

low pressure heater

17

low pressure heater

18

de-aerating heater

19

high pressure heater

21

high pressure heater

22

economizer

23

steam drum

24

boiler

25

drain tank

34

superheater

35

reheater

36

high pressure turbine

37

intermediate pressure turbine

38

low pressure turbine

41

condensate extraction pump

42

boiler feed pump

43

drains pump

44

pump

51

water anion polisher

52

acidic gases filter

53

air blower

61

nuclear reactor

62

pressurizer

63

steam generator

The first device (51) is the water anion polisher (WAP), which consists of a tank with anion exchanger designed to remove acidic contaminants from any water flowing into the cycle from a storage tank. It is preferred that the device 51 is installed on the effluent from each water storage tank. As an alternative, a single device can be installed on a common line from a series of storage tanks.

WAP is a vessel made of metal or composite materials, which is filled with an organic or inorganic based anion exchanger in hydroxyl form capable retention of acidic anions dissolved in water, including all those originating from ambient air. Since the capacity of anion exchangers, such as strong base anion exchange resins, for dissolved anions is limited, exhausted anion exchangers will have to be periodically regenerated and or replaced with new bed in hydroxyl form. Regeneration of anion exchangers is a well established process, which can be carried out with proper chemicals either locally in the plant or externally by outside contractors.

The second device (52) is acidic gases filter (AGF); tank with active media designed to remove acidic components from ambient air, which is used either for displacement of steam and/or maintaining non-aggressive atmosphere in stored plant equipment. Ambient air is either drawn into the cycle through AGF either naturally by vacuum forming in the cycle during the early stages of plant shut-down or later, when internal pressure approaches one on the outside, it may be blown in as necessary with the blower 53. Maintaining slight overpressure inside the cycle is beneficial, because it prevents its contamination with outside air. In the preferred embodiment, treated air is blown into the cycle of the conventional plant through vacuum breaker 13 at the main steam condenser 12, the de-aerator 18 and the steam drum 23. In a nuclear plant, treated air may also be used for corrosion protection of the primary circuit.

As an alternative, it may be also advantageous to blow treated air into any cycle component opened for service or maintenance to protect them against corrosion during those periods of time. Although several AGF units can be theoretically installed on each power generation cycle, it may be preferred that a centrally-installed AGF unit provides treated air to each unit of a power generation plant separately or as a part of plant service air system.

AGF unit is a tank constructed out off metal or composite materials, which contains active medium (or a mixture of different media) for removal of acidic gases from air. The capacity of any active medium in AGF is limited and each bed will therefore have to be either replaced or periodically regenerated. Regeneration of any of the selected active media is well established process and is not therefore covered in this publication. The regeneration process may be triggered either by exceedance of the effluent air quality or after treatment of a preset volume of treated air.

The benefit of the invention is that internal corrosion within cycles containing these filters will be minimized, because pH and dissolved solids content of water will remain around the clock within optimum chemistry control ranges. Contamination with oxygen and corresponding exceedance of oxygen concentration limit in system condensate will have only minor effect on internal plant equipment corrosion.

It will be understood that modifications can be made in the embodiments of the invention described herein.