EP2356376B1 - Procédé de nettoyage chimique et système à injection de vapeur - Google Patents

Procédé de nettoyage chimique et système à injection de vapeur Download PDF

Info

Publication number
EP2356376B1
EP2356376B1 EP09831147.5A EP09831147A EP2356376B1 EP 2356376 B1 EP2356376 B1 EP 2356376B1 EP 09831147 A EP09831147 A EP 09831147A EP 2356376 B1 EP2356376 B1 EP 2356376B1
Authority
EP
European Patent Office
Prior art keywords
steam
cleaning
heat exchanger
secondary side
adapter
Prior art date
Legal status (The legal status 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 status listed.)
Active
Application number
EP09831147.5A
Other languages
German (de)
English (en)
Other versions
EP2356376A4 (fr
EP2356376A1 (fr
Inventor
Robert D. Varrin, Jr.
Michael J. Little
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Westinghouse Electric Co LLC
Original Assignee
Westinghouse Electric Co LLC
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 Westinghouse Electric Co LLC filed Critical Westinghouse Electric Co LLC
Priority claimed from US12/630,729 external-priority patent/US8459277B2/en
Publication of EP2356376A1 publication Critical patent/EP2356376A1/fr
Publication of EP2356376A4 publication Critical patent/EP2356376A4/fr
Application granted granted Critical
Publication of EP2356376B1 publication Critical patent/EP2356376B1/fr
Active legal-status Critical Current
Anticipated expiration legal-status Critical

Links

Images

Classifications

    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/48—Devices for removing water, salt, or sludge from boilers; Arrangements of cleaning apparatus in boilers; Combinations thereof with boilers
    • F22B37/54—De-sludging or blow-down devices
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B08—CLEANING
    • B08B—CLEANING IN GENERAL; PREVENTION OF FOULING IN GENERAL
    • B08B3/00—Cleaning by methods involving the use or presence of liquid or steam
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B08—CLEANING
    • B08B—CLEANING IN GENERAL; PREVENTION OF FOULING IN GENERAL
    • B08B9/00—Cleaning hollow articles by methods or apparatus specially adapted thereto 
    • C—CHEMISTRY; METALLURGY
    • C23—COATING METALLIC MATERIAL; COATING MATERIAL WITH METALLIC MATERIAL; CHEMICAL SURFACE TREATMENT; DIFFUSION TREATMENT OF METALLIC MATERIAL; COATING BY VACUUM EVAPORATION, BY SPUTTERING, BY ION IMPLANTATION OR BY CHEMICAL VAPOUR DEPOSITION, IN GENERAL; INHIBITING CORROSION OF METALLIC MATERIAL OR INCRUSTATION IN GENERAL
    • C23G—CLEANING OR DE-GREASING OF METALLIC MATERIAL BY CHEMICAL METHODS OTHER THAN ELECTROLYSIS
    • C23G1/00—Cleaning or pickling metallic material with solutions or molten salts
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/002—Component parts or details of steam boilers specially adapted for nuclear steam generators, e.g. maintenance, repairing or inspecting equipment not otherwise provided for
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/48—Devices for removing water, salt, or sludge from boilers; Arrangements of cleaning apparatus in boilers; Combinations thereof with boilers
    • F22B37/483—Devices for removing water, salt, or sludge from boilers; Arrangements of cleaning apparatus in boilers; Combinations thereof with boilers specially adapted for nuclear steam generators
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/48—Devices for removing water, salt, or sludge from boilers; Arrangements of cleaning apparatus in boilers; Combinations thereof with boilers
    • F22B37/52—Washing-out devices
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F22—STEAM GENERATION
    • F22B—METHODS OF STEAM GENERATION; STEAM BOILERS
    • F22B37/00—Component parts or details of steam boilers
    • F22B37/02—Component parts or details of steam boilers applicable to more than one kind or type of steam boiler
    • F22B37/56—Boiler cleaning control devices, e.g. for ascertaining proper duration of boiler blow-down
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28G—CLEANING OF INTERNAL OR EXTERNAL SURFACES OF HEAT-EXCHANGE OR HEAT-TRANSFER CONDUITS, e.g. WATER TUBES OR BOILERS
    • F28G1/00—Non-rotary, e.g. reciprocated, appliances
    • F28G1/16—Non-rotary, e.g. reciprocated, appliances using jets of fluid for removing debris
    • F28G1/166—Non-rotary, e.g. reciprocated, appliances using jets of fluid for removing debris from external surfaces of heat exchange conduits
    • F—MECHANICAL ENGINEERING; LIGHTING; HEATING; WEAPONS; BLASTING
    • F28—HEAT EXCHANGE IN GENERAL
    • F28G—CLEANING OF INTERNAL OR EXTERNAL SURFACES OF HEAT-EXCHANGE OR HEAT-TRANSFER CONDUITS, e.g. WATER TUBES OR BOILERS
    • F28G9/00—Cleaning by flushing or washing, e.g. with chemical solvents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B08—CLEANING
    • B08B—CLEANING IN GENERAL; PREVENTION OF FOULING IN GENERAL
    • B08B2230/00—Other cleaning aspects applicable to all B08B range
    • B08B2230/01—Cleaning with steam
    • C—CHEMISTRY; METALLURGY
    • C11—ANIMAL OR VEGETABLE OILS, FATS, FATTY SUBSTANCES OR WAXES; FATTY ACIDS THEREFROM; DETERGENTS; CANDLES
    • C11D—DETERGENT COMPOSITIONS; USE OF SINGLE SUBSTANCES AS DETERGENTS; SOAP OR SOAP-MAKING; RESIN SOAPS; RECOVERY OF GLYCEROL
    • C11D2111/00—Cleaning compositions characterised by the objects to be cleaned; Cleaning compositions characterised by non-standard cleaning or washing processes
    • C11D2111/10—Objects to be cleaned
    • C11D2111/14—Hard surfaces
    • C11D2111/20—Industrial or commercial equipment, e.g. reactors, tubes or engines
    • C—CHEMISTRY; METALLURGY
    • C11—ANIMAL OR VEGETABLE OILS, FATS, FATTY SUBSTANCES OR WAXES; FATTY ACIDS THEREFROM; DETERGENTS; CANDLES
    • C11D—DETERGENT COMPOSITIONS; USE OF SINGLE SUBSTANCES AS DETERGENTS; SOAP OR SOAP-MAKING; RESIN SOAPS; RECOVERY OF GLYCEROL
    • C11D2111/00—Cleaning compositions characterised by the objects to be cleaned; Cleaning compositions characterised by non-standard cleaning or washing processes
    • C11D2111/40—Specific cleaning or washing processes
    • C11D2111/44—Multi-step processes

Definitions

  • the present invention applies to the chemical cleaning or combined chemical and mechanical cleaning of heat exchangers or vessels, including nuclear pressurized water reactor (PWR) steam generators.
  • Example materials targeted for removal by cleaning include those that reside on the secondary (boiling) side of heat exchangers or vessels and comprise metallic oxides (e.g., magnetite), metallic species (e.g., copper), other impurities (e.g ., mineral species) or waste materials.
  • the method described herein may also be used in conjunction with other deposit or waste management strategies such as dispersants or scale conditioning agent solutions, which are added to the heat exchanger or vessel to mitigate the accumulation of deposits in these systems or to modify the structure of these deposits once accumulation has occurred.
  • the method and system described herein may also be used with decontamination solutions or with other processes for cleaning heat exchangers or vessels, including the removal of waste, such as nuclear waste, from a vessel, heat exchanger or fluid systems where temperature control is required or helpful.
  • Chemical means include high and low temperature chemical cleaning, and mechanical means include processes such as pressure-pulse cleaning, water jetting or lancing, or bundle flushes with water or chemical solutions. Chemical means and mechanical means are often combined by performing them concurrently or sequentially.
  • Off-line processes refer to processes in which the supply, heating, pumping, mixing, cooling and draining of the chemical solutions is performed via the installation and use of temporary external equipment.
  • the equipment configurations associated with off-line processes are typically very complex, and require significant time and manpower to set up and operate.
  • Off-line processes allow electrochemical corrosion monitoring equipment to be installed inside the vessel such as a steam generator to ensure that no harmful side effects of the cleaning operation are occurring. Liquid samples can also be easily taken via temporary sample lines to monitor the process and to ensure that excessive corrosion of vessel or steam generator internals does not occur during the cleaning process due to off-normal process or chemistry conditions.
  • Plant heat Processes that use primary-to-secondary heat transfer to control the temperature of the cleaning process at a power plant such as a PWR are referred to as "plant heat” or “on-line” processes.
  • the equipment setup and manpower requirements are significantly reduced during on-line processes because heating and cooling of the secondary side (locations of deposits) is supplied from the primary side of the plant using plant systems such as decay heat from reactor core (for heating) or the plant residual heat removal (RHR) system (for cooling). As such, no external heating or cooling equipment is required. Because plant heat processes are applied while the plant is "on-line", there is no access to the vessel such as a steam generator prior to the cleaning. This prevents the installation of corrosion monitoring equipment inside the steam generator.
  • Liquid sampling is also more difficult during "on-line” processes because the vessel such as a steam generator may need to be partially drained back through plant systems in order to obtain a sample of the cleaning solvent.
  • process monitoring is much more difficult during "on-line” processes.
  • Excessive corrosion and other off-normal chemistry conditions have been known to occur during conventional "on-line” cleaning applications (see “ Application of AREVA Inhibitor-Free High Temperature Chemical Cleaning Process against Blockages on SG Tube Supports,” Dijoux, M. et al, presented at "NPC '08 Berlin, International Conference on Water Chemistry of Nuclear Reactor Systems," held in Berlin, Germany, September 15-18, 2008 ).
  • high temperature processes In chemical cleaning processes designed for complete removal of deposits, high temperature processes generally refer to those applied, for example, at 140 to 220°C (285 to 428°F), see U.S. Patent No. 5,264,041 to Kuhnke et al. ("Kuhnke”). These processes are usually applied with the temperature maintained by heat transfer from the primary side of the plant, often while the plant is shutting down for maintenance or refueling. As discussed earlier, these processes are referred to as "on-line” processes in the context of chemical cleaning.
  • the primary side of the plant, or reactor coolant system is the closed loop portion of the PWR plant comprising the fuel, reactor, reactor coolant pumps, the pressurizer, numerous reactor control and safety systems, and the tubes internal to the steam generators.
  • the secondary side is the portion of the plant which includes the outside of the tubes in the steam generators, the steam lines, turbines, condenser, several stages of pumps, and feedwater heaters.
  • Other examples of high temperature processes are e.g . German patent DE389883 , which discusses preheating feedwater with steam before it is inserted into a steam boiler and U.S. Patent No. 4,581,074 to Nadezha et al. (“Nadezha”), which teaches cleaning crud from the internal heat transfer surfaces of boiler tubes by impacting the crud with cleaning fluid at high speed super-heated by steam.
  • Low temperature processes generally refer to processes applied from, for example, 30°C to 140°C (85 to 285°F), with the temperature maintained by either: (1) primary to secondary side heat transfer (“on-line”), or (2) use of temporary equipment set up outside of the containment building (“off-line”).
  • Temporary equipment typically includes an external heating loop that exchanges heat indirectly with the main chemical cleaning process loop via an external heat exchanger (see discussion below). Heat is typically supplied to the external heating loop by a portable steam boiler, but may also be supplied by electrical heater(s) or by steam from an adjacent power plant. When steam is used, it is condensed on one side of a heat exchanger and not admixed with the cleaning solution (also referred to as indirect heating as opposed to direct steam injection).
  • the containment building houses the reactor (primary loop) and the steam generators. Steam produced on the "secondary side" of the steam generators exits the steam generators via steam lines which in turn pass through penetrations in the containment building to supply the turbine-generator. Condensed steam or "feedwater” then returns to the steam generators via separate penetrations in the containment building from the condenser through the auxiliary building which houses the aforementioned feedwater heaters, pumps and other equipment.
  • Temporary penetrations at the containment building boundary are also available but generally limited in size and number. These penetrations are often used to connect temporary equipment to the steam generators, but the limited number and size of the penetrations makes it difficult to link or interconnect complex cleaning equipment configurations located outside of containment to the steam generators.
  • German patent DE102004054471 discusses a steam generator cleaning process that uses complexing agents at elevated temperatures.
  • SGs there are two basic types of steam generators (SGs).
  • RSG recirculating steam generator
  • the tubes which constitute the primary to secondary side boundary are vertically oriented and U-shaped, such that the primary coolant enters and exits the SG near the bottom.
  • the tube "bundle" can consist of thousands of tubes.
  • the other type of steam generator is known as a once-through steam generator (OTSG).
  • OTSG once-through steam generator
  • the tubes are straight and vertically oriented such the primary coolant enters at the top of the SG and exits at the bottom.
  • steam is produced outside the tubes. Both types of steam generators may require periodic chemical cleaning or conditioning to reduce concerns with thermal efficiency and corrosion of the tube materials.
  • Partridge and Gorman describe the use of steam for indirectly heating of solvents (in an "external heat” process) by passing steam through a heat exchanger integral to the temporary chemical cleaning equipment system located outside of the containment building.
  • steam is available from a portable boiler, but may also be supplied from an adjacent power plant.
  • Remark discloses an on-line plant heat steam generator chemical cleaning process that involves introducing a chemical cleaning solvent to the secondary side of a steam generator and heating said solvent via heat transfer from the primary side of the plant (nuclear core decay heat and primary side recirculation pump heat) to the secondary side in "Mode 5."
  • Mode 5 is an industry and regulatory definition describing one of six operating modes ranging from power operations (Mode 1) to shutdown and "defueled” conditions (Mode 6).
  • Mode 5 is a condition of plant operations during which no electric power is being produced by the plant (the reactor is subcritical), but fuel remains in the core, with the primary temperature initially from 99 to 93°C (210 to 200°F) cooling down to less than 38°C (100°F).
  • the cleaning process disclosed by Remark is said to last for a period described as 24 to 36 hours.
  • the PWR plant would not stop cooling the plant during a shutdown to hold the temperature at the required cleaning temperature of 99 to 93°C (200 to 210°F).
  • the 24 to 36 hours represents what is known as "critical path" time, or time during which electricity is not being produced.
  • the value of electric power produced for 24 to 36 hours can be more than US$1,000,000. It is also not clear that the 24 to 36 hours includes time to inject the cleaning chemicals and partially drain the steam generators for sampling.
  • 24 to 36 hours of cleaning time may be inadequate at the temperatures cited in Remark, so actual critical path impact may be greater.
  • the Remark specification further describes the use of nitrogen sparging at 7.1 to 42.5 m 3 /min (250 to 1500 cubic feet/minute (cfm)) to promote mixing.
  • the benefits of gas sparging for mixing of the fluid on the secondary side of a steam generator were studied in the 1980's (see, for example, EPRI-NP 2993 entitled "Evaluation of Steam Generator Fluid Mixing during Layup").
  • modeling and testing demonstrated that complete turnover of the liquid on the secondary side of an RSG could be achieved at flows from 0.28 to 0.85 m 3 /min (10 to 30 cfm) in as little as seven minutes.
  • T mix 0.6 Q ⁇ 0.5
  • Q was the gas flow rate in cfm.
  • a 0.85 m 3 /min (30 cfm) flow corresponds to a 6 minute mixing time, typically more than adequate for most chemical cleaning operations.
  • a claimed advantage of the on-line process described in Remark is that it does not require that the steam generator be drained to install connections to the steam generators for the introduction, recirculation or draining of cleaning solvents.
  • off-line chemical cleaning processes usually require heating and cooling in a sequence of steps using external equipment set-up at a significant distance, up to 460 m (1500 feet) or more, from the SGs outside of the "containment building" which houses the steam generators. The distance is mandated by the need for a large "lay down" or set-up area for the external process heat equipment, and such space (typically more than 9,300 square meters (100,000 square feet)) is generally not available directly adjacent to the containment building.
  • the external cleaning system includes a complex array of heaters, pumps, valves, storage tanks, coolers and controls. Inside of containment, there can also be literally hundreds of feet of piping, numerous pumps, and hundreds of valves. The time to set up the external process system even before the plant shutdown (after which interconnections to the steam generators are made) can range from one to three months.
  • the time required to connect the external process system to the SGs can be an additional three to six days or more and involves up to four to twelve or more temporary adapters to be affixed to conventional access penetrations on the secondary side of the SGs.
  • an external heat cleaning process typically requires from 5 to 10 days (144 to 240 hours) for each group or set of steam generators that are cleaned.
  • These adapters include supply and return lines for solvents and rinses, drains, level control instrumentation taps, pressure instrumentation taps, temperature indicator taps, gas sparging, corrosion monitoring electronics penetrations, and sample line taps.
  • the necessity of many of these interconnections is to support external heating.
  • the actual application time for the chemical cleaning ranges from several days to several weeks, depending on the complexity of the process (number of solvent steps, rinses, etc .) .
  • Demobilization including removing the temporary adapters from the steam generators requires several more days. Whether or not the set-up, application, and demobilization are on "critical path" depends on other plant refueling and maintenance activities that are underway. In many cases, particularly in longer refueling outages, external heat chemical cleaning processes have not affected critical path.
  • an in situ electrochemical corrosion monitoring system allows for the nearly instantaneous detection of off-normal chemistry or process conditions that can lead to unacceptable corrosion.
  • CMS in situ electrochemical corrosion monitoring system
  • LPR linear polarization resistance
  • ZRA zero resistance ammetry
  • on-line / plant heat processes for cleaning nuclear steam generators such as the method described in Remark is that this type of process requires a less complicated and labor-intensive equipment setup. On-line processes may also result in reduced schedule impact, although the actual impact to critical path schedule would be plant-specific (many off-line external heat chemical cleanings of nuclear steam generators have not impacted critical path).
  • the primary disadvantage of on-line / plant heat processes is that process and corrosion monitoring may not be feasible or may be significantly more complicated, such that there is an increased potential for excessive corrosion, increased environmental impact, or other unwanted side effects.
  • traditional external cleaning processes are very safe in that they allow industry standard process monitoring techniques to be easily performed.
  • typical equipment configurations used during external processes are complex, and require significant time and manpower to setup and operate.
  • a feature of the cleaning method using direct steam injection disclosed herein is that this type of process combines the advantages of on-line / plant heat and off-line / external heat processes, offering a method of external heating that results in a greatly simplified equipment setup, while at the same time allowing process monitoring equipment to be installed inside the steam generators during the cleaning.
  • the specific advantages of the direct steam injection cleaning method, relative to traditional cleaning methods include: (1) greatly simplified equipment configuration, including a simple method of external heating, (2) shorter set-up times and reduced manpower requirements, (3) shorter demobilization times, (4) steam generator access prior to the cleaning to facilitate installation of online corrosion monitoring equipment and coupons inside the steam generators, and (5) ability to perform liquid sampling without needing to partially drain the steam generator as described in Remark.
  • direct steam injection has not been used as a means for heating during cleaning of nuclear steam generators and related applications due to concerns that direct steam injection could lead to damage of vessel internals as a result of large thermal gradients or cavitation induced in the vicinity of steam injection equipment and/or vibration of steam injection equipment inside the vessel being cleaned.
  • the direct steam injection method and apparatus disclosed herein have addressed these concerns and provide a means for introducing steam directly into nuclear steam generators or other vessels during cleaning applications with low thermal gradients in the vicinity of steam injection (e.g ., below acceptable thermal gradients defined in design basis documents for nuclear steam generators or other heat exchanger equipment), and with minimal cavitation or vibration induced by steam flow, thereby preventing mechanical damage to vessel internals.
  • the method of cleaning with direct steam injection is applicable to conventional chemical cleaning processes as described in Frenier and the EPRI/SGOG references, as well as cleaning options such as those described in Rootham I, Rootham II and Varrin.
  • the latter two patents describe uses of advanced "scale conditioning agents.”
  • the method described herein may also be used with dispersant or decontamination solutions, or any other processes for cleaning heat exchangers or similar vessels, or removing waste such as nuclear waste from similar vessels or fluid systems where temperature control is required or helpful.
  • a method according to the invention includes at least all features and method steps of appended independent claim 1.
  • a heat exchanger for removing deposits and impurities from the secondary side of a heat exchanger that will typically include the steps of removing a volume of working fluid from the secondary side of the heat exchanger sufficient to expose an access penetration; installing a temporary adapter in the exposed access penetration, the adapter being configured for direct steam injection; injecting steam through the temporary adapter and into the secondary side of the heat exchanger, wherein the injected steam heats the heat exchanger and residual fluid to a target cleaning temperature range; and maintaining the heat exchanger and the residual fluid within the cleaning target temperature range during a cleaning period.
  • the residual fluid may include one or more of the working fluid, chemical cleaning compounds, chemical cleaning solutions, chemical cleaning solvents and water.
  • Some embodiments of the method may include injecting a gas into the residual fluid at a rate sufficient to induce gas sparging within the residual fluid, the gas being selected from a group consisting of steam, non-condensible gases and mixtures thereof and may be injected through an inlet provided by a vessel blowdown system and/or a temporary adapter.
  • a cleaning solution may be formed in the heat exchanger by introducing a volume of water into the secondary side of the heat exchanger and introducing a predetermined quantity of one or more chemical cleaning reagents into the water. During the cleaning process an additional quantity of one or more chemical cleaning reagents may be introduced to maintain or improve the effectiveness of the cleaning.
  • the composition of the cleaning solution may be altered during the cleaning period to provide, for example, rapid initial removal of deposits followed by a more controlled or gentle removal to reduce damage to the underlying structure.
  • the volume of water introduced may be selected whereby the addition of steam condensate and the chemical cleaning reagent(s) will not exceed a predetermined secondary side volume.
  • the invention includes controlling a steam injection rate to produce a predetermined heating profile in the residual fluid, thereby reducing the likelihood of thermal shock and associated damage within the vessel being cleaned.
  • the steam utilized for the direct injection may include saturated steam, superheated steam and mixtures thereof provided through one or more temporary adapters sequentially or in combination to achieve the desired heating performance.
  • a controller may also be provided for controlling steam temperature and steam pressure of the injected steam to compensate for variations in liquid static head pressure range within the heat exchanger during the heating and/or cleaning period.
  • vents or purge valves may be provided on the heat exchanger for controlling the static head pressure within a desired range during the process.
  • inventions of the method may include admixing one or more non-condensible gas(es) with the steam to form a combined gas stream that may then be injected into the secondary side of the heat exchanger. It is anticipated that the non-condensible gas(es) may comprise between 0.01 and 3% of the combined gas stream in such an embodiment.
  • compositions and compounds may be utilized for cleaning the secondary side of a heat exchanger. It is anticipated that acceptable cleaning solutions may include one or more components selected from chelants, complexing agents and reducing agents, the selection being determined in part by the nature of the deposits being removed, the underlying material and the particular conditions and requirements of the heat exchanger being cleaned.
  • Complexing agents may include, for example, EDTA, NTA, organic acids and mixtures thereof.
  • a system according to the invention comprises at least all features of appended independent claim 11.
  • a first adapter configured for temporary installation on a first conventional access penetration provided on the heat exchanger, the first adapter including a flange configured for mating to the access penetration; means for securing the adapter to the access penetration including, for example, bolts, gaskets and alignment structures; a conduit or passage for introducing or removing fluid through the access penetration; and an opening provided within the secondary side of the heat exchanger.
  • the system will also typically include a steam source configured for connection to the conduit and a controller configured for controlling the steam injection into the secondary side of heat exchanger through the adapter.
  • the outlet within the heat exchanger may be configured as an eductor, as multiple eductors, as a nozzle, as a regulator-type direct steam nozzle, a sparger or any other configuration or combination that provides suitable mixing of the steam and the residual liquid.
  • Other example embodiments may include a plurality of adapters that are arranged and configured for inducing fluid flow within the secondary side of the heat exchanger from, for example, a first adapter to a second adapter.
  • An example embodiment of the method as applied to a heat exchanger typically includes the steps of taking the heat exchanger out of service, draining the working fluid from the secondary side of the heat exchanger, removing an access cover from at least one secondary side access penetration, installing a temporary adapter on the opened access penetration, the temporary adapter being arranged and configured for heating the heat exchanger system by injection of a heating fluid (e.g ., steam and/or other gas) into the secondary side of the heat exchanger, initiating supply of the heating fluid before, during or after filling the heat exchanger, supplying a volume of heating fluid to the heat exchanger sufficient to heat a cleaning agent to a temperature sufficient to achieve an increased cleaning rate within the heat exchanger, terminating the heating fluid injection after the cleaning is complete, draining the cleaning agent from the heat exchanger, removing the temporary adapter(s) from
  • a heating fluid e.g ., steam and/or other gas
  • inventions of the method may include: (1) additional steps including introducing a quantity of at least one cleaning chemical reagent, in either individual or premixed form, into the working liquid (e.g ., water) resident in the heat exchanger to form the liquid cleaning agent in situ , and (2) continuing to add the heating fluid continuously or intermittently during the cleaning process to compensate for energy lost by heat transfer to the surroundings.
  • working liquid e.g ., water
  • this introduction of the cleaning chemical reagent may be made directly into the heat exchanger through one of the temporary adapters or by an "external" introduction into one or more existing lines including, for example, drain lines, feed lines and/or blowdown lines that are normally connected to the heat exchanger.
  • the residual volume of working liquid within the heat exchanger should be adjusted or maintained at a volume that will accommodate the anticipated volume of steam condensate and chemical cleaning agents being introduced in order to avoid overfilling the heat exchanger.
  • Monitoring of liquid volume or level may be achieved by the existing plant instrument or by temporary instrumentation.
  • some form of volume and/or pressure relief may be incorporated to maintain the liquid volume and/or the pressure in the heat exchanger within target values for the duration of the cleaning operation.
  • the method and apparatus includes controlling the flow rate of the heating fluid to achieve and maintain a target heating rate or temperature range for the heat exchanger and/or the cleaning agent(s).
  • the heating fluid flow may be substantially constant, continuous but with a variable flow rate, and/or intermittent.
  • Example heating fluids may include, for example, superheated steam and/or saturated steam. It is anticipated that saturated steam from less than 0.69 to 17 bar gauge (10 psig to 250 psig) and/or steam superheated by up to about 55.6°C (100°F) would be suitable for use in practicing example embodiments of the disclosed method.
  • the steam temperature and pressure may be adjusted, for example, by increasing steam pressure to accommodate the liquid static head pressure in the heat exchanger as level increases, or by decreasing the steam flow rate, temperature or superheat after achieving the target temperature range.
  • An example apparatus for practicing the disclosed methods includes a temporary adapter configured for attachment to a conventional heat exchanger access penetration and may further include a flange that mates to the conventional access penetration, appropriate gasket(s) and fasteners for forming a fluid tight seal between the temporary adapter and the access penetration, one or more penetrations provided on the temporary adapter through which heating fluid and other materials may be supplied and/or removed from the heat exchanger, and one or more nozzles for delivering the heating fluid into the heat exchanger.
  • the nozzle(s) may be configured in a number of ways including, for example, an eductor, a regulator-type direct steam nozzle, a sparger, or a combination thereof.
  • the disclosed method provides for a number of apparatus configurations including those in which the total heating fluid nozzle area is adjustable (e.g ., through valving, disc travel or other means) or those in which the heating fluid is injected into a short hose or pipe connected to one adapter on the heat exchanger and allowed to recirculate back into the steam generator through a second adapter by configuring a simple recirculation loop that can, for example, be located inside the containment vessel.
  • the latter configuration is particularly well-suited if the heating fluid is supplied through an eductor nozzle mounted in the short recirculation line.
  • constituents used in formulating the cleaning agent may be injected into the recirculation loop (e.g., one or more cleaning agents used in traditional chemical cleaning processes, a scale conditioning agent, a dispersant and/or a decontamination agent).
  • an apparatus for practicing the disclosed method may provide for gas injection to provide additional mixing and/or to reduce the potential for cavitation or vibration of steam generator equipment.
  • the system according to the present invention includes such a gas injection.
  • the gas or gases utilized may be injected in a substantially constant, continuous but with a variable flow rate, and/or intermittent manner.
  • the gas may be injected with the heating fluid or through an existing plant system such as the steam generator bottom blowdown system.
  • Nitrogen, argon, other inert gases or mixtures thereof may be used when reducing conditions are required during the cleaning.
  • Air, oxygen, ozone, other oxidizing gases or mixtures thereof may be used when oxidizing conditions are required.
  • gas flow rate 0.14 to 2.8 m 3 /min (5 to 100 cfm) would be appropriate, and more preferably 0.14 to 0.84 m 3 /min (5 to 30 cfm).
  • This target flow rate range may be corrected for system overpressure.
  • Other embodiments may include, for example, electrochemical corrosion monitoring or periodic sampling of cleaning solutions in order to reduce the risk of damage to the vessel during the cleaning process.
  • the method involves allowing to plant to cool down in a conventional manner with no holds in Mode 5 until the temperature of the reactor coolant system on the primary side is less than about 40°C.
  • the steam generator is then drained.
  • One or more of the typically installed access penetration covers (called “hand hole” covers, “eye hole” covers, inspection port covers and the like) are removed.
  • the removed covers are replaced with temporary adapters wherein said adapters may be configured to permit (1) heating and maintaining the temperature of the steam generator and chemical cleaning solvents by injection of steam directly into the secondary side of the steam generator, (2) corrosion monitoring using CMS probes and coupons, (3) monitoring temperature or liquid level if other means such as typical plant instruments are not available, and/or (4) sampling the solvent to evaluate its chemical properties and the progress of the cleaning.
  • a small amount of non-condensible gas may be admixed with the injected steam to reduce the potential for steam cavitation at the nozzle and/or nozzle vibration. Steam cavitation at the nozzle is undesirable in that it may increase erosion wear of the steam injection nozzle / eductor and may also result in unacceptable noise levels during the process.
  • nitrogen, argon, or other inert gases may be used when reducing conditions are required during the cleaning.
  • Air, oxygen or ozone may be used when oxidizing conditions are required.
  • all of the above features could be incorporated into a single access penetration adapter. This is in contrast to the need to use up to ten (10) or more adapters for some external heat processes.
  • direct steam injection into the steam generator has not been used for heating required during the cleaning of nuclear steam generators by conventional chemical cleaning solvents or more recently developed scale conditioning agents.
  • direct steam injection is an extremely efficient technique for heating liquids as described in U.S. Patent No. 5,066,137 to King ("King") and references such as Schroyer, J. A., "Understanding the Basics of Steam Injection Heating", Chemical Engineering Progress, May 1997 and Pick, "Consider Direct Steam Injection for Heating Liquids," Chemical Engineering, June 1982 .
  • Direct steam injection heating results in reduced energy consumption compared to typical off-line / external heat processes because there is no hot condensate return as would occur in an indirect heat exchanger heated by steam in an external heating loop.
  • the design of the steam injection system for a nuclear steam generator can include one of several types of injectors including a sparger or venturi eductor. (More than one injector may be used in parallel for each SG.)
  • a "modulating" type injection system or steam mixing tee could also be used if a pump were located inside containment and forced flow from one adapter penetration through temporary piping or hoses to the steam injector penetration. This pumping arrangement is far simpler than the typical recirculation pump arrangement used to recirculate the solvents to a process equipment area often located more than 457 m (1,500 feet) from the steam generator. Hose lengths of as short as only 3 to 4.6 m (10 to 15 feet) may be required.
  • a steam source is connected.
  • the steam source could be a portable boiler set up outside, but close to, containment, requiring less than 37 to 46 m 2 (400 to 500 ft2) of lay down area as opposed to 9,300 m 2 (100,000 ft2) or more for a typical external heat process system.
  • steam from an adjacent power plant could be used. Either way, a steam line is routed from the steam source through a single containment penetration or through what is known as the equipment hatch, and attached to the adapter.
  • the steam line may be a flexible steam line or hard piping, but flexible steam line used in dozens of other industries and applications is preferred.
  • a gas source could be connected to the steam line to allow for pressure checks, but more importantly to provide a small concentration (a few percent) of gas comingled with the steam to suppress the potential for cavitation in the line or at the nozzle outlet. This gas may also be used to sweep residual steam out of the steam line when steam is no longer required.
  • This line is typically a 5.1 to 10.2 cm (2 inch to 4 inch) diameter line that draws liquid from the bottom of the steam generator during normal power operations in part to prevent the buildup of soluble and insoluble impurities in a RSG.
  • the blowdown line or pipe inside the SG is typically a perforated pipe which provides good distribution of chemicals and/or gas for sparging if the flow rate is controlled to a particular value.
  • connections to the blowdown line facilitate (1) introduction of premixed chemical cleaning solvent or concentrates, as well as for chemical makeup or replenishment during the cleaning process and (2) supply of gas for sparging to assist in mixing in the steam generator during heat up, cleaning and cool down.
  • Rinse water may also be injected via the blowdown system or the normal plant primary or auxiliary feedwater systems.
  • the chemical cleaning solvents may be drained to storage tanks via the connection to the blowdown system under gravity or by using the temporary chemical injection pump operating in reverse.
  • the steam generator is first partially filled with water using either conventional plant systems (auxiliary feedwater), or via blowdown from an external water source.
  • the initial fill level is selected so that the final (end of cleaning) fill level is reached after accumulation of: (1) the steam condensate initially injected to raise the temperature of the fluid inside the steam generator, (2) the chemical agents added to clean the steam generators, (3) the additional condensate from the steam injected to maintain the temperature of the steam generator and (4) any additional cleaning solvent injected during the cleaning application.
  • the final fill level is likely to be about 7.6 to 10.2 m (300 to 400 inches) above the bottom of the steam generator or "tubesheet.”
  • the final volume of liquid in such an application is typically 57 to 68 m 3 (15,000 to 18,000 gallons).
  • the initial water level may be on the order of 5.1 to 7.6 m (200 to 300 inches), and the final full volume may be different than the ranges stated above.
  • the steam source is then energized and steam, with or without a small percentage of non-condensible gas at up to 2% of the steam mass flow rate, is supplied directly to the steam generator.
  • steam with or without a small percentage of non-condensible gas at up to 2% of the steam mass flow rate, is supplied directly to the steam generator.
  • heating time would be on the order of four to seven hours with 8.6 bar saturated steam at 907 kg/h (125 psig at2,000 pounds per hour).
  • the pumping action of the eductor results in a jet pumping action that assists in maintaining uniformity in temperature on the secondary side of the SG.
  • Testing has also shown that with an eductor design, the induced pumping action and admixing of the surrounding fluid with the steam within or very near the eductor results in the fluid temperatures along the eductor jet centerline beyond approximately 5 to 7 eductor outlet diameters that are typically less than 5.6°C (10°F) higher than that of the bulk fluid.
  • a typical eductor outlet diameter is 2 to 5 cm.
  • the temperature of the fluid adjacent to the eductor housing perpendicular to the jet axis is essentially at the bulk fluid temperature due to fluid entrainment with the exiting liquid jet.
  • Gas sparging is optionally provided through a gas sparger integral to the adapter or via blowdown piping to maintain uniform chemical and temperature conditions in the steam generator.
  • chemical cleaning agents are introduced via blowdown system with a chemical injection pump. It may also be desirable to perform steam injection in parallel with the initial fill water or chemical injection for some applications.
  • samples of the solvent are periodically taken directly from a sample port on the adapter. There is no need to drain the steam generator to acquire samples. The results of the sample analysis are used to monitor the process per the recommendations of the previously cited references. Corrosion is also monitored in real time with an electrochemical CMS, thus minimizing the risk of unacceptable corrosion.
  • the solvent may be drained back through the plant blowdown system, and rinses are performed.
  • the rinses can be applied at a temperature lower than the solvent temperature to assist in cooling.
  • the invention described herein combines advantages of on-line cleaning processes such as equipment simplicity, reduced setup time, etc. with the advantages of external heat processes such as the ability to perform corrosion monitoring and obtain liquid samples directly from the secondary side of the steam generator.
  • advantages can be achieved with no active equipment (pumps, valves, controls, etc .) in containment, and only one interconnection from outside containment to inside containment (the steam line) per steam generator. If it is desirable to clean two or more steam generators in parallel, separate steam lines may be provided to each steam generator.
  • the direct steam injection method and apparatus disclosed herein reduce or eliminate concerns related to potential damage to internals in SGs or other vessels during cleaning applications as a result of excessive thermal gradients, cavitation, and/or vibration of steam injection equipment.
  • heating the steam generators by direct steam injection would be equally applicable to conventional chemical cleaning solvents such as those described by Frenier (chelant, organic acid, amine and mineral acid based processes) and the EPRI/SGOG references, as well as scale conditioning agents described in several of the above-referenced patents, or any other cleaning process where temperature control is required. It is further recognized that heating the steam generators by direct steam injection can be combined with mechanical cleaning methods performed before, simultaneously with, or after the chemical cleaning.
  • the steam generator (10) is connected to the external process system located outside of the plant using temporary adapters (17).
  • the steam generator includes a secondary side (11), a primary side (12), and a U-tube bundle (13).
  • the temporary adapters (17 and 18) are installed after the plant has been shut down, and the SGs drained. No connections are generally made to existing plant systems such as blowdown (19), feedwater (14), or the steam line (16).
  • a CMS system is also installed adjacent to the steam generator (21)
  • Equipment in the process area outside of containment can include pumps, boilers, cooling towers, control vans, heat exchangers, mix tanks, mix pumps, berms to contain spills and leaks, valves, and hundreds of other fittings and parts.
  • Up to six or more temporary containment penetrations (20) may be required for the external process system to interconnect with the steam generators. This includes penetrations for air to control valve positioners, nitrogen for inerting the system, and tube sheet drain lines.
  • the typical solvent recirculation pipe sizes at the penetrations are 10.2 to 15.2 cm (4 to 6 inches) in diameter, and diameters of up to 20.3 cm (8 inches) or more may be required.
  • Equipment in containment can include numerous hoses, pumps, piping, valves, flanges, leak prevention devices and catch basins (to contain spills and leaks). To operate the equipment depicted in FIG. 1 , up to 30 personnel or more per shift are usually required.
  • the steam generator (10) is connected to a temporary steam line (26) via an SG penetration adapter (17), preferably at a 10.2 to 20.3 cm (4 to 8 inch) "hand hole penetration.”
  • the typical plant cover on this access penetration would have been previously removed after cooling the SG to about 40°C or lower, and the steam generator having been drained using conventional plant procedures and systems.
  • the adapter may be further configured to allow for insertion of on-line corrosion monitors (21) or other instrument such as temperature monitoring device such as a thermocouple.
  • a single adapter is used, but two or more may be required if the penetrations are smaller than 10.2 to 20.4 cm (4 to 8 inches) or if components internal to the SG restrict access.
  • a single eductor temporary adapter (40) consists of a mounting flange (41) that mates to the existing vessel penetration, a penetration in the flange (42) for a rigid delivery tube (43) through which steam is supplied, a single eductor (44) and a heating fluid supply connection (45).
  • the eductor consists of a heating fluid inlet (46), suction inlets for entraining the vessel fluid (47), and an outlet (48).
  • a multiple eductor temporary adapter (50) consists of a mounting flange (51) that mates to the existing vessel penetration, a penetration in the flange (52) for a rigid delivery tube (53) through which steam is supplied, multiple eductors (54) and a heating fluid supply connection (55).
  • Each eductor consists of a heating fluid inlet (56), suction inlets for entraining the vessel fluid (57), and an outlet (58).
  • FIG. 5 a typical installation of a single eductor temporary adapter (40) is shown.
  • the adapter flange (41) mounts to the steam generator (10) at an existing penetration (61) using bolts (62) and a gasket for sealing (63).
  • a modulating type direct steam injection device would be mounted as part of or adjacent to the adapter, and a pump in containment would be used to transport fluid from the steam generator to a vessel in which direct steam injection would occur.
  • the combined stream water or cleaning solution from the steam generator, combined with injected steam
  • connections through an existing plant system outside of the containment building, preferably in the blowdown line (19), are made for introduction of water and/or chemicals into the SG.
  • the connection(s) also serve to allow for introduction of gas through blowdown piping to promote mixing, or establish oxidizing or reducing conditions in the steam generator as appropriate.
  • Alternatives for introducing the water or cleaning chemicals include introduction via a connection in the plant auxiliary feedwater system, as shown in FIG. 2 .
  • water is introduced into the steam generator. Level during the entire process may be monitored by existing plant instrumentation or by temporary level instruments. In the preferred embodiment, this water is demineralized or other high purity water (condensate water), supplied to the SGs using plant systems and procedures, e.g. via the auxiliary feedwater system.
  • the initial fill level is selected such that the final fill level after accumulation of condensed steam and the introduction of the chemical cleaning agents will be the target level for the cleaning. This is usually just over the top of the tube bundle but below critical steam generator components such as the "girth weld" (32), a weld known to be susceptible to cracking if corrosion in the form of pitting were to occur as a result of the secondary side cleaning.
  • Overfilling the SG also results in the potential for spill over of chemical and/or foam generated during the process into plant systems such as the feedwater system through the feedwater header. Overfilling also creates more waste.
  • the source of steam is preferably a portable package boiler (22) but may also be a nearby power plant. Make-up water is provided to the boiler (30).
  • the injection device affixed to the steam generator may be an eductor or sparger (27).
  • the time required to preheat the SG and water to say 90°C (195°F), a conventional application temperature for the EPRI/SGOG process described in the EPRI reference, would be approximately 6 hours based on a flow of 907 kg/hr (2000 pounds per hour) of 8.6 bar (125 psig) saturated steam (177°C or 352°F).
  • this heat up time represents a small fraction of the overall cleaning time, and adds little or no time at all if the filling, heating and chemical injections were to occur simultaneously.
  • the liquid exiting the eductor by entrainment with the steam is not at this pressure, but at a pressure equivalent to the water column head pressure in the SG.
  • the temperature a few nozzle diameters from the eductor has been measured to be less than 5.6°C (10°F) above that of the bulk fluid.
  • a small amount of non-condensible gas is also admixed with the steam at the steam supply to reduce noise / vibration and risk of any cavitation damage to the eductor device or adjacent vessel internals.
  • the volume of non-condensible gas is less than 1%, but in some instances it could range as high as 3% or more.
  • the overall flow of steam is controlled by a pressure regulating valve (28) external to containment.
  • the present method for heating the SG and the fill water is compatible with a number of cleaning chemical solvents including the EPRI/SGOG EDTA-based solvents described in the previous references.
  • This solvent uses EDTA, hydrazine, ammonium hydroxide and a corrosion inhibitor.
  • a concentrated formulation of this solvent (30-40% as EDTA) is then pumped from a holding tank (24), through hoses, via a pump (25) that is in turn connected to preferably the blowdown connection.
  • the final concentration of the solvent in the SG may be from 4 to 25% as EDTA.
  • the pumping rate is controlled so as to allow its temperature in the SG to be maintained by the steam injection.
  • the present method is also compatible with scale conditioning agents and other amine, organic acid, mineral acid or chelating / complexing agent based deposit removal solvents for oxides or metallic species.
  • Mixing during or after injection of the concentrate may be enhanced by either continuous sparging with gas via the blowdown system (19), comingling the concentrate with gas during injection, or after solvent injection is complete. Mixing may also be achieved by transferring liquid between heat exchangers when more than one heat exchanger is being cleaned at the same time.
  • the SG temperature is maintained by either periodic injections of steam or by injection of steam at a reduced rate, lower pressure, or lower temperature. All of these parameters are controlled from outside containment at the boiler.
  • Samples of the solvent may be obtained directly from the SG without draining the boiler (22) or by temporarily stopping sparging and sampling via an exiting connection in the blowdown system (23, 23a, 23b). If required, make-up chemical constituents may be added via blowdown using the injection pump (25). Examples would include replenishing the chemical agents, or makeup of critical chemical species (e.g., corrosion inhibitor or reducing agent in the case of reductive dissolution processes). Partial draining to the waste tanks (29) can be used to accommodate the volumes of makeups or replenishments. Note that FIG. 2 shows fewer waste tanks than FIG. 1 . This is because the waste volumes are lower in this process because no recirculation system is required. The recirculation system typically accounts for 5 to 25% of the overall system volume during an external heat cleaning process. This has the advantage of reducing waste treatment costs, which for nuclear steam generator cleanings can exceed US$8 per liter (US$30 per gallon) or several million dollars per application.
  • the plants steam system valves such as the atmospheric relief valves (31) could be periodically opened. This is standard procedure for chemical cleaning.
  • the gas may contain species such as nitrogen (an asphyxiant), amines such as ammonia or morpholine (mildly toxic) and hydrazine (a carcinogen). Therefore, it is an objective of this invention to reduce the flowrate of gas used for mixing or to establish reducing or oxidizing conditions as appropriate during the cleaning process.
  • Inert gases such as nitrogen or argon are typically used to promote reductive dissolution during cleaning processes (i.e., to remove among other species magnetite or other oxides).
  • Air, oxygen or ozone may be used to promote oxidative dissolution (i.e., to remove metals such as copper).
  • Gas sparging rates via the blowdown system are set so as to promote good mixing and temperature uniformity in the SGs, while at the same time minimizing environmental emissions.
  • the preferred range for the present invention is 0.15 to 2.8 m 3 /min (5 to 100 cfm). Although this rate is far below that reported in some prior art, testing and analyses has shown this rate is sufficient to "turnover" the secondary side of an RSG in about 10 minutes or less.
  • the sparging may also be continuous or intermittent. In intermittent applications, the time during which sparging is active should be a minimum of one volume turnover ( e.g ., 6 minutes at 0.85 m 3 /min (30 cfm)).
  • the process and equipment is applicable to conventional chemical cleaning processes, scale conditioning agents, dispersant or decontamination solutions, or any other processes for cleaning heat exchangers or similar vessels where temperature control is required or helpful.
  • Others skilled in the art would recognize that while the preferred embodiment described herein involves injecting chemicals through the plant blowdown system, an alternative would be to inject chemicals through a steam generator adapter, via the auxiliary feedwater system, or via another appropriate access point.

Landscapes

  • Engineering & Computer Science (AREA)
  • Mechanical Engineering (AREA)
  • Physics & Mathematics (AREA)
  • General Engineering & Computer Science (AREA)
  • Thermal Sciences (AREA)
  • Chemical & Material Sciences (AREA)
  • Combustion & Propulsion (AREA)
  • High Energy & Nuclear Physics (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Materials Engineering (AREA)
  • Metallurgy (AREA)
  • Organic Chemistry (AREA)
  • Cleaning By Liquid Or Steam (AREA)

Claims (14)

  1. Procédé de retrait de dépôts et d'impuretés du côté secondaire (11) d'un échangeur de chaleur (10) comprenant les étapes consistant à :
    retirer un volume de fluide de travail du côté secondaire (11) de l'échangeur de chaleur (10) suffisant pour exposer une pénétration d'accès ;
    installer un adaptateur temporaire (17) dans la pénétration d'accès exposée, l'adaptateur étant conçu pour diriger une injection de vapeur ;
    introduire un volume d'eau dans le côté secondaire (11) de l'échangeur de chaleur (10) ;
    introduire une quantité prédéterminée d'un réactif de nettoyage chimique dans l'eau pour former une solution de nettoyage du côté secondaire (11) de l'échangeur de chaleur (10), le réactif de nettoyage chimique étant sélectionné dans un groupe constitué d'agents chélateurs, d'agents complexants, d'agents réducteurs et de leurs mélanges ;
    injecter de la vapeur à travers l'adaptateur temporaire (17) et dans le côté secondaire (11) de l'échangeur de chaleur (10) de façon à chauffer l'échangeur de chaleur et un fluide résiduel à une plage de température de nettoyage ; et
    caractérisé par l'étape consistant à :
    maintenir l'échangeur de chaleur (10) et le fluide résiduel à l'intérieur de la plage de température cible de nettoyage pendant une période de nettoyage au moyen de la vapeur injectée (16) par une régulation d'un débit de la vapeur injectée.
  2. Procédé selon la revendication 1, dans lequel le fluide résiduel comprend un constituant sélectionné dans un groupe constitué d'un fluide de travail, de composés de nettoyage chimiques, de solutions de nettoyage chimiques, de solvants de nettoyage chimiques, d'eau et de leurs mélanges.
  3. Procédé selon l'une ou l'autre des revendications 1 ou 2, comprenant en outre l'étape consistant à :
    injecter un gaz dans le fluide résiduel à un débit suffisant pour induire un barbotage de gaz à l'intérieur du fluide résiduel, le gaz étant sélectionné dans un groupe constitué de vapeur, de gaz non condensables et de leurs mélanges.
  4. Procédé selon l'une quelconque des revendications 1 à 3, dans lequel le gaz est injecté dans le fluide résiduel à travers un orifice d'entrée sélectionné dans un groupe constitué d'un système d'évacuation de cuve (19) et de l'adaptateur temporaire (40).
  5. Procédé selon la revendication 1, comprenant en outre l'étape consistant à : introduire une quantité supplémentaire du réactif de nettoyage chimique pendant la période de nettoyage.
  6. Procédé selon l'une ou l'autre des revendications 1 ou 5, dans lequel le volume d'eau introduit est sélectionné, ce par quoi l'addition de condensat de vapeur et du réactif de nettoyage chimique ne dépassera pas un volume prédéterminé de côté secondaire (11).
  7. Procédé selon l'une quelconque des revendications 1 à 6, comprenant en outre l'étape consistant à : réguler un débit d'injection de vapeur pour produire un profil de chauffe prédéterminé dans le fluide résiduel.
  8. Procédé selon l'une quelconque des revendications 1 à 7, dans lequel la vapeur est sélectionnée dans un groupe constitué de vapeur saturée, de vapeur surchauffée et de leurs mélanges.
  9. Procédé selon l'une quelconque des revendications 1 à 8, comprenant en outre l'étape consistant à : réguler la température de vapeur et la pression de vapeur de la vapeur injectée pour compenser des variations dans une plage de pression de charge statique de liquide à l'intérieur de l'échangeur de chaleur pendant la période de nettoyage.
  10. Procédé selon la revendication 1, dans lequel l'agent complexant est sélectionné dans un groupe constitué d'EDTA, de NTA, d'acides organiques et de leurs mélanges.
  11. Système de retrait de dépôts et d'impuretés d'un côté secondaire (11) d'un échangeur de chaleur (10), comprenant :
    un premier adaptateur (17) conçu pour une installation temporaire sur une première pénétration d'accès classique, le premier adaptateur comprenant en outre
    une bride conçue pour un accouplement avec la pénétration d'accès ;
    un moyen destiné à fixer l'adaptateur à la pénétration d'accès ;
    un conduit (26) destiné à introduire ou à évacuer un fluide à travers la pénétration d'accès ; et
    une ouverture disposée à l'intérieur du côté secondaire (11) de l'échangeur de chaleur (10) ;
    une source de vapeur (22) conçue pour un raccordement au conduit (26),
    une source de gaz conçue pour un raccordement au conduit ; et
    un dispositif de régulation conçu pour réguler l'injection de vapeur dans le côté secondaire (11) de l'échangeur de chaleur (10) à travers l'adaptateur (17),
    caractérisé en ce que :
    en utilisation, ledit système est conçu pour mélanger un gaz non condensable alimenté par la source de gaz à la vapeur alimentée par la source de vapeur (22) pour former un flux de gaz combiné dans le conduit à des fins d'injection dans la solution de nettoyage du côté secondaire de l'échangeur de chaleur, et le dispositif de régulation modifie un débit d'écoulement de vapeur dans la solution de nettoyage de façon à élever et à maintenir la solution de nettoyage à l'intérieur d'une plage de température ciblée.
  12. Système selon la revendication 11, dans lequel un orifice de sortie du conduit (26) est conçu en tant qu'un éjecteur.
  13. Système selon la revendication 11, dans lequel un orifice de sortie du conduit (26) est sélectionné dans un groupe constitué de buses de vapeur directe de régulateur, d'arroseurs, d'éjecteurs et de leurs combinaisons.
  14. Système selon la revendication 11, dans lequel le conduit (26) comprend une buse d'injection de vapeur conçue pour, en utilisation, entraîner une masse de fluide présente dans le générateur de vapeur (10) pendant une injection dans le côté secondaire (11) de l'échangeur de chaleur du flux de gaz combiné à travers la buse d'injection de vapeur, de sorte qu'un entraînement de ladite masse de fluide favorise un mélange du flux de gaz combiné avec la masse de fluide et garantisse le fait que le flux de gaz combiné éjecté de la buse de vapeur soit sensiblement en équilibre thermique avec la masse de fluide.
EP09831147.5A 2008-12-03 2009-12-03 Procédé de nettoyage chimique et système à injection de vapeur Active EP2356376B1 (fr)

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US11971908P 2008-12-03 2008-12-03
PCT/US2009/066652 WO2010065785A1 (fr) 2008-12-03 2009-12-03 Procédé de nettoyage chimique et système à injection de vapeur
US12/630,729 US8459277B2 (en) 2008-12-03 2009-12-03 Chemical cleaning method and system with steam injection

Publications (3)

Publication Number Publication Date
EP2356376A1 EP2356376A1 (fr) 2011-08-17
EP2356376A4 EP2356376A4 (fr) 2018-02-28
EP2356376B1 true EP2356376B1 (fr) 2019-08-28

Family

ID=42233617

Family Applications (1)

Application Number Title Priority Date Filing Date
EP09831147.5A Active EP2356376B1 (fr) 2008-12-03 2009-12-03 Procédé de nettoyage chimique et système à injection de vapeur

Country Status (2)

Country Link
EP (1) EP2356376B1 (fr)
WO (1) WO2010065785A1 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11469006B2 (en) * 2016-08-04 2022-10-11 Dominion Engineering, Inc. Suppression of radionuclide deposition on nuclear power plant components

Families Citing this family (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN102537930B (zh) * 2010-12-17 2015-04-01 冯伟忠 直流锅炉的清洗方法
CN102169112B (zh) * 2010-12-29 2013-04-24 中国科学院广州能源研究所 一种用于天然气水合物低剂量抑制剂研究的装置和方法
CN104088623B (zh) * 2014-06-19 2015-05-27 中国石油大学(华东) 深水气井测试用水合物自动防治装置与防治方法
CN104343416B (zh) * 2014-10-24 2016-08-17 中国石油大学(华东) 井下节流阀、深水气井测试***及测试方法
CN104534919B (zh) * 2014-11-24 2016-03-16 河南巨龙生物工程股份有限公司 一种同时进行发酵罐盘管除垢与检漏的方法
CN105363712B (zh) * 2015-11-24 2019-01-18 中国航空工业集团公司沈阳飞机设计研究所 一种飞机表面蒸汽清洗***
JP6828195B2 (ja) * 2017-12-29 2021-02-10 ジョイント ストック カンパニー アトムエネルゴプロエクトＪｏｉｎｔ Ｓｔｏｃｋ Ｃｏｍｐａｎｙ Ａｔｏｍｅｎｅｒｇｏｐｒｏｅｋｔ パージ運転およびドレネージとの二重回路原子炉の蒸気発生装置

Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5425814A (en) * 1991-12-10 1995-06-20 Serv-Tech, Inc. Method for quick turnaround of hydrocarbon processing units

Family Cites Families (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
DE389883C (de) * 1924-02-09 G & J Weir Ltd Dampfstrahlwasservorwaermer
YU40938B (en) * 1978-12-28 1986-08-31 Westinghouse Electric Corp Device for vemoving mud sediments from a steam generator
US4273076A (en) * 1978-12-28 1981-06-16 Westinghouse Electric Corp. Steam generator sludge lancing apparatus
US4492186A (en) * 1982-08-23 1985-01-08 Proto-Power Management Corporation Steam generator sludge removal method
US4581074A (en) * 1983-02-03 1986-04-08 Mankina Nadezhda N Method for cleaning internal heat transfer surfaces of boiler tubes
US4676201A (en) * 1984-07-25 1987-06-30 Westinghouse Electric Corp. Method and apparatus for removal of residual sludge from a nuclear steam generator
US5066137A (en) * 1991-03-04 1991-11-19 King Leonard T Steam injection and mixing apparatus
US5257296A (en) * 1991-10-25 1993-10-26 Buford Iii Albert C Steam generator chemical solvent mixing system and method
US5507306A (en) * 1993-12-23 1996-04-16 Howmet Corporation Cleaning apparatus and method for cleaning internal airfoil cooling passages
CA2491960C (fr) * 2002-07-09 2011-08-16 Clyde Bergemann, Inc. Appareil de ramonage rotatif multi-support et systeme de nettoyage de chaudiere industrielle automatique
DE102004054471B3 (de) * 2004-11-11 2006-04-27 Framatome Anp Gmbh Reinigungsverfahren zur Entfernung von Magnetit enthaltenden Ablagerungen aus einem Druckbehälter eines Kraftwerks

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5425814A (en) * 1991-12-10 1995-06-20 Serv-Tech, Inc. Method for quick turnaround of hydrocarbon processing units

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11469006B2 (en) * 2016-08-04 2022-10-11 Dominion Engineering, Inc. Suppression of radionuclide deposition on nuclear power plant components

Also Published As

Publication number Publication date
WO2010065785A1 (fr) 2010-06-10
EP2356376A4 (fr) 2018-02-28
EP2356376A1 (fr) 2011-08-17

Similar Documents

Publication Publication Date Title
US8459277B2 (en) Chemical cleaning method and system with steam injection
EP2356376B1 (fr) Procédé de nettoyage chimique et système à injection de vapeur
US5764717A (en) Chemical cleaning method for the removal of scale sludge and other deposits from nuclear steam generators
US5841826A (en) Method of using a chemical solution to dislodge and dislocate scale, sludge and other deposits from nuclear steam generators
US6955706B2 (en) Liquid degassing system for power plant system layup
Rodríguez Corrosion control of nuclear steam generators under normal operation and plant-outage conditions: a review
US5257296A (en) Steam generator chemical solvent mixing system and method
US7302917B2 (en) Chemical cleaning of a steam generator during mode 5 generator shut down
US20100027731A1 (en) Bwr start up corrosion protection
Tatone et al. Steam generator tube performance. Experience with water-cooled nuclear power reactors during 1985
Drexler et al. Water chemistry operation experience and steam generator maintenance measures in PWRs
US20200312471A1 (en) Corrosion Mitigation Method for Carbon Steel Pipe
JP4183714B2 (ja) 炉内化学除染装置およびその除染方法
US20220102019A1 (en) Chemical decontamination method
Puzzuoli et al. Steam generator cleaning campaigns at Bruce A: 1993-1996
Little et al. Advanced Scale Conditioning Agent (ASCA) Applications: 2012 Experience Update
EP3494090B1 (fr) Suppression du dépôt de radionucléides sur des composants de centrale nucléaire
RU41510U1 (ru) Установка для периодической продувки горизонтального парогенератора
JP6691800B2 (ja) ニッケル付着量試験装置およびニッケル付着量試験方法
Amar Countermeasures for tube failures in pressurized water reactor steam generators
Poirier et al. SRNL Review And Assessment Of WTP UFP-02 Sparger Design And Testing
Crockett et al. “Low Temperature” FAC
Verma et al. Steam generators secondary side chemical cleaning at Point Lepreau using the Siemens high temperature process
Kamei et al. Experience on sodium removal from various components
CANDU CHEMICAL CLEANING OF THE BRUCE A STEAM GENERATORS

Legal Events

Date Code Title Description
PUAI Public reference made under article 153(3) epc to a published international application that has entered the european phase

Free format text: ORIGINAL CODE: 0009012

17P Request for examination filed

Effective date: 20101119

AK Designated contracting states

Kind code of ref document: A1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO SE SI SK SM TR

DAX Request for extension of the european patent (deleted)
RA4 Supplementary search report drawn up and despatched (corrected)

Effective date: 20180126

RIC1 Information provided on ipc code assigned before grant

Ipc: F28G 9/00 20060101ALI20180122BHEP

Ipc: F22B 37/54 20060101AFI20180122BHEP

Ipc: F22B 37/56 20060101ALI20180122BHEP

Ipc: F22B 37/00 20060101ALI20180122BHEP

Ipc: C23G 1/00 20060101ALI20180122BHEP

Ipc: F22B 37/52 20060101ALI20180122BHEP

Ipc: B08B 3/00 20060101ALI20180122BHEP

Ipc: F22B 37/48 20060101ALI20180122BHEP

RAP1 Party data changed (applicant data changed or rights of an application transferred)

Owner name: WESTINGHOUSE ELECTRIC COMPANY LLC

RIC1 Information provided on ipc code assigned before grant

Ipc: C23G 1/00 20060101ALI20190207BHEP

Ipc: F28G 1/16 20060101ALI20190207BHEP

Ipc: B08B 3/00 20060101ALI20190207BHEP

Ipc: F22B 37/48 20060101ALI20190207BHEP

Ipc: B08B 9/00 20060101ALI20190207BHEP

Ipc: F22B 37/52 20060101ALI20190207BHEP

Ipc: F22B 37/56 20060101ALI20190207BHEP

Ipc: F22B 37/54 20060101AFI20190207BHEP

Ipc: F22B 37/00 20060101ALI20190207BHEP

Ipc: C11D 11/00 20060101ALI20190207BHEP

Ipc: F28G 9/00 20060101ALI20190207BHEP

GRAP Despatch of communication of intention to grant a patent

Free format text: ORIGINAL CODE: EPIDOSNIGR1

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: GRANT OF PATENT IS INTENDED

INTG Intention to grant announced

Effective date: 20190329

GRAS Grant fee paid

Free format text: ORIGINAL CODE: EPIDOSNIGR3

GRAA (expected) grant

Free format text: ORIGINAL CODE: 0009210

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: THE PATENT HAS BEEN GRANTED

AK Designated contracting states

Kind code of ref document: B1

Designated state(s): AT BE BG CH CY CZ DE DK EE ES FI FR GB GR HR HU IE IS IT LI LT LU LV MC MK MT NL NO PL PT RO SE SI SK SM TR

REG Reference to a national code

Ref country code: GB

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: CH

Ref legal event code: EP

REG Reference to a national code

Ref country code: AT

Ref legal event code: REF

Ref document number: 1172863

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190915

REG Reference to a national code

Ref country code: IE

Ref legal event code: FG4D

REG Reference to a national code

Ref country code: DE

Ref legal event code: R096

Ref document number: 602009059650

Country of ref document: DE

REG Reference to a national code

Ref country code: NL

Ref legal event code: MP

Effective date: 20190828

REG Reference to a national code

Ref country code: LT

Ref legal event code: MG4D

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: NO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191128

Ref country code: HR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: SE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: FI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: PT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191230

Ref country code: LT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: NL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: BG

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191128

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: GR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191129

Ref country code: LV

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20191228

REG Reference to a national code

Ref country code: AT

Ref legal event code: MK05

Ref document number: 1172863

Country of ref document: AT

Kind code of ref document: T

Effective date: 20190828

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: TR

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

REG Reference to a national code

Ref country code: ES

Ref legal event code: FG2A

Ref document number: 2753437

Country of ref document: ES

Kind code of ref document: T3

Effective date: 20200408

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: RO

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: PL

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: EE

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: IT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: AT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: DK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: IS

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20200224

Ref country code: SM

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: SK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: CZ

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

REG Reference to a national code

Ref country code: DE

Ref legal event code: R097

Ref document number: 602009059650

Country of ref document: DE

PLBE No opposition filed within time limit

Free format text: ORIGINAL CODE: 0009261

STAA Information on the status of an ep patent application or granted ep patent

Free format text: STATUS: NO OPPOSITION FILED WITHIN TIME LIMIT

PG2D Information on lapse in contracting state deleted

Ref country code: IS

REG Reference to a national code

Ref country code: CH

Ref legal event code: PL

26N No opposition filed

Effective date: 20200603

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MC

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: SI

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LU

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191203

Ref country code: IE

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191203

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: LI

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191231

Ref country code: CH

Free format text: LAPSE BECAUSE OF NON-PAYMENT OF DUE FEES

Effective date: 20191231

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: CY

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MT

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

Ref country code: HU

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT; INVALID AB INITIO

Effective date: 20091203

PG25 Lapsed in a contracting state [announced via postgrant information from national office to epo]

Ref country code: MK

Free format text: LAPSE BECAUSE OF FAILURE TO SUBMIT A TRANSLATION OF THE DESCRIPTION OR TO PAY THE FEE WITHIN THE PRESCRIBED TIME-LIMIT

Effective date: 20190828

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: GB

Payment date: 20231229

Year of fee payment: 15

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: FR

Payment date: 20231219

Year of fee payment: 15

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: BE

Payment date: 20231219

Year of fee payment: 15

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: ES

Payment date: 20240110

Year of fee payment: 15

PGFP Annual fee paid to national office [announced via postgrant information from national office to epo]

Ref country code: DE

Payment date: 20231222

Year of fee payment: 15