ML081090293

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Pilgrim April 2008 Evidentiary Hearing - Intervenor Exhibit 18, GALL: NUREG-1801, Vol. 1, Rev. 1, Generic Lessons Learned (GALL) Report, September 2005, X1M-12 (10. Operating Experience, BWR Intergranular Stress); & XI M-96..
ML081090293
Person / Time
Site: Pilgrim
Issue date: 09/01/2005
From:
Office of Nuclear Reactor Regulation
To:
NRC/SECY/RAS
SECY RAS
References
50-293-LR, ASLBP 06-848-02-LR, Pilgrim-Intervenor-31, RAS J-61 NUREG-1801, Vol. 1, Rev. 1
Download: ML081090293 (10)
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NUE 1 V777,1e6"11 NUREG-1 801, Vol.!, Rev. 1 Generic Aging Lessons Learned (GALL) Report DOCKETED I I.RNR.

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OFFICE OF SECRETARY Pi1 I FMAKIN(r ANf-Summary Arl.il IrlIrATIONRR .TAFF Manuscript Completed- September 2005 Date Published: September 2005 Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

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.'7.-. CorrectiveActions: When measured water chemistry parameters are outside the specified range, corrective actions are taken to bring the pararneter back within the acceptable range and within the time period specified in the EPRI water chemistry guidelines. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process: Following corrective actions, additional samples are taken and analyzed to verify that the corrective actions were effective in returning the concentrations of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen, and hydrogen peroxide to within the acceptable ranges. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process.
9. Administrative Controls: Site. quality assurance (QA) procedures, review and approval

.. processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.

10. OperatingExperience: The EPRI guideline documents have been developed based on plant experience and have been shown to be effective over time with their widespread use. The specific examples of operating experience are as follows:

BWR: Intergranular stress corrosion cracking (IGSCC) has occurred in small- and large-diameter BWR piping made of austenitic stainless steels and nickel-base alloys.

Significant cracking has occurred in recirculation, core spray, residual heat removal (RHR) systems, and reactor water cleanup (RWCU) system piping welds. IGSCC has also occurred in a number of vessel internal components, including core shroud, access hole cover, top guide, and core spray spargers (Nuclear Regulatory Commission [NRC]

Bulletin 80-13, NRC Information Notice [IN] 95-17, NRC Generic. Letter (GL] 94-03, and NUREG-.1 544). No occurrence of SCC in piping and other components in standby liquid control systems exposed to sodium pentaborate solution has ever been reported (NUREG/CR-6001).

PWR PrimarySystem: The primary pressure boundary piping of PWRs has generally not been found to be affected by SCC because of low dissolved oxygen levels and control of primary water chemistry. However, the potential for SCC exists due to inadvertent introduction of contaminants into the. primary coolant system from unacceptable levels of contaminants in the boric acid, introduction through the free surface of the spent fuel .pool (which can be a natural collector of airbome contaminants), or introduction of oxygen during cooldown (NRC IN 84-18). Ingress of demineralizer resins into the primary system has caused IGSCC of Alloy 600 vessel head penetrations (NRC IN 96-11, NRC GL 97-01). Inadvertent introduction of sodium thiosulfate into the primary system has caused IGSCC of steam generator tubes. The SCC has occurred in safety injection lines (NRC INs 97-19 and 84-18), charging pump casing cladding (NRC INs 80-38 and 94-63),

instrument nozzles in safety .injection tanks (NRC IN 91-05), and safety-related SS piping systems that contain oxygenated, stagnant, or essentially stagnant borated coolant (NRC IN 97-19). Steam generator tubes and plugs and Alloy 600 penetrations have experienced primary water stress corrosion cracking (PWSCC) (NRC INs 89-33, 94-87, 97-88, 90-10, and 96-11; NRC Bulletin 89-01 and its two supplements).

NUREG-1801, Rev. I X1 M-1 2 September 2005

7. CorrectiveActions: The site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, confirmation process, and administrative controls.
8. ConfirmationProcess:See Item 7, above.
9. Administrative Controls:See Item 7, above.
10. OperatingExperience: Corrosion pits from the outside diameter have been discovered in buried piping with far less than 60 years of operation. Buried pipe that is coated and cathodically protected is unaffected after 60 years of service. Accordingly, operating experience from application of the NACE standards on non-nuclear systems demonstrates the effectiveness of this program.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteriafor Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NACE Standard RP-0169-96, Controlof External Corrosionon Undergroundor Submerged Metallic Piping Systems, 1996.

NACE Standard RP-0285-95, CorrosionControl of UndergroundStorage Tank Systems by Cathodic Protection,Approved March 1985, revised February 1995.

NUREG-1801, Rev. 1 Xl M-96 September 2005

N XI.M32 ONE-TIME INSPECTION Program Description The program includes measures to verify the effectiveness of an aging management program (AMP) and confirm the insignificance of an aging effect Situations in which additional confirmation is appropriate include (a) an aging effect is not expected to occur but the data is insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified environment, but the local environment may be more adverse than that generally expected; or (c) the characteristics of the aging effect include a long incubation period. For these cases, there is to be confirmation that either the aging effect is indeed not occurring, or the aging effect is occurring very slowly.so as not to affect the component or structure intended function during the period of extended operation.

A one-time inspection may also be used to provide additional assurance that aging that has not.

yet manifested itself is not occurring, or that the evidence of aging shows that the aging is so insignificant that an aging management program is not warranted., (Class 1 piping less than or equal to NPS 4 is addressed in Chapter Xl. M35, One Time Inspection of ASME Code Class I Small Bore-Piping)

One-time inspections may also be used to verify the system-wide effectiveness of an AMP that is designed to prevent or minimize aging to the extent that it will not cause the loss of intended function during the period of extended operation. For example, effective control of water chemistry can prevent some aging effects and minimize others. However, there may be locations that are isolated from the flow stream for extended periods and are susceptible to the gradual accumulation or concentration of agents that promote certain aging effects. This program provides inspections that either verifies that unacceptable degradation is not occurring or trigger additional actions that will assure the intended,function-of affected components will be..

maintained during the period of extended-operation.

The elements of the program include (a)determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience; (b) identification of the inspection locations in the system or component based on the aging effect; (c) determination of the examination technique, including acceptance criteria that would be effective in managing the aging effect for which the component is examined; and (d) evaluation of the need for follow-up'examinations to monitor the progression of aging ifage-related degradation is found that could jeopardize an intended function before the end of the period of extended operation.

When evidence of an aging effect is revealed by a one-time inspection, the routine evaluation of the inspection results would identify appropriate corrective actions.

As set forth below, an acceptable verification program may consist of a one-time inspection of selected components and susceptible locations in the system. An alternative acceptable program may include routine maintenance or a review of repair or inspection records to confirm that these components have been inspected for aging degradation and significant aging degradation has not occurred. One-time inspection, or any other action or program, created to verify the effectiveness of an AMP and confirm the absence of an aging effect, is to be reviewed by the staff on a plant-specific basis.

September 2005 X1 M-105 NUREG-1801, Rev. 1

Evaluation and Technical Basis

1. Scope of Program:The program includes measures to verify that unacceptable degradation is not occurring, thereby validating the effectiveness of existing AMPs or confirming that there is no need to manage aging-related degradation for the period of extended operation. The structures and components for which one-time inspection is specified to verify the effectiveness of the AMPs (e.g., water chemistry control, etc.) have been identified in the Generic Aging Lessons Learned (GALL) Report. Examples include the feedwater system components in boiling water reactors (BWRs) and pressurized water reactors (PWRs).
2. Preventive Actions: One-time inspection is an inspection activity independent of methods to mitigate or prevent degradation.
3. ParametersMonitored/Inspected:The program monitors parameters directly related to the degradation of a component. Inspection is to be performed by qualified personnel following procedures consistent with the requirements, of the American Society of Mechanical Engineers (ASME) Code and 10 CFR 50, Appendix B, using a variety of nondestructive examination (NDE) methods, including visual, volumetric, and surface techniques.
4. Detection of Aging Effects: The inspection includes a representative sample of the system population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin.

The program will rely on established NDE techniques, including-visual, ultrasonic, and surface techniques that are performed by qualified personnel following procedures consistent with the ASME Code and 10 CFR Part 50, Appendix B.

The inspection and test techniques will have a demonstrated history of effectiveness in detecting the aging effect of concern. Typically, the one time inspections should be performed as indicated in the following table.

NUREG-1801, Rev. 1 X1 M-106 September 2005

Examples of Parameters Monitored or Inspected And Aging Effect for Specific Structure or Componente Aging Aging Parameter Inspection Effect Mechanism Monitored Method1 0 Loss of Crevice Wall Thickness Visual (VT-1 or equivalent) and/or Material Corrosion Volumetric (RT or UT)

Loss of Galvanic Wall Thickness Visual (VT-3 or equivalent) and/or

'I Material Corrosion Volumetric (RT or UT)

Loss of General Wall Thickness Visual (VT-3 or equivalent) and/or' Material Corrosion Volumetric (RT or UT)

Loss of MIC Wall Thickness Visual (VT-3 or equivalent) and/or Material Volumetric (RT or UT)

Loss of Pitting Wall Thickness Visual ('VT-I or equivalent) and/or Material Corrosion Volumetric (RT or UT)

Loss of Erosion Wall Thickness Visual (VT-3 or equivalent) and/or Material Volumetric (RT or UT)

Loss of Fouling Tube Fouling Visual (VT-3 or equivalent) or Heat Enhanced VT-1 for CASS Transfer Cracking SCC or Cyclic Cracks Enhanced Visual (VT-1 or equivalent)

Loading and/or Volumetric (RT or UT)

Loss of Thermal Loosening of Visual (VT-3 or equivalent)

Preload Effects, Components Gasket Creep and Self-loosening With respect to inspection timing, the population of components .inspected before the end of the current operating term needs to be sufficient to provide reasonable assurance that the aging effect will not compromise any intended function at any time during the period of extended operation. Specifically, inspections need to be completed early enough to ensure that the aging effects that may affect intended functions early in the period of extended operation are appropriately managed. Conversely, inspections need to be timed to allow the inspected components to attain sufficient age to ensure that the aging effects with long incubation periods (i.e., those that may affect intended functions near the end of the period of extended operation) are identified. Within these constraints, thA applicant should schedule the inspection no earlier than 10 years prior to the period ofextenoed operation, anu it, sucn a wa-y asI tIo miin the,-impact on 'plant 6pdrationsiýrh-ve accumulated at least 30 years of use before inspections under this prograjbe in. -

sufficient times will have eidp.ao ror aging effects, if any, to be manit The examples provided in the table may not be appropriate for all relevant situations. If the applicant, chooses to use an alternative to the recommendations in this table, a technical justification should be provided as an exception to this AMP. This exception should list the AMR line-item component, examination technique, acceptance criteria, evaluation standard and a description of the justification.

10 Visual inspection may be used only when the inspection methodology examines the surface potentially experiencing the aging effect.

September 2005 XI M-107 NUREG-1801, Rev. 1

XI.M2 WATER CHEMISTRY Program Description The main objective of this program is to mitigate damage caused by corrosion and stress corrosion cracking (SCC). The water chemistry program for boiling water reactors (BWRs) relies on monitoring and control of reactor water chemistry based on industry guidelines such as the boiling water reactor vessel and internals project (BWRVIP)-29 (Electric Power Research Institute [EPRI] TR-103515) or later revisions. The BWRVIP-29 has three sets of guidelines: one for primary water, one for condensate and feedwater, and one for control rod drive (CRD) mechanism cooling water. The water chemistry program for pressurized water reactors (PWRs) relies on monitoring and control of reactor water chemistry based on industry guidelines for primary water and secondary water chemistry such as EPRI TR-1 05714, Rev. 3 and TR-102134, Rev. 3 or later revisions.

--- The water chemistry programs are generally effective in removing impurities from intermediate and high flow areas. The Generic Aging Lessons Learned (GALL) report identifies those circumstances in which the water chemistry program is to be augmented to manage the effects of aging for license renewal. For example, the water chemistry program may not be effective in low flow or stagnant flow areas. Accordingly, in certain cases as identified in the GALL Report, verification of the effectiveness of the chemistry control program is undertaken to ensure that significant degradation is not occurring and the component's intended function will be maintained during the extended period of operation. As discussed in the GALL Report for these specific cases, an acceptable verification program is a one-time inspection of selected components at susceptible locations in the system.

Evaluation and Technical Basis

1. Scope of Program:The program includes periodic monitoring and control of known detrimental contaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate concentrations below the levels known to result in loss of material or cracking.

Water chemistry control is in accordance with industry guidelines such as BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs, EPRI TR-105714 for primary water chemistry in PWRs, and EPRI TR-102134 for secondary water chemistry in PWRs.

2. PreventiveActions: The program includes specifications for chemical species, sampling and analysis frequencies, and corrective actions for control of reactor water chemistry.

System water chemistry is controlled to minimize contaminant concentration and mitigate loss of material due to general, crevice and pitting corrosion and cracking caused by SCC.

For BWRs, maintaining high water purity reduces susceptibility to SCC.

3. ParametersMonitored/Inspected:The concentration of corrosive impurities listed in the EPRI guidelines discussed above, which include chlorides, fluorides (PWRs only),

sulfates, dissolved oxygen, and hydrogen peroxide, are monitored to mitigate degradation of structural materials. Water quality (pH and conductivity) is also maintained in accordance with the guidance. Chemical species and water quality are monitored by in-process methods or through sampling. The chemical integrity of the samples is maintained and verified to ensure that the method of sampling and storage will not cause a change in the concentration of the chemical species in the samples.

Draft NUREG-1 801, Rev. 1 XI M-14 September 2005

BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-103515) for BWR reactor water recommend that the concentration of chlorides, sulfates, and dissolved oxygen are monitored and kept below the recommended levels to mitigate corrosion. The two impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend that the coolant conductivity and ECP are also monitored and kept below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod drive water recommend that conductivity, dissolved oxygen level, and concentrations of iron and copper (feedwater only) are monitored and kept below the recommended levels to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-1 03515) also include recommendations for controlling water chemistry in auxiliary systems: torus/pressure suppression chamber, condensate storage tank, and spent fuel pool.

PWR Primary Water Chemistry: The EPRI guidelines (EP RI TR-105714), for PWR primary water chemistry recommend that the concentration of chlorides, fluorides, sulfates, lithium, and dissolved oxygen and hydrogen are monitored and kept below the recommended levels to mitigate SCC of austenitic stainless steel, Alloy 600, and Alloy 690 components. TR-105714 provides guidelines for chemistry control in PWR auxiliary systems such as the boric acid storage tank, refueling water storage tank, spent fuel pool, letdown purification systems, and volume control tank.

PWR Secondary Water Chemistry: The EPRI guidelines (EPRI TR-102134), for PWR secondary water chemistry recommend monitoring and control of chemistry parameters (e.g., pH level, cation conductivity, sodium, chloride, sulfate, lead, dissolved oxygen, iron, copper, and hydrazine) to mitigate steam generator tube degradation caused by denting, intergranular attack (IGA), outer diameter stress corrosion cracking (ODSCC), or crevice and pitting corrosion. The monitoring and control of these parameters, especially the pH level, also mitigates general (for steel components), crevice, and pitting corrosion of the steam generator shell and the balance of plant materials of construction (e.g., steel, stainless steel, and copper).

4. Detection of Aging Effects: This is a mitigation program and does not provide for detection of any aging effects.

In certain cases as identified in the GALL Report, inspection of select components is to be undertaken to verify the effectiveness of the chemistry control program and to ensure that significant degradation is not occurring and the component intended function will be maintained during the extended period of operation.

5. Monitoring and Trending: The frequency of sampling water chemistry varies (e.g.,

continuous, daily, weekly, or as needed) based on plant operating conditions and the EPRI water chemistry guidelines. Whenever corrective actions are taken to address an abnormal chemistry condition, increased sampling is utilized to verify the effectiveness of these actions.

6. Acceptance Criteria:Maximum levels for various contaminants are maintained be low the system specific limits as indicated by the limits specified in the corresponding EPRI water September 2005 X1 M-1 5 Draft NUREG-1 801, Rev. 1

chemistry guidelines. Any evidence of aging effects or unacceptable water chemistry results is evaluated, the root cause identified, and the condition corrected.

7. Corrective Actions: When measured water chemistry parameters are outside the specified range, corrective actions are taken to bring the parameter back within the acceptable range and within the time period specified in the EPRI water chemistry guidelines. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
8. Confirmation Process: Following corrective actions, additional samples are taken and analyzed to verify that the corrective actions were effective in returning the concentrations

.of contaminants such as chlorides, fluorides, sulfates, dissolved oxygen, and hydrogen peroxide to within the acceptable ran ges. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process.

9. Administrative Controls: Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address administrative controls.
10. Operating Experience: The EPRI guideline documents have been developed based on plant experience and have been shown to be effective over time with their widespread use. The specific examples of operating experience are as follows:

BWR: Intergranular stress corrosion cracking (IGSCC) has occurred in small- and large-diameter BWR piping made of austenitic stainless steels and nickel-base alloys.

Significant cracking has occurred in recirculation, core spray, residual heat removal (RHR) systems, and reactor water cleanup (RWCU) system piping welds. IGSCC has also occurred in a number of vessel internal components, including core shroud, access hole cover, top guide, and core spray spargers (Nuclear Regulatory Commission [NRC]

Bulletin 80-13, NRC Information Notice [IN] 95-17, NRC Generic Letter [GL] 94-03, and NUREG-1 544). No occurrence of SCC in piping and other com ponents in standby liquid control systems exposed to sodium pentaborate solution has ever been reported (NUREG/CR-6001).

PWR Primary System: The primary pressure boundary piping of PWRs has generally not been found to be affected by SCC because of low dissolved oxygen levels and control of primary water chemistry. However, the potential for SCC exists due to inadvertent introduction of contaminants into the primary coolant system from unacceptable levels of contaminants in the boric acid, introduction through the free surface of the spent fuel pool (which can be a natural collector of airborne contaminants), or introduction of oxygen during cooldown (NRC IN 84-18). Ingress of demineralizer resins into the primary system has caused IGSCC of Alloy 600 vessel head penetrations (NRC IN 96-11, NRC GL 97-01). Inadvertent introduction of sodium thiosulfate into the primary system has caused IGSCC of steam generator tubes. The SCC has occurred in safety injection lines (NRC INs 97-19 and 84-18), charging pump casing cladding (NRC INs 80-38 and 94-63),

instrument nozzles in safety injection tanks (NRC IN 91-05), and safety-related SS piping Draft NUREG-1801, Rev. 1 Xl M-16 September 2005

PWR Secondary System: Steam generator tubes have experienced ODSCC, IGA, wastage, and pitting (NRC IN 97-88, NRC GL 95-05). Carbon steel support plates in steam generators have experienced genera I corrosion. The steam generator shell has experienced pitting and stress corrosion cracking (NRC INs 82-37, 85-65, and 90-04).

Such operating experience has provided feedback to revisions of the EPRI water chemistry guideline documents.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteriafor Nuclear Power Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

BWRVIP-29 (EPRI TR-103515), BWR Water Chemistry Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 1994.

BWRVIP-79, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, March 2000.

BWRVIP-1 30, BWR Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, October 2000.

EPRI TR-1 02134, PWR Secondary Water Chemistry Guideline-Revision 3, Electric Power Research Institute, Palo Alto, CA, May 1993.

EPRI TR-105714, PWR Primary Water Chemistry Guidelines-Revision 3, Electric Power Research Institute, Palo Alto, CA, Nov. 1995.

EPRI TR-1002884, PWR Primary Water Chemistry Guidelines, Electric Power Research Institute, Palo Alto, CA, October 2003.

NRC Bulletin 80-13, Crackingin Core Spray Piping, U.S. Nuclear Regulatory Commission, May 12,1980.

NRC Bulletin 89-01, Failureof Westinghouse Steam GeneratorTube Mechanical Plugs, U.S. Nuclear Regulatory Commission, May 15, 1989.

NRC Bulletin 89-01, Supplement 1, Failureof Westinghouse Steam GeneratorTube Mechanical Plugs, U.S. Nuclear Regulatory Commission, November 14, 1989.

NRC Bulletin 89-01, Supplement 2, Failure of Westinghouse Steam GeneratorTube Mechanical Plugs, U.S. Nuclear Regulatory Commission, June 28, 1991.

September 2005 Xl M-17 Draft NUREG-1801, Rev. 1

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