XI.M20 (NUREG-2191 R0)
XI.M20 OPEN-CYCLE COOLING WATER SYSTEM
Program Description
The program relies, in part, on implementing portions of the recommendations for the U.S. Nuclear Regulatory Commission (US NRC) Generic Letter (GL) 89-13 to provide reasonable assurance that the effects of aging on the open-cycle cooling water (OCCW) (or service water) system will be managed for the subsequent period of extended operation. US NRC GL 89-13 defines the OCCW system as a system or systems that transfer heat from safety-related systems, structures, and components (SSCs) to the ultimate heat sink. The program is comprised of the aging management aspects of the applicant’s response to US NRC GL 89-13 including: (a) a program of surveillance and control techniques to significantly reduce the incidence of flow blockage problems as a result of biofouling; (b) a program to verify heat transfer capabilities of all safety-related heat exchangers cooled by the OCCW system; and (c) a program for routine inspection and maintenance to provide reasonable assurance that loss of material, corrosion, erosion, cracking, fouling, and biofouling cannot degrade the performance of safety-related systems serviced by the OCCW system. Since the guidance in US NRC GL 89-13 was not specifically developed to address aging management, this program includes enhancements to the guidance in US NRC GL 89-13 that address operating experience (OE) to provide reasonable assurance that aging effects are adequately managed.
The OCCW system program manages aging effects of components in raw water systems, such as service water, by using a combination of preventive, condition monitoring, and performance monitoring activities. These include: (a) surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, and fouling in the OCCW system or structures and components (SCs) serviced by the OCCW system; (b) inspection of components for signs of loss of material, corrosion, erosion, cracking, fouling, and biofouling; and (c) testing of the heat transfer capability of heat exchangers that remove heat from components important to safety.
For buried OCCW system piping, the aging effects on the external surfaces are managed by the Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report aging management program (AMP) XI.M41, “Buried and Underground Piping and Tanks,” but the internal surfaces are managed by this program. The aging management of closed-cycle cooling water systems is described in AMP XI.M21A, “Closed Treated Water Systems,” and is not included as part of this program. Service water system components or components in other raw water systems that are not included within the scope of GL 89-13 may be managed by AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.” However, water systems for fire protection are managed by AMP XI.M27, “Fire Water System.” If the OCCW system program manages loss of coating integrity for internal coatings or linings, the program includes the guidance provided in the “scope of program” program element of AMP XI.M42, “Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.”
Evaluation and Technical Basis
- 1. Scope of Program: The program addresses piping, piping components, piping elements, and heat exchanger components exposed to raw water in the OCCW system. The program applies to components constructed of various materials including steel, stainless steel (SS), aluminum, copper alloys, titanium, nickel alloy, fiberglass, polymeric materials, and concrete. The program may manage loss of coating integrity as provided in the recommendations of AMP XI.M42. This program references US NRC GL 89-13; plant activities in response to US NRC GL 89-13 may be credited for this program, as appropriate.
- 2. Preventive Actions: This program is primarily a condition monitoring program; however, some preventive actions may be effective. Implementation of US NRC GL 89-13 includes control techniques, such as chemical treatment whenever the potential for biofouling exists. Treatment with chemicals mitigates microbiologically influenced corrosion (MIC) and buildup of macroscopic biofouling debris from biota such as blue mussels, oysters, or clams. Periodic flushing of infrequently used cooling loops removes accumulations of biofouling agents, corrosion products, debris, and silt. The use of degradation resistant materials and the application of internal coatings or lining may be included.
- 3. Parameters Monitored or Inspected: This program addresses loss of material, reduction of heat transfer, flow blockage, and in some materials, cracking. This program: (a) inspects surfaces of components exposed to raw water for presence of fouling; (b) monitors heat transfer performance of components affected by fouling in the OCCW system; and (c) monitors the condition of piping and components to provide reasonable assurance that loss of material, loss of coating or lining integrity (when this program is used in lieu of AMP XI.M42), cracking, and flow blockage do not degrade the performance of the safety-related systems supplied by the OCCW system. For those portions of the OCCW system where flow monitoring is not performed, test results from the monitored portions of the system are used to calculate friction (or roughness) factors and are used to confirm that design flow rates will be achieved with the overall fouling identified in the system. If the aging effects associated with concrete piping are being managed, American Concrete Institute (ACI) 349.3R and ACI 201.R1 provide acceptable bases for parameters monitored or inspected.
- 4. Detection of Aging Effects: Inspection scope, methods (e.g., visual or volumetric inspections, performance testing), and frequencies are in accordance with the applicant’s docketed response to NRC GL 89-13. As noted in US NRC GL 89-13, testing frequencies can be adjusted to provide assurance that equipment will perform the intended function between test intervals, but should not exceed 5 years. Visual inspections are used to identify fouling, and loss of coating or lining integrity (when this program is used in lieu of AMP XI.M42) and provide a qualitative assessment for loss of material due to various forms of corrosion and erosion. Examinations of polymeric and concrete materials should be consistent with the examinations described in AMP XI.M38. Volumetric examinations, such as ultrasonic testing, eddy current testing, and radiography are used to quantify the extent of wall thinning or loss of material.
- Inspections and tests are performed by personnel qualified in accordance with site procedures and programs to perform the specified task. Inspections within the scope of the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) should follow procedures consistent with the ASME Code. Non-ASME Code inspections follow site procedures that include requirements for items such as lighting, distance, offset, surface coverage, presence of protective coatings, and cleaning processes. For concrete components, the qualifications of personnel performing inspections and evaluations are specified in ACI 349.3R.
- 5. Monitoring and Trending: For heat exchangers that are tested for heat transfer capability, test results are trended to verify adequacy of testing frequencies. For heat exchangers that are inspected for degradation in lieu of testing, inspection results are trended to evaluate adequacy of inspection frequencies. If fouling is identified, the system is evaluated for the impact on the heat transfer capability of the system. Friction (or roughness) factors are trended to confirm design flow rates can be achieved in the portions of the OCCW system where flow monitoring is not performed. Evidence of corrosion is evaluated for its potential impact on the integrity of the piping. For ongoing degradation due to specific aging mechanisms (e.g., MIC), the program includes trending of wall thickness measurements at susceptible locations to adjust the monitoring frequency and the number of inspection locations.
- 6. Acceptance Criteria: Predicted wall thicknesses at the next scheduled inspection are greater than the components’ minimum wall thickness requirements. As applicable, coatings or linings meet the acceptance criteria from AMP XI.M42. For heat exchangers, heat removal capability is within design values. For ongoing degradation mechanisms (e.g., MIC), the program includes criteria for the extent or rate of degradation that will prompt more comprehensive corrective actions. If concrete piping is being managed, acceptance criteria are derived from ACI 349.3R, as applicable.
- 7. Corrective Actions: Results that do not meet the acceptance criteria are addressed in the applicant’s corrective action program under those specific portions of the quality assurance (QA) program that are used to meet Criterion XVI, “Corrective Action,” of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B. Appendix A of the GALL-SLR Report describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill the corrective actions element of this AMP for both safety-related and nonsafety-related SCs within the scope of this program.
- The program includes reevaluation, repair, or replacement of components that do not meet minimum wall thickness requirements. If fouling is identified, the overall effect is evaluated for reduction of heat transfer, flow blockage, loss of material, and (if applicable) chemical treatment effectiveness. For ongoing degradation mechanisms (e.g., MIC), the frequency and extent of wall thickness inspections are increased commensurate with the significance of the degradation.
- If the cause of the aging effect for each applicable material and environment is not corrected by repair or replacement for all components constructed of the same material and exposed to the same environment, additional inspections are conducted if one of the inspections does not meet acceptance criteria. The number of increased inspections is determined in accordance with the site’s corrective action program; however, no fewer than five additional inspections are conducted for each inspection that did not meet acceptance criteria, or 20 percent of each applicable material, environment, and aging effect combination is inspected, whichever is less. At multi-unit sites, the additional inspections include inspections at all of the units with the same material, environment, and aging effect combination.
- 8. Confirmation Process: The confirmation process is addressed through those specific portions of the QA program that are used to meet Criterion XVI, “Corrective Action,” of 10 CFR Part 50, Appendix B. Appendix A of the GALL-SLR Report describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill the confirmation process element of this AMP for both safety-related and nonsafety-related SCs within the scope of this program.
- 9. Administrative Controls: Administrative controls are addressed through the QA program that is used to meet the requirements of 10 CFR Part 50, Appendix B, associated with managing the effects of aging. Appendix A of the GALL-SLR Report describes how an applicant may apply its 10 CFR Part 50, Appendix B, QA program to fulfill the administrative controls element of this AMP for both safety-related and nonsafety-related SCs within the scope of this program.
- 10. Operating Experience: Loss of material due to corrosion, including MIC and erosion, has been identified (US NRC Information Notice (IN) 85-30, IN 2007-06, Licensee Event Reports (LER) 247/2001-006, LER 306/2004-001, LER 483/2005-002, LER 331/2006-003, LER 255/2007-002, LER 454/2007-002, LER 254/2011-001, LER 255/2013-001, LER 286/2014-002). Protective coatings have failed, leading to unanticipated corrosion (IN 85-24, IN 2007-06, LER 286/2002-001, LER 286/2011-003). Reduction of heat transfer and flow blockage due to fouling has occurred in piping and in heat exchangers from protective coating failures, and accumulations of silt and sediment (IN 81-21, IN 86-96, IN 2004-07, IN 2006-17, IN 2007-28, IN 2008-11, LER 413/1999-010, LER 305/2000-007, LER 266/2002-003, LER 413/2003-004, LER 263/2007-004, LER 321/2010-002, LER 457/2011-001, LER 457/2011-002, LER 397/2013-002). Cracking due to stress corrosion cracking has occurred in brass tubing (LER 305/2002-002), and pitting in SS has occurred (LER 247/2013-004).
- The review of plant-specific OE during the development of this program is to be broad and sufficiently detailed to detect instances of aging effects that have repeatedly occurred. In some instances, recurring internal corrosion may warrant program enhancements. Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants (SRP-SLR) Sections 3.2.2.2.7, 3.3.2.2.7, and 3.4.2.2.6, “Loss of Material Due to Recurring Internal Corrosion,” include criteria to identify instances of recurring internal corrosion and recommendations for augmenting aging management activities.
- The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry OE including research and development such that the effectiveness of the AMP is evaluated consistent with the discussion in Appendix B of the GALL-SLR Report.
References
10 CFR Part 50, Appendix B, “Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016.
10 CFR 50.55a, “Codes and Standards.” Washington, DC: U.S. Nuclear Regulatory Commission. 2016.
ACI. ACI Standard 201.1R-08, “Guide for Conducting a Visual Inspection of Concrete in Service.” Farmington Hills, Michigan: American Concrete Institute. 2008.
_____. ACI Standard 349.3R-02, “Evaluation of Existing Nuclear Safety-Related Concrete Structures.” Farmington Hills, Michigan: American Concrete Institute. 2002.
ASME. ASME Code Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components.” New York, New York: The American Society of Mechanical Engineers. 2008.
EPRI. EPRI 1008282, “Life Cycle Management Sourcebook for Nuclear Plant Service Water Systems.” Palo Alto, California: Electric Power Research Institute. March 2005.
_____. EPRI 1010059, “Service Water Piping Guideline.” Palo Alto, California: Electric Power Research Institute. September 2005.
Licensee Event Report 247/2001-006, “Pipe Erosion Results in Service Water System Leakage in Containment.” Agencywide Documents Access and Management System (ADAMS) Accession No. ML020090594. https://lersearch.inl.gov/LERSearchCriteria.aspx. December 2001.
Licensee Event Report 247/2013-004, “Technical Specification Prohibited Condition Due to an Inoperable Essential Service Water Header as a Result of Pin Hole Leaks in Code Class 3 SW Piping.” ADAMS Accession No. ML13319B082. https://lersearch.inl.gov/LERSearchCriteria.aspx. November 2013.
Licensee Event Report 254/2011-001, “Loss of Both Divisions of Residual Heat Removal System.” ADAMS Accession No. ML11174A039. https://lersearch.inl.gov/LERSearchCriteria.aspx. June 2011.
Licensee Event Report 255/2007-002, “Inoperable Containment Due to Containment Air Cooler Through-Wall Flaw.” ADAMS Accession No. ML070871046. https://lersearch.inl.gov/LERSearchCriteria.aspx. March 2007.
Licensee Event Report 255/2013-001, “Technical Specification Required Shutdown Due to a Component Cooling Water System Leak.” ADAMS Accession No. ML13100A019. https://lersearch.inl.gov/LERSearchCriteria.aspx. April 2013.
Licensee Event Report 263/2007-004, “Degradation of Emergency Service Water Flow to Emergency Core Cooling System Room Cooler.” ADAMS Accession No. ML072430882. https://lersearch.inl.gov/LERSearchCriteria.aspx. August 2007.
Licensee Event Report 266/2002-003, “Possible Common Mode Failure of AFW Due to Partial Clogging of Recirculation Orifices.” ADAMS Accession No. ML032890115. https://lersearch.inl.gov/LERSearchCriteria.aspx. October 2003.
Licensee Event Report 286/2002-001, “Operation in a Condition Prohibited by Technical Specifications Due to an Inoperable Service Water Pipe Caused by a Leak that Exceeded Allowable Outage Time.” ADAMS Accession No. ML022000155. https://lersearch.inl.gov/LERSearchCriteria.aspx. July 2002.
Licensee Event Report 286/2011-003, “Technical Specification Required Shutdown and a Safety System Functional Failure for a Leaking Service Water Pipe Causing Flooding in the SW Valve Pit Preventing Access for Accident Mitigation.” ADAMS Accession No. ML11123A165. https://lersearch.inl.gov/LERSearchCriteria.aspx. April 2011.
Licensee Event Report 286/2014-002, “Technical Specification Prohibited Condition Due to an Inoperable Essential Service Water Header as a Result of Socket Weld Leak in Code Class 3 SW Piping.” ADAMS Accession No. ML14087A009. https://lersearch.inl.gov/LERSearchCriteria.aspx. March 2014.
Licensee Event Report 305/2000-007, “Alternate Service Water Supply Piping Obstructed.” ADAMS Accession No. ML003726758. https://lersearch.inl.gov/LERSearchCriteria.aspx. June 2000.
Licensee Event Report 305/2002-002, “Technical Specifications Required Shutdown: CCW System Leak Could Not Be Repaired Within LCO.” ADAMS Accession No. ML021920465. https://lersearch.inl.gov/LERSearchCriteria.aspx. July 2002.
Licensee Event Report 306/2004-001, “Shutdown Required by Technical Specifications Due to Two Trains of Containment Cooling Inoperable.” ADAMS Accession No. ML050890314. https://lersearch.inl.gov/LERSearchCriteria.aspx. March 2005.
Licensee Event Report 321/2010-002, “Degraded Plant Service Water Cooling to Main Control Room Air Conditioner Results in Loss of Function.” ADAMS Accession No. ML101650089. https://lersearch.inl.gov/LERSearchCriteria.aspx. June 2010.
Licensee Event Report 331/2006-003, “Residual Heat Removal Service Water Pump Inoperable Due to Motor Cooler Failures.” ADAMS Accession No. ML062490486. https://lersearch.inl.gov/LERSearchCriteria.aspx. August 2006.
Licensee Event Report 397/2013-002, “Main Control Room Cooler Failed Surveillance.” ADAMS Accession No. ML13141A288. https://lersearch.inl.gov/LERSearchCriteria.aspx. May 2013.
Licensee Event Report 413/1999-010, “Both Catawba Units Operated Outside Their Design Basis and Unit 2 Experienced a Forced Shutdown as a Result of Flow Restriction Caused by Corrosion of the Auxiliary Feedwater System Assured Suction Source Piping Due to Inadequate Testing.” https://lersearch.inl.gov/LERSearchCriteria.aspx. July 1999.
Licensee Event Report 413/2003-004, “1A Containment Spray System Inoperable for Longer than Technical Specifications Allow Due to Heat Exchanger Fouling.” ADAMS Accession No. ML031970061. https://lersearch.inl.gov/LERSearchCriteria.aspx. July 2003.
Licensee Event Report 454/2007-002, “Technical Specification Required Shutdown of Unit 1 and Unit 2 Due to an Ultimate Heat Sink Pipe Leak.” ADAMS Accession No. ML080660544. https://lersearch.inl.gov/LERSearchCriteria.aspx. March 2008.
Licensee Event Report 457/2011-001, “Asiatic Clam Shells in Essential Service Water Supply Piping to the 2A Auxiliary Feedwater Pump Resulted in the Auxiliary Feedwater System Inoperability.” ADAMS Accession No. ML112010177. https://lersearch.inl.gov/LERSearchCriteria.aspx. July 2011.
Licensee Event Report 457/2011-002, “Auxiliary Feedwater System Inoperability Due to Additional Asiatic Clam Shells in Essential Service Water Supply Piping.” ADAMS Accession No. ML11263A185. https://lersearch.inl.gov/LERSearchCriteria.aspx. September 2011.
Licensee Event Report 483/2005-002, “Plant Shutdown Required by Technical Specification 3.7.8 for an Inoperable Train of Essential Service Water.” ADAMS Accession No. ML051460343. https://lersearch.inl.gov/LERSearchCriteria.aspx. May 2005.
US NRC. Generic Letter 89-13, “Service Water System Problems Affecting Safety-Related Components.” Washington, DC: U.S. Nuclear Regulatory Commission. July 1989.
_____. Generic Letter 89-13, Supplement 1, “Service Water System Problems Affecting Safety-Related Components.” Washington, DC: U.S. Nuclear Regulatory Commission. April 1990.
_____. Information Notice 81-21, “Potential Loss of Direct Access to Ultimate Heat Sink.” Washington, DC: U.S. Nuclear Regulatory Commission. July 1981.
_____. Information Notice 85-24, “Failures of Protective Coatings in Pipes and Heat Exchangers.” Washington, DC: U.S. Nuclear Regulatory Commission. March 1985.
_____. Information Notice 85-30, “Microbiologically Induced Corrosion of Containment Service Water System.” Washington, DC: U.S. Nuclear Regulatory Commission. April 1985.
_____. Information Notice 86-96, “Heat Exchanger Fouling Can Cause Inadequate Operability of Service Water Systems.” Washington, DC: U.S. Nuclear Regulatory Commission. November 1986.
_____. Information Notice 2004-07, “Plugging of Safety Injection Pump Lubrication Oil Coolers with Lakeweed.” Washington, DC: U.S. Nuclear Regulatory Commission. April 2004.
_____. Information Notice 2006-17, “Recent Operating Experience of Service Water Systems Due to External Conditions.” Washington, DC: U.S. Nuclear Regulatory Commission. July 2006.
_____. Information Notice 2007-06, “Potential Common Cause Vulnerabilities in Essential Service Water Systems.” Washington, DC: U.S. Nuclear Regulatory Commission. February 2007.
_____. Information Notice 2007-28, “Potential Common Cause Vulnerabilities in Essential Service Water Systems Due to Inadequate Chemistry Controls.” Washington, DC: U.S. Nuclear Regulatory Commission. September 2007.
_____. Information Notice 2008-11, “Service Water System Degradation at Brunswick Steam Electric Plant Unit.” Washington, DC: U.S. Nuclear Regulatory Commission. June 2008.