ML031080100

Summary of Telecommunication with Omaha Public Power District (OPPD) to Discuss Draft Requests for Additional Information (Rais) for the Renewal of the Operating License for Fort Calhoun Station, Unit 1 (FCS)

ML031080100
Person / Time
Site:	Fort Calhoun
Issue date:	04/17/2003
From:	William Burton NRC/NRR/DRIP/RLEP
To:
Burton W, NRR/DRIP/RLEP, 415-2853
References
SIP Test Sample upto2-6-04
Download: ML031080100 (14)

Text

April 17, 2003 LICENSEE:

Omaha Public Power District FACILITY:

Fort Calhoun Station, Unit 1

SUMMARY

OF TELECOMMUNICATION WITH OMAHA PUBLIC POWER DISTRICT (OPPD) TO DISCUSS DRAFT REQUESTS FOR ADDITIONAL INFORMATION (RAIs) FOR THE RENEWAL OF THE OPERATING LICENSE FOR FORT CALHOUN STATION, UNIT 1 (FCS)

On September 25, 2002, the NRC staff (the staff) and representatives from OPPD held a telecommunication (telecon) to discuss draft RAIs resulting from the staffs review of license renewal application (LRA) Sections 3.2, 3.5, B.2.7, B.2.9, and B.3.3. A list of telecon participants is enclosed. OPPD has had an opportunity to review and comment on this summary.

3.2 Engineered Safety Features 3.2.1-D1 LRA Table 3.2-1, row 3.2.1.04, states in the Discussion column, that no FCS containment isolation valves (CIVs) and associated piping, in systems that are not addressed in this or other sections of this application, were determined to be subject to the aging effect of loss of material due to microbiologically influenced corrosion (MIC). This statement is not clear. To determine whether these components are applicable to FCS and, in order to assess the adequacy of the management of the aging effects associated with these components, please clarify what the statement means. Specifically, does the GALL Report address the CIVs and associated piping at FCS? If so, provide the evaluation recommended by the GALL Report and identify the associated aging management program(s) (AMP(s)) credited for managing loss of material due to MIC in these components.

Telecon Discussion:

OPPD had no questions with this RAI, and stated that the discussion column of LRA AMR Item 3.2.1.04 has a typographical error. The word not at the end of the second line of that entry should not be there. The discussion item should read, No FCS containment isolation valves and associated piping in systems that are addressed in this or other sections of this application were determined to be subject to the aging effect of loss of material due to microbiologically influenced corrosion. OPPD will clarify this in the RAI response. The staff asked that OPPDs response also include background information to support their conclusion that no FCS containment isolation valves and associated piping were determined to be subject to loss of material due to MIC.

3.2.3-D1 In LRA Table 3.2-3, if the terms, safety injection tank and accumulator are used interchangeably for FCS, explain why FCS safety injection tanks (cf. Row Number 3.2.3.01) are associated with the material of stainless steel, whereas accumulators (cf. Row Number 3.2.3.02) are associated with carbon steel with stainless steel cladding, for the same kind of environment.

Telecon Discussion:

OPPD had no questions with this RAI, and clarified that these component terms are not used interchangeably, since they are two separate and distinct components. They have been identified separately in Table 2.3.2.1-1 of the LRA, specifically, to prevent such confusion. Referring to this table, the SI leakage cooler accumulators are addressed under the Component Type Leakage Accumulators. The safety injection tanks are addressed under the Component Type Injection Tanks.

The SI leakage cooler accumulators, SI-7A, -7B, -7C, and -7D, are carbon steel vessels, internally clad with stainless steel. SI-7A and -7B are located in zones A5 and A8, respectively, on drawing E-23866-210-130, sheet 2 (Sh. 2). SI-7C and -7D are located in zones A8 and A5, respectively, on drawing E-23866-210-130, Sh. 2B.

The safety injection tanks, SI-6A, -6B, -6C, and -6D, are wholly stainless steel vessels. SI-6A and -6B are located in zones C/D3 and C/D6, respectively, on drawing E-23866-210-130, Sh. 2. SI-6C and -6D are located in zones C/D6 and C/D3, respectively, on drawing E-23866-210-130, Sh. 2B.

3.2.3-D2 In LRA Table 3.2-3, row 3.2.3.02, based on the review results of the GALL Report, for leakage accumulators (or safety injection tanks) with leaking chemically treated borated water, the corresponding FCS aging effects requiring management (AERMs) should be loss of material/boric acid corrosion, instead of crack initiation and growth/stress corrosion cracking. Also, according to Volume 2, V.D1.7-a of the GALL Report, the aging management program to be relied on for this aging effect should be GALL program XI.M10, Boric Acid Corrosion,"

instead of GALL program XI.M2, Water Chemistry, as required by V.D1.7-b.

Explain the discrepancies.

Telecon Discussion:

OPPD had no questions with this RAI, and clarified that LRA aging management review (AMR) Item 3.2.3.02 applies to the stainless steel liner of the SI leakage cooler accumulators, as indicated in the FCS Material column of that entry.

Refer to Table 2.3.2.1-1 of the LRA. For the Leakage Accumulator Component Type in that table, the reader is provided with links to LRA AMR Item 3.2.3.02, for the accumulator internals, and to LRA AMR Item 3.2.1.11 for the accumulator externals. For the Injection Tank Component Type, the reader is provided links to LRA AMR Items 3.2.2.04 and 3.2.3.01.

B.2.7 Periodic Surveillance and Preventive Maintenance (PM) Program B.2.7-D1 The staff has read the program description for this aging management program, and is concerned that its purpose may conflict with the surveillance and maintenance activities associated with 10 CFR 50.65 Requirements for monitoring the effectiveness of maintenance at nuclear power plant, (the Maintenance Rule). In order to better understand how this aging management program will differ from and supplement the maintenance rule, please discuss the surveillance and preventive maintenance activities that will be performed by this program, and how they will supplement activities performed under the maintenance rule, including the criteria to be used and the frequency to evaluate the effectiveness of the program in achieving its goals of aging management.

Telecon Discussion:

OPPD had no questions with this RAI.

B.2.7-D2 Item 3, Parameters Monitored or Inspected, of LRA Section B.2.7 considers surface condition as one of the parameters for monitoring age-related degradations. The staff believes that to adequately determine surface degradation of concrete, physical properties such as honeycombs, chemical leaching and/or discoloration should be inspected. Does the scope of inspection program cover the monitoring of changes in physical properties of concrete from visual signs of honeycombs, chemical leaching, and/or discoloration in concrete?

Telecon Discussion:

OPPD had no questions with this RAI.

B.2.9 Steam Generator Program B.2.9-D1 The applicant stated that its steam generator integrity program is consistent with GALL program XI.M19, Steam Generator Tube Integrity, in the GALL Report.

However, the GALL Report provides only generic guidelines for the ten attributes. The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes. Therefore, the applicant should address the following items as they relate to the steam generator tubes.

Preventive Actions GALL program XI.M19 states that NEI 97-06, Steam Generator Program Guidelines, was under staff review at the time GALL was developed. NEI 97-06 is still under staff review and has not been incorporated into the applicants technical specifications. Therefore, please identify the preventive actions, including the use of water chemistry, that will be taken to mitigate degradation in the steam generators. Also, in the table on page B-3 of the LRA, it states that loose parts monitoring is not credited for aging management. Therefore, it is unclear to the staff why the steam generator program is being enhanced to write an annunciator response procedure for the loose parts monitor for the steam generator. Please clarify this apparent discrepancy.

Telecon Discussion:

OPPD had no questions with this RAI, and indicated that the original LRA stated that an annunciator response procedure for loose parts monitoring was going to be written only to ensure that they are in compliance with NEI 97-06 (which requires that the licensee have an annunciator response procedure). The licensee also clarified that the original LRA was in error in that an annunciator response procedure already exists.

Detection of Aging Effects Because NEI 97-06 was under staff review at the time of the issuance of GALL program XI.M19, the staff is unclear whether the guidance in this document will be implemented by the applicant. NEI 97-06 is still under staff review and has not been incorporated into the applicants technical specifications. Therefore, please identify how aging effects will be detected, including the method or technique used to detect the aging effect, the inspection frequency, and the sample size. Explain how these will ensure that the aging effect will be detected and corrected before the loss of the components intended function.

Telecon Discussion:

OPPD had no questions with this RAI.

Monitoring and Trending GALL program XI.M19 states that condition monitoring assessments are performed to determine whether structural and accident leakage criteria have been satisfied. Operational assessments are performed after inspections to verify that structural and leakage integrity is maintained during the operating interval until the next inspection. NEI 97-06 guidelines and Technical Specifications are used to select the time of the next inspection. Because NEI 97-06 is still under staff review, the staff is unclear whether the guidance in this document will be implemented by the applicant. Please identify how condition monitoring and operational assessments are performed.

Telecon Discussion:

OPPD had no questions with this RAI.

B.2.9-D2 The applicant stated that the steam generator program is consistent with GALL program XI.M19, Steam Generator Tube Integrity, in the GALL Report, with the exception of two enhancements. The applicant stated that its steam generator program also includes aging management activities to address plant-specific AMP requirements identified in Tables 3.1-1 and 3.1-2. However, the GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes. Therefore, please respond to the following related items:

1.

Table 3.1-1, row 3.1.1.02, Steam Generator Shell Assembly, states that the aging effect for this component (i.e., loss of material due to pitting and crevice corrosion) is managed, in part, by the steam generator program (B.2.9). It is not clear to the staff how the steam generator program manages this aging effect. In addition, because the GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes, provide details for the following attributes for this component: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria. Ensure that the discussion identifies how the steam generator program manages this aging effect (e.g., the part of this component that is managed by the steam generator program and how it is managed by the steam generator program).

2.

Table 3.1-1, row 3.1.1.15, (Alloy 600) Steam generator tubes, repair sleeves, and plugs, states that the aging effects for these components are managed, in part, by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for the repair sleeves and plugs: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

3.

Table 3.1-1, row 3.1.1.16, Tube support lattice bars made of carbon steel, states that the aging effect for this component is managed by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for this component:

Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

4.

Table 3.1-1, row 3.1.1.17, Carbon steel tube support plate, states that the aging effect for this component is managed by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for this component: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

5.

Table 3.1-2, row 3.1.2.06, Secondary side of the tubesheet, steam generator feedwater, steam and instrument nozzles, and feedwater nozzle safe ends, states that the aging effect for these components is managed by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for this component: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

6.

Table 3.1-2, row 3.1.2.07, Steam generator tube plugs, states that the aging effect for this component is managed by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for this component: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

7.

Table 3.1.2, row 3.1.2.14, Steam generator steam nozzle safe end, steam generator feed ring, states that the aging effect for these components is managed by the steam generator program (B.2.9). The GALL Report states that the scope of GALL program XI.M19 is specific to steam generator tubes; therefore, provide details for the following attributes for this component: Preventive Actions, Parameters Monitored/Inspected, Detection of Aging Effects, Monitoring and Trending, and Acceptance Criteria.

Telecon Discussion:

OPPD had no questions with the RAI, and stated that, for the added scope components, OPPD credits the following aging management activities:

(1)

Visual inspections are credited for aging management for all components (including tubesheet); however, the nozzles are not inspected, but are bounded by a visual inspection of the carbon steel feedwater ring, which is more susceptible to aging than the low-alloy steel or carbon steel nozzles.

(2)

Eddy-current testing is credited for aging management of the internal tubes and plugs.

(3)

Sludge removal is credited as a preventive action for the secondary-side tubesheet degradation.

In order to help evaluate this issue, the staff asked that OPPD specifically address each component identified in the RAI for each program element identified in the RAI (e.g., preventive actions, parameters monitored/inspected, etc.).

B.3.2-D2 The detection of aging effects in buried components is plant-specific and depends on plant operating experience as well as industry operating experience.

Therefore, the staff must further evaluate the applicants operating experience and proposed inspection frequency. The staff requests the licensee to expand the discussion of this AMP to include the inspection frequency and the applicable industry operating experience.

Telecon Discussion:

OPPD had no questions with this RAI. The staff explained that the Advisory Committee on Reactor Safeguards has a concern regarding aging management of buried components. They are not comfortable with the idea that buried components will be inspected when they are excavated, when there is no set frequency of excavation. In order to get a realistic idea of how often buried components are excavated, the staff asked OPPD to identify what in-scope systems have buried components and what proportion of the systems are buried.

Also, what is the history of excavation of these systems? Specifically, when were they dug-up and for what reasons were they dug-up? These answers will give some indication of how often the staff could expect that the components would be inspected. Also, the staff asked OPPD to discuss how inspections of the inside of the components can be used to assess the condition of the component exterior. The staff will revise the RAI to clarify its request as follows:

The detection of aging effects in buried components is plant-specific and depends on plant operating experience as well as industry operating experience. Therefore, the staff must further evaluate the applicants operating experience and proposed inspection frequency. The staff requests the licensee to expand the discussion of this AMP to include the breakdown (system name, component, and percentage of total buried components) of the components in this system, the inspection frequency and the applicable industry operating experience. Specifically, the applicant should discuss how often these buried components have been excavated during the current operating term, for what reason they were excavated, and, based on this operating experience, how often the components may be excavated during the period of extended operation. In addition, the applicant should discuss how internal inspection techniques and methods can be used to assess the condition of the component exterior.

B.3.3 General Corrosion of External Surfaces Program B.3.3-D6 The General Corrosion of External Surface Program as described in Section B.3.3 of the LRA is credited for managing aging effects of loss of material and cracking for certain components identified in that section. The applicant stated that aging effects can be detected by visual observation and inspection of external surfaces including evidence of leaking fluid for certain components that are not routinely accessible. The staff believes that inspection for evidence of leaking fluids also provides indirect monitoring of certain components that are not routinely accessible. The presence of fluid leakage from a component, however, would indicate that the component could not perform its intended function as a pressure boundary. Therefore, in order to determine whether this program will adequately manage aging effects of inaccessible components, the staff requests the applicant to clarify whether the scope of auxiliary systems listed in LRA Section B.3.3 includes components that are not routinely accessible and may rely on the indirect monitoring of fluid leakage. In addition, the applicant is requested to discuss the operating history of these components to demonstrate that the applicable aging effects will be adequately managed prior to the loss of their intended functions.

Telecon Discussion The staff agreed to revise the RAI to eliminate the reference to auxiliary systems.

Instead, the RAI addresses components in any system that are not routinely accessible. OPPD will clarify that this AMP is not credited with managing aging in inaccessible areas (there are other AMPs which accomplish this), and clarify that this AMP is intended to identify conditions which, if not corrected, could create conditions which could lead to age-related degradation. This would include walkdowns to identify leakage that can be corrected before the leakage could lead to degradation of external surfaces, and in turn, could result in the loss of the components intended function. The RAI will be revised as follows:

The General Corrosion of External Surfaces Program as described in Section B.3.3 of the LRA is credited for managing aging effects of loss of material and cracking. The application states that aging effects can be detected by visual observation and inspection of external surfaces including evidence of leaking fluid for certain components that are not routinely accessible. The staff believes that inspection for evidence of leaking fluids also provides indirect monitoring of certain components that are not routinely accessible. The presence of fluid leakage from a component, however, would indicate that the component may not perform its intended function as a pressure boundary.

Therefore, in order to determine whether this program will adequately manage the aging effects of inaccessible components, the staff requests the applicant to clarify whether the scope of systems listed in Section B.3.3 includes components that are not routinely accessible and which rely on the indirect monitoring of fluid leakage. In addition, the applicant is requested to discuss the operating history of these components to demonstrate that the applicable aging effects will be adequately managed prior to the loss of their intended functions.

/RA/

William F. Burton, Project Manager License Renewal Section License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket No.: 50-285

Enclosure:

As stated cc w/enclosure: See next page fluid leakage from a component, however, would indicate that the component may not perform its intended function as a pressure boundary.

Therefore, in order to determine whether this program will adequately manage the aging effects of inaccessible components, the staff requests the applicant to clarify whether the scope of systems listed in Section B.3.3 includes components that are not routinely accessible and which rely on the indirect monitoring of fluid leakage. In addition, the applicant is requested to discuss the operating history of these components to demonstrate that the applicable aging effects will be adequately managed prior to the loss of their intended functions

/RA/

William F. Burton, Project Manager License Renewal Section License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket No.: 50-285

Enclosure:

As stated cc w/enclosure: See next page Distribution:

See next page DOCUMENT NAME: C:\\ORPCheckout\\FileNET\\ML031080100.wpd OFFICE LA:RLEP:DRIP PM:RLEP:DRIP SC:RLEP:DRIP NAME YEdmonds WBurton SLee DATE 4/16/03 4/15/03 4/17/03 OFFICIAL RECORD COPY

DISTRIBUTION: Summary of 9/25/02 Telecon - Fort Calhoun, Dated: April 17, 2003 HARD COPY RLEP R/F W. Burton E-MAIL:

PUBLIC J. Johnson W. Borchardt D. Matthews F. Gillespie RidsNrrDe E. Imbro G. Bagchi K. Manoly W. Bateman J. Calvo C. Holden P. Shemanski H. Nieh G. Holahan H. Walker S. Black B. Boger D. Thatcher G. Galletti C. Li J. Moore R. Weisman M. Mayfield A. Murphy W. McDowell S. Smith (srs3)

T. Kobetz C. Munson S. Duraiswamy RLEP Staff T. Mensah A. Wang K. Kennedy (RIV)

LIST OF ATTENDEES OMAHA PUBLIC POWER DISTRICT(OPPD)

FORT CALHOUN STATION, UNIT 1 SEPTEMBER 25, 2002 TELECON Attendees Affiliation Butch Burton NRC Don Findlay OPPD Ken Henry OPPD Cheryl Khan NRC Donna Latwaitis OPPD Carol Lauron OPPD Arnold Lee NRC Enclosure

Ft. Calhoun Station, Unit 1 cc:

Winston & Strawn ATTN: James R. Curtiss, Esq.

1400 L Street, NW.

Washington, DC 20005-3502 Chairman Washington County Board of Supervisors P.O. Box 466 Blair, NE 68008 Mr. John Kramer, Resident Inspector U.S. Nuclear Regulatory Commission Post Office Box 310 Fort Calhoun, NE 68023 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011 Ms. Sue Semerera, Section Administrator Nebraska Health and Human Services Systems Division of Public Health Assurance Consumer Services Section 301 Centennial Mall, South P.O. Box 95007 Lincoln, NE 68509-5007 Mr. David J. Bannister Manager - Fort Calhoun Station Omaha Public Power District Fort Calhoun Station FC-1-1 Plant P.O. Box 550 Fort Calhoun, NE 68023-0550 Mr. John B. Herman Manager - Nuclear Licensing Omaha Public Power District Fort Calhoun Station FC-2-4 Adm.

P.O. Box 550 Fort Calhoun, NE 68023-0550 Mr. Richard P. Clemens Division Manager - Nuclear Assessments Omaha Public Power District Fort Calhoun Station P.O. Box 550 Fort Calhoun, NE 68023-0550 Mr. Daniel K. McGhee Bureau of Radiological Health Iowa Department of Public Health 401 SW. 7th Street Suite D Des Moines, IA 50309 Mr. R. T. Ridenoure Division Manager - Nuclear Operations Omaha Public Power District Fort Calhoun Station FC-2-4 Adm.

P.O. Box 550 Fort Calhoun, NE 68023-0550 Mr. John Fassell, LLRW Program Manager Health and Human Services Regulation and Licensure Consumer Health Services 301 Centennial Mall, South P.O. Box 95007 Lincoln, NE 68509-5007 W. Dale Clark Library Attn: Margaret Blackstone 215 South 15th Street Omaha, NE 68102 Blair Public Library Attn: Ruth Peterson 210 South 17th Street Blair, NE 68008-2055 Mr. Alan P. Nelson Nuclear Energy Institute 1776 I Street, NW., Suite 400 Washington, DC 20006-3708