ML14178A962

Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station License Renewal Application

ML14178A962
Person / Time
Site:	Davis Besse
Issue date:	07/07/2014
From:	Sayoc E License Renewal Projects Branch 1
To:	Lieb R FirstEnergy Nuclear Operating Co
Sayoc E, 415-4084
References
TAC ME4640
Download: ML14178A962 (8)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 July 7, 2014 Mr. Raymond A. Lieb Vice President Davis-Besse Nuclear Power Station FirstEnergy Nuclear Operating Company 5501 North State Route 2 Oak Harbor, OH 43449

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL APPLICATION (TAC NO. ME4640)

Dear Mr. Lieb:

By letter dated August 27, 2010, FirstEnergy Nuclear Operating Company submitted an application pursuant to Title 10 of the Code of Federal Regulations Part 54 for renewal of Operating License NPF-3 for the Davis-Besse Nuclear Power Station. The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) is reviewing this application in accordance with the guidance in NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants. During its review, the staff has identified areas where additional information is needed to complete the review. The staffs requests for additional information are included in the enclosure. Further requests for additional information may be issued in the future.

Items in the enclosure were discussed with Cliff Custer, of your staff, and a mutually agreeable date for the response is July 30, 2014. If you have any questions, please contact me by telephone at 301-415-4084 or by e-mail at Emmanuel.Sayoc@nrc.gov Sincerely,

/RA/

Emmanuel Sayoc, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-346

Enclosure:

As stated cc w/encl: Listserv

ML14178A962 *concurred via email OFFICE LA:DLR/RPB2* PM:DLR/RPB1 BC:DLR/RPB1 PM:DLR/RPB1 NAME IKing ESayoc YDiaz-Sanabria ESayoc DATE 7/1/14 7/7/14 7/7/14 7/7/14

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL APPLICATION (TAC NO. ME4640)

DISTRIBUTION:

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E. Keegan B. Harris (OGC)

C. Kanatas(OGC)

E. Brown J. Uribe

DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL APPLICATION SUPPLEMENTAL REQUESTS FOR ADDITIONAL INFORMATION RAI 3.0.3-3a

Background:

The response to request for additional information (RAI) 3.0.3-3 dated January 31, 2014, states that a representative sample of internally coated piping components consisting of at least 73 1-foot axial length circumferential segments of piping or 50 percent of the total length of each coating material and environment combination will be inspected.

Issue:

The staff has concluded that inspection locations should be selected based on susceptibility to degradation and consequences of failure in addition to potential problems identified during prior inspections, and known service life history. The RAI response did not address this aspect of selecting coating inspection locations. In addition, it does not state the length of piping that will be examined if geometric limitations impede access to the entire internal circumference of any piping segment.

Request:

1. State the criteria for selecting a representative sample of internally coated piping and piping components.

2. State the length of piping that will be examined if geometric limitations impede access to the entire internal circumference of any piping segment.

RAI 3.0.3-3b

Background:

The response to RAI 3.0.3-3 states that adhesion testing should be conducted to ensure that the blister is completely surrounded by sound coating bonded to the surface. It also states that locations where access to the interior of components is permitted, adhesion testing should be conducted for coated areas that are determined to be suspect, deficient, or degraded as directed by the coatings program owner.

Issue:

By adding the premise should to the testing requirements criteria, the staff believes the threshold for performing adhesion testing is not clearly defined and may lead to ambiguity.

Furthermore, LRA Section A.1.44 provides the UFSAR supplement for the Service Level III Coatings and Linings Monitoring Program. The staff noted that there are no requirements in the UFSAR supplement to conduct adhesion testing for coated surfaces determined to not meet the acceptance criteria. Draft LR-ISG-2013-01, Table 3.0-1 states, [f]or coated surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing). The test consists of destructive or nondestructive adhesion testing using ASTM International Standards endorsed in RG 1.54, Service Level I, II, and III Protective Coatings Applied to Nuclear Plants.

ENCLOSURE

Request:

1. Confirm that adhesion testing shall be conducted in accordance with the guidance established in LR-ISG-2013-01. Otherwise, provide adequate justification if another methodology is to be used in lieu of the guidance developed by the staff. The response should clearly define why the alternate methodology meets or exceeds the guidance established in LR-ISG-2013-01.

2. If the guidance in LR-ISG-2013-01 is to be used, revise the UFSAR Section A.1.44 to be consistent with the draft LR-ISG-2013-01. Otherwise, state the basis for not including the requirements for adhesion testing.

RAI B.2.18-2

Background:

The parameters monitored/inspected and detection of aging effects program elements of LR-ISG-2012-02 aging management program (AMP) XI.M27 recommend that internal visual inspections used to detect loss of material should be capable of detecting surface irregularities that could be indicative of wall loss below nominal pipe wall thickness due to corrosion and corrosion product deposition and that where such irregularities are detected, follow-up volumetric examinations are performed.

The acceptance criteria program element of LR-ISG-2012-02 AMP XI.M27 states that,

[a]dditionally, if the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material is removed and its source is determined and corrected.

Issue:

The staff noted that the changes to the Fire Water Program in Amendment No. 48, dated February 19, 2014, did not include these recommendations.

Request:

State the basis for not including these recommendations in the Fire Water Program, or revise the program to include these recommendations.

RAI 3.0.3.4.3-01

Background:

LRA Section 2.3.3.21 states that the miscellaneous liquid radwaste system satisfies the scoping criteria for 10 CFR 54.4(a)(2). License renewal drawing M-037C, Clean Liquid Radioactive Waste System, states that the clean waste receiver tanks are in-scope and have a nominal capacity of 103,000 gallons.

Issue:

LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation, revised the scope of program program element of Generic Aging Lessons Learned (GALL) Report AMP XI.M29, Aboveground Metallic Tanks, to include certain indoor large-volume tanks (e.g., greater than 100,000 gallons) in the

scope of this program. During its review of the changes to the Aboveground Steel Tanks Program described by letter dated February 19, 2014, the staff noted that the clean waste receiver tanks may meet the revised guidance, but were not included in the scope of the program.

Request:

State whether the clean waste receiver tanks should be in the scope of LR-ISG-2012-02 AMP XI.M29. If so:

1. Revise the program to include the clean waste receiver tanks, or

2. State the basis for why it is not necessary to include these tanks in the scope of the Aboveground Steel Tanks Inspection Program.

3. State whether there are other indoor tanks that should be within the scope of the Aboveground Steel Tanks Inspection Program.

RAI 3.0.3.4.3-02

Background:

The External Surfaces Monitoring Program was revised by letter dated February 19, 2014, to include inspections related to Corrosion Under Insulation (CUI). The revised Aboveground Steel Tanks Inspection Program does not include inspections related to CUI.

During the audit, the staff noted that the Borated Water Storage Tank (BWST) is insulated, and is located in an environment which could result in stress corrosion cracking of the stainless steel tank (e.g., located within 1/2 mile of a salt treated highway, or other sources of chlorides). The response to RAI B.2.2-2 dated May 24, 2011, states that: (a) the outdoor air environment could result in an Aging Effect Requiring Management (AERM) for the BWST; (b) the polyurethane foam insulation installed on the BWST is limited to leach less than 1000 ppm chlorides; and (c) the Aboveground Steel Tanks Inspection Program was revised to manage Stress Corrosion Cracking (SCC) for the BWST. The response to RAI B.2.2-2 describes the insulation as polyurethane foam on a base coat of epoxy-polyamide with an intermediate layer of butyl rubber and a top layer of aliphatic urethane.

Issue:

It is not clear to the staff whether the inspections related to CUI in the External Surfaces Monitoring Program include inspections of the BWST insulation. The number and periodicity of inspections in LR-IG-2012-02 AMP XI.M29 are generally in alignment with those for LR-IG-2012-02 AMP XI.M36, External Surfaces Monitoring of Mechanical Components; however, the recommended inspection locations are different.

Based on a review of Licensee Event Report No. NP-82-01, dated October 11, 1984, the staff noted that the insulation for the BWST was added a number of years after the plant was placed in service. The staff also noted that RG 1.36, Nonmetallic Thermal Insulation for Austenitic Stainless Steel, Figure 1, recommends an upper limit of chlorides and fluorides dependent on the sodium and silicate content of the insulation. The specificity of the response to RAI B.2.2-2 in relation to chloride content of the insulation is inadequate to conclude that the leachable chlorides and fluorides would not result in SCC. Given that the exterior surfaces of the tank could have been exposed to elevated levels of chlorides prior to the application of the insulation and the potential amount of leachable chloride in the insulation, the staff seeks clarification on the specific inspections and periodicity of inspections, which will be used to manage loss of

material due to pitting and crevice corrosion, and cracking on the exterior surfaces of the BWST.

In addition, the insulation appears to be that which would be described as tightly adhering insulation. LR-IG-2012-02 AMP XI.M29 does not require removal of tightly adhering insulation unless there is evidence of damage to the moisture barrier. This might not be appropriate depending on whether pre-installation inspections of the bare metal surfaces were conducted and the plant-specific operating experience related to the integrity of the insulations moisture barrier.

Request:

1. Confirm whether the insulation installed on the BWST is considered as tightly adhering insulation and impermeable to moisture.

2. State whether inspections of the BWST insulation will be conducted under the External Surfaces Monitoring Program. If this is the case, state the extent and periodicity of inspections, the inspection methods, and how inspection locations will be selected. If no inspections will be conducted, state the basis for why there is reasonable assurance that the BWST will perform its current licensing basis intended functions.

3. State whether visual and surface examinations sufficient to detect loss of material due to pitting and crevice corrosion and cracking were conducted on the external surfaces of the BWST prior to installing the insulation. If they were not conducted, state the basis for why bare metal inspections would not have to be conducted prior to the period of extended operation.

4. Provide a summary of plant-specific operating experience related to the integrity of the BWST insulation. If there have been instances of damage to the insulation such that moisture could have penetrated to the surface of the BWST, state what inspections have been conducted on the bare metal surfaces of the tank. If none were conducted, state the basis for why bare metal inspections would not have to be conducted prior to the period of extended operation.

RAI 2.3.3.26-2

Background:

By notice in the Federal Register on November 22, 2013, the NRC announced the availability of LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation. By letter dated February 19, 2014, Davis-Besse Nuclear Power Station (Davis-Besse) stated that it had reviewed LR-ISG-2012-02 and identified changes needed for the LRA to align with the updated guidance in the LR-ISG. For loss of material due to recurring internal corrosion, Davis-Besse stated that it had identified recurring internal corrosion in the service water system at the site. The response states that nondestructive examination methods, including visual examinations and ultrasonic testing, are used to detect fouling and loss of material. It also states when visual inspections are used to identify loss of material, the inspection technique is capable of detecting surface irregularities that could indicate wall loss below nominal wall thickness, and where such irregularities are detected, follow-up volumetric wall thickness examinations are performed. The response also states that the Open-Cycle Cooling Water program utilizes the corrective action program to document degradations and to evaluate corrosion rates so piping and related components are cleaned and replaced prior to loss of function.

Issue:

LR-ISG-2012-02 added Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (SRP-LR), Further Evaluation Section 3.3.2.2.8, Loss of Material due to Recurring Internal Corrosion, that discusses the need for considering augmented requirements to ensure the adequate management of any recurring aging effects. This Further Evaluation section includes the following five aspects:

1. State why the programs examination methods will be sufficient to detect the recurring aging effect before affecting the ability of a component to perform its intended function.

2. State the basis for the adequacy of the augmented inspections.

3. State what parameters will be trended as well as the decision points where increased inspections would be implemented.

4. State how inspections of components that are not easily accessed will be conducted.

5. State how leaks in any involved buried or underground components will be identified.

6. Although the cited letter discussed some portions of the above aspects, it did not clearly address all of the criteria discussed in the Further Evaluation section. The staff noted that the LRA included a discussion regarding the identification of wall thickness measurements in segments of service water piping that were below procedural limits, but met design requirements. However, the cited letter did not discuss whether augmented inspections would be performed to manage the recurring internal corrosion.

Request:

Please provide additional information that would clarify how FirstEnergy Nuclear Operating Company intends to meet each of the five elements of the Further Evaluation section stated above for LR-ISG-2012-02.