ML18152B623

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Forwards Response to NRC GL 98-04, Potential for Degradation of ECCS & CSS After LOCA Because of Construction & Protective Coating Deficiencies & Foreign Matl in Containment.
ML18152B623
Person / Time
Site: Surry, North Anna  Dominion icon.png
Issue date: 11/10/1998
From: Ohanlon J
VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
98-449, GL-98-04, GL-98-4, NUDOCS 9811170264
Download: ML18152B623 (26)
v • d • e


Text

VIRGINIA ELECTRIC AND PowER CoMPANY Ri:cuMoNo, VIRGINIA 23261 e

November 10, 1998 United States Nuclear Regulatory Commission Serial No.98-449 Attention: Document Control Desk NL&OS/SLW RO Washington, D. C. 20555-0001 Docket Nos. 50-280, 281 50-338, 339 License Nos. DPR-32, 37 NPF-4, 7 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY SURRY AND NORTH ANNA POWER STATIONS UNITS 1 AND 2 NRC GENERIC LETTER 98-04: POTENTIAL FOR DEGRADATION OF THE EMERGENCY CORE COOLING SYSTEM AND THE CONTAINMENT SPRAY SYSTEM AFTER A LOSS-OF-COOLANT ACCIDENT BECAUSE OF CONSTRUCTION AND PROTECTIVE COATING DEFICIENCIES AND FOREIGN MATERIAL IN CONTAINMENT GL 98-04 addresses several issues regarding foreign material intrusion and coating detachment which have the potential for degradation of the emergency core cooling (ECCS) and the containment spray (CS) systems. Specifically, the NRC is requesting information which confirms compliance with 10 CFR 50.46 for long term cooling capability as well as a description of how the plant specific programs for procuring, applying and maintaining Service Level 1 coatings are in compliance with the plant specific licensing basis.

Pursuant to 10 CFR 50.54(f), the requested information is provided in Attachment 1 for Surry Units 1 and 2 and in Attachment 2 for North Anna Units 1 and 2. The information provided is a summary of the current programs and licensing basis information. No new commitments or changes to previous commitments, are made or should be inferred from the information provided.

Please contact us if you have any questions or require additional information.

Very truly yours, James P. O'Hanlon Senior Vice President - Nuclear Attachments 9811170264 981110 PDR ADOCK 05000280 P PDR

  • r Commitments made in this letter: None.

cc: US.Nuclear Regulatory Commission Region II Atlanta Federal Center 61 Forsyth Street, S.W., Suite 23T85 Atlanta, Georgia 30303 Mr. R. A. Musser NRG Senior Resident Inspector Surry Power Station Mr. M. J. Morgan NRG Senior Resident Inspector North Anna Power Station Mr. Anthony R. Pietrangelo Nuclear Energy Institute 1776 I Street, NW, Suite 400 Washington D.C. 20006-3708 Mr. Biff Bradley Nuclear Energy Institute 1776 I Street, NW, Suite 400 Washington D.C. 20006-3708

COMMONWEALTH OF VIRGINIA )

)

COUNTY OF HENRICO )

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by J. P. O'Hanlon, who is Senior Vice President - Nuclear, of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this JD'Il:1 day of nov[nlh.vL , 19 qct.

My Commission Expires: March 31, 2000.

C (SEAL)

e I

Attachment 1 NRC GENERIC LETTER 98-04: POTENTIAL FOR DEGRADATION OF THE EMERGENCY CORE COOLING SYSTEM AND THE CONTAINMENT SPRAY SYSTEM AFTER A LOSS-OF-COOLANT ACCIDENT BECAUSE OF CONSTRUCTION AND PROTECTIVE COATING DEFICIENCIES AND FOREIGN MATERIAL IN CONTAINMENT RESPONSE TO REQUESTED INFORMATION SURRY POWER STATION UNITS 1 AND 2 VIRGINIA ELECTRIC AND POWER COMPANY

1 ..

Docket~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 1 of 11 Surry Power Station Response to GL 98-04 Generic Letter 98-04 Requested Information:

(1) A summary description of the plant-specific program or programs implemented to ensure that Service Level 1 protective coatings used inside containment are procured, applied, and maintained in compliance with applicable regulatory requirements and the plant-specific program meets the applicable criteria of 10 CFR Part 50, Appendix B, as well as information regarding any applicable standards, plant-specific procedures, or guidance used for: (a) controlling the procurement of coatings and paints used at the facility, (b) the qualification testing of protective coatings, and (c) surface preparation, application, surveillance, and maintenance activities for protective coatings. Maintenance activities involve reworking degraded coatings, removing degraded coatings to sound coatings, correctly preparing the surfaces, applying new coatings, and verifying the quality of the coatings.

Response

Virginia Power has implemented controls for the procurement, application, and maintenance of Service Level 1 protective coatings used inside containment in a manner that is consistent with the licensing basis and regulatory requirements applicable to Surry Power Station Units 1 and 2. The requirements of 10 CFR Part 50 Appendix B are implemented through specification of appropriate technical and quality requirements for the Service Level 1 coatings program that include ongoing maintenance activities.

For Surry Power Station Units 1 and 2, Service Level 1 coatings (i.e., coatings procured, applied and maintained by Virginia Power) are subject to the requirements of the Surry UFSAR Sections 4.2.2.1 System Design and Operation (Components - Reactor Vessel), 6.2.3.3 Safety Injection System (Chemical Additives), and 15.5.1.12 Specific Containment Structure Designs (Containment Structure - Ground Water Protection and Corrosion). Reference to regulatory guides, ANSI, ASTM, or other guidance documents or standards in this response, but not specifically stated in the Surry UFSAR does not infer the use of such documents as a licensing. or regulatory commitment. . *Procedures

.~'

Docke~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 2 of 11 and p'rogrammatic controls provide adequate assurance that the applicable requirements for the procurement, application, inspection, and maintenance of coatings are implemented. Virginia Power has recently completed a self-assessment of its safety-related coatings program utilizing the EPRI TR-109937 "Guideline on Nuclear Safety-Related Coatings" as a comparison.

Enhancements to the program, which were identified during the assessment, will be considered for inclusion into the appropriate process procedures.

Coated components supplied by vendors, for installation inside containment, are purchased as a result of a design change, a repair or refurbishment for maintenance, or a replacement. The coatings applied to vendor supplied components are specified to meet or exceed the coating requirements of the licensing basis. If the vendor cannot provide a coating system to meet the original specification, coating requirements are evaluated and upgrading to a qualified coating system may be required.

Although conformance to Regulatory Guide 1.54 is not a licensing commitment for Surry, Virginia Power incorporates the intent of Regulatory Guide 1.54 as the primary guidance used for coating activities performed by Virginia Power inside containment. Additionally; (a) Procurement of Service Level 1 coatings used for new, repair, or replacement coating activities are procured from vendors with an approved quality assurance program meeting the applicable requirements of 10 CFR Part 50 Appendix B. Virginia Power specifies in procurement documents the applicable technical and quality requirements that the vendor is required to meet when supplying Service Level 1 coatings.

Receipt inspection activities are conducted in accordance with procedures that are consistent with ANSI N45.2.2 and provide adequate assurance that the coatings received meet the requirements of the procurement document. Virginia Power conforms to ANSI N45.2.2 regarding storage of Service Level 1 coatings. The extent of conformance of Virginia Power's quality assurance program to applicable regulatory guides and ANSI standards is as stated in Virginia Power's Quality Assurance Program Topical Report.

(b) The performance testing of Service Level 1 coatings for new applications, repair, or replacement activities inside containment meets the applicable re*qUiremerits contained *in the* 1icensirig basis *retefrehced *above.

  • These
  • J Docke~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 3 of 11

'coatings have been evaluated as meeting the applicable performance requirements. Virginia Power's coating program specifies that these coatings be qualified in accordance with ANSI N101.2. New and

,_ replacement Service* Level 1 coatings applied by Virginia Power have been incorporated into Virginia Power's coating program. Evaluations include qualification testing for alternate surface preparation techniques and single coat applications.

(c) The surface preparation, application and surveillance during installation of Service Level 1 coatings used for new applications, repair, or replacement activities inside containment meet the applicable requirements contained in the standards and regulatory commitments referenced above. Virginia Power's installation specification for inside containment protective coatings contains the technical requirements for surface preparation and coating application. Specific procedural content and direction are contained in safety-related application procedures. Large scale coating over existing coating systems as a recovery technique is not permitted.

Applicator personnel are qualified in accordance with procedures consistent with ASTM 4227 and ASTM 4228. Coating inspectors are qualified in accordance with ANSI N45.2.6. Documentation of these activities is consistent with the applicable requirements of ANSI N 101.4.

Visual inspections are conducted during refueling outages to assess the condition of coatings inside containment. Enhancement of Virginia Power's current practices is in progress using EPRI TR-109937 as a guide. In addition, Virginia Power has initiated ASME Section XI IWE inspections. Deviations noted during the inspections will be processed through the corrective action process. If conditions are determined to significantly degrade or fail the containment sump capability due to coating degradation, an appropriate Maintenance Rule evaluation of degraded containment coatings will be completed. The Maintenance Rule evaluation would include determination if the condition was maintenance preventable and if goals should be established.

2(ii) For plants without the above licensing-basis requirements, information shall be provided to demonstrate compliance with the requirements of 10CFR50.46b(5), "Long-term cooling" and the functional capability of the safety-related CSS as set forth in your

    • "licensiri~f *basis. -*u *a *ucensee --*ca*n
  • demoristrate "this** compliance
  • Docket~.50-280,281, 338,339
  • Serial No.98-449 Attachment 1 Page 4 of 11
  • without quantifying the amount of unqualified coatings, this is acceptable.

The following description and referenced materials presents the licensing basis for Surry Power Station Units 1 and 2 relative to conformance with 10 CFR 50.46{b)(5), "Long-term cooling." The focus of this description involves the ability to provide extended decay heat removal including related assumptions for debris that could block containment emergency sump screens.

Surry Units 1 and 2 are licensed to the following general requirements that relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b}{5} and the functional capability of the safety-related CSS:

This requirement became part of the Surry Units 1 and 2 licensing basis upon issuance of an Order for Modification of License, dated December 27, 1974 (Reference a). This supplemented the original licensing basis, which was in accordance with the Interim Acceptance Criteria (Reference b). The Surry Unit 1 an.d 2 original Safety Evaluation Report (Reference c) documents the original licensing basis under the Interim Acceptance Criteria.

  • GDC 37 (Draft), "Engineered Safety Features Basis of Design," July 11, 1967
  • GDC 38 (Draft), "Reliability and Testability of Engineered Safety Features,"

July 11, 1967

  • GDC 41 (Draft), "Engineered Safety Features Performance Capability," July 11, 1967
  • GDC 42 (Draft), "Engineered Safety Features Components Capability," July 11, 1967

!- l

( ..

Docket* . 50-280, 281, 3S8, 339 Serial No.98-449 Attachment 1 Page 5 of 11

July 11, 1967

  • GDC 52 (Draft), "Containment Heat Removal Systems," July 11, 1967
  • GDC 58 (Draft), "Inspection of Containment Pressure-Reducing Systems,"

July 11, 1967

  • GDC 59 (Draft}, "Testing of Containment Pressure-Reducing Systems Components," July 11, 1967
  • GDC 60 (Draft), "Testing of Containment Spray Systems," July 11, 1967 Surry Units 1 and 2 satisfy the following detailed licensing basis requirements that relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:
  • the onset of long-term cooling mode is defined as the time at which the switchover from injection mode to the sump recirculation mode is performed
  • the core must be maintained in a subcritical state by the borated water delivered via the ECCS, with no credit taken for insertion of control rods
  • emergency operating procedures contain provisions to alternate between cold leg and hot leg recirculation injection to prevent precipitation of boric acid in the core
  • the RS System shall provide cooling for containment sump water following a OBA, such that water recirculated to the reactor coolant system will provide adequate core cooling
  • the RS System shall be capable of maintaining the subatmospheric pressure in the containment for an extended period following the design basis accident
  • the LHSI and RS System pumps shall be capable of meeting NPSH requirements-under . LOCA-conditions - * * ,. * -* - ** *
  • Docket* . 50-280, 281, 338, 339 Serial No.98-449 Attachment 1 Page 6 of 11 The following additional licensing commitments that are applicable to Surry Units 1 and 2 relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:

UFSAR Commitments The following discussion pertaining to containment spray systems and sump performance as it relates to debris effects is excerpted from the current UFSAR, Revision 29. This discussion represents the current licensing basis for Surry Units 1 and 2 regarding these effects. The relevant UFSAR section numbers are indicated. The description extant when the Surry Units 1 and 2 SER (Reference c) was issued, was contained in the FSAR, inclusive of Amendment No. 32, dated February 11, 1972. Material which has been revised since the original FSAR is denoted below in bold text.

"Section 6.3.1.3, Description [for Spray System]

NRC Bulletin 93-02 (Reference d) required licensees to evaluate their facilities for the potential of fibrous material installed or stored in containment to detrimentally affect the functional capability of the Emergency Core Cooling System (ECCS) due to the clogging of suction strainers. The potential effects of fibrous debris on the Surry ECCS was evaluated and provided to the NRC in response to the Bulletin (Reference e).

The reactor containment contains the following types of permanent fibrous material which have been considered for their potential to become fibrous debris in the event of a LOCA or high energy line break:

1. Ventilation filters
2. Fire stop material (Cerafiber)
3. Pipe/component insulation Ventilation filters are considered not to be a significant contributor of fibrous debris at the containment sump screens because of the strength of the filter media and the encapsulation/retaining screens employed in installation. Fire stop material, used in electrical cable trays are also not considered to contribute significant debris at the containment sumps because of its installation design and location. Only pipe/component insulation is considered to be a credible source of fibrous debris because ofthe quantity inslalled *and its*1ocaticfr1~

Docket~.50-280,281, 338,339 Serial No.98-449 Attachment 1 Page 7 of 11 The steam generator cubicles contain the largest quantity of insulation that could be exposed to a LOCA/high energy line break. No other credible mechanism for insulation dislodgment has been identified. The area of influence of a high energy line break is also the largest in the steam generator cubicles due to the large diameter piping and components present. The design of the steam generator cubicles is such that it is very difficult for insulation debris to exit the cubicles. On the operating floor, any insulation debris that is ejected out of the steam generator cubicle openings over the bioshield wall and/or the crane wall would not likely be transported from the operating floor to the containment sump due to the complex and protracted path through grating or down stairwells. Inside the cubicles insulation debris would have to pass through floor grating to reach the elevation below. Should any insulation debris inside the cubicles manage to reach the lower level of the cubicles, it must then pass through a door/grating.

Debris created by a LOCA in the reactor cavity would not be expected to reach the containment sump since the cavity is completely enclosed on the bottom and the sides, and any debris blown upward to the operating floor would have to be transported along a complex and protracted path through grating and down stairwells before it could reach the sump. This also includes the area of the in-core sump room. Any debris created by a LOCA in the pressurizer cubicle would likewise be required to migrate down stairwells or through grating to reach the containment sump and is not likely to deposit a significant volume of debris at the sump due to this complex and protracted path.

Based on the evaluation discussed above, it was concluded that the effectiveness of the ECCS will not be compromised as a result of containment sump blockage due to the potential for dislodged fibrous material during a LOCA/high energy line break.

As detailed above, probability of screen clogging is remote. However, if the first-stage or the second-stage screens of one of the suction points did become clogged so that no water could be supplied to a pump suction, the cross-connecting line would supply water to that pump from the other section of the sump through the other 12-inch suction line. Thus, both pumps would remain operational.

The screen assembly is designed to prevent debris large enough to cause

. clogged. spray.. nozzles from .reaching .the -recirculation .spray ,subsystems. The screen assembly for the pump suctions is divided into two stages. The first stage

  • Docket~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 8 of 11 is a trash rack and roughing screen arrangement completely surrounding the sump. The second stage consists of cylindrical screens of fine mesh over each suction point. The trash rack and all screening and screen supports are designed to the Seismic Class I requirements.

The first stage of the screen assembly consists of inclin.ed grating, which acts as a trash screen to. prevent large pieces of debris from reaching the sump. Inside the grating, ther.e are two layers of screening, the first consisting of a roughing mesh and the second of a final mesh with an opening approximating the size of the smallest nozzle orifice in the recirculation spray header. The first-stage screening is divided at the centerline of the sump by a screening partition so that the physical failure of either half of the first stage will have little or no effect on the operation of the other half. Each half of the first stage has an area of.

approximately 79 ft 2 per section, for a total first-stage screen area of approximately 158 ft 2 , not including the screening partition at the centerline of the sump.

The second stage of the screen assembly consists of cylindrical screens surrounding the pump suction points. The low head safety injection and outside recirculation spray pumps' cylindrical suction screens each have a total vertical screening area of approximately 27 ft2 and the inside recirculation spray pumps' cylindrical suction screens each have a total vertical screening area of approximately 55 ft2

  • The cylindrical screens extend from the containment liner in the sump to the first stage screen assembly above the sump. These cylindrical screens provide for continuous filtered flow to the pump suction point in the event of failure of the first-stage screen assembly.

The probability of screen clogging is remote. However, the screen assemblies are arranged so that no single failure results in the clogging of all suction points.

In fact, a first-stage screen assembly failure coupled with the plugging or failure of the suction point cylindrical screens must occur for any one of the suction points to be lost. Sufficient screen area is provided to ensure that system operation during incident conditions is not impaired, and entrance flow velocities are low enough to prevent entrainment of most small particles."

Technical Specifications Commitments The Surry Units 1 and 2 Technical Specifications contain the following provisions which enhance the ability of the containment sump to support systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional .capab_ility _of t~_e safety~~elat~-~ <:;~S: ........... *-*- . .

  • I I Docket* . 50-280, 281, 338, 339 Serial No.98-449
  • Attachment 1 Page 9 of 11 "Specification 4.5, Spray System Tests D. A visual inspection of the containment sump and the inside containment recirculation spray pump wells and the engineered safeguards suction inlets shall be performed once per 18 months and/or after major maintenance activities in the containment. The inspection should verify that the containment sump and pump wells are free of debris that could degrade system operation and that the sump components (i.e., trash racks, screens) are properly installed and show no sign of structural distress or excessive corrosion."

"Specification 4.11, Safety Injection System Tests C.5.c Verifying, by visual inspection, that each low head safety injection pump suction inlet from the containment sump is free of debris that could degrade system operation. Perform each refueling outage and/or after major maintenance activities in the containment."

At the time Surry Units 1 and 2 were licensed, no distinction was drawn between the various potential sources for post-LOCA debris. The ECCS and spray systems were intended to function, even with debris partially obstructing the sumps, and regardless of the source of the debris. The design evaluation, submitted as part of the original licensing basis for Surry Units 1 and 2, demonstrates that the emergency core cooling and containment spray systems will continue to provide sufficient cooling flow so as to fulfill the long-term cooling functions required to conform with 10 CFR 50.46(b)(5).

The NRC approved the original assessment of the spray and ECCS systems as meeting the requirements of 10 C.F.R 50.46(b)(5) in the Surry SER (Reference c). In Section 3.2.2.2, Emergency Core Cooling System (ECCS), of the Surry SER, the following is stated with regard to the ECCS systems:

"The emergency core cooling system continues to remove decay heat and to reduce the core temperature following a transient. Emergency core cooling water which spills from the reactor coolant system rupture collects in the containment sump where it is mixed with the cooler containment spray and recirculation spray water. The sump water is recirculated to the reactor vessel by the low head safety injection system. No single failure of active emergency core cooling system components, and no single failure of passive components during the long-term cooling phase will reduce

  • system periormance below*acceptable*levels." * * *- *

'* 'I Docket~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 10 of 11 In Section 3.2.2.4, Containment Spray of the Surry SER, the following is stated with regard to the spray systems (Containment Spray and Recirculation Spray):

"We have reviewed the design of the system as installed and the redundancy provided for vital equipment and have concluded that the system is adequate to cool the containment following a loss-of-coolant accident."

The current licensing basis for Surry Units 1 and 2, as accepted by the NRG in the SER (Reference c), provides both the regulatory and safety basis for safety system performance. Coatings are not treated separately in the licensing basis for Surry Units 1 and 2 ECCS design. Consistent with applicable regulatory requirements, the type and quantity of debris were not explicitly considered when the original calculations for the ECCS sump head loss were performed. The assessment of potential sump debris was documented and accepted during original licensing without specific quantification of effects by calculation. The licensing basis thus does not distinguish or consider the source of the LOCA-generated debris.

(2)(ii)(a) If commercial-grade coatings are being used at your facility for Service Level 1 applications, and such coatings are not dedicated or controlled under your Appendix 8 Quality Assurance Program, provide the regulatory and safety basis for not controlling these coatings in accordance with such a program. Additionally, explain why the facility's licensing basis does not require such a program.

Response

Virginia Power does not currently employ commercial grade dedication for Service Level 1 coating that are applied inside containment at Surry Power Station Units 1 and 2.

  • Docket~.50-280,281,338,339 Serial No.98-449 Attachment 1 Page 11 of 11

References:

(a) Letter to Virginia Electric & Power Company from Robert A. Purple,

  • forwarding "Order for Modification of License," December 27, 1974.

(b) Interim Acceptance Criteria for Emergency Core Cooling Systems for Light Water Power Reactors, 36 F.R. 12247, June 29, 1971, as amended 36 F.R.

24082, December 18, 1971 .

(c) Safety Evaluation by the Division of Reactor Licensing, US Atomic Energy Commission, Surry Power Station Units 1 and 2, Docket Nos. 50-280 and 50-281, February 23, 1972.

(d) NRC Bulletin No. 93-02: "Debris Plugging of Emergency Core Cooling Suction Strainers," May 11, 1993.

(e) Letter from Virginia Electric and Power Company to the NRC, Serial No.93-307, June 10, 1993, Forwards Response to NRC Bulletin 93-02.

,t} I fl Attachment 2 NRC GENERIC LETTER 98-04: POTENTIAL FOR DEGRADATION OF THE EMERGENCY CORE COOLING SYSTEM AND THE CONTAINMENT SPRAY SYSTEM AFTER A LOSS-OF-COOLANT ACCIDENT BECAUSE OF CONSTRUCTION AND PROTECTIVE COATING DEFICIENCIES AND FOREIGN MATERIAL IN CONTAINMENT RESPONSE TO REQUESTED INFORMATION NORTH ANNA POWER STATION UNITS 1 AND 2 VIRGINIA ELECTRIC AND POWER COMPANY

Docketl. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 1 of 10 North Anna Power Station Response to GL 98-04 Generic Letter 98-04 Requested Information:

(1) A summary description of the plant-specific program or programs implemented to ensure that Service Level 1 protective coatings used inside containment are procured, applied, and maintained in compliance with applicable regulatory requirements and the plant-specific program meets the applicable criteria of 10 CFR Part 50, Appendix B, as well as information regarding any applicable standards, plant-specific procedures, or guidance used for: (a) controlling the procurement of coatings and paints used at the facility, (b) the qualification testing of protective coatings, and (c) surface preparation, application, surveillance, and maintenance activities for protective coatings. Maintenance activities involve reworking degraded coatings, removing degraded coatings to sound coatings, correctly preparing the surfaces, applying new coatings, and verifying the quality of the coatings.

Response

Virginia Power has implemented controls for the procurement, application, and maintenance of Service Level 1 protective coatings used inside containment in a manner that is consistent with the licensing basis and regulatory requirements applicable to North Anna Power Station Units 1 and 2. The requirements of 10 CFR Part 50 Appendix B are implemented through specification of appropriate technical and quality requirements for the Service Level 1 coatings program that includes ongoing maintenance activities.

For North Anna Power Station Units 1 and 2, Service Level 1 coatings (i.e.,

coatings procured, applied and maintained by Virginia Power are subject to the requirements of the North Anna UFSAR Section 3.8.2.7.6, Protective Coatings (Paints), specifically section 3.8.2.7.6.2.5, Operations Phase. This section discusses the North Anna specification that governs the coating systems to be used inside containment and the application requirements for coatings applied post-construction. Reference to regulatory guides, ANSI, ASTM, or other guidance _d()cuments or_ S!<<:lJ]d_c1,rds__ !11 this_ rE:3~pqns.e_, but_n~.t ~pecifiq_ally staJ~d in the North Anna UFSAR does not infer the use of such documents as a licensing or regulatory commitment. Procedures and programmatic controls provide adequate assurance that the applicable requirements for the procurement, application, inspection, and maintenance of coatings are implemented. Virginia Power has recently completed a self-assessment of its safety-related coatings program utilizing the EPRI TR-109937 "Guideline on Nuclear Safety-Related

Dockett. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 2 of 10 Coatings" as a comparison. Enhancements to the program, which were identified during the assessment, will be considered for inclusion into the appropriate process procedures.

Coated components supplied by vendors for installation inside containment are subject to the requirements of UFSAR Section 3.8.2.7.6.3 Vendor Supplied Coating of Components tor Installation Inside Containment. These components are purchased as a result of a design change, a repair or refurbishment for maintenance, or a replacement. The coatings applied to vendor supplied components are specified to meet or exceed the coating requirements of the licensing basis, which may require the coating system to be qualified tor OBA environmental conditions. If the vendor cannot provide a coating system to meet the original specification, coating requirements are evaluated and upgrading to a qualified coating system may be required. A significant reduction of unqualified coatings inside containment was accomplished with the completion of the North Anna Power Station Units 1 and 2 Steam Generator Replacement Projects.

Although conformance to Regulatory Guide 1.54 is not a licensing commitment tor North Anna, Virginia Power incorporates the intent of Regulatory Guide 1.54 as the primary guidance used tor coating activities performed by Virginia Power inside containment. Additionally; (a) Procurement of Service Level 1 coatings used tor new, repair, or replacement coating activities are procured from vendors with an approved quality assurance program meeting the applicable requirements of 10 CFR Part 50 Appendix 8. Virginia Power specifies in procurement documents the applicable technical and quality requirements that the vendor is required to meet when supplying Service Level 1 coatings.

Receipt inspection activities are conducted in accordance with procedures that are consistent with ANSI N45.2.2 and provide adequate assurance that the .coatings received meet the requirements of the procurement document. Virginia Power conforms to ANSI N45.2.2 regarding storage of Service Level 1 coatings. The extent of conformance of Virginia Power's quality assurance program to applicable regulatory guides and ANSI standards is as stated in Virginia Power's Quality Assurance Program Topical Report.

(b) The qualification testing of Service Level 1 coatings for new applications, repair; '"or* replacement **activities* 1nside -conlairimenf meets* the* applicable requirements contained in the licensing basis referenced above. These coatings have been evaluated as meeting the applicable standards and regulatory requirements referenced. Virginia Power's coating program specifies that these coatings be qualified in accordance with ANSI N101.2.

New and replacement Service Level 1 coatings applied by Virginia Power

Docket~.50-280,281,338, 339 Serial No.98-449 Attachment 2 Page 3 of 10 have been incorporated into Virginia Power's coating program.

Evaluations include qualification testing for alternate surface preparation techniques and single coat applications.

(c) The surface preparation, application and surveillance during installation of Service Level 1 coatings used for new applications, repair, or replacement activities inside containment meet the applicable requirements contained in the standards and regulatory commitments referenced above. Virginia Power's installation specification for inside containment protective coatings contains the technical requirements for surface preparation and coating application. Specific procedural content and direction are contained in safety-related application procedures. Large scale coating over existing coating systems as a recovery technique is not permitted.

Applicator personnel are qualified in accordance with procedures consistent with ASTM 4227 and ASTM 4228. Coating inspectors are qualified in accordance with ANSI N45.2.6. The North Anna coating inspector training program has been developed to contain the basic elements of the NACE coating inspector certification program 1 .

Documentation of these activities is consistent with the applicable requirements of ANSI N101.4.

Visual inspections are conducted during refueling outages to assess the condition of coatings inside containment. Enhancement of Virginia Power's current practices is in progress using EPRI TR-109937 as a guide. In addition, Virginia Power has initiated ASME Section XI IWE inspections. Deviations noted during the inspections will be processed through the corrective action process. If conditions are determined to significantly degrade or fail the containment sump capability due to coating degradation, an appropriate Maintenance Rule evaluation of degraded containment coatings will be completed. The Maintenance Rule evaluation would include determination if the condition was maintenance preventable and if goals should be established.

2(ii) For plants without the above licensing-basis requirements, information shall be provided to demonstrate compliance with the requirements of 10CFR50.46b(5), "Long-term cooling" and the functional capability of the safety-related CSS as set forth in your licensing basis. If a licensee can demonstrate this compliance

  • Withciut quantifying"*the'" amou"iit- of *tinqualifiea *-cc>'atings~*-*-this
  • is acceptable.

Response

1 Letter from J.P. O'Hanlon to NRC, "Clarification of Response to Notice of Violation Documented in NRC Inspection Report Nos.50-338/84-30 and 50-339/84-30", dated November 3, 1998.

  • .l ( f '~

Docketl. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 4 of IO The following description and referenced materials presents the licensing basis for North Anna Power Station Units 1 and 2 relative to conformance with 10 CFR 50.46(b)(5), "Long-term cooling." The focus of this description involves the ability to provide extended decay heat removal including related assumptions for debris that could block containment emergency sump screens. North Anna Units 1 and 2 are licensed to the following general requirements that relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:

  • GDC 38, "Containment Heat Removal," July 7, 1971
  • GDC 39, "Inspection of Containment Heat Removal System," July 7, 1971
  • GDC 40,"Testing of Containment Heat Removal System," May 21, 1971 North Anna Units 1 and 2 satisfy the following detailed licensing basis requirements that relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:
  • the onset of long-term cooling mode is defined as the time at which the switchover from injection mode to the sump recirculation mode is performed.
  • the core must be maintained in a subcritical state by the borated water delivered via the ECCS, with no credit taken for insertion of control rods.
  • emergency operating procedures contain provisions to alternate between cold leg -and .hot-leg reGirculation-*injection -to prevent J:>reeipitation -of.-boric-acid in the core.

,,_ l' Docketl. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 5 of 10

  • the RS System shall be capable of maintaining the subatmospheric pressure in the containment following a LOCA.
  • the LHSI and RS System pumps shall be capable of meeting NPSH requirements under LOCA conditions.

The following additional licensing commitments that are applicable to North Anna Units 1 and 2 relate to systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:

UFSAR Commitments The following discussion pertaining to containment spray systems and sump performance as it relates to debris effects is excerpted from the current UFSAR, Revision 34. This discussion represents the current licensing basis for North Anna Units 1 and 2 regarding these effects. The relevant UFSAR section numbers are indicated. The description extant when the North Anna Units 1 and 2 SER (Reference a) was issued was contained in the FSAR, inclusive of Amendment No. 51, dated May 17, 1976. Material which has been revised since the o*riginal FSAR, is denoted below in bold text.

"Section 6.2.2.2, System Design [Containment Depressurization System]

The containment sump screens are designed to prevent particles, larger in size than the smallest restriction within the RS system spray nozzles, from entering the RS and the LHSI systems.

As described in Section 3.8.2.7.6, protective coatings (paints) on exposed concrete and carbon steel surfaces remain intact if subjected to the environment associated with a postulated LOCA. It should be noted that the paint on the steam generators and pressurizer is not qualified. 2 The surfaces of these components are covered with metal jacketed insulation and therefore, normally not exposed. It is unlikely that large volumes of paint chips removed by concentrated LOCA forces will reach the containment floor. However, should paint chips or other debris reach the containment floor near the sump, all particles larger than the smallest restriction within the systems taking suction from the sump will be prevented from entering the sump by the second-and third-stage fine mesh sump screens. Smaller particles and silt that do not settle out on

  • *the-containment -floor-* away**from-the -sump*-and -are-recirculated ~will *-have no -

adverse effects upon the system components. The turbulent flow characteristics within the piping systems and components are sufficient to maintain the particles in suspension.

2 Most of the unqualified steam generator paint has been removed as a result of the steam generator replacement modification and decontamination activities. See UFSAR Table 3.8-11, Rev. 34.

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  • q. t::" i e Docket~.50-280,281, 338,339 Serial No.98-449 Attachment 2 Page 6 of 10 Insulation Debris and Transport

.The following sources are considered to determine the potential origin of debris due to a pipe or equipment failure that results in a LOCA:

1. The containment structure contains no loose insulation. All insulation is encapsulated.
2. Insulation in the path of the high energy coolant jet and/or a whipping pipe from the following areas:
a. Steam generator cubicles (including paint under steam generator insulation)
b. Pressurizer cubicle (including paint under pressurizer insulation)
c. Reactor cavity.
d. Adjacent to the portion of the pressurizer spray piping under the steam generator and pressurizer cubicles.
3. Supplementary reactor shield material saddles (see Chapter 12 for description) located in the reactor cavity.
4. Particle debris of the type that is uniformly distributed throughout the containment (Reference 22).
5. Failure of non-safety-related equipment within the containment. The debris that this failure could generate would be a small quantity of relatively large and heavy pieces. These items, if they were to reach the containment floor, would sink rapidly and would not be expected to contribute to sump screen blockage.

No sand plugs, sand bags, or loose insulation are located inside the containment.

The steam generator cubicles contain the largest quantity of insulation that could be exposed to a high-energy coolant jet and/or whipping pipe. No other mechanism for insulation dislodgment has been identified. The area of influence of a high-energy coolant jet is also the largest in the steam generator cubicles due to the large pipe diameters present. Break areas inside the steam generator cubicles are discussed in Section 6.2.1.1.2.

The resolution of the concerns associated with the provisions of adequate

..NPSH . under. non-debris .conditions, -and-adequate-housekeeping. practices, are expected to reduce the likelihood of problems during recirculation.

However, in the event that LHSI recirculation system problems such as pump cavitation or air entrainment do occur, the operator should have the capability to recognize and contend with these problems. Instrumentation available to monitor recirculation is summarized in Table 6.2-40."

Docke~s.50-280,281,338,339 Serial No.98-449 Attachment 2 Page 7 of 10 Technical Specifications Commitments The North Anna Units 1 and 2 Technical Specifications contain the following provisions which enhance the ability of the containment sump to support systems designed to meet the long term cooling requirements of 10CFR50.46(b)(5) and the functional capability of the safety-related CSS:

"Specification 4.5.2, Emergency Core Cooling Systems-Surveillance Requirements Each ECCS subsystem shall be demonstrated OPERABLE:

c. By a visual inspection which verifies that no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. This visual inspection shall be performed:
1. For all accessible areas of the containment prior to establishing CONTAINMENT INTEGRITY, and
2. Of the areas affected within containment at the completion of each containment entry when CONTAINMENT INTEGRITY is established.
d. At least once per 18 months by:
1. A visual inspection of the containment sump and verifying that the subsystem suction inlets are not restricted by debris and that the sump components (trash racks, screens, etc.) show no evidence of structural distress or corrosion."

Applicability of Regulatory Guide 1.82, Revision 1 The initial North Anna Units 1 and 2 Safety Evaluation Report (Reference a) was issued in June 1976, which was subsequent to issuance of Regulatory Guide 1.82, Rev. 0 (June 1974). However, there is no documented licensing commitment to Regulatory Guide 1.82 for North Anna Power Station Units 1 and

2. In the response to NRG Bulletin 93-02 (Reference b), Virginia Power committed that any future use of fibrous material in the containment at North Anna would continue to be evaluated, in accordance with the existing programs, for the potential to reduce the functional capability of the ECCS **system*. Design Changes 90-13 (Unit 1) and 93-011 (Unit 2) implemented replacement steam generators for North Anna Units 1 and 2. As part of this modification, it was proposed that fibrous blanket insulation be installed to replace the existing encapsulated insulation on the steam generators. The effects of adding this insulation to containment were analyzed by performing a debris generation and

e Docket Nos. 50-280, 281, 338, 339 f ' ' Serial No.98-449 Attachment 2 Page 8 of 10 transport analysis which incorporated the guidance of Regulatory Guide 1.82, Revision 1. This analysis supported a 10CFR50.59 safety evaluation which concluded that the SG replacement did not represent an unreviewed safety question. NRC documented their review of the 10CFR50.59 safety evaluation for this modification in Reference c. The letter concludes that the program and analyses supporting the 10CFR50.59 evaluation for the North Anna Unit 1 Steam Generator Replacement Project was found to be acceptable. This letter contained no discussion of the debris analysis or any commitment to R.G. 1.82. It is concluded that the application of the guidance of Regulatory Guide 1.82, Revision 1 in the Steam Generator Replacement Project is an instance of employing available guidance, consistent with the commitment in ~eference b, but without general application to the licensing basis. Specifically, this action does not represent a general licensing commitment to Regulatory Guide 1.82, Revision 1 for North Anna Units 1 and 2.

At the time North Anna Units 1 and 2 were licensed, no distinction was drawn between the various potential sources for post-LOCA debris. The ECCS and spray systems were intended to function, even with debris partially obstructing the sumps, and regardless of the source of the debris. The design evaluation submitted as part of the original licensing basis for North Anna Units 1 and 2 demonstrates that the emergency core cooling and containment spray systems will continue to provide sufficient cooling flow so as to fulfill the long-term cooling functions required to conform with 10 CFR 50.46(b)(5).

The NRC approved the original assessment of the spray and ECCS systems as meeting the requirements of 10 CFR 50.46(b)(5) in Supplement 9 of the North Anna SER (Reference d). In Section 6.3.8, Pertormance Evaluation, of Referenced, the following is stated with regard to the ECCS systems:

"Based on this review and previous supplements of the Safety Evaluation Report describing our review of the emergency core cooling system for the North Anna plant, we conclude that the emergency core cooling system pertormance conforms to the acceptance criteria of Section 50.46 of 10 CFR 50."

With respect to effects of post-LOCA sump debris, several questions were posed by the NRC staff during licensing of North Anna Unit 2. NRC approved the original assessment of the emergency core cooling system design in Supplement 11 of the No"rth Anna SER (Reference--f). ThedOllowiiig is stated* in 'Section 6.3.6 of Reference f:

,<'. __ f ,,_"

e Docket Nos. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 9 of 10 "6.3.6 Post-Loss-of-Coolant Accident (LOCA) Sump Debris 6.3.6.6 Summary Based on the considerations noted above with respect to housekeeping requirements, the avoidance of materials likely to form small-sized debris, the lack of an apparent mechanism for blockage of more than the previously tested value of fifty percent of the screen area by larger debris, and the ability to monitor and control the low pressure injection system status, we conclude that the present design of North Anna Unit 2 provides reasonable assurance that the post-loss-of-coolant accident recirculation of core coolant will not be impaired by debris, meets the requirements of 10 CFR 50.46 and Criterion 35 of the General Design Criteria, given in 10 CFR 50 Appendix A, and is therefore acceptable."

The current licensing basis for North Anna Units 1 and 2, as accepted by the NRC's SER and its supplements, provides both the regulatory and safety basis for safety system performance. The affected system designs are the same for North Anna Units 1 and 2 and the licensing basis has been integrated in the UFSAR. Coatings are not treated separately in the licensing basis for North Anna Units 1 and 2 ECCS design. Consistent with applicable regulatory requirements, the type and quantity of debris were not explicitly considered when the original calculations for the ECCS sump head loss were performed. The assessment of sump debris was documented and accepted during original licensing without specific quantification of effects by calculation. The licensing basis thus does not distinguish or consider the source of the LOCA-generated debris.

(2)(ii)(a) If commercial-grade coatings are being used at your facility for Service Level 1 applications, and such coatings are not dedicated or controlled under your Appendix B Quality Assurance Program, provide the regulatory and safety basis for not controlling these coatings in accordance with such a program. Additionally, explain why the facility's licensing basis does not require such a program.

Response

Virginia Power does not currently employ commercial grade dedication for Service Level 1 coatings that are applied inside containment at North Anna Power Station Units 1 and 2.

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  • e Docket Nos. 50-280, 281, 338, 339 Serial No.98-449 Attachment 2 Page 10 of 10

References:

(a) Safety Evaluation Report by the Office of Nuclear Reactor Regulation, USNRC, North Anna Power Station-Units 1 and 2, Docket Nos. 50-338 and 50-339, NUREG-0053, June 1976.

(b) Letter from Virginia Electric and Power Company to the NRG, Serial No.93-307, June 10, 1993, Forwards Response to NRG Bulletin 93-02.

(c) Letter from Leon B. Engle (NRG) to W. L. Stewart (Va. Power), "Final Report-Steam Generator Replacement Program (SGRP) 50.59 Audit/Review: North Anna Power Station, Unit No. 1 (NA-1 )," February 24, 1993.

(d) Supplement 9 to the Safety Evaluation Report by the Office of Nuclear Reactor Regulation, USNRC, North Anna Power Station-Units 1 and 2, Docket Nos. 50-338 and 50-339, NUREG-0053, March 31, 1978.

(e) NRG Bulletin No. 93-02: "Debris Plugging of Emergency Core Cooling Suction Strainers," May 11 , 1993.

(f) Supplement 11 to the Safety Evaluation Report by the Office of Nuclear Reactor Regulation, USNRC, North Anna Power Station-Unit 2, Docket No.

50-339, NUREG-0053, August 1980.

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