RS-03-007, Exelon/Amergen Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.

Exelon/Amergen Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.

ML030280682
Person / Time
Site:	Byron, Braidwood, Crane
Issue date:	01/21/2003
From:	Jamie Benjamin AmerGen Energy Co, Exelon Generation Co, Exelon Nuclear
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
5928-03-20238, BL-02-001, RS-03-007
Download: ML030280682 (77)

Text

Exelon.

An Exelon/British Energy Company www.exeloncorp.com Nuclear AmerGen Energy Company, LLC 200 Exelon Way Exelon Generation Suite 345 4300 Winfield Road Kennett Square, PA 19348 Wanrenville, IL60555 RS-03-007 5928-03-20238 January 21, 2003 United States Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Braidwood Station, Units I and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units I and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455 Three Mile Island Station, Unit 1 Facility Operating License No. DPR-50 NRC Docket No. 50-289

Subject:

ExelonlAmerGen Response to Request for Additional Information Regarding NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity

References:

(1) Letter from J. A. Benjamin (Exelon Generation Company, LLC) to NRC, dated May 17, 2002 (2) Letter from Mahesh Chawla (NRC) to John L. Skolds (Exelon Generation Company, LLC), dated November 20, 2002 (3) Letter from Timothy G. Colbum (NRC) to John L. Skolds (AmerGen Energy Company, LLC), dated November 21, 2002 On March 18, 2002, the NRC issued Bulletin 2002-01, *Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.' The Bulletin Included a request for the basis for concluding licensees' boric acid inspection programs meet the requirements of Generic Letter 88-05, "Bodc Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components In PWR plants." Reference I provided the requested Information for Braidwood and Byron Stations and Three Mile Island Station, Unit 1. The NRC concluded that additional information is necessary to complete their review and requested additional information, relative to the specificity of the boric acid corrosion control programs, be provided within sixty days of receipt of the letters (i.e., References 2 and 3). The requested additional Information Is attached and as suggested In Reference 1, each of the attributes Identified for an Improved boric acid corrosion control program were considered in the preparation of the attached responses.

-AC15

January 21, 2003 U. S. Nuclear Regulatory Commission Page 2 Attachments I and 2 to this letter provide the Exelon Generation Company, LLC response for Braidwood Station, Units 1 and 2, and Byron Station, Units I and 2, respectively. Attachment 3 provides the AmerGen Energy Company, LLC response for Three Mile Island Station, Unit 1.

These responses are due to the NRC January 21, 2003.

The following table identifies commitments made in this document. Any other actions discussed in the submittal represent intended or planned actions. They are described to the NRC for the NRC's information and are not regulatory commitments.

COMMITMENT COMMITED DATE OR "OUTAGE" Braidwood Station will comply with the recent Material Not Applicable Reliability Project (MRP) recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the Electric Power Research Institute (EPRI) PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002 Byron Station will comply with the recent MRP Not Applicable recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PMMP Steering committee, dated December 2, 2002 Three Mile Island Station, Unit I is planning to install a During the refueling camera above the insulation to visually inspect the bare outage currently metal around the incore instrumentation nozzle scheduled for October penetrations. 2003 (T1 R1 5).

Ifyou have any questions or desire additional information regarding this letter, please contact Don Cecchett at (630) 657-2826.

Respectfully, Respectfully, Vice President, Vice President, Licensing and Regulatory Affairs Licensing and Regulatory Affairs Exelon Generation Company, LLC AmerGen Energy Company, LLC Attachments: Attachment 1, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Attachment 2, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Attachment 3, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1

ATTACHMENT I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Exelon Generation Company, LLC

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 On November 20, 2002, the NRC issued a request for additional information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was requested within 60 days receipt of the RAI.

1. Provide detailedinformation on, and the technical basis for, the inspection techniques,scope, extent of coverage, and frequency of Inspections,personnel qualifications,and degree of insulationremoval for examination of Alloy 600 pressure boundarymaterialand dissimilarmetal Alloy 82/182 welds and connections In the reactorcoolantpressureboundary (RCPB). Include specific discussion of inspection of locations where reactorcoolantleaks have the potentialto come in contact with and degrade the subject material(e.g., reactor pressurevessel (RPV) bottom head).

Response

The following is a listing of the requested information regarding the Alloy 600 pressure boundary material and dissimilar metal Alloy 82/182 welds and locations in the Braidwood Station, Unit I and Unit 2 reactor coolant pressure boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. These items include, In the steam generators, the steam generator tubing, the tube sheet cladding, the primary head divider plate and attachment welds, the primary nozzle closure rings and closure ring welds. For the reactor pressure vessels (RPVs), the core support guide lugs and welds, six per RPV, are not included in the list. The RPV flange o-ring leakage monitoring tube is not included on the list because it is not exposed to the temperature and pressure conditions that facilitate primary water stress corrosion cracking (PWSCC).

Also not listed are the Alloy 690 materials and Alloy 52/152 weld materials in the Braidwood Station, Unit I replacement steam generators. Installed In the Fall of 1998, the Unit 1 steam generators do not contain any Alloy 600 or Alloy 82/182 materials.

The American Society of Mechanical Engineers ASME Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. Braidwood Station, currently in the 2 rd Inservice Inspection Interval, is committed to the 1989 Edition, no addenda, of ASME Section XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of Braidwood Station's commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in pressurized water reactor (PWR) Plants."

Page 1 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 The ASME Section XI and GL 88-05 requirements for visual examinations conducted at Braidwood Station to locate evidence of leakage from pressure retaining components are contained in procedure ER-AA-335-015, "VT-2 Visual Examination."

In addressing the extent of coverage, ER-AA-335-015 states:

"4.4.4. PERFORM VT-2 examination as close to the component as possible, even though the examination is essentiallyhands-off.

1. USE existing ladder(s), scaffolding, etc. to reduce the examination distance or to maximize examined surface areasif permitted by plant conditions (such as safety or health physics). INSTALLATION of ladder(s)or scaffolding for the sole purpose of conducting the VT-2 examinationsis not required.

2. If permittedby plant conditions (such as safety or health physics), then CONSIDER the use of remote optical aids to reduce the examination distance or to maximize examined surface areas."

This procedure does not specify examination details for specific components in the RCPB and associated systems, but rather provides general requirements applicable to all examined areas.

ER-AA-335-015 requires that accessible external surfaces of pressure retaining components be examined for evidence of leakage including evidence of boric acid accumulations from borated systems. If the components are inaccessible for the direct VT-2 examination, the procedure requires that the surrounding area, including floor area or equipment surfaces located underneath the components, be examined.

The procedure does not require that insulated components be de-insulated to perform a VT-2 examination. The procedure states that for insulated components, accessible and exposed insulation surfaces, including each insulation joint, be examined. For essentially vertical surfaces, the insulation at the lowest elevation where leakage may be detectable must be examined. Also, the surrounding area, including floor areas or equipment surfaces located underneath the component, is examined for evidence of leakage. The procedure requires that examiners give particular attention to discoloration of residue on surfaces in order to detect evidence of boric acid accumulations from borated reactor coolant leakage.

While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require Insulation removal.

In summary, the components listed in the following table are examined using ASME Section XI and ER-AA-335-015 requirements. These requirements address the technical basis for the scope, inspection technique, inspection frequency, personnel qualifications, and, in general, extent of coverage.

Page 2 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Usting IRom Unit Component Inspection Personnel Extent of Frequency Degree of CorrectIve Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type I I RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams The Insulation is not No corrective actions welds (4 hot leg safe-ends, for Leakage (VT-2) by Certified Level II by looking for are performed twice removed for the required to date.

4 cold leg safe-ends, 8 or III VT-2 evidence of leakage each refuel outage: VT-2 examinations.

total) Examiners. Results around the pipe first, in Mode 3 reviewed by insulation joints and going into the The insulation is a Certified Level III along the annulus outage after cycle stainless steel Examiners. of the piping operation at a reflective (mirror) penetration, pressure and design. There are temperature at or 3, 120 *"segments slightly less than buckled around the normal operating pipe-nozzle OD.

conditions, and then again In Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Exams performed 100% of the risk Once per ISI Insulation Is not (ultrasonic) by Certified Level II Informed ISI Interval. Last removed for this examination of the or IIIultrasonic examination examined in the exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1997. performed from the welds. In EPRI TR-112657 pipelnozzle Inner Rev. B-A, *Revised diameter with an Risk Informed automated Inservice Inspection Inspection tool.

Evaluation Procedure.'

Page 3 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material ListingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 2 1 RPV head penetrations 79 Previous VT-2 Exams performed VT-2 examinations The VT-2 exams Insulation Is No corrective total exams performed by Certified Level II have been are performed twice removed as actions required to

-53 Control Rod Drive with the RPV head or III VT-2 performed on the each refuel outage: necessary to date.

Mechanisms (CRDMs) Insulation in-place. Examiners. Results accessible areas of first, in Mode 3 facilitate the BMV

-2 Reactor Vessel Level reviewed by the head. going into the exam.

-5Indication System (RVLIS) thermocouple Bare metal visual Certified Level III outage after cycle

- 18 spare VHPs Examiners. These exams are operation at a Peripheral vertical (BMV) inspection conducted on the pressure and and horizontal

-I1head vent using specific RPV head with the temperature at or panels are Inspection shroud assembly slightly less than designed for guidelines have access doors normal operating removal.

been developed opened and the conditions, and and will be RPV head then again In Mode The RPV head Implemented. Insulation In-place. 3 coming out of the insulation is a outage at normal series of 3 thick operating mirror Insulation temperature and panels. The pressure with a 4 Insulation Is hour hold time. Installed in a flat field across the top ABMV exam Is of the RPVhead scheduled for the and Is stepped Spring of 2003. The down as it extent and approaches the frequency of outer perimeter of additional the RPV head.

examinations to be In accordance with fMRP.

Page 4 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units i and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 3 1 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is For previous No corrective instrumentation exams performed by Certified Level II has been performed each exams, the actions required to penetrations (58 total) with the RPV lower or IIIVT-2 performed with refuel outage or insulation has not date.

head Insulation In- Examiners. Results RPV lower head during a forced been removed.

place. reviewed by insulation In-place outage of sufficient Certified Level III looking for leakage duration. The insulation at Examiners. at insulation joints, the bottom of the The examination is RPV is a flat, performed at horizontal deck of operating pressure stainless steel and temperature, mirror panels. The with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold deck stands off time, beneath the from the bottom of RPV. the lower head providing a clearance of 8". The center panels are fixed around the 58 in-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 5 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units 1 and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 4 1 Pressurizer surge nozzle to Volumetric Exams performed 1000% of the risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) by certified Level II informed ISI Interval. Last been, and will be, actions required to examination of the or III ultrasonic examination examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1997. volumetric weld. in EPRI TR-1 12657 examination.

Rev. B-A, "Revised Risk Informed The Insulation is Inservice Inspection part of the Evaluation pressurizer lower Procedure." head insulation arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation Is not by Certified Level II by looking for are performed twice removed for the VT or IIIVT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe first, in Mode 3 reviewed by insulation joints, going Into the The Insulation is Certified Level III along the surge line outage after cycle part of the Examiners. piping and on the operation at a pressurizer lower containment floor pressure and head Insulation beneath the temperature at or arrangement. There pressurizer surge slightly less than are 4 segments nozzle, normal operating enclosing the surge conditions, and nozzle. The panels then again In Mode are stainless steel, 3 coming out of the mirror panels with outage at normal buckled snaps for operating removal.

temperature and pressure with a 4 fhour hold time.

Page 6 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braldwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 5 1 Pressurizer spray nozzle to Volumetric E~xams perforrned Informed ISI Interval. Last been, and will be, actions required to safe-end weld (1 weld) (ultrasonic) by certified Level II examination of the or III ultrasonic examination examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Fall of 1998. volumetric weld. in EPRI TR-1 12657 examination.

Rev. B-A, 'Revised Risk Informed The Insulation Is Inservice Inspection part of the Evaluation pressurizer head Procedure.* insulation arrangement. There are 2 semi-circular, fiat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I I _____________ .1 VT-2 Exam performed by Exam is performed -r The VT-2 exams --I-The Insulation Is not Certified Level II or by looking for are performed twice removed for the VT IIIVT-2 Examiners. evidence of leakage each refuel outage: 2 examinations.

Results reviewed around the nozzle first, In Mode 3 by Certified Level III to pipe Insulation going Into the The Insulation is Examiners. joint. outage after cycle part of the operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less than are 2 semi-circular, normal operating flat panels conditions, and enclosing the spray then again In Mode nozzle. The panels 3 coming out of the are 4' thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

I I ______________________ II I I I hour hold time.

Page 7 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Insulation Corrective Action Techniques Qualifications Coverage Removal!

Insulation Type

-6 1 Pressurizer relief valve volumetric iExams pernormed II by certified Level informed ISI Interval. Last been, and will be, actions required to nozzle to safe-end weld (I (ultrasonic) removed for the date.

examination of the or III ultrasonic examination examined In the weld) Fall of 1998. volumetric nozzle to safe-end Examiners. volume, Figure 4-9 weld. inEPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The insulation is Inservice Inspection part of the Evaluation pressurizer head Procedure." insulation arrangement. There are 4 segmented, fiat panels endosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I .1 ______________

-r-The exams VT-2 exams T The insulation Isnot VT-2 Exam performed by Exam is performed The VT-2 -- The Insulation for theIs VT not Certified Level IIor by looking for are performed twice removed III Vr-2 Examiners. evidence of leakage each refuel outage: 2 examinations.

Results reviewed around the pipe to first, in Mode 3 by Certified Level III nozzle Insulation going Into the The Insulation Is Examiners. joint. outage after cycle part of the operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less then are 4 segmented, normal operating fiat panels conditions, and enclosing the relief then again in Mode nozzle. The panels 3 coming out of the are 4" thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time.

I I 1 1: 1 1 I _______________________________ ______________________ .1_______________________ J _______________________ _______________________

Page 8 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removalc Insulation Type 7 1 Pressurizer safety valve Volumetric Exams performed 100%of0the risk Once per 1513 Interval. Two of the been, and will be. actions required to nozzle to safe-end weld (3 (ultrasonic) by certified Level II Informed ISI examination of the or III ultrasonic examination welds were removed for the date.

welds) volumetric nozzle to safe-end Examiners. volume, Figure 4-9 examined In the welds. in EPRI TR-112657 Sping of 1994, and examination.

Rev. B-A, Revised the third weld was Risk Informed examined in the The Insulation is Inservice Inspection Fall of 1995. part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, flat panels enclosing each of the safety valve nozzies. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

________ 1 4 - .4 The VT-2 exams -r The insulation is not VT-2 Exams performed Exam Is performed removed for the VT by Certified Level II by looking for are performed twice or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going Into the The Insulation Is Certified Level III joints. outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing each of then again in Mode the safety valve 3 coming out of the nozzles. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

_______________________________ +/- ______________________ .1 J _______________________

Page 9 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 8 2 RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams The Insulation Is not No Corrective welds (4 hot leg safe-ends, for leakage (VT-2) by Certified Level II by looking for are performed twice removed for the VT- actions required to 4 cold leg safe-ends, 8 or Ill VT-2 evidence of leakage each refuel outage: 2 examinations, date.

total) Examiners. Results around the pipe first. In Mode 3 reviewed by Insulation Joints and going into the The Insulation Is a Certified Level III along the annulus outage after cycle stainless steel Examiners. of the piping operation at a reflective (mirror) penetration. pressure and design. There are temperature at or 3, 1200 segments slightly less than buckled around the normal operating pipe nozzle OD.

conditions, and then again In Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation Is not (ultrasonic) (UT) Level II or Ill Informed ISI Interval. Last removed for this examination of the Examiners. examination examined In the exam. The exam Is nozzle to safe-end volume, Figure 4-9 Fall of 1997. performed from the welds. in EPRI TR-112657 pipelnozzle Inner Rev. B-A, "Revised diameter with an Risk Informed automated Inservice Inspection Inspection tool.

Evaluation Procedure."

Page 10 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material ListingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 9 2 RPV head penetrations A Bare Metal Visual Exams performed BMV of the RPV The BMV exam Insulation Is No corrective (VHP) 79 total (BMV) using VT-2 by Certified Level II head surface and a was performed in removed as actions required to

- 53 CRDMs techniques was or III VT-2 360 degree view of the Spring of 2002. necessary to date. In addition,

- 2 RVLIS performed in Spring Examiners. Results all VHPs with slight The extent and facilitate the BMV for the Spring 2002

-.5 Thermocouple 2002. Specific reviewed by obstruction of the frequency of exam. examination, there

- 18 spare VHPs inspection Certified Level III head vent additional were no corrective

- I head vent guidelines were Examiners. penetration, examinations to be Peripheral vertical actions taken as developed and in accordance with and horizontal there was no Implemented. MRP. panels are evidence of leakage designed for on the RPV head Previous VT-2 removal, surface and no exams performed RPV head with the RPV head The RPV head degradation was Insulation In-place. Insulation is a identified.

series of 3' thick mirror insulation panels. The Insulation is Installed in a flat field across the top of the RPV head and is stepped down as it approaches the outer perimeter of the RPV head.

Page 11 of 25

Attachment 1 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units 1 and 2 Braldwood Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 10 2 RPV lower head In-core Previous VT-2 Exams performed The examination The examination Is For previous No corrective Instrumentation exams performed by Certified Level II has been performed each exams, the actions required to penetrations (58 total) with the RPV lower or IIIVT-2 performed with refuel outage or Insulation has not date.

head insulation In- Examiners. Results RPV lower head during a forced been removed.

place. reviewed by Insulation In-place outage of sufficient Certified Level III looking for leakage duration. The insulation at Examiners. at insulation joints, the bottom of the The examination Is RPV Is a flat, performed at horizontal deck of operating pressure stainless steel and temperature, mirror panels. The with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold deck stands off time, beneath the from the bottom of RPV. the lower head providing a clearance of 8". The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 12 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 11 2 Pressurizer surge nozzle to Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT) Level IIor III Informed ISI Interval. Last been, and will be. actions required to examination of the Examiners. examination examined In the removed for the date.

nozzle to safe-end volume, Figure 4-9 Fall of 1997. volumetric welds. in EPRI TR-1 12657 examination.

Rev. B-A, *Revised Risk Informed The insulation is Inservice Inspection part of the Evaluation pressurizer lower Procedure." head insulation arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed twice removed for the VT or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe first, in Mode 3 reviewed by Insulation joints, going Into the The insulation is Certified Level III along the surge line outage after cycle part of the Examiners. piping and on the operation at a pressurizer lower containment floor pressure and head Insulation beneath pressurizer temperature at or arrangement. There surge nozzle. slightly less than are 4 segments normal operating enclosing the surge conditions, and nozzle. The panels then again in Mode are stainless steel, 3 coming out of the mirror panels with outage at normal buckled snaps for operating removal.

temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Page 13 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 12 2 Pressurizer spray nozzle to Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT) Level IIor III Informed ISI interval. Last been, and will be, actions required to examination of the Examiners. examination examined In the removed for the date.

nozzle to safe-end volume, Figure 4-9 Spring of 1999. volumetric welds. inEPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The Insulation is Inservice Inspection part of the Evaluation pressurizer head Procedure." insulation arrangement. There are 2 semi-circular, flat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed twice removed for the VT or IIIVT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going into the The insulation is Certified Level III joint, outage after cycle part of the Examiners. operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less than are 2 semi-circular, normal operating fiat panels conditions, and enclosing the spray then again InMode nozzle. The panels 3 coming out ofthe are 4' thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time. _I_ I _I Page 14 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braldwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Typed Votumetric ulnasonM nenrna *..midatinn has Nocrelv 13 2 Pressurizer relief valve Cl.ertified Ultrasonic (UT) Level II or III 100%/oftle Informed ISI 1R1sk Interval. Last been. and will be, actions required to nozzle to safe-end weld (1 (ultrasonic) removed for the date.

examination of the Examiners. examination examined In the weld) Sping of 1999. volumetric nozzle to safe-end volume, Figure 4-9 in EPRI TR-112657 examination.

welds.

Rev. B-A. "Revised Risk Informed The insulation Is Inservice Inspection part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I -- I ___________________________ I

-r I

-r-The insulation The Insulation Isnot VT-2 Exams performed by Certified Level II Exam is performed by looking for The Vr-2 exams are performed twice removed for theIs VTnot or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, in Mode 3 reviewed by nozzle insulation going Into the The Insulation is Certified Level III joint. outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing the relief then again In Mode nozzle. The panels 3 coming out of the are 4' thick outage at normal stainless steel.

operating minror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time.

I I I II ________________

I I ________________

I Page 15 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Techniques Qualifications Coverage Insulation Removal/

Insulation Type Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective 14 2 Pressurizer safety valve (ultrasonic) (UT) Level II or III Informed ISI Interval. Two of the been, and will be, actions required to nozzle to safe-end weld (3 examination of the Examiners. examination welds were removed for the date.

welds) nozzle to safe-end volume, Figure 4-9 examined In the volumetric welds. In EPRI TR-112657 Fall of 1994, and examination.

Rev. B-A. "Revised the third was Risk Informed examined In the The insulation Is Inservice Inspection Spring of 1996. part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, fiat panels enclosing each of the safety nozzles.

The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams The Insulation Is not by Certified Level II by looking for are performed twice removed for the VT or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going Into the The Insulation Is Certified Level III joints, outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing each of then again in Mode the safety nozzles.

3 coming out of the The panels are 4' outage at normal thick stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time. _I Page 16 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braldwood Station RCPB Alloy Material UstingI Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Component Techniques Qualifications Coverage Insulation Removal/

Insulation Type A visual using direct Exams performed The drain line, The direct visual The insulation Is No corrective 15 2 Steam generator primary actions required to head drain lines (4 total) VT-2 techniques by Certified Level II weld, and lower examination Is removed to was performed In VT-2 Examiners. head surface performed each facilitate the date.

the Spring of 2002 around the drain time the steam examination.

on 2 of the 4 steam line were examined generator primary generator drain for steam channel head Is de- The Insulation lines and generators A and insulated, (typically around the steam surrounding head C.. for eddy current generator lower surface. inspection). head is a series of removable stainless Previous VT-2 steel mirror panels.

exams performed The bottom panel Is with the steam a horizontal disc generator lower that is set off of the head Insulation In- steam generator place. head and encloses the head, the drain line, and the drain line isolation valve.

Page 17 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2

2. Provide the technical basis for determiningwhether or not Insulation is removed to examine all locations where conditionsexist that could cause high concentrationsof boric acid on pressureboundarysurfaces or locations that are susceptible to primary waterstress corrosioncracking (Alloy 600 base metal and dissimilarmetalAlloy 82/182 welds). Identify the type of insulationfor each component examined, as well as any limitationsto removal of Insulation. Also include In your response actions involving removal of insulation requiredby your proceduresto Identify the sourceof leakage when relevantconditions (e.g., rust stains,boric acid stains,or boric acid deposits)are found.

Response

Except for bolted connections on borated ASME Section XI Class 1, 2 and 3 systems discussed below, Braidwood Station procedures do not require that insulated RCPB components be de insulated to perform VT-2 examinations. The basis for this has been that leakage from RCPB components should be detectable at insulated joints or surrounding areas given that the systems have been at normal pressure for, in most cases, a full operating cycle. While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In general, Braidwood Station ASME Section XI Class 1, 2, and 3 components in the containment containing borated water, if insulated, have removable stainless steel reflective style insulation. Outside the containment, blanket insulation is used. Most insulation is removable, but there are exceptions. The insulation panels around the incore instrumentation guide tubes at the bottom of the RPV lower head are not intended to be removed. A set of peripheral horizontal panels are buckled in place and can be removed for access to the incore instrumentation guide tubes at the bottom of the RPV lower head. The horizontal panels around the VHPs are not removable; however, the side vertical panels are removable. The specific style of insulation for other locations in the RCPB is listed in the table in the response to Question 1.

Bolted Connections Insulated bolted connections in the RCPB (i.e., ASME Section XI, Class 1) and in borated ASME Section XI Class 2 and Class 3 support systems have insulation removed in order to perform ASME section XI VT-2 examinations. The scope includes bolted connections that are installed in systems that are borated for the purpose of controlling reactivity. The ASME Section XI requirements on the extent of insulation removal and the plant conditions under which the insulation is removed have been modified by Braidwood Station Inservice Inspection Relief Requests 12R-12 and 12R-30. Both of these alternatives to ASME Section XI requirements have been authorized for use at Braidwood Station by the NRC.

Relief Request 12R-12 allows for insulation removal and the performance of the VT-2 exam on bolted connections in borated systems to be performed with the system depressurized. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examination. Additionally, for ASME Section XI Class 2 and 3 borated systems, VT-2 examinations are performed on approximately 36 month Page 18 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 frequencies, which coincides with plant refueling outages, not allowing the period between inspections on individual components to exceed 45 months. This frequency for individual components is more restrictive than the "Periodic Frequency" allowed by ASME Section XI for Class 2 and 3 systems described in tables IWC-2500 or IWD-2500.

Relief Request 12R-30 allows the removal of insulation from certain ASME Section XI, Class 1 valves for VT-2 examination to be performed on an extended frequency. The insulation is removed from the bolted connections and a VT-2 examination is conducted, with the system depressurized, on a once per 10 year interval frequency. These valves are also VT-2 examined with the insulation installed after a minimum four hour hold time at normal operating pressure at the end of each refueling outage and in Mode 3 during shutdown for each refueling outage.

Dissimilar Metal Welds Insulated dissimilar metal welded piping connections that contain Alloy 82/182 are typically not de-insulated for VT-2 examinations. A list of these nozzle to safe-end welds and the type of insulation is provided in the table in the response to Question 1. Examinations of these areas are performed in response to GL 88-05 and are conducted in Mode 3 going into an outage, typically, after a cycle of operation. Therefore, an adequate time is allowed for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The eight RPV nozzle to safe-end welds are considered inaccessible to perform direct VT-2 examination. The welds are located in an area between the concrete RPV shield wall and the concrete primary shield wall. This area enclosing the RPV nozzles and connected piping is referred to as the "sand box" area. The sand box area is only accessible from above, from the refueling cavity floor, by removing normally sealed steel plates. The normal technique for viewing potential leakage in this area is to look along the reactor coolant piping as it passes though the annulus of the bio-shield wall towards the RPV. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints inside the annulus. The RPV nozzle to safe-end weld insulation is not routinely removed since the sand box area is considered a high dose, confined space.

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluatingthe potentialfor leakage In Inaccessibleareas. In addition, describethe degree of Inaccessibility,and identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessibleareas.

Response

For the RCPB components, Braidwood Station personnel perform walkdowns during refueling outages, forced outages and, depending on circumstances, during power operations. Typical at-power containment walkdowns of accessible areas for leakage would be initiated at the request of the Operations Department Ifunidentified leakage was trending up or at the request of Radiation Protection personnel ifthere was an unexpected Increase in containment atmosphere gas or particulate levels. For at-power walkdowns, the area of interest may be limited for as low as reasonably achievable (ALARA) considerations. VT-2 certified personnel Page 19 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 perform the walkdowns during refueling outages and, in most cases, during forced outages and at power operations.

As described in the response to Question 2, the areas considered inaccessible are the "sand boxes" which enclose the eight RPV nozzles. Leakage from these areas is identified by visual examination along the horizontal surface of the insulated piping as it passes through the concrete annulus.

Braidwood Station uses a containment floor drain sump and a reactor cavity sump to collect, measure and record unidentified leakage in accessible and inaccessible areas in the containment. Both of these sumps are instrumented to identify leakages of 1.0 gpm within one hour and are recorded and alarmed in the main control room. The containment floor drain and reactor cavity sump inputs are checked each shift. A reactor coolant system (RCS) mass balance is performed when unidentified leakage is suspected and at the prescribed Technical Specification intervals. This provides early indication to the operator of potential unidentified leakage. Also, the reactor makeup control system is used to maintain proper reactor coolant inventory, volume control tank (VCT) level is continuously recorded and quantities of boric acid and makeup water injected are totaled and flow rates recorded in the control room.

The reactor coolant contains radioactivity that, when released to the containment, can be detected by radiation monitoring instrumentation. Radioactivity detection systems are used for monitoring both particulate and gaseous activities and can be used to identify RCS leakage.

The detection of RCS leakage using radiation monitors depends on the concentration of radioactivity in the RCS and detector background count rate.

Air temperature and pressure monitoring methods may also be used to infer unidentified leakage to the containment. Although containment temperature and pressure fluctuate slightly during unit operation, a rise above the normally indicated range of values may indicate RCS leakage into the containment.

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections), to demonstrate that continued operation with the observed leakage is acceptable. Also describe the acceptance criteriathat was establishedto make such a determination. Provide the technical basis used to establish the acceptance criteria. In addition,

a. if observed leakage Is determined to be acceptablefor continued operation, describe what inspection/monitoringactions are taken to trend/evaluatechanges in leakage, or

b. ff observedleakage Is not determined to be acceptable, describe what corrective actionsare taken to addressthe leakage.

Response

Braidwood Station personnel use engineering procedure BwVP 200-11, "Evaluation of ASME Section Xl Class 1, 2, and 3 Bolted Connections." This procedure describes the requirements Page 20 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 and instructions for the evaluation of ASME Section XI Class 1, 2, and 3 bolted connections when external leakage is detected. The procedure provides instructions for the corrective actions that must be implemented in the event the structural integrity of any ASME Section XI Class 1, 2, or 3 bolted connection is determined to be suspect.

When evidence of leakage is identified from a bolted connection, the procedure requires an evaluation to be performed. This evaluation considers the location of the leak, leak rate, extent of deposit accumulation, extent of wastage, corrosiveness of process fluid, materials, length of time bolting has been in service and the effect on other structures or components. A condition report is initiated for non-conforming conditions and a recommendation for repair, replacement, or monitoring is provided. Active leakage from the RCS is repaired prior to completing a refuel outage.

The bases for the evaluation/determination criteria of BwVP 200-11 are derived from the provisions of Braidwood Station Inservice Inspection Relief Request 12R-1 3. This request was approved by the NRC.

Braidwood Station personnel use the corrective action process, specifically a condition report, to determine the acceptability for continued operation when a non-conforming condition is identified. Within the condition report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the non-conforming condition is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For a non-conforming condition that is determined to be unacceptable, repair or replacement is required.

5. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wallcracking in the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or Installedleakage detection instrumentation,but has the potentialfor causingboric acid corrosion. The NRC has had a concern with the bottom reactorpressurevessel head incore instrumentation nozzles because of the high consequences associatedwith loss of integrity of the bottom head nozzles. Describe how your program would evaluate evidence of possible leakage in this Instance. In addition,explain how your programaddresses leakage that may impact components that are in the leak path.

Response

As explained in the table in the response to Question 1, items 3 and 10, the insulation at the bottom of the RPV lower head stands off of the head surface by a minimum of eight inches at the very bottom of the lower head curvature. Visual examinations of the Braidwood Station, Unit 1 and Unit 2 RPV lower head, scheduled for the Spring of 2003 and Fall of 2003, respectfully, will require removing insulation panels to view the metal surface. Any leakage from lower head penetrations would be visible.

Page 21 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Reactor coolant and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels. The incore penetration instrument tubes that connect to the nozzles are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or openings of the insulation, there are no pressure retaining components beneath the RPV that could be affected. This leakage from the RPV bottom head nozzles would collect in the reactor cavity sump described in the response to Question 3. The reactor cavity sump input is recorded each shift and abnormal readings are required to be reported to the Shift Manager. This notification would result in an evaluation and a condition report would be initiated, as necessary.

6. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundary leakage that may result from through-waltcracking in certain components and configurationsfor othersmall diameternozzles. Low levels of leakage may call into question relianceon visual detection techniques or Installedleakage detection instrumentation,but has the potentialfor causingboric acid corrosion.

Describehow your program would evaluate evidence of possible leakage In this instance. In addition,explain how your programaddressesleakage that may impact components that are In the leak path.

Response

The leakage detection capabilities at Braidwood Station were discussed in the response to Questions 3 and 5 above. The visual examination and evaluation procedures at Braidwood Station require that components in the area of a leak be examined and evaluated. In the case of Braidwood Station, the vast majority of components in the RCPB are stainless steel.

7. Explain how any aspects of your program (e.g., insulationremoval, Inaccessibleareas, low levels of leakage, evaluation of relevant conditions)make use of susceptibility models or consequence models.

Response

Vessel Head Penetrations (VHP)

Braidwood Station personnel have based the examination requirements for the Unit I and Unit 2 VHPs on the Electric Power Research Institute (EPRI) Material Reliability Project (MRP) susceptibility model for PWSCC. This ranking (i.e., MRP-48) identifies Braidwood Station, Unit 1 and Unit 2 as "low susceptibility" plants rated 640 and 65th, respectively, out of the 69 PWR units in the study. As of January 1, 2003, the Braidwood Station, Units have an effective degradation year (EDY) value of 1.6 putting the Units in the lowest of the three susceptibility categories established by the NRC in Bulletin 2002-02, "Reactor Pressure Vessel Head and RPV Head Penetration Nozzle Inspection Programs."

Because of this lower susceptibility, Braidwood Station personnel perform qualified, effective bare metal visual (BMV) inspections of the RPV head surface and VHPs. The BMV inspection for Braidwood Station, Unit 2 was completed in the Spring of 2002 with no evidence of VHP leakage found. The BMV inspection for Braidwood Station, Unit I is scheduled for the Spring of 2003.

Page 22 of 25

Attachment 1 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Steam Generator Drain Lines As listed in the table in the response to Question 1, the steam generator primary head drain lines for Braidwood Station, Unit 2 are made of Alloy 600 and Alloy 82/182 materials. The bottom surface of the steam generator primary head, the 3/8" drain lines and drain line isolation valves are enclosed in the lower head insulation package. Based on a susceptibility model developed by Westinghouse, Braidwood Station is visually examining the four Unit 2 drain lines whenever the steam generator lower head insulation package is removed to support the eddy current testing of the steam generator tubing.

In the last Unit 2 refueling outage in the Spring of 2002, the "A" steam generator was eddy current tested and therefore the lower head surface and drain line were visually examined.

There were no recordable indications, no signs of boric acid deposits or any degradation of the carbon steel lower head surface.

In addition, in the GL 88-05 walkdown performed in Mode 3 during a plant shutdown in the Spring of 2002, boric acid deposits were identified along the seam of the bottom horizontal insulation panel of the NC" steam generator lower head. As required by examination procedure and the corrective action process, the insulation was removed to investigate the source and extent of the leakage. The lower head surface and drain line of the "C"steam generator were visually examined. There were no signs of boric acid deposits on the steam generator lower head or any degradation of the carbon steel surface. The leakage and boric acid deposits were from a leaking drain line isolation valve dripping onto the horizontal insulation panel directly under the drain line. The deposits were cleaned and the valve was repaired.

Based on the recommendations of the susceptibility model, the drain line and the steam generator lower head surface for all four Braidwood Station, Unit 2 steam generators are scheduled for visual examination in the Fall of 2003.

8. Providea summary of recommendationsmade by your reactor vendor on visual inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken or plan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Vessel Closure Head Penetrations As stated above in the response to Question 7, Braidwood Station personnel are following the examination recommendations of the industry effort on the Alloy 600/82/182 issue.

Westinghouse, the reactor vendor, and Babcock & Wilcox, the reactor manufacturer, are part of this industry effort. Based on the lower susceptibility of the Braidwood Station, Unit I and Unit 2 VHP nozzles, the recommended visual examinations are being performed. Braidwood Station personnel have followed all MRP recommendations and will comply with the recent MRP recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002.

Page 23 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Reactor Vessel Nozzle Safe-Ends, Reactor Lower Head Nozzles, and Pressurizer Nozzle Safe-Ends The current program for the examination of these components is listed In the table in the response to Question 1. Exelon Nuclear corporate and Braidwood Station personnel are currently working with Westinghouse on developing a comprehensive inspection, repair and/or mitigation program for all Alloy 600/82/182 components in the RCPB.

9. Provide the basis for concluding that the inspectionsand evaluations describedIn your responses to the above questions comply with your plant TechnicalSpecifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of MechanicalEngineers (ASME) Code by reference. Specifically,address how your boric acid corrosioncontrolprogram complies with ASME Section Xi, paragraphIWA-5250 (b) on corrective actions. Include a descriptionof the proceduresused to implement the correctiveactions.

Response

Braidwood Station Technical Specification (TS) Limiting Condition for Operation (LCO) 3.4.13.a states that there shall be no pressure boundary leakage. Pressure bypass boundary leakage is defined as leakage, except steam generator tube leakage, through a non-isolable fault in a reactor coolant system component body, pipe wall, or RPV wall. If pressure boundary leakage is detected, the action statements for this LCO require that the affected unit be in Mode 3 in six hours and be in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The resolution of leakage indications in the corrective action program requires evaluation of the impact on this TS.

Compliance with the zero non-isolable leakage criteria is met by performing GL 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards." In addition, the unidentified leakage limit of one gpm defined in TS LCO 3.4.13.b is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a requires that inservice inspection and testing be performed in accordance with the requirements of ASME Section XI. ASME Section XI contains applicable rules for examination, evaluation and repair of code class components, including the RCPB.

For this, the 2 nd Inservice Inspection Interval, Braidwood Station personnel have implemented the 1989 edition, with no addenda, of ASME Section XI. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"Ifboric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether Page 24 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, Braidwood Station personnel use Exelon Nuclear Procedure ER-AA-335-015, "VT-2 Visual Examination." Paragraph 4.6.1.4 of this procedure states:

"If boric acid residues are detected on components, then LOCATE the leakage source and the areasof generalcorrosion. EVALUATE components with local areasof general corrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptable for continued service, or whether repairor replacementis required."

The Exelon Nuclear procedure LS-AA-125, "Corrective Action Program (CAP) Procedure" defines the requirements for condition identification, condition review, investigation, and closeout.

Page 25 of 25

ATTACHMENT 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Exelon Generation Company, LLC

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 On November 20, 2002, the NRC issued a request for additional information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was required within 60 days of receipt of the RAI.

1. Providedetailed information on, and the technicalbasis for, the Inspection techniques, scope, extent of coverage, and frequency of inspections,personnel qualifications,and degree of Insulation removal for examinationof Alloy 600 pressureboundarymaterialand dissimilarmetal Alloy 82/182 welds and connections in the reactorcoolant pressureboundary (RCPB). Include specific discussionof inspection of locationswhere reactorcoolant leaks have the potentialto come in contact with and degrade the subject material(e.g., reactor pressure vessel (RPV) bottom head).

Response

The following is a listing of the requested information regarding the Alloy 600 pressure boundary material and dissimilar metal Alloy 82/182 welds and locations in the Byron Station, Unit I and Unit 2 reactor coolant pressure boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. These items include, in the steam generators, the steam generator tubing, the tube sheet cladding, the primary head divider plate and attachment welds, the primary nozzle closure rings and closure ring welds. For the reactor pressure vessels (RPVs), the core support guide lugs and welds, six per RPV, are not included in the list. The RPV flange o-ring leakage monitoring tube is not included on the list because it is not exposed to the temperature and pressure conditions that facilitate primary water stress corrosion cracking (PWSCC).

Also not listed are the Alloy 690 materials and Alloy 52/152 weld materials in the Byron Station, Unit I replacement steam generators. Installed in the Winter of 1997, the Unit 1 steam generators do not contain any Alloy 600 or Alloy 82/182 materials.

The American Society of Mechanical Engineers (ASME)Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. Byron Station, currently in the 2 nd Inservice Inspection Interval, is committed to the 1989 Edition, no addenda, of ASME Section XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of Byron Station's commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants."

Page 1 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 The ASME Section XI and GL 88-05 requirements for visual examinations conducted at Byron Station to locate evidence of leakage from pressure retaining components are contained in procedure ER-AA-335-015, "VT-2 Visual Examination."

In addressing the extent of coverage, ER-AA-335-015 states:

"4.4.4. PERFORM VT-2 examination as close to the component as possible, even though the examination is essentiallyhands-off.

1. USE existing ladder(s), scaffolding, etc. to reduce the examination distance or to maximize examined surface areasif permittedby plant conditions (such as safety or health physics). INSTALLATION of ladder(s) or scaffolding for the sole purpose of conducting the VT-2 examinationsis not required.

2. If permitted by plant conditions (such as safety or health physics), then CONSIDER the use of remote optical aids to reduce the examinationdistance or to maximize examined surface areas."

This procedure does not specify examination details for specific components in the RCPB and associated systems, but rather provides general requirements applicable to all examined areas.

ER-AA-335-015 requires that accessible external surfaces of pressure retaining components be examined for evidence of leakage including evidence of boric acid accumulations from borated systems. If the components are inaccessible for the direct VT-2 examination, the procedure requires that the surrounding area including floor area or equipment surfaces located underneath the components be examined.

The procedure does not require that insulated components be de-insulated to perform a VT-2 examination. The procedure states that for insulated components, accessible and exposed insulation surfaces, including each insulation joint, be examined. For essentially vertical surfaces, the insulation at the lowest elevation where leakage may be detectable must be examined. Also, the surrounding area including floor areas or equipment surfaces located underneath the component is examined for evidence of leakage. The procedure requires that examiners give particular attention to discoloration of residue on surfaces in order to detect evidence of boric acid accumulations from borated reactor coolant leakage.

While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In summary, the components listed in the following table are examined using ASME Section XI and ER-AA-335-01 5 requirements. These requirements address the technical basis for the scope, inspection technique, inspection frequency, personnel qualifications, and, in general, extent of coverage.

Page 2 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal!

Insulation Type I RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams are The Insulation is not No corrective actions welds (4 hot leg safe-ends, for leakage (VT-2) by Certified Level by looking for performed twice each removed for the required to date.

4 cold leg safe-ends. 8 IIor III V`17-2 evidence of refuel outage: first, in VT-2 examinations.

total) Examiners. leakage around the Mode 3 going Into the Results reviewed pipe insulation outage after cycle The Insulation is a by Certified Level joints and along the operation at a stainless steel III Examiners. annulus of the pressure and reflective (mirror) piping penetration. temperature at or design. There are slightly less than 3, 120 *"segments normal operating buckled around the conditions, and then pipe-nozzle OD.

again in Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation Is not (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the removed for this examination of the Level II or III examination Spring of 1996. exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 performed from the welds. in EPRI TR-112657 pipelnozzle Inner Rev. B-A, Revised diameter with an Risk Informed automated Inservice Inspection tool.

Inspection Evaluation Procedure.'

Page 3 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Itemn Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 2 1 RPV head penetrations 79 Previous VT-2 Exams performed VT-2 examinations The VT-2 exams are Insulation is No corrective total exams performed by Certified Level have been performed twice each removed as actions required to

-53 CRDMs with the RPV head IIor ill VT-2 performed on the refuel outage: first, in necessary to date.

-2 RVLIS Insulation in-place. Examiners. accessible areas of Mode 3 going into the facilitate the BMV

-5 Thermocouple

-18 spare VHPs Bare Metal Visual Results reviewed the head. outage after cycle exam.

by Certified Level operation at a

- I head vent (BMV) using III Examiners. These exams are pressure and Peripheral vertical specific Inspection conducted on the temperature at or and horizontal guidelines have RPV head with the slightly less than panels are been developed shroud assembly normal operating designed for and will be access doors conditions, and then removal.

Implemented. opened and the again In Mode 3 RPV head coming out of the The RPV head Insulation in-place, outage at normal Insulation is a operating series of 3" thick temperature and mirror Insulation pressure with a 4 panels. The hour hold time. insulation Is Installed in a fiat A BMV exam Is field across the top scheduled for the Fall of the RPV head of 2003. The extent and is stepped and frequency of down as it additional approaches the examinations to be In outer perimeter of accordance with the RPV head.

MRP.

A partial BMV was completed during the Spring of 2002 on Unit I to verify that no degradation to the head had occurred from a previous leak.

Approximately 80%

of the RPV head was examined with no degradation found.

Page 4 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation RemovalU Insulation Type 3 1 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is Insulation is No corrective instrumentation exams performed by Certified Level has been performed each removed to actions required to penetrations (58 total) with the RPV lower IIor III VT-2 performed with refuel outage or facilitate Mode 5 date.

head Insulation Examiners. RPV lower head during a forced BMV examinations.

panels removed as Results reviewed Insulation removed outage of sufficient necessary to by Certified Level during Mode 5. duration. The insulation at visually exam the IIIExaminers. the bottom of the bottom of the The examination The examinations are RPV is a fiat, vessel and in-core has been performed twice, horizontal deck of nozzles. performed with once during Mode 5 stainless steel RPV lower head and then again at minor panels. The insulation in-place operating pressure deck stands off looking for leakage and temperature, with from the bottom of at Insulation joints, a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time, the lower head beneath the RPV. providing a clearance of 8".

The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 5 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 4 1 Pressurizer surge nozzle to Volumeic Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) Utrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level IIor III examination Spring of 1997. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. In EPRI TR-112657 Not currently included examination.

Rev. B-A, "Revised In risk informed Risk Informed Inspection program The insulation is Inservice scope. part of the Inspection pressurizer lower Evaluation head insulation procedure." arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe Insulation outage after cycle The Insulation Is by Certified Level joints, along the operation at a part of the Ill Examiners. surge line piping pressure and pressurizer lower and on the temperature at or head Insulation containment floor slightly less than arrangement. There beneath normal operating are 4 segments pressurizer surge conditions, and then enclosing the surge nozzle. again In Mode 3 nozzle. The panels coming out of the are stainless steel, outage at normal mirror panels with operating buckled snaps for temperature and removal.

pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Page 6 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type 1 Pressurizer spray nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective 5

safe-end weld (1 weld) (ultrasonic) Ultrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level IIor III examination Fall of 1988. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. in EPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 2 semi-circular, flat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT IIor iII VT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed nozzle to pipe outage after cycle The Insulation is by Certified Level insulation joint. operation at a part of the III Examiners. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 2 semi-circular, conditions, and then flat panels again In Mode 3 enclosing the spray coming out of the nozzle. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 7 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal!

Insulation Type 6 1 Pressurizer relief valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (1 (ultrasonic) Ultrasonic (UT) Informed ISI Last examined inthe been, and will be, actions required to weld) examination of the Level IIor III examination Fall of 1997. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. in EPRI TR-112657 examination.

Rev. B-A, *Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going into the Results reviewed pipe to nozzle outage after cycle The insulation Is by Certified Level Insulation joint, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again in Mode 3 enclosing the relief coming out of the nozzle. The panels outage at normal are 4"thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 8 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units 1 and 2 Byron Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 7 1 Pressurizer safety valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (3 (ultrasonic) Ultrasonic (UT) Informed ISl The three welds were been, and will be, actions required to welds) examination of the Level 11 or Ill examination each examined in the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Fall of 1988, Spring volumetric welds. in EPRI TR-112657 of 1990 and Sring of examination.

Rev. B-A, Revised 1996 for the I Risk Informed Interval, and in the The Insulation is Inservice Fall of1997 for the part ofthe Inspection 2f Interval. pressurizer head Evaluation insulation Procedure. arrangement. There are 4 segmented.

flat panels enclosing each of the safety nozzles.

The panels are 4*

thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT II or IIIVT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The Insulation Is by Certified Level insulation joints, operation at a part of the III Examiners. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again in Mode 3 enclosing each of coming out of the the safety nozzles.

outage at normal The panels are 4" operating thick stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 9 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units 1 and 2 Byron Station RCPB Alloy Material UstingI Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type 2 RPV nozzJe to safe-end Visual Inspection Exams performed Exam is performed The VT-2 exams are The insulation Is not No corrective 8

welds (4 hot leg safe-ends, for leakage (VT-2). by Certified Level by looking for performed twice each removed for the VT- actions required to 4 cold leg safe-ends, 8 II or III VT-2 evidence of refuel outage: first, In 2 examinations, date.

total). Examiners. leakage around the Mode 3 going into the Results reviewed pipe Insulation outage after cycle The Insulation is a by Certified Level joints and along the operation at a stainless steel IIIExaminers. annulus of the pressure and reflective (mirror) piping penetration, temperature at or design. There are slightly less than 3. 120 *"segments normal operating buckled around the conditions, and then pipe-nozzle OD.

again in Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation is not (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the removed for this examination of the Level II or III examination Spring of 1998. exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 performed from the welds, in EPRI TR-112657 pipelnozzle Inner Rev. B-A, 'Revised diameter with an Risk Informed automated Inservice inspection tool.

Inspection Evaluation Procedure.!

Page 10 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 9 2 RPV head penetrations A Bare Metal Visual Exams performed BMV of the RPV The BMV exam was Insulation Is No corrective (VHP) 79 total (BMV) using V'r-2 by Certified Level head surface and a performed in the Fall removed as actions required to

-53 CRDMs techniques was IIor III VT-2 360 degree view of of 2002. The extent necessary to date. In addition,

-2 RVLIS performed in Fail Examiners. all VHPs with slight and frequency of facilitate the BMV for the Fall 2002

-5 Thermocouple 2002. Specific Results reviewed obstruction of the additional exam. examination, there

-18 spare VHPs Inspection by Certified Level head vent examinations to be In were no corrective

- I head vent guidelines were III Examiners. penetration. accordance with Peripheral vertical actions taken as developed and MRP. and horizontal there was no Implemented. panels are evidence of leakage designed for on the RPV head Previous VT-2 removal, surface and no exams performed RPV head with the RPV head The RPV head degradation was Insulation in-place. Insulation is a identified.

series of 3' thick mirror Insulation panels. The Insulation Is Instafled In a flat field across the top of the RPV head and is stepped down as it approaches the outer perimeter of the RPV head.

Page 11 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 10 2 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is Insulation Is No corrective Instrumentation exams performed by Certified Level has been performed each removed to actions required to penetrations (58 total). with the RPV lower IIor III VT-2 performed with refuel outage or facilitate Mode 5 date.

head Insulation Examiners. RPV lower head during a forced BMV examinations.

panels removed as Results reviewed insulation removed outage of sufficient necessary to by Certified Level during Mode 5. duration. The Insulation at visually exam the III Examiners. the bottom of the bottom of the The examination The examinations are RPV Is a fiat, vessel and in-core has been performed twice, horizontal deck of nozzles, performed with once during Mode 5 stainless steel RPV lower head and then again at mirror panels. The insulation In-place operating pressure deck stands off looking for leakage and temperature, with from the bottom of at Insulation joints, a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time, the lower head beneath the RPV. providing a clearance of 8".

The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 12 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material ListingI IRem Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 11 2 Pressurizer surge nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) Ultrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level II or III examination Fall of 1998. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. In EPRI TR-112657 examination.

Rev. B-A, 'Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer lower Evaluation head Insulation Procedure.' arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT II or Ill VT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe Insulation outage after cycle The insulation Is by Certified Level Joints, along the operation at a part of the Ill Examiners. surge line piping pressure and pressurizer lower and on the temperature at or head Insulation containment floor slightly less than arrangement. There beneath normal operating are 4 segments pressurizer surge conditions, and then enclosing the surge nozzle. again in Mode 3 nozzle. The panels coming out of the are stainless steel, outage at normal mirror panels with operating buckled snaps for temperature and removal.

pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Page 13 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 12 2 Pressurizer spray nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld). (ultrasonic) Ultrasonic (UT) Informed ISI Last examined inthe been, and will be, actions required to examination of the Level IIor III examination Spring of 1990. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. inEPRI TR-112657 examination.

Rev. B-A. Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation insulation Procedure." arrangement. There are 2 semi-cIrcular.

fiat panels enclosing the spray nozzle. The panels are 4"thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation Is not by Certified Level by looking for performed twice each removed for the Vr IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The Insulation is by Certified Level Insulation joint, operation at a pert of the IIIExaminers. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 2 semi-circular, conditions, and then fiat panels again in Mode 3 enclosing the spray coming out of the nozzle. The panels outage at normal are 4"thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 14 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units i and 2 Byron Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 13 2 Pressurizer relief valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (1 (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the been, and will be, actions required to weld). examination of the Level IIor III examination Spring of 1995 for the removed for the date.

nozzle to safe-end Examiners. volume. Figure 4-9 1a Interval and In the volumetric welds. inEPRI TR-112657 Spring of 2001 for the examination.

Rev. B-A, Revised 2' Interval.

Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure. arrangement There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The Insulation Is not by Certified Level by looking for performed twice each removed for the VT IIor IIIVT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going into the Results reviewed pipe to nozzle outage after cycle The Insulation is by Certified Level insulation joint, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then flat panels again InMode 3 enclosing the relief coming out of the nozzle. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 15 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 14 2 Pressurizer safety valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (3 (ultrasonic) Ultrasonic (UT) Informed ISI The 3 welds were been, and will be, actions required to welds). examination of the Level IIor III examination each examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1990 and volumetric welds. inEPRI TR-112657 the Fall of 1993 for examination.

Rev. B-A, Revised the I" Interval and in Risk Informed the Spring of 2001 for The Insulation is Inservice the 2' interval, part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 4 segmented, fiat panels enclosing each of the safety nozzles.

The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT IIor IIIVT.2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The insulation is by Certified Level insulation joints, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again inMode 3 enclosing each of coming out of the the safety nozzles.

outage at normal The panels are 4" operating thick stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 16 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Materal Usting Personnel Extent of Frequency Degree of Corrective Action IRem Unit Component Inspection Techniques Qualifications Coverage Insulation Removal/

Insulation Type Exams performed The drain line, The direct visual The Insulation Is No corrective 15 2 Steam generator primary A visual using direct VT-2 techniques by Certified Level weld, and lower examination is removed to actions required to head drain lines (4 total). date.

was performed on IIVT-2 Examiners. head surface performed each time facilitate the the four steam around the drain the steam generator examination.

generator drain line were examined primary channel head lines and for steam Is de-insulated. The insulation surrounding head generators A', (typically for eddy around the steam surface. The "C" "B", "C"and "D'. current Inspection). generator lower steam generator head is a series of visual Inspection removable stainless was performed steel mirror panels.

during the June The bottom panel is 2002 forced outage a horizontal disc and the W, B" and that Is set off of the "D"steam steam generator generator visual head and encloses Inspections were the head, the drain performed during line, and the drain the Fall 2002 refuel line Isolation valve.

outage.

Previous VT-2 exams performed with the steam generator lower head Insulation In place.

Page 17 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2

2. Providethe technicalbasis for determining whether or not Insulationis removed to examine all locations where conditions exist that could cause high concentrationsof boric acid on pressureboundary surfaces or locations that are susceptible to primary waterstress corrosioncracking (Alloy 600 base metal and dissimilarmetal Alloy 82/182 welds). Identify the type of insulationfor each component examined, as well as any limitationsto removal of Insulation. Also include in your response actions involving removal of insulationrequiredby your proceduresto identify the source of leakage when relevantconditions (e.g., rust stains,boric acidstains, or boric acid deposits) are found.

Response

Except for bolted connections on borated ASME Section XI Class 1, 2 and 3 systems discussed below, Byron Station procedures do not require that insulated RCPB components be de insulated to perform VT-2 examinations. The basis for this has been that leakage from RCPB components should be detectable at insulated joints or surrounding areas given that the systems have been at normal pressure for, in most cases, a full operating cycle. While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In general, Byron Station ASME Section XI Class 1, 2, and 3 components in the containment containing borated water, if insulated, has removable stainless steel reflective style insulation.

Outside the containment, blanket insulation is used. Most insulation is removable, but there are exceptions. The insulation panels around the incore instrumentation guide tubes at the bottom of the RPV lower head are not intended to be removed. A set of peripheral horizontal panels are buckled in place and can be removed for access to the incore instrumentation guide tubes at the bottom of the RPV lower head. The horizontal panels around the VHPs are not removable; however, the side vertical panels are removable. The specific style of insulation for other locations in the RCPB is listed in the table in the response to Question 1.

Bolted Connections Insulated bolted connections in the RCPB (i.e., ASME Section XI, Class 1) and in borated ASME Section XI Class 2 and Class 3 support systems have insulation removed in order to perform ASME Section XI VT-2 examinations. The scope includes bolted connections that are installed in systems that are borated for the purpose of controlling reactivity. The ASME Section XI requirements on the extent of insulation removal and the plant conditions under which the insulation is removed have been modified by Byron Station Inservice Inspection Relief Requests 12R-1 1, Rev. 2 and 12R-34. Both of these alternatives to ASME Section XI requirements have been authorized for use at Byron Station by the NRC.

Relief Request 12R-1 I allows for insulation removal and the performance of the VT-2 exam on bolted connections in borated systems to be performed with the system depressurized. The approved altemative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examination. Additionally, for ASME Section XI Class 2 and 3 borated systems, VT-2 examinations are performed on approximately 36 month frequencies, which coincides with plant refueling outages, not allowing the period between inspections on individual components to exceed 45 months. This frequency for individual components is more restrictive than the "Periodic Frequency" allowed by ASME Section XI for Class 2 and 3 systems described in tables IWC-2500 or IWD-2500.

Page 18 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Relief Request 12R-34 allows the removal of insulation from certain ASME Section XI Class 1 valves for VT-2 examination to be performed on an extended frequency. The insulation is removed from the bolted connections and a VT-2 examination is conducted, with the system depressurized, on a once per 10 year interval frequency. These valves are also VT-2 examined with the insulation installed after a minimum four hour hold time at normal operating pressure at the end of each refueling outage and in Mode 3 during shutdown for each refueling outage.

Dissimilar Metal Welds Insulated dissimilar metal welded piping connections that contain Alloy 82/182 are typically not de-insulated for VT-2 examinations. A list of these nozzle to safe-end welds and the type of insulation is provided in the table in the response to Question 1. Examinations of these areas are performed in response to GL 88-05 and are conducted in Mode 3 going into the outage, typically, after a cycle of operation. Therefore, an adequate time is allowed for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The eight RPV nozzle to safe-end welds are considered inaccessible to perform direct VT-2 examination. The welds are located in an area between the concrete RPV shield wall and the concrete primary shield wall. This area enclosing the RPV nozzles and connected piping is referred to as the "sand box" area. The sand box area is only accessible from above, from the refueling cavity floor, by removing normally sealed steel plates. The normal technique for viewing potential leakage in this area is to look along the reactor coolant piping as it passes though the annulus of the bio-shield wall towards the RPV. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints inside the annulus. The RPV nozzle to safe-end weld insulation is not routinely removed since the sand box area is considered a high dose, confined space.

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluatingthe potential for leakage in inaccessibleareas. In addition, describe the degree of inaccessibility,and identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessibleareas.

Response

For the RCPB components, Byron Station personnel perform walkdowns during refueling outages, forced outages and, depending on circumstances, during power operations. Typical at-power containment walkdowns of accessible areas for leakage would be initiated at the request of the Operations Department if unidentified leakage was trending up or at the request of Radiation Protection personnel if there was an unexpected increase in containment atmosphere gas or particulate levels. For at-power walkdowns, the area of interest may be limited for as low as reasonably achievable (ALARA) considerations. VT-2 certified personnel perform the walkdowns during refueling outages and, in most cases, during forced outages and at power operations.

As described in the response to Question 2, the areas considered inaccessible are the "sand boxes" which enclose the eight RPV nozzles. Leakage from these areas is identified by visual examination along the horizontal surface of the insulated piping as it passes through the concrete annulus.

Page 19 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units i and 2 Byron Station uses a containment floor drain sump and a reactor cavity sump to collect, measure and record unidentified leakage in accessible and inaccessible areas in the containment. Both of these sumps are instrumented to identify leakages of 1.0 gpm within one hour and are recorded and alarmed in the main control room. The containment floor drain and reactor cavity sump inputs are checked each shift. A reactor coolant system (RCS) mass balance is performed when unidentified leakage is suspected and at the prescribed Technical Specification intervals. This provides early indication to the operator of potential unidentified leakage. Also, the reactor makeup control system is used to maintain proper reactor coolant inventory, volume control tank (VCT) level is continuously recorded and quantities of boric acid and makeup water injected are totaled and flow rates recorded in the control room.

The reactor coolant contains radioactivity that, when released to the containment, can be detected by radiation monitoring instrumentation. Radioactivity detection systems are used for monitoring both particulate and gaseous activities and can be used to identify RCS leakage.

The detection of RCS leakage using radiation monitors depends on the concentration of radioactivity in the RCS and detector background count rate.

Air temperature and pressure monitoring methods may also be used to infer unidentified leakage to the containment. Although containment temperature and pressure fluctuate slightly during unit operation, a rise above the normally indicated range of values may indicate RCS leakage into the containment.

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections), to demonstratethat continuedoperation with the observed leakage is acceptable. Also describethe acceptancecriteria that was establishedto make such a determination. Providethe technical basis used to establish the acceptance criteria. In addition,

a. If observedleakage is determined to be acceptablefor continued operation, describe what inspection/monitoringactionsare taken to trend/evaluatechanges in leakage, or

b. If observed leakage is not determined to be acceptable,describe what correctiveactions are taken to address the leakage.

Response

Byron Station personnel use engineering procedures BVP 200-10, "ISVIIST Recordable Indication Investigations," BVP 200-1 OT1, uRecordable Indication Record," and BVP 200-1 0T3, "ASME Section XI Bolted Connection Evaluation." These procedures describe the requirements and instructions for the evaluation of ASME Section XI Class 1, 2, and 3 bolted connections when external leakage is detected. These procedures provide instructions for the corrective actions that must be implemented in the event the structural integrity of any ASME Section XI Class 1, 2, or 3 bolted connection is determined to be suspect.

When evidence of leakage is identified from a bolted connection, the procedure requires an evaluation to be performed. This evaluation considers the location of the leak, leak rate, extent of deposit accumulation, extent of wastage, corrosiveness of process fluid, materials, length of time bolting has been in service and the effect on other structures or components. A condition Page 20 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 report is initiated for non-conforming conditions and a recommendation for repair, replacement, or monitoring is provided. Active leakage from the RCS is repaired prior to completing a refuel outage.

The bases for the evaluation/determination criteria of BVP 200-1 0T3 are derived from the provisions of Byron Station Inservice Inspection Relief Request 12R-12. This request was approved by the NRC.

Byron Station uses the corrective action process, specifically a condition report, to determine the acceptability for continued operation when a non-conforming condition is identified. Within the Condition Report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the non-conforming condition is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For a non-conforming condition that is determined to be unacceptable, repair or replacement is required.

5. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wall cracking in the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or installedleakage detection Instrumentation,but has the potentialfor causingboric acid corrosion. The NRC has had a concern with the bottom reactorpressure vessel head Incore Instrumentation nozzles because of the high consequences associatedwith loss of Integrityof the bottom head nozzles. Describehow your program would evaluate evidence of possible leakage in this Instance. In addition,explain how yourprogram addresses leakage that may Impact components that are In the leak path.

Response

As explained in the table in the response to Question 1, items 3 and 10, the insulation at the bottom of the RPV lower head stands off of the head surface by a minimum of eight inches at the very bottom of the lower head curvature. Visual examinations of the Byron Station, Unit 1 and Unit 2 RPV lower head, scheduled for the Fall of 2003 and Fall of 2003, respectfully, will require removing insulation panels to view the metal surface. Any leakage from lower head penetrations would be visible. This examination is normally performed twice each refueling outage as described in the table in the response to Question 1.

Reactor coolant and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels. The incore penetration instrument tubes that connect to the nozzles are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or opening of the insulation, there are no pressure retaining components beneath the RPV that could be affected. This leakage from the RPV bottom head nozzles would collect in the reactor cavity sump described in the response to Question 3. The reactor cavity sump input is recorded each shift and abnormal readings are required to be reported to the Shift Manager. This notification would result in an evaluation and a condition report would be initiated, as necessary.

Page 21 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2

6. Explain the capabilitiesof your programto detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wallcracking in certain components and configurationsfor other small diameternozzles. Low levels of leakage may call into question reliance on visual detection techniques or Installed leakage detection instrumentation,but has the potentialfor causing boric acid corrosion.

Describehow your program would evaluate evidence of possible leakage in this instance.In addition, explain how your program addresses leakage that may impact components that are In the leak path.

Response

The leakage detection capabilities at Byron Station were discussed in the response to Questions 3 and 5 above. The visual examination and evaluation procedures at Byron Station require that components in the area of a leak be examined and evaluated. In the case of Byron Station, the vast majority of components in the RCPB are stainless steel.

7. Explain how any aspects of your program(e.g., insulationremoval, inaccessible areas, low levels of leakage, evaluation of relevant conditions)make use of susceptibility models or consequence models.

Response

Vessel Head Penetrations (VHPs)

Byron Station personnel have based the examination requirements for the Unit I and Unit 2 VHPs on the EPRI Material Reliability Project (MRP) susceptibility model for PWSCC. This ranking (i.e., MRP-48) identifies Byron Station, Unit I and Unit 2 as "low susceptibility" plants rated 66 and 6 7 th, respectively, out of the 69 PWR units in the study. As of September 2002, Byron Station, Unit 1 had an effective degradation year (EDY) value of 1.8 and as of the next refueling outage for Unit 2 in September of 2003, an EDY of 2.0, putting the Units in the lowest of the three susceptibility categories established by the NRC in Bulletin 2002-02, "Reactor Pressure Vessel Head and RPV Head Penetration Nozzle Inspection Programs."

Because of this lower susceptibility, Byron Station personnel perform qualified, effective bare metal visual (BMV) inspections of the RPV head surface and VHPs. The BMV inspection for Byron Station, Unit 2 was completed in the Fall of 2002 with no evidence of VHP leakage found.

The BMV inspection for Byron Station, Unit I is scheduled for the Fall of 2003. A partial BMV was completed during the Spring 2002 on Unit 1 to verify that no degradation to the head had occurred from a previous leak. Approximately 80% of the RPV head was examined with no degradation found.

Steam Generator Drain Lines As listed in the table in the response to Question1, the steam generator primary head drain lines for Byron Station, Unit 2 are made of Alloy 600 and Alloy 82/182 materials. The bottom surface of the steam generator primary head, the 3/8" drain lines and drain line isolation valves are enclosed in the lower head insulation package. Based on a susceptibility model developed by Westinghouse, Byron Station is visually examining the four Unit 2 drain lines whenever the Page 22 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 steam generator lower head insulation package is removed to support the eddy current testing of the steam generator tubing.

All four steam generator drain lines were visually examined as described in the table in the response to Question 1. There were no recordable indications, no signs of boric acid deposits or any degradation of the carbon steel lower head surface.

8. Provide a summary of recommendationsmade by your reactorvendor on visual Inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken orplan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Vessel Head Penetrations As stated above in the response to Question 7, Byron Station personnel are following the examination recommendations of the industry effort on the Alloy 600/821182 issue.

Westinghouse, the reactor vendor, and Babcock & Wilcox, the reactor manufacturer, are part of this industry effort. Based on the lower susceptibility of the Byron Station, Unit I and Unit 2 VHP nozzles, the recommended visual examinations are being performed. Byron Station personnel have followed all MRP recommendations and will comply with the recent MRP recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002.

RPV Nozzle Safe-Ends, Reactor Lower Head Nozzles, and Pressurizer Nozzle Safe-Ends The current program for the examination of these components is listed in the table in the response to Question 1. Exelon Nuclear corporate and Byron Station personnel are currently working with Westinghouse on developing a comprehensive inspection, repair and/or mitigation program for all Alloy 600/82/182 components in the RCPB.

9. Provide the basis for concluding that the inspections and evaluationsdescribed In your responses to the above questions comply with your plant Technical Specifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of MechanicalEngineers (ASME) Code by reference. Specifically, addresshow your boric acid corrosioncontrol program complies with ASME Section Xl, paragraphIWA-5250 (b) on corrective actions. Include a description of the procedures used to implement the corrective actions.

Response

Byron Station Technical Specification (TS) Limiting Condition for Operation (LCO) 3.4.13.a states that there shall be no pressure boundary leakage. Pressure boundary leakage is defined as leakage, except steam generator tube leakage, through a non-insoluble fault in a reactor coolant system component body, pipe wall, or RPV wall. If pressure boundary leakage is detected, the action statements for this LCO require that the affected unit be in Mode 3 in six hours and be in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The resolution of leakage indications in the corrective action program requires evaluation of the impact on this TS.

Page 23 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Compliance with the zero non-isolable leakage criteria is met by performing GL 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards." In addition, the unidentified leakage limit of one gpm defined in TS LCO 3.4.13.b is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a, requires that inservice inspection and testing be performed in accordance with the requirements of ASME Section XI. ASME Section XI contains applicable rules for examination, evaluation and repair of code class components, including the RCPB.

For this, the 2 nd Inservice Inspection Interval, Byron Station personnel have implemented the 1989 edition, with no addenda, of ASME Section XI. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"If boric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, Byron Station personnel use Exelon Nuclear Procedure ER-AA-335-015, "VT-2 Visual Examination." Paragraph 4.6.1.4 of this procedure states:

"ffboric acid residues are detected on components, then LOCATE the leakage source and the areasof generalcorrosion. EVALUATE components with local areasof general corrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptablefor continued service, or whether repairorreplacement is required."

The Exelon Nuclear procedure LS-AA-125, "Corrective Action Program (CAP) Procedure" defines the requirements for condition identification, condition review, investigation, and closeout.

Page 24 of 24

ATTACHMENT 3 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I-AmerGen Energy Company, LLC (AmerGen)

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I On November 21, 2002, the NRC issued a Request for Additional Information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was required within 60 days of the date of the RAI for TMI Unit I that was categorized as a Bin 2 plant in the RAI.

NRC Question

1. Provide detailed information on, and the technical basis for, the inspection techniques, scope, extent of coverage, and frequency of Inspections, personnel qualifications, and degree of insulation removal for examination of Alloy 600 pressure boundary material and dissimilar metal Alloy 821182 welds and connections in the reactor coolant pressure boundary (RCPB). Include specific discussion of inspection of locations where reactor coolant leaks have the potential to come In contact with and degrade the subject material (e.g., reactor pressure vessel (RPV) bottom head).

Response

Introduction IBackground Regulatory Requirements:

10 CFR 50.55a, "Codes and standards," identifies the codes and standards requirements for operating nuclear power plants. Section (f) identifies the in-service testing requirement and section (g) identifies the in-service inspection requirements. For facilities whose construction permit was issued prior to July 1, 1971 (the construction permit for Three Mile Island Unit 1 was issued on May 18, 1968), components are required to meet the requirements of paragraphs (g)(4) and (g)(5) to the extent practical.

Paragraph (g)(4) states, "...components (including supports) which are classified as American Society of Mechanical Engineers (ASME Code) Class 1, Class 2 and Class 3 must meet the requirements, except design and access provisions and preservice examination requirements, set forth in Section XI of editions of the ASME Boiler and Pressure Vessel Code and Addenda that become effective subsequent to editions specified in paragraphs (g)(2) and (g)(3) .... to the extent practical within the limitations of design, geometry and materials of construction...."

The ASME Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. TMI Unit 1, currently in the 3rd Inservice Inspection Interval, is committed to the 1995 Edition, through the 1996 Addenda, of ASME XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of the TMI Unit I commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants."

Page 1 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Development of the Boric Acid Corrosion Control (BACC) Program at TMI Unit I (since 1982):

On June 2, 1982, the NRC issued IE Bulletin 82-02, "Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of PWR Plants.' The purpose of this bulletin was twofold; first, to notify licensees and construction permit holders about incidents of severe degradation of threaded fasteners (bolts and studs) in closures in the reactor coolant pressure boundary (RCPB) and secondly, to require appropriate actions.

The scope of the resulting action items included threaded fasteners (studs or bolts) in steam generator and pressurizer manway closures, valve bonnets and pump flange connections installed on lines having a nominal diameter of six inches or greater and control rod drive flange and pressurizer heater connections that do not have seal welds to provide leak-tight integrity.

The response identified bolted closures of the RCPB that had experienced leakage with the resultant inspections made and corrective measures taken to eliminate leakage. It also identified RCPB closures and connections where fastener lubricants were used and the lubricant's composition. The only instance of the use of injection sealant was on the decay heat drop line and was reported, as required. A review of maintenance procedures and training was performed to assess threaded fastener practices.

Maintenance procedures were determined to be adequate to meet the requirements specified in IE Bulletin 82-02. In addition, training on bolting procedures was added to the mechanical maintenance training program. Finally, a report of specific connections examined since the issuance of NRC Information Notice No. 82-02 was provided to the NRC in letters dated August 3, 1982 and December 5, 1985. No evidence of RCPB stud or bolt failures was noted.

In 1989, to address concerns identified in NRC Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel RCPB Components in PWR Plants," TMI Unit 1 developed Technical Data Report (TDR) No. 946, "TMI-1 Evaluation of Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components". The existing TMI Unit I boric acid corrosion inspection requirements are based on the recommendations of this report.

This report identified specific RCPB locations most vulnerable to concentrated boric acid corrosion and the carbon steel targets of this leakage. These targets include;

"* reactor vessel,

"* pressurizer,

"* steam generator upper and lower heads,

"* hot and cold leg piping,

"* reactor coolant pump casing to piping bi-metallic weld,

"* studs on all manway I handholds or nozzles or valve packing assemblies,

"* core flood and high pressure injection nozzle safe ends,

"* pressurizer spray and surge lines, and

"* carbon steel sections of instrument piping and carbon steel valve bodies.

TDR No. 946 also provides clarification of the methodology for assessing component damage. Programmatic controls were developed to provide continuing assurance of extremely low probability of significant degradation to the RCPB components due to concentrated boric acid corrosion.

Page 2 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I TDR No. 946 divided RCPB components into three groups according to the potential consequences of their leakage onto other RCPB carbon steel components. This was intended to assist in placing appropriate emphasis on leakage inspections and evaluations. Group I components are RCPB components with mechanical joints, and the RCPB targets of the leakage. Group 2 components are RCPB components with mechanical joints for which unchecked corrosion of their targets could result in a RCPB leak equivalent to a leak from a line size greater than one inch (within the plant's normal makeup capability). Group 2 components are a subset of Group I components. Group 3 components are RCPB components with mechanical joints for which unchecked corrosion of their targets could result in a RCPB failure that exceeds the plant's normal makeup capability without first alerting the operator by exceeding the unidentified leak rate limit. Group 3 components are a subset of Group 2 components.

The reactor pressure vessel incore monitoring instrument (IMI) nozzles are not addressed as a component in TDR No. 946. A detailed discussion of the IMI nozzles is provided in response to Question No. 5.

All Group 1, Group 2 and Group 3 components, as well as others identified in TDR No.

946, are identified for ASME Section XI visual inspections (VT-2) prior to startup following each refueling outage. Each item has an individual sign-off to document the inspection. If evidence of leakage is noted during these inspections, programmatic requirements are in place to ensure that an engineering evaluation of the safety consequences of identified leakage is performed, and the condition corrected via corrective maintenance or component replacement. Additional non-ASME Section XI walkdowns are performed during plant cool down conditions to identify any evidence of leakage.

TDR No. 946, dated January 10, 1989, acknowledges the importance of the boric acid corrosion control issue and concludes with:

"Borated water leakage onto the RCPB can result in severe corrosion damage. The cooling effect of a leak on a hot RCPB surface can be sufficient to keep the surface moist, allowing for development of highly corrosive boric acid solutions.

Laboratory corrosion data and documented cases of severe RCPB corrosion demonstrate the problem. Boric acid corrosion rates of up to I to 2 inches per year are expected for carbon steels at RCS operating temperatures.

Minimizing the chance of severe RCPB degradation from boric acid corrosion is crucial to safe plant operation. At TMI Unit 1, a program of leakage inspections coupled with engineering evaluations and maintenance is the primary means of minimizing the probability of corrosion damage."

Subsequently, in response to NRC Information Notice 90-10: *Primary Water Stress Corrosion Cracking (PWSCC) of Inconel 600" (February 23, 1990), TMI Unit 1 commissioned a study of the use of nickel-base alloys. B&W Nuclear Technologies completed their report, "Nickel-Base Alloy Usage at TMI-1" (Report No. 51-1179885) in June 1990. This proprietary report provides a summary listing of nickel-base alloys used in the construction of the TMI Unit I reactor coolant system (excluding fuel assemblies Page 3 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit i and their control components) to be used in assessing possible in-service inspection locations. This report serves as a basis for the component identification in the attached table. BWNT Report No. 51-1179885 also identified that the effect of temperature on the initiation time for Alloy 600 SCC is an important variable, and that Alloy 600 failures have typically occurred at operating temperatures greater than approximately 600 F.

In accordance with the recommendations of BWNT Report No. 51-1179885, TMI Unit 1 inspects all pressurizer nozzle to safe end welds and the reactor vessel internals upper core barrel bolts during each 10-year in-service inspection period. These sites were characterized as most susceptible to Alloy 600 SCC. Other locations that were identified as possibly susceptible to Alloy 600 SCC, based strictly on temperature, were the reactor vessel and head and the reactor coolant piping. This report does not identify the incore monitoring instrumentation nozzles as a priority for Alloy 600 SCC inspections because of the lower operating temperatures.

In 1998, Framatome Technologies completed a study to rank on a relative basis each of the Alloy 600 components for potential failure due to PWSCC. A ranking was performed for each of the B&W Owners Group Plants. The results of this report, uAlloy 600 PWSCC Susceptibility Model, 51-5001951-01, December 16, 1998,0 are discussed in the response to Question No. 7.

Insulation removal is discussed in detail in response to Question No. 2.

Reactor Pressure Vessel Bottom Head Construction:

The reactor vessel is constructed of low alloy steel. The design pressure is 2500 PSI and the design temperature is 650 degrees F. The sides of the vessel are constructed of SA-533B, Class 1 plate with a stainless steel clad on the inner surface. The minimum wall thickness is 8.4 inches. The lower head is a forging of A-508 material with a minimum thickness of 5 inches. This component is also clad with stainless steel. There are 52 incore instrument nozzles that penetrate the lower vessel head. These are fabricated from ASME SB-166 Alloy 600 (Inconel) barstock. This material was supplied by B&W Tubular Products Division with heat number M6378. The initial size before machining was 2.25 inches outer diameter. This material was either hot rolled or hot finished, annealed and pickled. As stated in BWNT Report No. 51-1179885, these nozzles were most likely installed with a GTAW root pass with Alloy 82 weld metal then completed using the manual metal arc technique with Alloy 182 weld metal.

The reactor vessel was constructed under the following governing specifications: 1) The American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section III "Rules for Construction of Nuclear Vessels," 1965, and all applicable Code cases and Addenda for Class A vessels as of June 20, 1967, 2) The American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section IX,Welding Qualifications, 1965, 3) The Babcock and Wilcox Company Equipment Specification CS-3-22, dated May 26, 1970, and 4) The Babcock and Wilcox Company, Quality Control Department Specifications covering Welding, Non-Destructive Testing, Heat Treatment, Cleaning and Testing.

The area below the bottom head insulation is surrounded by concrete and is referred to as the reactor vessel cavity area. This area is located within the primary shield. The area is approximately twelve feet in diameter and approximately nine feet high. Other Page 4 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I than the incore instrument piping, there is no equipment in this area. A personal access hatch (approximately four feet high by four feet wide) and three ventilation ports (approximately one foot diameter) are provided through the structural concrete. Access to this area is restricted (due to dose rates) when the reactor is critical or when any incore instrumentation is pulled from the fuel. This area is not normally entered when the reactor coolant system is heated.

Insulation Design:

The thermal insulation for the reactor vessel is reflective type, designed and manufactured by Diamond Power Specialty Corporation and known as SS-MIRROR or MIRROR insulation. The insulation is of 100% stainless steel construction with carbon steel support members. The insulation was provided as pre-fabricated panels with adjacent panels matched to fit (tapped screw holes in overlapping members at the joints). The insulation is designed with clearances between the reactor vessel outer diameter and the inside diameter of the insulation assemblies to allow for thermal expansion of the vessel. The insulation panels are banded together with stainless steel bands.

For the bottom head panel placement, three sections of support steel were used. These were welded together after being put in place in the cavity area. Insulation panels were then bolted through one-inch diameter cutouts and attached with three-inch square washers, lock washers and nuts. This assembly was then raised and attached to the concrete wall using self-drilling anchors.

The following table provides a listing of the requested information of the Alloy 600 pressure boundary material and Alloy 82/182 welds and locations in the TMI Unit 1 Reactor Coolant Pressure Boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to RCPB components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. For the reactor vessel, these items include the guide lugs, reactor internal bolting block plate, the internal jack- screw locking cup and bolt locking cup. For the pressurizer, the spray nozzle connection inside the pressurizer is not included. In the once-through steam generators, the items are the steam generator tubing and the tube sheet cladding.

Page 5 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type IT Reactor vessel nozzle to Visual Inspection Exams performed Exam is performed The VT-2 exams The insulation Is not No corrective safe-end welds (2 core flood for Leakage (VT- by Certified Level II by looking for are performed each removed for the actions required to nozzles) 2) VT-2 examiners, evidence of leakage refuel outage: VT-2 examinations, date.

around the pipe coming out of the Insulation joints and outage at normal The insulation Is a along the annulus operating stainless steel of the piping temperature and reflective (mirror) penetration. pressure with a 4 design around the hour hold time. pipe-nozzle OD.

Non-ASME Section XI walkdowns are performed during plant cool down conditions to identify any evidence of leakage.

Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation is not (ultrasonic) (UT) Level 111111 Last examined in removed for this examination of the Examiners, the Fall of 2001. exam. The exam is nozzle to safe-end Next scheduled performed from the welds. exam for TMI-1 is pipetnozzle inner Fall 2011. diameter with an automated inspection tool.

Page 6 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type Reactor vessel head Previous VT-2 Exams performed Exam is performed The VT-2 exams The RV head Bare metal, UT and penetrations (VHP) 71 total exams performed by Certified Level II by looking for are performed each insulation is a PT examinations 2 1 and corrective

-69 CRDMs with the RPV VT-2 examiners, evidence of leakage refuel outage: series of mirror

- 1 RVLIS head Insulation in- around the pipe and coming out of the insulation panels. actions taken in the

- 0 Thermocouple (Plugged) place. insulation joints, outage at normal The insulation is 1R14 refueling

- I head vent operating installed in a flat outage are The reactor temperature and field across the top described in vessel head is pressure with a 4 of the RPV head. AmerGen letter to scheduled to be hour hold time. the NRC dated April replaced with a Peripheral vertical 1, 2002 (5928-02 new head in and horizontal 20091) in response October 2003. panels are to NRC Bulletin designed for 2002-01, 15 day removal. Insulation response is not removed for requirement.

VT-2 examination at normal operating temperature and pressure.

Page 7 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Ahloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 3 1 RPV lower head in-core Previous VT-2 Exams performed Exam is performed The examination Is For previous After the 9R instrumentation penetrations exams performed by Certified Level II by looking for performed once exams, the refueling outage (52 total) with the RPV VT-2 examiners, evidence of leakage during each refuel Insulation has not (1991), cleaning lower head around the pipe and outage. been removed, was performed by insulation in- insulation joints, removing boron place. TMI Unit 1 The insulation at residue from six is planning to the bottom of the suspect guide tubes install a camera vessel Is a flat, and from within the above the horizontal deck of primary shield, and insulation to stainless steel performing a water visually inspect mirror panels. The flush of the area the bare metal deck stands off Including the vessel around the incore from the bottom of insulation, primary instrumentation the lower head shield walls and nozzle providing a guide tubes and penetrations clearance of about within the cooling during the 6 inches. The annulus conducted refueling outage panels are fixed from the seal plate currently around the 52 in- area.

scheduled for core guide tubes.

October 2003 (TIR15).

4 1 Pressurizer surge nozzle to Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT)/Penetrant Last examined in been, and will be, actions required to examination of the Level I/Ill the Fail of 1999. removed for the date.

nozzle to safe-end Examiners. volumetric welds. A surface Next scheduled examination.

exam is also exam for TMI-1 Is required by Fall 2009.

Section Xl Code._I Page 8 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-1 Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Techniques Qualifications Coverage Insulation Removal/

Insulation Type VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed removed for the VT VT-2 examiners, evidence of leakage each refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is a operating series of form fitting temperature and stainless steel, pressure with a 4 mirror styled panels hour hold time. with stainless steel bands that allow for removal.

Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation has No corrective Pressurizer spray nozzle to actions required to safe-end weld (1 weld) (ultrasonic) and (UT) Penetrant been, and will be, Surface Level 1ill/ Last examined in removed for the date.

examination of the Examiners. the Fall of 2001. volumetric nozzle to safe-end examination.

welds.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners. evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation Is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement (NUKON).

Surface exam, Certified Penetrant Once per 10 years. Insulation has No corrective Pressurizer relief valve actions required to nozzle to flange weld (1 weld) (Less than 4 Level liIll 100%. Last examined in been, and will be, Nominal Pipe Size examiners, the Fall of 1997. removed for the date.

(NPS) surface examination.

Page 9 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-1 Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type VT-2 Exams performed Exam is performed The VT-2 exams The insulation Is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners, evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement (NUKON).

7 1 Pressurizer safety valve Surface exam, Certified Penetrant 100% Once per 10 years. Insulation has been No corrective nozzle to flange weld (2 less than NPS 4. Level 11411 and will be removed actions required to welds) Examiner. The 2 welds were for the surface date.

last examined in the examination.

Fall of 1997.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners, evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement II_(NUKON).

8 1 RC drain line nozzle to safe- Volumetric Certified Ultrasonic 100% Once per 10 years Insulation has been No corrective end and safe-end to nozzle (ultrasonic) and (UT) Level IlIII per ISl schedule. and will be removed actions required to welds (6 welds) surface exam for Examiners.- for the date.

> NPS 4 examinations.

RC pumps pipe to elbow and Certified Penetrant pipe to pipe welds Surface exam for Level IIll1 (9 welds) < NPS 4 ExaminersI_ I NOTE : The MIRROR Insulation on the pressurizer and once-through-steam-generator upper heads have been replaced with NUKON Insulation, manufactured by Owens-Coming Fiberglass Corporation.

Page 10 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Results of Previous Inspections of the Reactor Vessel Bottom Head Cavity Area:

Due to transfer canal water leakage past the seal plate, an inspection was performed in the cavity area during 1991 (9R refueling outage). In summary, the area was cleaned and no primary system leakage was present. The following provides a summary of the 9R Outage inspection:

During 9R, Plant Engineering performed inspections of remote areas of TMI-1. One such area was within the primary shield underneath the reactor vessel lower head. This inspection was performed when all the incores were removed from the guide tubes awaiting replacement. The initial entry into the area found boron deposition on numerous incore tubes and the interior wall of the primary shield opposite the exhaust of the AH-E-2 fans. The examination during this entry was video taped. It was noted that water was dripping down from the cooling annulus in the vicinity of the incore chase.

After review of the videotape, Plant Engineering noted the amount of boron accumulation and the arrangement of deposition under the vessel. Engineering suspected that heavy localized deposits may have been a result of a leak in one or more incore guide tubes with mixing by the reactor cavity fans. As a result, plans were made to remove boron from six suspect stainless steel guide tubes, perform a visual inspection for a leak followed up by an NDE examination, application of a freeze seal and a 1000 PSI hydro of each tube from the incore seal plate. Each of the six guide tubes was successfully tested with no leakage identified.

Boron removal work was then performed within the primary shield followed by a water flush of the area including the vessel insulation, primary shield walls and guide tubes.

After this work was completed, a water flush was also performed within the cooling annulus conducted from the seal plate area. The flush was concentrated in the area where seal plate leakage had been earlier detected. A final entry was made to remove standing water and clean the floor.

The final assessment for boron accumulation was as follows:

"* There was 3 to 4 inches of standing water being retained within the primary shield.

"* Water leakage was from the seal plate while the transfer canal was flooded.

"* The dispersion of boron was due to the air turbulence induced by the AH-E-2 fans entering the cavity near floor level to the left of the primary shield entrance.

"* The total dose for the effort was 1.8 man-rem of which 0.6 was attributed to boron removal activities.

Subsequent to the 9R refueling outage transfer canal seal plate leakage, Operations surveillance OPS-$419 was created. This task inspects the reactor vessel cavity area and the area within the reactor head support skirt. A summary of these results, based on a review of the last three refueling outage inspections, follows:

Page 11 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1

" In 1997, standing water was found in the cavity area with some minor rusting noted.

" In 1999 (13R), no abnormal conditions were noted and a video tape was made. The videotape was reviewed with no significant abnormal conditions noted. However, a thin layer of water on the floor and some minor boron streaks were noted.

" In 2001 (TI R14), only photos were taken due to dose rate that limited entry into the cavity area. These photos were reviewed with no significant abnormalities noted, except for minor rusting of the air inlet piping and minor boron streaks on shield wall.

• The 1999 and 2001 conditions noted are indicative of some minor transfer canal seal plate leakage.

In conclusion, the reactor cavity area underneath the vessel has been inspected every refueling outage since at least 1991 (9R) with no significant abnormal conditions found.

These visual inspections (VT-2) did not specifically examine the bottom of the reactor vessel where the incore instrument nozzles penetrate the vessel because insulation completely covers this area and prevents visual inspection of the actual penetration.

These inspections did assess the general condition of this area and did identify indications of boron accumulation (most probably from canal seal plate leakage). Based on previous results, we are confident that any significant indications of leakage from the incore instrument nozzles would have been identified during these visual inspections.

Locations Where RCS Leakage has the Potential to Come Into Contact with the RPV Bottom Head:

There are no components located below the reactor vessel in the cavity area except the incore monitor tubes. These provide the only potential source of leakage located below the bottom head. Leakage onto the bottom head from elevations above can only originate from components whose weld interface is contained within the primary shield enclosure. For Alloy 600182/182 welds, these components include:

"* Reactor vessel upper head control rod housing bodies (69)

"* Reactor vessel upper head thermocouple nozzles (2)

"* Reactor vessel lower head incore monitoring instrumentation nozzles (52)

"* Core flood nozzle to safe-end welds (2)

Page 12 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I NRC Question

2. Provide the technicalbasis for determining whether or not insulationis removed to examine all locations where conditions exist that could cause high concentrationsof boric acidon pressureboundarysurfaces or locations that are susceptible to primarywater stress corrosioncracking (Alloy 600 base metal and dissimilarmetal Alloy 82H182 welds). Identify the type of insulationfor each component examined,as well as any limitations to removal of insulation. Also include in your response actions involving removal of insulationrequiredby your proceduresto identify the source of leakage when relevant conditions (e.g., rust stains,boric acidstains, or boric acid deposits) are found.

Response

The basis for determining whether or not insulation is removed for examinations at TMI Unit I is consistent with ASME Section XI allowances which reflect practicality, cost, and dose considerations. The degree of insulation removal and insulation design is described in the Table provided in the response to Question No. 1.

Pipingq and Bolted Connections:

The visual examination (VT-2) of borated systems (for the purpose of controlling reactivity) requires insulation to be removed from pressure retaining bolted connections.

For other components, the visual examination may be conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation.

The ASME requirements on the extent of insulation removal and the plant conditions under which the insulation is removed, have been modified by TMI Unit I Inservice Inspection Relief Requests RR-00-08 and RR-00-09. Both of these alternatives to the ASME Section XI requirements have been authorized for use at TMI Unit I by the NRC.

Relief Request RR-00-08 allows the performance of the leakage tests on bolted connections in Class 1 borated systems to be performed without the removal of insulation. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examinations (to allow for leakage propagation from the insulation). Additionally, the insulation is removed from Class 1 bolted connections and a VT-2 visual examination is conducted with the system depressurized. These inspections are performed each refueling outage (nominal 24 month frequency).

Relief Request RR-00-09 allows the insulation around the bolted connections around the electrical pressurizer heater connections to remain installed during the VT-2 examinations of this area. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examinations (to allow for leakage propagation from the insulation). These inspections are performed each refueling outage (nominal 24 month frequency) with the plant at hot shutdown.

Page 13 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I For insulated piping and components, a four-hour hold time at nominal operating pressure or hydrostatic test pressure is required as specified in the implementing procedures. For systems borated for the purpose of controlling reactivity, insulation is removed from pressure retaining bolted connections for visual examination VT-2 (unless relief has been authorized). Where normal access methods allow, pressure-retaining nuts, studs, bolts, capscrews and washers are visually inspected for evidence or indication of boric acid corrosion. This includes inspection for wastage, missing metal, cracks, pits, boric acid accumulation, corrosion products, and damaged or missing threads. For other than pressure retaining bolted connections, visual examination (VT-2) is conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation. In accordance with ASME Section XI, essentially vertical surfaces of insulation are examined at the lowest elevation where leakage may be detectable, and essentially horizontal surfaces of insulation are examined at each insulation joint. When examining insulated components, the examination of the surrounding area (including floor areas or equipment surfaces located undemeath the components) for evidence of leakage, or other areas to which such leakage may be channeled, is required. Discoloration or residue on surfaces examined is given particular attention to detect evidence of boric acid accumulations from borated reactor coolant leakage.

During the examination, particular attention is given to the insulated areas of components constructed of ferritic steels to detect evidence of boric acid residues whose sources derive from borated reactor coolant, and which may have accumulated during the service period preceding the examination. Any recordable indications identified during these inspections are evaluated by engineering through the corrective action program. The following conditions are considered recordable:

• Leakage from other than locations where leakage is normally expected and collected

• Inoperative leakage collection system

• Areas of general corrosion

• Corrosion which appears to have reduced the wall thickness by more than 10%

of the component, or which results in a surface transition with less than a 3 to I taper. (Rust with no visible thickness (no flaking) is acceptable without further evaluation)

• Any areas of structural distress (i.e., bent hangers, etc.)

• Boric acid residues on ferritic steel (verification of leakage source shall also be recorded)

In accordance with TMI Unit I VT-2 leakage examination Procedure SP 1300-6, if leakage occurs at a bolted connection, the corrective measures and evaluations of ASME Section XI as modified by NRC approved relief (RR-00-08), are required to be performed. Leakage at a bolted connection also requires at least one bolt to be removed and be VT-3 examined, per SP 1300-6.

Page 14 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Dissimilar Metal Welds:

Insulated dissimilar metal welded piping connections that contain Alloy 82/182 typically do not have insulation removed for VT-2 examinations. Welds NPS 4 and larger receive a volumetric and surface examination per ASME Section XI. A list of these nozzle to safe-end welds and the type of insulation is provided in the Table contained in the response to Question No. 1. Examinations of these areas are performed in response to Generic Letter 88-05 and are conducted at hot shutdown after a four hour hold time to allow for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The two reactor vessel nozzle to safe-end welds (core flood nozzles) are the only components considered inaccessible to direct VT-2 examination. The welds are located in an area between the concrete reactor vessel shield wall and the concrete primary shield wall. This area enclosing the reactor vessel nozzles and connected piping is referred to as the "sand plug" area. The sand plug area is only accessible from the refuel canal floor. The normal technique for viewing potential leakage in this area is to visually inspect along the piping as it passes though the D-ring wall. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints. The reactor vessel nozzle to safe-end weld insulation is not removed. These welds are examined internally by Ultrasonic Testing (UT) as part of the 10-year Inservice Inspection Program requirements.

Reactor Vessel Penetrations:

TMI Unit 1 reactor vessel penetrations in the lower head are scheduled for visual examination in the Fall 2003 refueling outage. A bare metal visual inspection of the TMI Unit I upper vessel head penetrations was performed in the Fall of 2001, prior to startup of the current operating cycle. The upper head is scheduled to be replaced in the Fall of 2003.

In general, TMI Unit I Class 1, 2, and 3 RCPB components containing borated water, if insulated, have removable, stainless steel, reflective style insulation. Regulatory Guide 1.82, "Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," guidance is utilized for review of changes to thermal insulation installed on the primary coolant system piping and components. The panels around the reactor vessel head are removable. The insulation panels around the pressurizer heaters are not easily removed. Relief Request RR-00-09 allows this insulation to remain in place due to personnel dose exposure and the potential damage to the heaters associated with the insulation removal.

TMI Unit I VT-2 leakage examination Procedure SP 1300-6 specifies that in the event boric acid residues are detected, the insulation shall be removed from the components to the extent necessary to permit visual examination of the surfaces wetted by reactor coolant leakage, in order to detect evidence of corrosion. This procedure also specifies that for a recordable indication, the specific location of the leak shall be determined by the removal of any insulation, which interferes with the determination of the leakage Page 15 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I source. The leakage source, when determined, shall be identified and its specific location defined and documented by measured distances from adjacent welds, components, etc.

NRC Question

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluating the potential for leakage in inaccessibleareas. In addition, describethe degree of Inaccessibility,and Identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessible areas.

Response

For RCPB components, TMI Unit I performs inspections to identify any reactor coolant system leakage following a plant shutdown, during any refueling outage and, depending on circumstances, at-power. Typical at-power containment visual inspections of accessible areas for leakage would be initiated at the request of the operations department if unidentified leakage were trending up or if there was an unexpected increase in containment atmosphere gas or particulate levels. For at-power visual inspections, the area of interest would be limited for ALARA considerations. VT-2 certified personnel perform the visual inspections for refueling outages and in most cases for forced and at-power visual inspections. Visual inspections performed during plant shutdowns include the reactor head area, the reactor coolant system and the makeup system, both inside and outside the secondary shields inside the reactor building.

See the response to Question No. 5 for a discussion of the detection methods used for inaccessible areas. TMI Unit I does not have any plans to install additional leak detection instrumentation at this time; however, TMI continues to monitor industry activities in this area.

NRC Question

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections) to demonstratethat continued operationwith the observedleakage is acceptable. Also describe the acceptance criteriathat was establishedto make such a determination. Provide the technical basis used to establish the acceptance criteria. In addition,

a. If observed leakage Is determinedto be acceptable for continued operation,describe what Inspection/monitoringactionsare taken to trend/evaluatechanges in leakage, or Page 16 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I

a. If observed leakage is determined to be acceptablefor continued operation,describe what inspection/monitoringactionsare taken to trend/evaluatechanges In leakage, or

b. If observed leakage Is not determined to be acceptable,describe what corrective actions are taken to address the leakage.

Response

TMI Unit 1 utilizes Technical Specification Surveillance Procedure Nos. 1300-6, "VT-2 Leakage Exams, 1300-6Q, "Leakage Exam for Insulated Bolted Connections,n and Administrative Procedure No. ER-AA-335-015, "VT-2 Visual Examination," to control these examinations. These procedures describe the requirements and instructions for the evaluation of any indications found during visual examinations, including those of insulated bolted connections. The procedures provide instructions for the corrective actions that must be implemented in the event the structural integrity of any component or bolted connection is determined to be suspect.

For insulated piping and components, a four-hour hold time at nominal operating pressure or hydrostatic test pressure is required as specified in the implementing procedures. For systems borated for the purpose of controlling reactivity, insulation is removed from pressure retaining bolted connections for visual examination VT-2 unless prior relief has been granted. Where normal access controls allow, pressure retaining nuts, studs, bolts, capscrews and washers are visually inspected for evidence or indication of boric acid corrosion. Inspections are conducted for wastage, missing metal, cracks, pits, boric acid accumulation, corrosion products, and damaged or missing threads. For other than pressure retaining bolted connections, visual examinations are conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation. Essentially vertical surfaces of insulation are examined at the lowest elevation where leakage may be detectable. Essentially horizontal surfaces of insulation are examined at each insulation joint. When examining insulated components, the examination of the surrounding area (including floor areas or equipment surfaces located underneath the components) for evidence of leakage, or other areas to which such leakage may be channeled, is required. Discoloration or residue on surfaces examined is given particular attention to detect evidence of boric acid accumulations from borated reactor coolant leakage.

During the examination, particular attention is given to the insulated areas of components constructed of ferritic steels to detect evidence of boric acid residues whose sources derive from borated reactor coolant, and which may have accumulated during the service period preceding the examination. Any recordable indications are evaluated.

The following conditions are considered recordable:

• Leakage from other than locations where leakage is normally expected and collected

• Inoperative leakage collection system Page 17 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I

• Areas of general corrosion

• Corrosion which appears to have reduced the wall thickness by more than 10%

of the component, or which results in a surface transition with less than a 3 to 1 taper. (Rust with no visible thickness (no flaking) is acceptable without further evaluation)

• Any areas of structural distress (i.e., bent hangers, etc.)

• Boric acid residues on ferritic steel (verification of leakage source shall also be recorded)

If leakage occurs at a bolted connection, the corrective measures and the evaluations of ASME Section XI (as modified by NRC approved reliefs) are performed. Components with local areas of general corrosion that reduce the wall thickness by more than 10%

are required to be evaluated by plant engineering. This evaluation will determine whether the component may be acceptable for continued service or whether repair or replacement is required.

TMI Unit 1 uses the corrective action process, specifically the condition report, to determine the acceptability for continued operation when leakage is identified. Within the condition report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the leakage is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For leakage that is determined to be unacceptable repair or replacement is required.

NRC Question

5. Explain the capabilitiesof your program to detect the low levels of reactor coolantpressureboundary leakage that may result from through-wall crackingIn the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or installedleakage detection instrumentation,but has the potentialfor causing boric acid corrosion. The NRC has had concern with the bottom reactorpressure vessel head incore Instrumentationnozzles because of the high consequences associatedwith loss of Integrityof the bottom head nozzles. Describe how your program would evaluate evidence of possible leakage in this Instance. In addition,explain how your program addressesleakage that may impact components that are in the leak path.

Response

As explained in the response to Question No. 1, Item 2, the insulation at the bottom of the reactor vessel lower head stands off of the head surface by approximately six inches at the very bottom of the lower head curvature. Visual examinations of the TMI Unit 1 reactor vessel lower head, scheduled for the Fall of 2003, may require removing Page 18 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I insulation to view the metal surface. Any evidence of leakage from lower head penetrations will be visible.

Reactor coolant water/condensed vapor and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels and the supporting structural carbon steel. The incore penetration instrument tubes, which connect to the Alloy 600 nozzles, are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or opening of the insulation, there are no pressure retaining components beneath the reactor vessel that could be affected.

Plant Technical Specifications require monitoring leakage (including primary-to secondary leakage) from the reactor coolant system (RCS) and the makeup and purification system. This differs from Standard Technical Specifications in that the makeup and purification system is included in the scope of monitoring for TMI Unit 1.

This monitoring is intended to assure that any reactor coolant leakage does not compromise the safe operation of the facility. When the reactor is critical and above two percent power, two reactor coolant leakage detection systems of different operating principles are required to be in operation for the reactor building in accordance with Technical Specification 3.1.6, with one of the two systems sensitive to radioactivity.

These systems include containment radiation monitors, mass balance calculations, reactor building sump level monitoring and reactor building humidity monitors. The primary method used at TMI Unit I for quantifying RCS and makeup and purification system leakage is the mass balance calculation.

During power operations, containment radiation monitors, reactor building sump level instruments and reactor building humidity monitors are generally in service continuously.

Mass balance calculations are required to be performed daily. These calculations are normally performed over a two-hour period and are calculated by the plant process computer. The accuracy of this calculation allows identification of changes in leakage rates of less than 0.1 gpm.

Plant Technical Specifications also require that if the total reactor coolant leakage rate exceeds ten gpm, the reactor is to be placed into hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. If unidentified reactor coolant leakage (excluding normal evaporative losses) from the RCS pressure boundary exceeds one gpm or if any reactor coolant leakage is evaluated as unsafe, the reactor is required to be placed into hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. The unidentified leakage limit of one gpm is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a matter of hours, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

Unexpected changes in the trend of the measured leak rate are identified and dispositioned in the corrective action program with subsequent investigation and operability evaluation.

Page 19 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I If a reactor shutdown is required, the rate of shutdown and the conditions of shutdown are determined by a safety evaluation for each case and justified in writing as soon as practicable. Action to evaluate the safety implications of RCS leakage is initiated within four hours of detection. The nature, as well as the magnitude, of the leak is considered in this evaluation. Maintaining exposure of offsite personnel to radiation within the guidelines of 10 CFR 20, "Standards for Protection Against Radiation," is also required within this evaluation. Other factors that are recommended to be included in this evaluation are;

1. Consideration of leakage effects on operation of associated system instrumentation which is important to safety,

2. Consideration of leakage effects on associated system operation during normal and emergency operations,

3. Consideration of leakage effects on the environmental qualification of surrounding equipment which is important to safety,

4. Consideration of restriction of required personnel access to operate or maintain important to safety equipment under normal and emergency conditions,

5. The potential for identified leak to grow to unsafe magnitudes under continued operation, and

6. The effects of boric acid wastage on carbon steel components, piping, supports, etc. To the extent practical evidence of boric acid leakage is not disturbed until engineering has been notified to evaluate the possibility of carbon steel wastage. RCS leakage should be redirected to minimize carbon steel corrosion.

If reactor shutdown is required, the reactor will not be restarted until the leak is repaired or until the problem is otherwise corrected.

NRC Question

6. Explain the capabilitiesof your program to detect the low levels of reactor coolantpressure boundaryleakage that may result from through-wallcrackingIn certain components and configurationsfor othersmall diameternozzles. Low levels of leakage may call Into question reliance on visual detection techniques or Installedleakage detection Instrumentation,but has the potentialfor causing boric acidcorrosion. Describe how your program would evaluate evidence of possible leakage in this instance. In addition,explain how yourprogram addresses leakage that may Impact components that are in the leak path.

Response

See the response to Question Nos. 3 and 5. The visual examination and evaluation procedures at TMI Unit I require that components in the area of a leak be examined and, if necessary, be evaluated.

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I NRC Question

7. Explain how any aspects of your program(e.g., Insulation removal,Inaccessible areas,low levels of leakage, evaluation of relevant conditions)make use of susceptibilitymodels or consequence models.

Response

In 1998, Framatome Technologies completed a study to rank on a relative basis each of the Alloy 600 components for potential failure due to PWSCC. This ranking was performed for each of the B&W Owners Group Plants ("Alloy 600 PWSCC Susceptibility Model, 51-5001951-01, Proprietary, December 16, 1998). However, TMI Unit I currently does not make use of any susceptibility models or consequence models to identify or rank the Alloy 600 component locations. The basis for TMI Unit I inspections of dissimilar metal welds is ASME Section Xl. TMI Unit I continues to monitor the status of the susceptibility predictions through the B&W Owners Group.

NRC Question

8. Provide a summary of recommendationsmade by your reactorvendor on visual Inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken or plan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Babcock & Wilcox (B&VV), the reactor manufacturer, issued Condition Report No.

6014542 on April 1, 2002. This document raised the concern that, while the incore instrumentation nozzles have been ranked low in susceptibility to PWSCC, additional evaluations have ranked the incore nozzles high in failure consequence. B&W recommended that effective visual inspections of the lower reactor vessel head area (OD) be conducted. They also recommended that development of new NDE techniques and repair processes be substantially accelerated. Framatome ANP also issued a Preliminary Report of Safety Concern (PSC) 4-02, related to the chemical samples taken at Davis-Besse associated with potential IMI nozzle leakage, in a letter to the B&W Owners Group Members, dated October 11, 2002. This letter reiterated the recommendation that based on the current state of qualified non-destructive examination (NDE) techniques and accessibility concerns, a bare metal visual examination of the IMI nozzle/lower reactor vessel head interface area should be performed at the earliest opportunity.

Based on this and other recommendations, TMI Unit 1 is planning to install a camera above the insulation to visually inspect the bare metal around the incore instrumentation nozzle penetrations during the refueling outage currently scheduled for October 2003 (TI R1 5). TMI Unit I is currently evaluating the development and use of new NDE Page 21 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Based on this and other recommendations, TMI Unit I is planning to install a camera above the insulation to visually inspect the bare metal around the incore instrumentation nozzle penetrations during the refueling outage currently scheduled for October 2003 (TI R1 5). TMI Unit 1 is currently evaluating the development and use of new NDE techniques and repair processes to support the TIR15 outage inspection. No additional specific recommendations have been provided by the reactor vendor.

NRC Question

9. Provide the basis for concluding that the Inspections and evaluationsdescribed in your responses to the above questions comply with your plant Technical Specifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of Mechanical Engineers(ASME) Code by reference. Specifically, addresshow your boric acid corrosioncontrol programcomplies with ASME Section Xl, paragraphIWA-5250 (b) on correctiveactions. Include a descriptionof the proceduresused to implement the corrective actions.

Response

TMI Unit I Technical Specification Limiting Condition for Operation, (LCO), 3.1.6 states that there shall be no pressure boundary leakage, except steam generator tube leakage, through a nonisolable fault in a reactor coolant system component body, pipe wall, or vessel wall. If pressure boundary leakage is detected, the action statements for this LCO requires that the reactor shall be shutdown and a cool-down to cold shutdown initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. Actions to evaluate the safety implications of reactor coolant system leakage are required to be initiated within four hours of detection.

Compliance with the zero, non-isolable leakage criteria is met by performing Generic Letter 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards" and by monitoring reactor coolant leakage trends using diverse methods (mass balance calculation, radiation monitors, reactor building sump level accumulation and reactor building humidity monitoring), as required by plant-specific technical specifications. In addition, the unidentified leakage limit of one gpm is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a requires that inservice inspection and testing be performed in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, "Inservice Inspection of Nuclear Plant Components."Section XI contains applicable rules for examination, evaluation and repair of code class components, including the reactor coolant pressure boundary.

Page 22 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1 For this, the 3 RD Inservice Inspection Interval, TMI Unit I has implemented the 1995 edition, with 1966 addenda, of ASME Section Xl. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"Ifboric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, TMI Unit I utilizes Technical Specification Surveillance Procedure Nos. 1300-6, "VT-2 Leakage Exams," 1300-6Q, "Leakage Exam for Insulated Bolted Connections," and Administrative Procedure No. ER-AA-335-015, "VT-2 Visual Examination," to control these examinations and any subsequent corrective actions. Corporate Procedure No. ER-AA-335-015, 'V7-2 Visual Examination,"

Paragraph 4.6.1.4 states:

"iffboric acid residues are detected on components, then LOCATE the leakage source and the areasof general corrosion. EVALUATE components with local areasof generalcorrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptable for continued service, or whether repairor replacementis required."

Corporate Procedure No. LS-AA-125, "Corrective Action Program (CAP) Procedure,"

defines the requirements for condition identification, condition review, investigation, and closeout.

Page 23 of 23

Text

Exelon.

An Exelon/British Energy Company www.exeloncorp.com Nuclear AmerGen Energy Company, LLC 200 Exelon Way Exelon Generation Suite 345 4300 Winfield Road Kennett Square, PA 19348 Wanrenville, IL60555 RS-03-007 5928-03-20238 January 21, 2003 United States Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D. C. 20555-0001 Braidwood Station, Units I and 2 Facility Operating License Nos. NPF-72 and NPF-77 NRC Docket Nos. STN 50-456 and STN 50-457 Byron Station, Units I and 2 Facility Operating License Nos. NPF-37 and NPF-66 NRC Docket Nos. STN 50-454 and STN 50-455 Three Mile Island Station, Unit 1 Facility Operating License No. DPR-50 NRC Docket No. 50-289

Subject:

ExelonlAmerGen Response to Request for Additional Information Regarding NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity

References:

(1) Letter from J. A. Benjamin (Exelon Generation Company, LLC) to NRC, dated May 17, 2002 (2) Letter from Mahesh Chawla (NRC) to John L. Skolds (Exelon Generation Company, LLC), dated November 20, 2002 (3) Letter from Timothy G. Colbum (NRC) to John L. Skolds (AmerGen Energy Company, LLC), dated November 21, 2002 On March 18, 2002, the NRC issued Bulletin 2002-01, *Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity.' The Bulletin Included a request for the basis for concluding licensees' boric acid inspection programs meet the requirements of Generic Letter 88-05, "Bodc Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components In PWR plants." Reference I provided the requested Information for Braidwood and Byron Stations and Three Mile Island Station, Unit 1. The NRC concluded that additional information is necessary to complete their review and requested additional information, relative to the specificity of the boric acid corrosion control programs, be provided within sixty days of receipt of the letters (i.e., References 2 and 3). The requested additional Information Is attached and as suggested In Reference 1, each of the attributes Identified for an Improved boric acid corrosion control program were considered in the preparation of the attached responses.

-AC15

January 21, 2003 U. S. Nuclear Regulatory Commission Page 2 Attachments I and 2 to this letter provide the Exelon Generation Company, LLC response for Braidwood Station, Units 1 and 2, and Byron Station, Units I and 2, respectively. Attachment 3 provides the AmerGen Energy Company, LLC response for Three Mile Island Station, Unit 1.

These responses are due to the NRC January 21, 2003.

The following table identifies commitments made in this document. Any other actions discussed in the submittal represent intended or planned actions. They are described to the NRC for the NRC's information and are not regulatory commitments.

COMMITMENT COMMITED DATE OR "OUTAGE" Braidwood Station will comply with the recent Material Not Applicable Reliability Project (MRP) recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the Electric Power Research Institute (EPRI) PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002 Byron Station will comply with the recent MRP Not Applicable recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PMMP Steering committee, dated December 2, 2002 Three Mile Island Station, Unit I is planning to install a During the refueling camera above the insulation to visually inspect the bare outage currently metal around the incore instrumentation nozzle scheduled for October penetrations. 2003 (T1 R1 5).

Ifyou have any questions or desire additional information regarding this letter, please contact Don Cecchett at (630) 657-2826.

Respectfully, Respectfully, Vice President, Vice President, Licensing and Regulatory Affairs Licensing and Regulatory Affairs Exelon Generation Company, LLC AmerGen Energy Company, LLC Attachments: Attachment 1, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Attachment 2, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Attachment 3, Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1

ATTACHMENT I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Exelon Generation Company, LLC

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 On November 20, 2002, the NRC issued a request for additional information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was requested within 60 days receipt of the RAI.

1. Provide detailedinformation on, and the technical basis for, the inspection techniques,scope, extent of coverage, and frequency of Inspections,personnel qualifications,and degree of insulationremoval for examination of Alloy 600 pressure boundarymaterialand dissimilarmetal Alloy 82/182 welds and connections In the reactorcoolantpressureboundary (RCPB). Include specific discussion of inspection of locations where reactorcoolantleaks have the potentialto come in contact with and degrade the subject material(e.g., reactor pressurevessel (RPV) bottom head).

Response

The following is a listing of the requested information regarding the Alloy 600 pressure boundary material and dissimilar metal Alloy 82/182 welds and locations in the Braidwood Station, Unit I and Unit 2 reactor coolant pressure boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. These items include, In the steam generators, the steam generator tubing, the tube sheet cladding, the primary head divider plate and attachment welds, the primary nozzle closure rings and closure ring welds. For the reactor pressure vessels (RPVs), the core support guide lugs and welds, six per RPV, are not included in the list. The RPV flange o-ring leakage monitoring tube is not included on the list because it is not exposed to the temperature and pressure conditions that facilitate primary water stress corrosion cracking (PWSCC).

Also not listed are the Alloy 690 materials and Alloy 52/152 weld materials in the Braidwood Station, Unit I replacement steam generators. Installed In the Fall of 1998, the Unit 1 steam generators do not contain any Alloy 600 or Alloy 82/182 materials.

The American Society of Mechanical Engineers ASME Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. Braidwood Station, currently in the 2 rd Inservice Inspection Interval, is committed to the 1989 Edition, no addenda, of ASME Section XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of Braidwood Station's commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in pressurized water reactor (PWR) Plants."

Page 1 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 The ASME Section XI and GL 88-05 requirements for visual examinations conducted at Braidwood Station to locate evidence of leakage from pressure retaining components are contained in procedure ER-AA-335-015, "VT-2 Visual Examination."

In addressing the extent of coverage, ER-AA-335-015 states:

"4.4.4. PERFORM VT-2 examination as close to the component as possible, even though the examination is essentiallyhands-off.

1. USE existing ladder(s), scaffolding, etc. to reduce the examination distance or to maximize examined surface areasif permitted by plant conditions (such as safety or health physics). INSTALLATION of ladder(s)or scaffolding for the sole purpose of conducting the VT-2 examinationsis not required.

2. If permittedby plant conditions (such as safety or health physics), then CONSIDER the use of remote optical aids to reduce the examination distance or to maximize examined surface areas."

This procedure does not specify examination details for specific components in the RCPB and associated systems, but rather provides general requirements applicable to all examined areas.

ER-AA-335-015 requires that accessible external surfaces of pressure retaining components be examined for evidence of leakage including evidence of boric acid accumulations from borated systems. If the components are inaccessible for the direct VT-2 examination, the procedure requires that the surrounding area, including floor area or equipment surfaces located underneath the components, be examined.

The procedure does not require that insulated components be de-insulated to perform a VT-2 examination. The procedure states that for insulated components, accessible and exposed insulation surfaces, including each insulation joint, be examined. For essentially vertical surfaces, the insulation at the lowest elevation where leakage may be detectable must be examined. Also, the surrounding area, including floor areas or equipment surfaces located underneath the component, is examined for evidence of leakage. The procedure requires that examiners give particular attention to discoloration of residue on surfaces in order to detect evidence of boric acid accumulations from borated reactor coolant leakage.

While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require Insulation removal.

In summary, the components listed in the following table are examined using ASME Section XI and ER-AA-335-015 requirements. These requirements address the technical basis for the scope, inspection technique, inspection frequency, personnel qualifications, and, in general, extent of coverage.

Page 2 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Usting IRom Unit Component Inspection Personnel Extent of Frequency Degree of CorrectIve Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type I I RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams The Insulation is not No corrective actions welds (4 hot leg safe-ends, for Leakage (VT-2) by Certified Level II by looking for are performed twice removed for the required to date.

4 cold leg safe-ends, 8 or III VT-2 evidence of leakage each refuel outage: VT-2 examinations.

total) Examiners. Results around the pipe first, in Mode 3 reviewed by insulation joints and going into the The insulation is a Certified Level III along the annulus outage after cycle stainless steel Examiners. of the piping operation at a reflective (mirror) penetration, pressure and design. There are temperature at or 3, 120 *"segments slightly less than buckled around the normal operating pipe-nozzle OD.

conditions, and then again In Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Exams performed 100% of the risk Once per ISI Insulation Is not (ultrasonic) by Certified Level II Informed ISI Interval. Last removed for this examination of the or IIIultrasonic examination examined in the exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1997. performed from the welds. In EPRI TR-112657 pipelnozzle Inner Rev. B-A, *Revised diameter with an Risk Informed automated Inservice Inspection Inspection tool.

Evaluation Procedure.'

Page 3 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material ListingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 2 1 RPV head penetrations 79 Previous VT-2 Exams performed VT-2 examinations The VT-2 exams Insulation Is No corrective total exams performed by Certified Level II have been are performed twice removed as actions required to

-53 Control Rod Drive with the RPV head or III VT-2 performed on the each refuel outage: necessary to date.

Mechanisms (CRDMs) Insulation in-place. Examiners. Results accessible areas of first, in Mode 3 facilitate the BMV

-2 Reactor Vessel Level reviewed by the head. going into the exam.

-5Indication System (RVLIS) thermocouple Bare metal visual Certified Level III outage after cycle

- 18 spare VHPs Examiners. These exams are operation at a Peripheral vertical (BMV) inspection conducted on the pressure and and horizontal

-I1head vent using specific RPV head with the temperature at or panels are Inspection shroud assembly slightly less than designed for guidelines have access doors normal operating removal.

been developed opened and the conditions, and and will be RPV head then again In Mode The RPV head Implemented. Insulation In-place. 3 coming out of the insulation is a outage at normal series of 3 thick operating mirror Insulation temperature and panels. The pressure with a 4 Insulation Is hour hold time. Installed in a flat field across the top ABMV exam Is of the RPVhead scheduled for the and Is stepped Spring of 2003. The down as it extent and approaches the frequency of outer perimeter of additional the RPV head.

examinations to be In accordance with fMRP.

Page 4 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units i and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 3 1 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is For previous No corrective instrumentation exams performed by Certified Level II has been performed each exams, the actions required to penetrations (58 total) with the RPV lower or IIIVT-2 performed with refuel outage or insulation has not date.

head Insulation In- Examiners. Results RPV lower head during a forced been removed.

place. reviewed by insulation In-place outage of sufficient Certified Level III looking for leakage duration. The insulation at Examiners. at insulation joints, the bottom of the The examination is RPV is a flat, performed at horizontal deck of operating pressure stainless steel and temperature, mirror panels. The with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold deck stands off time, beneath the from the bottom of RPV. the lower head providing a clearance of 8". The center panels are fixed around the 58 in-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 5 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units 1 and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 4 1 Pressurizer surge nozzle to Volumetric Exams performed 1000% of the risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) by certified Level II informed ISI Interval. Last been, and will be, actions required to examination of the or III ultrasonic examination examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1997. volumetric weld. in EPRI TR-1 12657 examination.

Rev. B-A, "Revised Risk Informed The Insulation is Inservice Inspection part of the Evaluation pressurizer lower Procedure." head insulation arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation Is not by Certified Level II by looking for are performed twice removed for the VT or IIIVT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe first, in Mode 3 reviewed by insulation joints, going Into the The Insulation is Certified Level III along the surge line outage after cycle part of the Examiners. piping and on the operation at a pressurizer lower containment floor pressure and head Insulation beneath the temperature at or arrangement. There pressurizer surge slightly less than are 4 segments nozzle, normal operating enclosing the surge conditions, and nozzle. The panels then again In Mode are stainless steel, 3 coming out of the mirror panels with outage at normal buckled snaps for operating removal.

temperature and pressure with a 4 fhour hold time.

Page 6 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braldwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 5 1 Pressurizer spray nozzle to Volumetric E~xams perforrned Informed ISI Interval. Last been, and will be, actions required to safe-end weld (1 weld) (ultrasonic) by certified Level II examination of the or III ultrasonic examination examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Fall of 1998. volumetric weld. in EPRI TR-1 12657 examination.

Rev. B-A, 'Revised Risk Informed The Insulation Is Inservice Inspection part of the Evaluation pressurizer head Procedure.* insulation arrangement. There are 2 semi-circular, fiat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I I _____________ .1 VT-2 Exam performed by Exam is performed -r The VT-2 exams --I-The Insulation Is not Certified Level II or by looking for are performed twice removed for the VT IIIVT-2 Examiners. evidence of leakage each refuel outage: 2 examinations.

Results reviewed around the nozzle first, In Mode 3 by Certified Level III to pipe Insulation going Into the The Insulation is Examiners. joint. outage after cycle part of the operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less than are 2 semi-circular, normal operating flat panels conditions, and enclosing the spray then again In Mode nozzle. The panels 3 coming out of the are 4' thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

I I ______________________ II I I I hour hold time.

Page 7 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI item Unit Component Inspection Personnel Extent of Frequency Degree of Insulation Corrective Action Techniques Qualifications Coverage Removal!

Insulation Type

-6 1 Pressurizer relief valve volumetric iExams pernormed II by certified Level informed ISI Interval. Last been, and will be, actions required to nozzle to safe-end weld (I (ultrasonic) removed for the date.

examination of the or III ultrasonic examination examined In the weld) Fall of 1998. volumetric nozzle to safe-end Examiners. volume, Figure 4-9 weld. inEPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The insulation is Inservice Inspection part of the Evaluation pressurizer head Procedure." insulation arrangement. There are 4 segmented, fiat panels endosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I .1 ______________

-r-The exams VT-2 exams T The insulation Isnot VT-2 Exam performed by Exam is performed The VT-2 -- The Insulation for theIs VT not Certified Level IIor by looking for are performed twice removed III Vr-2 Examiners. evidence of leakage each refuel outage: 2 examinations.

Results reviewed around the pipe to first, in Mode 3 by Certified Level III nozzle Insulation going Into the The Insulation Is Examiners. joint. outage after cycle part of the operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less then are 4 segmented, normal operating fiat panels conditions, and enclosing the relief then again in Mode nozzle. The panels 3 coming out of the are 4" thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time.

I I 1 1: 1 1 I _______________________________ ______________________ .1_______________________ J _______________________ _______________________

Page 8 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removalc Insulation Type 7 1 Pressurizer safety valve Volumetric Exams performed 100%of0the risk Once per 1513 Interval. Two of the been, and will be. actions required to nozzle to safe-end weld (3 (ultrasonic) by certified Level II Informed ISI examination of the or III ultrasonic examination welds were removed for the date.

welds) volumetric nozzle to safe-end Examiners. volume, Figure 4-9 examined In the welds. in EPRI TR-112657 Sping of 1994, and examination.

Rev. B-A, Revised the third weld was Risk Informed examined in the The Insulation is Inservice Inspection Fall of 1995. part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, flat panels enclosing each of the safety valve nozzies. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

________ 1 4 - .4 The VT-2 exams -r The insulation is not VT-2 Exams performed Exam Is performed removed for the VT by Certified Level II by looking for are performed twice or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going Into the The Insulation Is Certified Level III joints. outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing each of then again in Mode the safety valve 3 coming out of the nozzles. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

_______________________________ +/- ______________________ .1 J _______________________

Page 9 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 8 2 RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams The Insulation Is not No Corrective welds (4 hot leg safe-ends, for leakage (VT-2) by Certified Level II by looking for are performed twice removed for the VT- actions required to 4 cold leg safe-ends, 8 or Ill VT-2 evidence of leakage each refuel outage: 2 examinations, date.

total) Examiners. Results around the pipe first. In Mode 3 reviewed by Insulation Joints and going into the The Insulation Is a Certified Level III along the annulus outage after cycle stainless steel Examiners. of the piping operation at a reflective (mirror) penetration. pressure and design. There are temperature at or 3, 1200 segments slightly less than buckled around the normal operating pipe nozzle OD.

conditions, and then again In Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation Is not (ultrasonic) (UT) Level II or Ill Informed ISI Interval. Last removed for this examination of the Examiners. examination examined In the exam. The exam Is nozzle to safe-end volume, Figure 4-9 Fall of 1997. performed from the welds. in EPRI TR-112657 pipelnozzle Inner Rev. B-A, "Revised diameter with an Risk Informed automated Inservice Inspection Inspection tool.

Evaluation Procedure."

Page 10 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braidwood Station RCPB Alloy Material ListingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 9 2 RPV head penetrations A Bare Metal Visual Exams performed BMV of the RPV The BMV exam Insulation Is No corrective (VHP) 79 total (BMV) using VT-2 by Certified Level II head surface and a was performed in removed as actions required to

- 53 CRDMs techniques was or III VT-2 360 degree view of the Spring of 2002. necessary to date. In addition,

- 2 RVLIS performed in Spring Examiners. Results all VHPs with slight The extent and facilitate the BMV for the Spring 2002

-.5 Thermocouple 2002. Specific reviewed by obstruction of the frequency of exam. examination, there

- 18 spare VHPs inspection Certified Level III head vent additional were no corrective

- I head vent guidelines were Examiners. penetration, examinations to be Peripheral vertical actions taken as developed and in accordance with and horizontal there was no Implemented. MRP. panels are evidence of leakage designed for on the RPV head Previous VT-2 removal, surface and no exams performed RPV head with the RPV head The RPV head degradation was Insulation In-place. Insulation is a identified.

series of 3' thick mirror insulation panels. The Insulation is Installed in a flat field across the top of the RPV head and is stepped down as it approaches the outer perimeter of the RPV head.

Page 11 of 25

Attachment 1 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units 1 and 2 Braldwood Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 10 2 RPV lower head In-core Previous VT-2 Exams performed The examination The examination Is For previous No corrective Instrumentation exams performed by Certified Level II has been performed each exams, the actions required to penetrations (58 total) with the RPV lower or IIIVT-2 performed with refuel outage or Insulation has not date.

head insulation In- Examiners. Results RPV lower head during a forced been removed.

place. reviewed by Insulation In-place outage of sufficient Certified Level III looking for leakage duration. The insulation at Examiners. at insulation joints, the bottom of the The examination Is RPV Is a flat, performed at horizontal deck of operating pressure stainless steel and temperature, mirror panels. The with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold deck stands off time, beneath the from the bottom of RPV. the lower head providing a clearance of 8". The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 12 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 11 2 Pressurizer surge nozzle to Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT) Level IIor III Informed ISI Interval. Last been, and will be. actions required to examination of the Examiners. examination examined In the removed for the date.

nozzle to safe-end volume, Figure 4-9 Fall of 1997. volumetric welds. in EPRI TR-1 12657 examination.

Rev. B-A, *Revised Risk Informed The insulation is Inservice Inspection part of the Evaluation pressurizer lower Procedure." head insulation arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed twice removed for the VT or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe first, in Mode 3 reviewed by Insulation joints, going Into the The insulation is Certified Level III along the surge line outage after cycle part of the Examiners. piping and on the operation at a pressurizer lower containment floor pressure and head Insulation beneath pressurizer temperature at or arrangement. There surge nozzle. slightly less than are 4 segments normal operating enclosing the surge conditions, and nozzle. The panels then again in Mode are stainless steel, 3 coming out of the mirror panels with outage at normal buckled snaps for operating removal.

temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Page 13 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 12 2 Pressurizer spray nozzle to Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT) Level IIor III Informed ISI interval. Last been, and will be, actions required to examination of the Examiners. examination examined In the removed for the date.

nozzle to safe-end volume, Figure 4-9 Spring of 1999. volumetric welds. inEPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The Insulation is Inservice Inspection part of the Evaluation pressurizer head Procedure." insulation arrangement. There are 2 semi-circular, flat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed twice removed for the VT or IIIVT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going into the The insulation is Certified Level III joint, outage after cycle part of the Examiners. operation at a pressurizer head pressure and insulation temperature at or arrangement. There slightly less than are 2 semi-circular, normal operating fiat panels conditions, and enclosing the spray then again InMode nozzle. The panels 3 coming out ofthe are 4' thick outage at normal stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time. _I_ I _I Page 14 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Braldwood Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Typed Votumetric ulnasonM nenrna *..midatinn has Nocrelv 13 2 Pressurizer relief valve Cl.ertified Ultrasonic (UT) Level II or III 100%/oftle Informed ISI 1R1sk Interval. Last been. and will be, actions required to nozzle to safe-end weld (1 (ultrasonic) removed for the date.

examination of the Examiners. examination examined In the weld) Sping of 1999. volumetric nozzle to safe-end volume, Figure 4-9 in EPRI TR-112657 examination.

welds.

Rev. B-A. "Revised Risk Informed The insulation Is Inservice Inspection part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

I -- I ___________________________ I

-r I

-r-The insulation The Insulation Isnot VT-2 Exams performed by Certified Level II Exam is performed by looking for The Vr-2 exams are performed twice removed for theIs VTnot or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, in Mode 3 reviewed by nozzle insulation going Into the The Insulation is Certified Level III joint. outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing the relief then again In Mode nozzle. The panels 3 coming out of the are 4' thick outage at normal stainless steel.

operating minror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time.

I I I II ________________

I I ________________

I Page 15 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braidwood Station RCPB Alloy Material UstingI Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Techniques Qualifications Coverage Insulation Removal/

Insulation Type Volumetric Certified Ultrasonic 100% of the Risk Once per ISI Insulation has No corrective 14 2 Pressurizer safety valve (ultrasonic) (UT) Level II or III Informed ISI Interval. Two of the been, and will be, actions required to nozzle to safe-end weld (3 examination of the Examiners. examination welds were removed for the date.

welds) nozzle to safe-end volume, Figure 4-9 examined In the volumetric welds. In EPRI TR-112657 Fall of 1994, and examination.

Rev. B-A. "Revised the third was Risk Informed examined In the The insulation Is Inservice Inspection Spring of 1996. part of the Evaluation pressurizer head Procedure." Insulation arrangement. There are 4 segmented, fiat panels enclosing each of the safety nozzles.

The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams The Insulation Is not by Certified Level II by looking for are performed twice removed for the VT or III VT-2 evidence of leakage each refuel outage: 2 examinations.

Examiners. Results around the pipe to first, In Mode 3 reviewed by nozzle Insulation going Into the The Insulation Is Certified Level III joints, outage after cycle part of the Examiners. operation at a pressurizer head pressure and Insulation temperature at or arrangement. There slightly less than are 4 segmented, normal operating flat panels conditions, and enclosing each of then again in Mode the safety nozzles.

3 coming out of the The panels are 4' outage at normal thick stainless steel, operating mirror panels with temperature and buckled snaps for pressure with a 4 removal.

hour hold time. _I Page 16 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Braldwood Station RCPB Alloy Material UstingI Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Component Techniques Qualifications Coverage Insulation Removal/

Insulation Type A visual using direct Exams performed The drain line, The direct visual The insulation Is No corrective 15 2 Steam generator primary actions required to head drain lines (4 total) VT-2 techniques by Certified Level II weld, and lower examination Is removed to was performed In VT-2 Examiners. head surface performed each facilitate the date.

the Spring of 2002 around the drain time the steam examination.

on 2 of the 4 steam line were examined generator primary generator drain for steam channel head Is de- The Insulation lines and generators A and insulated, (typically around the steam surrounding head C.. for eddy current generator lower surface. inspection). head is a series of removable stainless Previous VT-2 steel mirror panels.

exams performed The bottom panel Is with the steam a horizontal disc generator lower that is set off of the head Insulation In- steam generator place. head and encloses the head, the drain line, and the drain line isolation valve.

Page 17 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2

2. Provide the technical basis for determiningwhether or not Insulation is removed to examine all locations where conditionsexist that could cause high concentrationsof boric acid on pressureboundarysurfaces or locations that are susceptible to primary waterstress corrosioncracking (Alloy 600 base metal and dissimilarmetalAlloy 82/182 welds). Identify the type of insulationfor each component examined, as well as any limitationsto removal of Insulation. Also include In your response actions involving removal of insulation requiredby your proceduresto Identify the sourceof leakage when relevantconditions (e.g., rust stains,boric acid stains,or boric acid deposits)are found.

Response

Except for bolted connections on borated ASME Section XI Class 1, 2 and 3 systems discussed below, Braidwood Station procedures do not require that insulated RCPB components be de insulated to perform VT-2 examinations. The basis for this has been that leakage from RCPB components should be detectable at insulated joints or surrounding areas given that the systems have been at normal pressure for, in most cases, a full operating cycle. While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In general, Braidwood Station ASME Section XI Class 1, 2, and 3 components in the containment containing borated water, if insulated, have removable stainless steel reflective style insulation. Outside the containment, blanket insulation is used. Most insulation is removable, but there are exceptions. The insulation panels around the incore instrumentation guide tubes at the bottom of the RPV lower head are not intended to be removed. A set of peripheral horizontal panels are buckled in place and can be removed for access to the incore instrumentation guide tubes at the bottom of the RPV lower head. The horizontal panels around the VHPs are not removable; however, the side vertical panels are removable. The specific style of insulation for other locations in the RCPB is listed in the table in the response to Question 1.

Bolted Connections Insulated bolted connections in the RCPB (i.e., ASME Section XI, Class 1) and in borated ASME Section XI Class 2 and Class 3 support systems have insulation removed in order to perform ASME section XI VT-2 examinations. The scope includes bolted connections that are installed in systems that are borated for the purpose of controlling reactivity. The ASME Section XI requirements on the extent of insulation removal and the plant conditions under which the insulation is removed have been modified by Braidwood Station Inservice Inspection Relief Requests 12R-12 and 12R-30. Both of these alternatives to ASME Section XI requirements have been authorized for use at Braidwood Station by the NRC.

Relief Request 12R-12 allows for insulation removal and the performance of the VT-2 exam on bolted connections in borated systems to be performed with the system depressurized. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examination. Additionally, for ASME Section XI Class 2 and 3 borated systems, VT-2 examinations are performed on approximately 36 month Page 18 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 frequencies, which coincides with plant refueling outages, not allowing the period between inspections on individual components to exceed 45 months. This frequency for individual components is more restrictive than the "Periodic Frequency" allowed by ASME Section XI for Class 2 and 3 systems described in tables IWC-2500 or IWD-2500.

Relief Request 12R-30 allows the removal of insulation from certain ASME Section XI, Class 1 valves for VT-2 examination to be performed on an extended frequency. The insulation is removed from the bolted connections and a VT-2 examination is conducted, with the system depressurized, on a once per 10 year interval frequency. These valves are also VT-2 examined with the insulation installed after a minimum four hour hold time at normal operating pressure at the end of each refueling outage and in Mode 3 during shutdown for each refueling outage.

Dissimilar Metal Welds Insulated dissimilar metal welded piping connections that contain Alloy 82/182 are typically not de-insulated for VT-2 examinations. A list of these nozzle to safe-end welds and the type of insulation is provided in the table in the response to Question 1. Examinations of these areas are performed in response to GL 88-05 and are conducted in Mode 3 going into an outage, typically, after a cycle of operation. Therefore, an adequate time is allowed for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The eight RPV nozzle to safe-end welds are considered inaccessible to perform direct VT-2 examination. The welds are located in an area between the concrete RPV shield wall and the concrete primary shield wall. This area enclosing the RPV nozzles and connected piping is referred to as the "sand box" area. The sand box area is only accessible from above, from the refueling cavity floor, by removing normally sealed steel plates. The normal technique for viewing potential leakage in this area is to look along the reactor coolant piping as it passes though the annulus of the bio-shield wall towards the RPV. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints inside the annulus. The RPV nozzle to safe-end weld insulation is not routinely removed since the sand box area is considered a high dose, confined space.

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluatingthe potentialfor leakage In Inaccessibleareas. In addition, describethe degree of Inaccessibility,and identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessibleareas.

Response

For the RCPB components, Braidwood Station personnel perform walkdowns during refueling outages, forced outages and, depending on circumstances, during power operations. Typical at-power containment walkdowns of accessible areas for leakage would be initiated at the request of the Operations Department Ifunidentified leakage was trending up or at the request of Radiation Protection personnel ifthere was an unexpected Increase in containment atmosphere gas or particulate levels. For at-power walkdowns, the area of interest may be limited for as low as reasonably achievable (ALARA) considerations. VT-2 certified personnel Page 19 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 perform the walkdowns during refueling outages and, in most cases, during forced outages and at power operations.

As described in the response to Question 2, the areas considered inaccessible are the "sand boxes" which enclose the eight RPV nozzles. Leakage from these areas is identified by visual examination along the horizontal surface of the insulated piping as it passes through the concrete annulus.

Braidwood Station uses a containment floor drain sump and a reactor cavity sump to collect, measure and record unidentified leakage in accessible and inaccessible areas in the containment. Both of these sumps are instrumented to identify leakages of 1.0 gpm within one hour and are recorded and alarmed in the main control room. The containment floor drain and reactor cavity sump inputs are checked each shift. A reactor coolant system (RCS) mass balance is performed when unidentified leakage is suspected and at the prescribed Technical Specification intervals. This provides early indication to the operator of potential unidentified leakage. Also, the reactor makeup control system is used to maintain proper reactor coolant inventory, volume control tank (VCT) level is continuously recorded and quantities of boric acid and makeup water injected are totaled and flow rates recorded in the control room.

The reactor coolant contains radioactivity that, when released to the containment, can be detected by radiation monitoring instrumentation. Radioactivity detection systems are used for monitoring both particulate and gaseous activities and can be used to identify RCS leakage.

The detection of RCS leakage using radiation monitors depends on the concentration of radioactivity in the RCS and detector background count rate.

Air temperature and pressure monitoring methods may also be used to infer unidentified leakage to the containment. Although containment temperature and pressure fluctuate slightly during unit operation, a rise above the normally indicated range of values may indicate RCS leakage into the containment.

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections), to demonstrate that continued operation with the observed leakage is acceptable. Also describe the acceptance criteriathat was establishedto make such a determination. Provide the technical basis used to establish the acceptance criteria. In addition,

a. if observed leakage Is determined to be acceptablefor continued operation, describe what inspection/monitoringactions are taken to trend/evaluatechanges in leakage, or

b. ff observedleakage Is not determined to be acceptable, describe what corrective actionsare taken to addressthe leakage.

Response

Braidwood Station personnel use engineering procedure BwVP 200-11, "Evaluation of ASME Section Xl Class 1, 2, and 3 Bolted Connections." This procedure describes the requirements Page 20 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 and instructions for the evaluation of ASME Section XI Class 1, 2, and 3 bolted connections when external leakage is detected. The procedure provides instructions for the corrective actions that must be implemented in the event the structural integrity of any ASME Section XI Class 1, 2, or 3 bolted connection is determined to be suspect.

When evidence of leakage is identified from a bolted connection, the procedure requires an evaluation to be performed. This evaluation considers the location of the leak, leak rate, extent of deposit accumulation, extent of wastage, corrosiveness of process fluid, materials, length of time bolting has been in service and the effect on other structures or components. A condition report is initiated for non-conforming conditions and a recommendation for repair, replacement, or monitoring is provided. Active leakage from the RCS is repaired prior to completing a refuel outage.

The bases for the evaluation/determination criteria of BwVP 200-11 are derived from the provisions of Braidwood Station Inservice Inspection Relief Request 12R-1 3. This request was approved by the NRC.

Braidwood Station personnel use the corrective action process, specifically a condition report, to determine the acceptability for continued operation when a non-conforming condition is identified. Within the condition report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the non-conforming condition is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For a non-conforming condition that is determined to be unacceptable, repair or replacement is required.

5. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wallcracking in the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or Installedleakage detection instrumentation,but has the potentialfor causingboric acid corrosion. The NRC has had a concern with the bottom reactorpressurevessel head incore instrumentation nozzles because of the high consequences associatedwith loss of integrity of the bottom head nozzles. Describe how your program would evaluate evidence of possible leakage in this Instance. In addition,explain how your programaddresses leakage that may impact components that are in the leak path.

Response

As explained in the table in the response to Question 1, items 3 and 10, the insulation at the bottom of the RPV lower head stands off of the head surface by a minimum of eight inches at the very bottom of the lower head curvature. Visual examinations of the Braidwood Station, Unit 1 and Unit 2 RPV lower head, scheduled for the Spring of 2003 and Fall of 2003, respectfully, will require removing insulation panels to view the metal surface. Any leakage from lower head penetrations would be visible.

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Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 Reactor coolant and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels. The incore penetration instrument tubes that connect to the nozzles are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or openings of the insulation, there are no pressure retaining components beneath the RPV that could be affected. This leakage from the RPV bottom head nozzles would collect in the reactor cavity sump described in the response to Question 3. The reactor cavity sump input is recorded each shift and abnormal readings are required to be reported to the Shift Manager. This notification would result in an evaluation and a condition report would be initiated, as necessary.

6. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundary leakage that may result from through-waltcracking in certain components and configurationsfor othersmall diameternozzles. Low levels of leakage may call into question relianceon visual detection techniques or Installedleakage detection instrumentation,but has the potentialfor causingboric acid corrosion.

Describehow your program would evaluate evidence of possible leakage In this instance. In addition,explain how your programaddressesleakage that may impact components that are In the leak path.

Response

The leakage detection capabilities at Braidwood Station were discussed in the response to Questions 3 and 5 above. The visual examination and evaluation procedures at Braidwood Station require that components in the area of a leak be examined and evaluated. In the case of Braidwood Station, the vast majority of components in the RCPB are stainless steel.

7. Explain how any aspects of your program (e.g., insulationremoval, Inaccessibleareas, low levels of leakage, evaluation of relevant conditions)make use of susceptibility models or consequence models.

Response

Vessel Head Penetrations (VHP)

Braidwood Station personnel have based the examination requirements for the Unit I and Unit 2 VHPs on the Electric Power Research Institute (EPRI) Material Reliability Project (MRP) susceptibility model for PWSCC. This ranking (i.e., MRP-48) identifies Braidwood Station, Unit 1 and Unit 2 as "low susceptibility" plants rated 640 and 65th, respectively, out of the 69 PWR units in the study. As of January 1, 2003, the Braidwood Station, Units have an effective degradation year (EDY) value of 1.6 putting the Units in the lowest of the three susceptibility categories established by the NRC in Bulletin 2002-02, "Reactor Pressure Vessel Head and RPV Head Penetration Nozzle Inspection Programs."

Because of this lower susceptibility, Braidwood Station personnel perform qualified, effective bare metal visual (BMV) inspections of the RPV head surface and VHPs. The BMV inspection for Braidwood Station, Unit 2 was completed in the Spring of 2002 with no evidence of VHP leakage found. The BMV inspection for Braidwood Station, Unit I is scheduled for the Spring of 2003.

Page 22 of 25

Attachment 1 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Steam Generator Drain Lines As listed in the table in the response to Question 1, the steam generator primary head drain lines for Braidwood Station, Unit 2 are made of Alloy 600 and Alloy 82/182 materials. The bottom surface of the steam generator primary head, the 3/8" drain lines and drain line isolation valves are enclosed in the lower head insulation package. Based on a susceptibility model developed by Westinghouse, Braidwood Station is visually examining the four Unit 2 drain lines whenever the steam generator lower head insulation package is removed to support the eddy current testing of the steam generator tubing.

In the last Unit 2 refueling outage in the Spring of 2002, the "A" steam generator was eddy current tested and therefore the lower head surface and drain line were visually examined.

There were no recordable indications, no signs of boric acid deposits or any degradation of the carbon steel lower head surface.

In addition, in the GL 88-05 walkdown performed in Mode 3 during a plant shutdown in the Spring of 2002, boric acid deposits were identified along the seam of the bottom horizontal insulation panel of the NC" steam generator lower head. As required by examination procedure and the corrective action process, the insulation was removed to investigate the source and extent of the leakage. The lower head surface and drain line of the "C"steam generator were visually examined. There were no signs of boric acid deposits on the steam generator lower head or any degradation of the carbon steel surface. The leakage and boric acid deposits were from a leaking drain line isolation valve dripping onto the horizontal insulation panel directly under the drain line. The deposits were cleaned and the valve was repaired.

Based on the recommendations of the susceptibility model, the drain line and the steam generator lower head surface for all four Braidwood Station, Unit 2 steam generators are scheduled for visual examination in the Fall of 2003.

8. Providea summary of recommendationsmade by your reactor vendor on visual inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken or plan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Vessel Closure Head Penetrations As stated above in the response to Question 7, Braidwood Station personnel are following the examination recommendations of the industry effort on the Alloy 600/82/182 issue.

Westinghouse, the reactor vendor, and Babcock & Wilcox, the reactor manufacturer, are part of this industry effort. Based on the lower susceptibility of the Braidwood Station, Unit I and Unit 2 VHP nozzles, the recommended visual examinations are being performed. Braidwood Station personnel have followed all MRP recommendations and will comply with the recent MRP recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002.

Page 23 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braldwood Station, Units I and 2 Reactor Vessel Nozzle Safe-Ends, Reactor Lower Head Nozzles, and Pressurizer Nozzle Safe-Ends The current program for the examination of these components is listed In the table in the response to Question 1. Exelon Nuclear corporate and Braidwood Station personnel are currently working with Westinghouse on developing a comprehensive inspection, repair and/or mitigation program for all Alloy 600/82/182 components in the RCPB.

9. Provide the basis for concluding that the inspectionsand evaluations describedIn your responses to the above questions comply with your plant TechnicalSpecifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of MechanicalEngineers (ASME) Code by reference. Specifically,address how your boric acid corrosioncontrolprogram complies with ASME Section Xi, paragraphIWA-5250 (b) on corrective actions. Include a descriptionof the proceduresused to implement the correctiveactions.

Response

Braidwood Station Technical Specification (TS) Limiting Condition for Operation (LCO) 3.4.13.a states that there shall be no pressure boundary leakage. Pressure bypass boundary leakage is defined as leakage, except steam generator tube leakage, through a non-isolable fault in a reactor coolant system component body, pipe wall, or RPV wall. If pressure boundary leakage is detected, the action statements for this LCO require that the affected unit be in Mode 3 in six hours and be in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The resolution of leakage indications in the corrective action program requires evaluation of the impact on this TS.

Compliance with the zero non-isolable leakage criteria is met by performing GL 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards." In addition, the unidentified leakage limit of one gpm defined in TS LCO 3.4.13.b is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a requires that inservice inspection and testing be performed in accordance with the requirements of ASME Section XI. ASME Section XI contains applicable rules for examination, evaluation and repair of code class components, including the RCPB.

For this, the 2 nd Inservice Inspection Interval, Braidwood Station personnel have implemented the 1989 edition, with no addenda, of ASME Section XI. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"Ifboric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether Page 24 of 25

Attachment I Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Braidwood Station, Units I and 2 the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, Braidwood Station personnel use Exelon Nuclear Procedure ER-AA-335-015, "VT-2 Visual Examination." Paragraph 4.6.1.4 of this procedure states:

"If boric acid residues are detected on components, then LOCATE the leakage source and the areasof generalcorrosion. EVALUATE components with local areasof general corrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptable for continued service, or whether repairor replacementis required."

The Exelon Nuclear procedure LS-AA-125, "Corrective Action Program (CAP) Procedure" defines the requirements for condition identification, condition review, investigation, and closeout.

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ATTACHMENT 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Exelon Generation Company, LLC

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 On November 20, 2002, the NRC issued a request for additional information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was required within 60 days of receipt of the RAI.

1. Providedetailed information on, and the technicalbasis for, the Inspection techniques, scope, extent of coverage, and frequency of inspections,personnel qualifications,and degree of Insulation removal for examinationof Alloy 600 pressureboundarymaterialand dissimilarmetal Alloy 82/182 welds and connections in the reactorcoolant pressureboundary (RCPB). Include specific discussionof inspection of locationswhere reactorcoolant leaks have the potentialto come in contact with and degrade the subject material(e.g., reactor pressure vessel (RPV) bottom head).

Response

The following is a listing of the requested information regarding the Alloy 600 pressure boundary material and dissimilar metal Alloy 82/182 welds and locations in the Byron Station, Unit I and Unit 2 reactor coolant pressure boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. These items include, in the steam generators, the steam generator tubing, the tube sheet cladding, the primary head divider plate and attachment welds, the primary nozzle closure rings and closure ring welds. For the reactor pressure vessels (RPVs), the core support guide lugs and welds, six per RPV, are not included in the list. The RPV flange o-ring leakage monitoring tube is not included on the list because it is not exposed to the temperature and pressure conditions that facilitate primary water stress corrosion cracking (PWSCC).

Also not listed are the Alloy 690 materials and Alloy 52/152 weld materials in the Byron Station, Unit I replacement steam generators. Installed in the Winter of 1997, the Unit 1 steam generators do not contain any Alloy 600 or Alloy 82/182 materials.

The American Society of Mechanical Engineers (ASME)Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. Byron Station, currently in the 2 nd Inservice Inspection Interval, is committed to the 1989 Edition, no addenda, of ASME Section XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of Byron Station's commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants."

Page 1 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 The ASME Section XI and GL 88-05 requirements for visual examinations conducted at Byron Station to locate evidence of leakage from pressure retaining components are contained in procedure ER-AA-335-015, "VT-2 Visual Examination."

In addressing the extent of coverage, ER-AA-335-015 states:

"4.4.4. PERFORM VT-2 examination as close to the component as possible, even though the examination is essentiallyhands-off.

1. USE existing ladder(s), scaffolding, etc. to reduce the examination distance or to maximize examined surface areasif permittedby plant conditions (such as safety or health physics). INSTALLATION of ladder(s) or scaffolding for the sole purpose of conducting the VT-2 examinationsis not required.

2. If permitted by plant conditions (such as safety or health physics), then CONSIDER the use of remote optical aids to reduce the examinationdistance or to maximize examined surface areas."

This procedure does not specify examination details for specific components in the RCPB and associated systems, but rather provides general requirements applicable to all examined areas.

ER-AA-335-015 requires that accessible external surfaces of pressure retaining components be examined for evidence of leakage including evidence of boric acid accumulations from borated systems. If the components are inaccessible for the direct VT-2 examination, the procedure requires that the surrounding area including floor area or equipment surfaces located underneath the components be examined.

The procedure does not require that insulated components be de-insulated to perform a VT-2 examination. The procedure states that for insulated components, accessible and exposed insulation surfaces, including each insulation joint, be examined. For essentially vertical surfaces, the insulation at the lowest elevation where leakage may be detectable must be examined. Also, the surrounding area including floor areas or equipment surfaces located underneath the component is examined for evidence of leakage. The procedure requires that examiners give particular attention to discoloration of residue on surfaces in order to detect evidence of boric acid accumulations from borated reactor coolant leakage.

While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In summary, the components listed in the following table are examined using ASME Section XI and ER-AA-335-01 5 requirements. These requirements address the technical basis for the scope, inspection technique, inspection frequency, personnel qualifications, and, in general, extent of coverage.

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Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal!

Insulation Type I RPV nozzle to safe-end Visual Inspection Exams performed Exam Is performed The VT-2 exams are The Insulation is not No corrective actions welds (4 hot leg safe-ends, for leakage (VT-2) by Certified Level by looking for performed twice each removed for the required to date.

4 cold leg safe-ends. 8 IIor III V`17-2 evidence of refuel outage: first, in VT-2 examinations.

total) Examiners. leakage around the Mode 3 going Into the Results reviewed pipe insulation outage after cycle The Insulation is a by Certified Level joints and along the operation at a stainless steel III Examiners. annulus of the pressure and reflective (mirror) piping penetration. temperature at or design. There are slightly less than 3, 120 *"segments normal operating buckled around the conditions, and then pipe-nozzle OD.

again in Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation Is not (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the removed for this examination of the Level II or III examination Spring of 1996. exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 performed from the welds. in EPRI TR-112657 pipelnozzle Inner Rev. B-A, Revised diameter with an Risk Informed automated Inservice Inspection tool.

Inspection Evaluation Procedure.'

Page 3 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Itemn Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 2 1 RPV head penetrations 79 Previous VT-2 Exams performed VT-2 examinations The VT-2 exams are Insulation is No corrective total exams performed by Certified Level have been performed twice each removed as actions required to

-53 CRDMs with the RPV head IIor ill VT-2 performed on the refuel outage: first, in necessary to date.

-2 RVLIS Insulation in-place. Examiners. accessible areas of Mode 3 going into the facilitate the BMV

-5 Thermocouple

-18 spare VHPs Bare Metal Visual Results reviewed the head. outage after cycle exam.

by Certified Level operation at a

- I head vent (BMV) using III Examiners. These exams are pressure and Peripheral vertical specific Inspection conducted on the temperature at or and horizontal guidelines have RPV head with the slightly less than panels are been developed shroud assembly normal operating designed for and will be access doors conditions, and then removal.

Implemented. opened and the again In Mode 3 RPV head coming out of the The RPV head Insulation in-place, outage at normal Insulation is a operating series of 3" thick temperature and mirror Insulation pressure with a 4 panels. The hour hold time. insulation Is Installed in a fiat A BMV exam Is field across the top scheduled for the Fall of the RPV head of 2003. The extent and is stepped and frequency of down as it additional approaches the examinations to be In outer perimeter of accordance with the RPV head.

MRP.

A partial BMV was completed during the Spring of 2002 on Unit I to verify that no degradation to the head had occurred from a previous leak.

Approximately 80%

of the RPV head was examined with no degradation found.

Page 4 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation RemovalU Insulation Type 3 1 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is Insulation is No corrective instrumentation exams performed by Certified Level has been performed each removed to actions required to penetrations (58 total) with the RPV lower IIor III VT-2 performed with refuel outage or facilitate Mode 5 date.

head Insulation Examiners. RPV lower head during a forced BMV examinations.

panels removed as Results reviewed Insulation removed outage of sufficient necessary to by Certified Level during Mode 5. duration. The insulation at visually exam the IIIExaminers. the bottom of the bottom of the The examination The examinations are RPV is a fiat, vessel and in-core has been performed twice, horizontal deck of nozzles. performed with once during Mode 5 stainless steel RPV lower head and then again at minor panels. The insulation in-place operating pressure deck stands off looking for leakage and temperature, with from the bottom of at Insulation joints, a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time, the lower head beneath the RPV. providing a clearance of 8".

The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

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Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 4 1 Pressurizer surge nozzle to Volumeic Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) Utrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level IIor III examination Spring of 1997. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. In EPRI TR-112657 Not currently included examination.

Rev. B-A, "Revised In risk informed Risk Informed Inspection program The insulation is Inservice scope. part of the Inspection pressurizer lower Evaluation head insulation procedure." arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe Insulation outage after cycle The Insulation Is by Certified Level joints, along the operation at a part of the Ill Examiners. surge line piping pressure and pressurizer lower and on the temperature at or head Insulation containment floor slightly less than arrangement. There beneath normal operating are 4 segments pressurizer surge conditions, and then enclosing the surge nozzle. again In Mode 3 nozzle. The panels coming out of the are stainless steel, outage at normal mirror panels with operating buckled snaps for temperature and removal.

pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

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Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type 1 Pressurizer spray nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective 5

safe-end weld (1 weld) (ultrasonic) Ultrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level IIor III examination Fall of 1988. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. in EPRI TR-112657 examination.

Rev. B-A, "Revised Risk Informed The insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 2 semi-circular, flat panels enclosing the spray nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT IIor iII VT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed nozzle to pipe outage after cycle The Insulation is by Certified Level insulation joint. operation at a part of the III Examiners. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 2 semi-circular, conditions, and then flat panels again In Mode 3 enclosing the spray coming out of the nozzle. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 7 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal!

Insulation Type 6 1 Pressurizer relief valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (1 (ultrasonic) Ultrasonic (UT) Informed ISI Last examined inthe been, and will be, actions required to weld) examination of the Level IIor III examination Fall of 1997. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. in EPRI TR-112657 examination.

Rev. B-A, *Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going into the Results reviewed pipe to nozzle outage after cycle The insulation Is by Certified Level Insulation joint, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again in Mode 3 enclosing the relief coming out of the nozzle. The panels outage at normal are 4"thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 8 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units 1 and 2 Byron Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 7 1 Pressurizer safety valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (3 (ultrasonic) Ultrasonic (UT) Informed ISl The three welds were been, and will be, actions required to welds) examination of the Level 11 or Ill examination each examined in the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Fall of 1988, Spring volumetric welds. in EPRI TR-112657 of 1990 and Sring of examination.

Rev. B-A, Revised 1996 for the I Risk Informed Interval, and in the The Insulation is Inservice Fall of1997 for the part ofthe Inspection 2f Interval. pressurizer head Evaluation insulation Procedure. arrangement. There are 4 segmented.

flat panels enclosing each of the safety nozzles.

The panels are 4*

thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam Is performed The VT-2 exams are The Insulation is not by Certified Level by looking for performed twice each removed for the VT II or IIIVT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The Insulation Is by Certified Level insulation joints, operation at a part of the III Examiners. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again in Mode 3 enclosing each of coming out of the the safety nozzles.

outage at normal The panels are 4" operating thick stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 9 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units 1 and 2 Byron Station RCPB Alloy Material UstingI Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type 2 RPV nozzJe to safe-end Visual Inspection Exams performed Exam is performed The VT-2 exams are The insulation Is not No corrective 8

welds (4 hot leg safe-ends, for leakage (VT-2). by Certified Level by looking for performed twice each removed for the VT- actions required to 4 cold leg safe-ends, 8 II or III VT-2 evidence of refuel outage: first, In 2 examinations, date.

total). Examiners. leakage around the Mode 3 going into the Results reviewed pipe Insulation outage after cycle The Insulation is a by Certified Level joints and along the operation at a stainless steel IIIExaminers. annulus of the pressure and reflective (mirror) piping penetration, temperature at or design. There are slightly less than 3. 120 *"segments normal operating buckled around the conditions, and then pipe-nozzle OD.

again in Mode 3 coming out of the outage at normal operating temperature and pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation is not (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the removed for this examination of the Level II or III examination Spring of 1998. exam. The exam is nozzle to safe-end Examiners. volume, Figure 4-9 performed from the welds, in EPRI TR-112657 pipelnozzle Inner Rev. B-A, 'Revised diameter with an Risk Informed automated Inservice inspection tool.

Inspection Evaluation Procedure.!

Page 10 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 9 2 RPV head penetrations A Bare Metal Visual Exams performed BMV of the RPV The BMV exam was Insulation Is No corrective (VHP) 79 total (BMV) using V'r-2 by Certified Level head surface and a performed in the Fall removed as actions required to

-53 CRDMs techniques was IIor III VT-2 360 degree view of of 2002. The extent necessary to date. In addition,

-2 RVLIS performed in Fail Examiners. all VHPs with slight and frequency of facilitate the BMV for the Fall 2002

-5 Thermocouple 2002. Specific Results reviewed obstruction of the additional exam. examination, there

-18 spare VHPs Inspection by Certified Level head vent examinations to be In were no corrective

- I head vent guidelines were III Examiners. penetration. accordance with Peripheral vertical actions taken as developed and MRP. and horizontal there was no Implemented. panels are evidence of leakage designed for on the RPV head Previous VT-2 removal, surface and no exams performed RPV head with the RPV head The RPV head degradation was Insulation in-place. Insulation is a identified.

series of 3' thick mirror Insulation panels. The Insulation Is Instafled In a flat field across the top of the RPV head and is stepped down as it approaches the outer perimeter of the RPV head.

Page 11 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 10 2 RPV lower head In-core Previous VT-2 Exams performed The examination The examination is Insulation Is No corrective Instrumentation exams performed by Certified Level has been performed each removed to actions required to penetrations (58 total). with the RPV lower IIor III VT-2 performed with refuel outage or facilitate Mode 5 date.

head Insulation Examiners. RPV lower head during a forced BMV examinations.

panels removed as Results reviewed insulation removed outage of sufficient necessary to by Certified Level during Mode 5. duration. The Insulation at visually exam the III Examiners. the bottom of the bottom of the The examination The examinations are RPV Is a fiat, vessel and in-core has been performed twice, horizontal deck of nozzles, performed with once during Mode 5 stainless steel RPV lower head and then again at mirror panels. The insulation In-place operating pressure deck stands off looking for leakage and temperature, with from the bottom of at Insulation joints, a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time, the lower head beneath the RPV. providing a clearance of 8".

The center panels are fixed around the 58 In-core guide tubes and are not designed for removal. The peripheral panels are removable and allow access to the lower RPV head surface.

Page 12 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material ListingI IRem Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 11 2 Pressurizer surge nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) Ultrasonic (UT) Informed ISI Last examined in the been, and will be, actions required to examination of the Level II or III examination Fall of 1998. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. In EPRI TR-112657 examination.

Rev. B-A, 'Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer lower Evaluation head Insulation Procedure.' arrangement. There are 4 segments enclosing the surge nozzle. The panels are stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT II or Ill VT-2 evidence of refuel outage: first, In 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe Insulation outage after cycle The insulation Is by Certified Level Joints, along the operation at a part of the Ill Examiners. surge line piping pressure and pressurizer lower and on the temperature at or head Insulation containment floor slightly less than arrangement. There beneath normal operating are 4 segments pressurizer surge conditions, and then enclosing the surge nozzle. again in Mode 3 nozzle. The panels coming out of the are stainless steel, outage at normal mirror panels with operating buckled snaps for temperature and removal.

pressure with a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> hold time.

Page 13 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Listing Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 12 2 Pressurizer spray nozzle to Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective safe-end weld (1 weld). (ultrasonic) Ultrasonic (UT) Informed ISI Last examined inthe been, and will be, actions required to examination of the Level IIor III examination Spring of 1990. removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 volumetric welds. inEPRI TR-112657 examination.

Rev. B-A. Revised Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation insulation Procedure." arrangement. There are 2 semi-cIrcular.

fiat panels enclosing the spray nozzle. The panels are 4"thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation Is not by Certified Level by looking for performed twice each removed for the Vr IIor III VT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The Insulation is by Certified Level Insulation joint, operation at a pert of the IIIExaminers. pressure and pressurizer head temperature at or Insulation slightly less than arrangement. There normal operating are 2 semi-circular, conditions, and then fiat panels again in Mode 3 enclosing the spray coming out of the nozzle. The panels outage at normal are 4"thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 14 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units i and 2 Byron Station RCPB Alloy Material UstingI Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 13 2 Pressurizer relief valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (1 (ultrasonic) Ultrasonic (UT) Informed ISI Last examined In the been, and will be, actions required to weld). examination of the Level IIor III examination Spring of 1995 for the removed for the date.

nozzle to safe-end Examiners. volume. Figure 4-9 1a Interval and In the volumetric welds. inEPRI TR-112657 Spring of 2001 for the examination.

Rev. B-A, Revised 2' Interval.

Risk Informed The Insulation is Inservice part of the Inspection pressurizer head Evaluation Insulation Procedure. arrangement There are 4 segmented, flat panels enclosing the relief nozzle. The panels are 4" thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The Insulation Is not by Certified Level by looking for performed twice each removed for the VT IIor IIIVT-2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going into the Results reviewed pipe to nozzle outage after cycle The Insulation is by Certified Level insulation joint, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then flat panels again InMode 3 enclosing the relief coming out of the nozzle. The panels outage at normal are 4" thick operating stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 15 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Material Usting Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removall Insulation Type 14 2 Pressurizer safety valve Volumetric Certified 100% of the Risk Once per ISI Interval. Insulation has No corrective nozzle to safe-end weld (3 (ultrasonic) Ultrasonic (UT) Informed ISI The 3 welds were been, and will be, actions required to welds). examination of the Level IIor III examination each examined In the removed for the date.

nozzle to safe-end Examiners. volume, Figure 4-9 Spring of 1990 and volumetric welds. inEPRI TR-112657 the Fall of 1993 for examination.

Rev. B-A, Revised the I" Interval and in Risk Informed the Spring of 2001 for The Insulation is Inservice the 2' interval, part of the Inspection pressurizer head Evaluation Insulation Procedure.' arrangement. There are 4 segmented, fiat panels enclosing each of the safety nozzles.

The panels are 4' thick stainless steel, mirror panels with buckled snaps for removal.

VT-2 Exams performed Exam is performed The VT-2 exams are The insulation is not by Certified Level by looking for performed twice each removed for the VT IIor IIIVT.2 evidence of refuel outage: first, in 2 examinations.

Examiners. leakage around the Mode 3 going Into the Results reviewed pipe to nozzle outage after cycle The insulation is by Certified Level insulation joints, operation at a part of the IIIExaminers. pressure and pressurizer head temperature at or insulation slightly less than arrangement. There normal operating are 4 segmented, conditions, and then fiat panels again inMode 3 enclosing each of coming out of the the safety nozzles.

outage at normal The panels are 4" operating thick stainless steel, temperature and mirror panels with pressure with a 4 buckled snaps for hour hold time. removal.

Page 16 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Byron Station RCPB Alloy Materal Usting Personnel Extent of Frequency Degree of Corrective Action IRem Unit Component Inspection Techniques Qualifications Coverage Insulation Removal/

Insulation Type Exams performed The drain line, The direct visual The Insulation Is No corrective 15 2 Steam generator primary A visual using direct VT-2 techniques by Certified Level weld, and lower examination is removed to actions required to head drain lines (4 total). date.

was performed on IIVT-2 Examiners. head surface performed each time facilitate the the four steam around the drain the steam generator examination.

generator drain line were examined primary channel head lines and for steam Is de-insulated. The insulation surrounding head generators A', (typically for eddy around the steam surface. The "C" "B", "C"and "D'. current Inspection). generator lower steam generator head is a series of visual Inspection removable stainless was performed steel mirror panels.

during the June The bottom panel is 2002 forced outage a horizontal disc and the W, B" and that Is set off of the "D"steam steam generator generator visual head and encloses Inspections were the head, the drain performed during line, and the drain the Fall 2002 refuel line Isolation valve.

outage.

Previous VT-2 exams performed with the steam generator lower head Insulation In place.

Page 17 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2

2. Providethe technicalbasis for determining whether or not Insulationis removed to examine all locations where conditions exist that could cause high concentrationsof boric acid on pressureboundary surfaces or locations that are susceptible to primary waterstress corrosioncracking (Alloy 600 base metal and dissimilarmetal Alloy 82/182 welds). Identify the type of insulationfor each component examined, as well as any limitationsto removal of Insulation. Also include in your response actions involving removal of insulationrequiredby your proceduresto identify the source of leakage when relevantconditions (e.g., rust stains,boric acidstains, or boric acid deposits) are found.

Response

Except for bolted connections on borated ASME Section XI Class 1, 2 and 3 systems discussed below, Byron Station procedures do not require that insulated RCPB components be de insulated to perform VT-2 examinations. The basis for this has been that leakage from RCPB components should be detectable at insulated joints or surrounding areas given that the systems have been at normal pressure for, in most cases, a full operating cycle. While the removal of insulation is not necessarily required for the performance of a VT-2 exam, if evidence of leakage or boric acid residue is detected, the procedure requires that the leakage source be located which may require insulation removal.

In general, Byron Station ASME Section XI Class 1, 2, and 3 components in the containment containing borated water, if insulated, has removable stainless steel reflective style insulation.

Outside the containment, blanket insulation is used. Most insulation is removable, but there are exceptions. The insulation panels around the incore instrumentation guide tubes at the bottom of the RPV lower head are not intended to be removed. A set of peripheral horizontal panels are buckled in place and can be removed for access to the incore instrumentation guide tubes at the bottom of the RPV lower head. The horizontal panels around the VHPs are not removable; however, the side vertical panels are removable. The specific style of insulation for other locations in the RCPB is listed in the table in the response to Question 1.

Bolted Connections Insulated bolted connections in the RCPB (i.e., ASME Section XI, Class 1) and in borated ASME Section XI Class 2 and Class 3 support systems have insulation removed in order to perform ASME Section XI VT-2 examinations. The scope includes bolted connections that are installed in systems that are borated for the purpose of controlling reactivity. The ASME Section XI requirements on the extent of insulation removal and the plant conditions under which the insulation is removed have been modified by Byron Station Inservice Inspection Relief Requests 12R-1 1, Rev. 2 and 12R-34. Both of these alternatives to ASME Section XI requirements have been authorized for use at Byron Station by the NRC.

Relief Request 12R-1 I allows for insulation removal and the performance of the VT-2 exam on bolted connections in borated systems to be performed with the system depressurized. The approved altemative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examination. Additionally, for ASME Section XI Class 2 and 3 borated systems, VT-2 examinations are performed on approximately 36 month frequencies, which coincides with plant refueling outages, not allowing the period between inspections on individual components to exceed 45 months. This frequency for individual components is more restrictive than the "Periodic Frequency" allowed by ASME Section XI for Class 2 and 3 systems described in tables IWC-2500 or IWD-2500.

Page 18 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Relief Request 12R-34 allows the removal of insulation from certain ASME Section XI Class 1 valves for VT-2 examination to be performed on an extended frequency. The insulation is removed from the bolted connections and a VT-2 examination is conducted, with the system depressurized, on a once per 10 year interval frequency. These valves are also VT-2 examined with the insulation installed after a minimum four hour hold time at normal operating pressure at the end of each refueling outage and in Mode 3 during shutdown for each refueling outage.

Dissimilar Metal Welds Insulated dissimilar metal welded piping connections that contain Alloy 82/182 are typically not de-insulated for VT-2 examinations. A list of these nozzle to safe-end welds and the type of insulation is provided in the table in the response to Question 1. Examinations of these areas are performed in response to GL 88-05 and are conducted in Mode 3 going into the outage, typically, after a cycle of operation. Therefore, an adequate time is allowed for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The eight RPV nozzle to safe-end welds are considered inaccessible to perform direct VT-2 examination. The welds are located in an area between the concrete RPV shield wall and the concrete primary shield wall. This area enclosing the RPV nozzles and connected piping is referred to as the "sand box" area. The sand box area is only accessible from above, from the refueling cavity floor, by removing normally sealed steel plates. The normal technique for viewing potential leakage in this area is to look along the reactor coolant piping as it passes though the annulus of the bio-shield wall towards the RPV. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints inside the annulus. The RPV nozzle to safe-end weld insulation is not routinely removed since the sand box area is considered a high dose, confined space.

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluatingthe potential for leakage in inaccessibleareas. In addition, describe the degree of inaccessibility,and identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessibleareas.

Response

For the RCPB components, Byron Station personnel perform walkdowns during refueling outages, forced outages and, depending on circumstances, during power operations. Typical at-power containment walkdowns of accessible areas for leakage would be initiated at the request of the Operations Department if unidentified leakage was trending up or at the request of Radiation Protection personnel if there was an unexpected increase in containment atmosphere gas or particulate levels. For at-power walkdowns, the area of interest may be limited for as low as reasonably achievable (ALARA) considerations. VT-2 certified personnel perform the walkdowns during refueling outages and, in most cases, during forced outages and at power operations.

As described in the response to Question 2, the areas considered inaccessible are the "sand boxes" which enclose the eight RPV nozzles. Leakage from these areas is identified by visual examination along the horizontal surface of the insulated piping as it passes through the concrete annulus.

Page 19 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units i and 2 Byron Station uses a containment floor drain sump and a reactor cavity sump to collect, measure and record unidentified leakage in accessible and inaccessible areas in the containment. Both of these sumps are instrumented to identify leakages of 1.0 gpm within one hour and are recorded and alarmed in the main control room. The containment floor drain and reactor cavity sump inputs are checked each shift. A reactor coolant system (RCS) mass balance is performed when unidentified leakage is suspected and at the prescribed Technical Specification intervals. This provides early indication to the operator of potential unidentified leakage. Also, the reactor makeup control system is used to maintain proper reactor coolant inventory, volume control tank (VCT) level is continuously recorded and quantities of boric acid and makeup water injected are totaled and flow rates recorded in the control room.

The reactor coolant contains radioactivity that, when released to the containment, can be detected by radiation monitoring instrumentation. Radioactivity detection systems are used for monitoring both particulate and gaseous activities and can be used to identify RCS leakage.

The detection of RCS leakage using radiation monitors depends on the concentration of radioactivity in the RCS and detector background count rate.

Air temperature and pressure monitoring methods may also be used to infer unidentified leakage to the containment. Although containment temperature and pressure fluctuate slightly during unit operation, a rise above the normally indicated range of values may indicate RCS leakage into the containment.

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections), to demonstratethat continuedoperation with the observed leakage is acceptable. Also describethe acceptancecriteria that was establishedto make such a determination. Providethe technical basis used to establish the acceptance criteria. In addition,

a. If observedleakage is determined to be acceptablefor continued operation, describe what inspection/monitoringactionsare taken to trend/evaluatechanges in leakage, or

b. If observed leakage is not determined to be acceptable,describe what correctiveactions are taken to address the leakage.

Response

Byron Station personnel use engineering procedures BVP 200-10, "ISVIIST Recordable Indication Investigations," BVP 200-1 OT1, uRecordable Indication Record," and BVP 200-1 0T3, "ASME Section XI Bolted Connection Evaluation." These procedures describe the requirements and instructions for the evaluation of ASME Section XI Class 1, 2, and 3 bolted connections when external leakage is detected. These procedures provide instructions for the corrective actions that must be implemented in the event the structural integrity of any ASME Section XI Class 1, 2, or 3 bolted connection is determined to be suspect.

When evidence of leakage is identified from a bolted connection, the procedure requires an evaluation to be performed. This evaluation considers the location of the leak, leak rate, extent of deposit accumulation, extent of wastage, corrosiveness of process fluid, materials, length of time bolting has been in service and the effect on other structures or components. A condition Page 20 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 report is initiated for non-conforming conditions and a recommendation for repair, replacement, or monitoring is provided. Active leakage from the RCS is repaired prior to completing a refuel outage.

The bases for the evaluation/determination criteria of BVP 200-1 0T3 are derived from the provisions of Byron Station Inservice Inspection Relief Request 12R-12. This request was approved by the NRC.

Byron Station uses the corrective action process, specifically a condition report, to determine the acceptability for continued operation when a non-conforming condition is identified. Within the Condition Report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the non-conforming condition is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For a non-conforming condition that is determined to be unacceptable, repair or replacement is required.

5. Explain the capabilitiesof your program to detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wall cracking in the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or installedleakage detection Instrumentation,but has the potentialfor causingboric acid corrosion. The NRC has had a concern with the bottom reactorpressure vessel head Incore Instrumentation nozzles because of the high consequences associatedwith loss of Integrityof the bottom head nozzles. Describehow your program would evaluate evidence of possible leakage in this Instance. In addition,explain how yourprogram addresses leakage that may Impact components that are In the leak path.

Response

As explained in the table in the response to Question 1, items 3 and 10, the insulation at the bottom of the RPV lower head stands off of the head surface by a minimum of eight inches at the very bottom of the lower head curvature. Visual examinations of the Byron Station, Unit 1 and Unit 2 RPV lower head, scheduled for the Fall of 2003 and Fall of 2003, respectfully, will require removing insulation panels to view the metal surface. Any leakage from lower head penetrations would be visible. This examination is normally performed twice each refueling outage as described in the table in the response to Question 1.

Reactor coolant and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels. The incore penetration instrument tubes that connect to the nozzles are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or opening of the insulation, there are no pressure retaining components beneath the RPV that could be affected. This leakage from the RPV bottom head nozzles would collect in the reactor cavity sump described in the response to Question 3. The reactor cavity sump input is recorded each shift and abnormal readings are required to be reported to the Shift Manager. This notification would result in an evaluation and a condition report would be initiated, as necessary.

Page 21 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2

6. Explain the capabilitiesof your programto detect the low levels of reactorcoolant pressureboundaryleakage that may result from through-wallcracking in certain components and configurationsfor other small diameternozzles. Low levels of leakage may call into question reliance on visual detection techniques or Installed leakage detection instrumentation,but has the potentialfor causing boric acid corrosion.

Describehow your program would evaluate evidence of possible leakage in this instance.In addition, explain how your program addresses leakage that may impact components that are In the leak path.

Response

The leakage detection capabilities at Byron Station were discussed in the response to Questions 3 and 5 above. The visual examination and evaluation procedures at Byron Station require that components in the area of a leak be examined and evaluated. In the case of Byron Station, the vast majority of components in the RCPB are stainless steel.

7. Explain how any aspects of your program(e.g., insulationremoval, inaccessible areas, low levels of leakage, evaluation of relevant conditions)make use of susceptibility models or consequence models.

Response

Vessel Head Penetrations (VHPs)

Byron Station personnel have based the examination requirements for the Unit I and Unit 2 VHPs on the EPRI Material Reliability Project (MRP) susceptibility model for PWSCC. This ranking (i.e., MRP-48) identifies Byron Station, Unit I and Unit 2 as "low susceptibility" plants rated 66 and 6 7 th, respectively, out of the 69 PWR units in the study. As of September 2002, Byron Station, Unit 1 had an effective degradation year (EDY) value of 1.8 and as of the next refueling outage for Unit 2 in September of 2003, an EDY of 2.0, putting the Units in the lowest of the three susceptibility categories established by the NRC in Bulletin 2002-02, "Reactor Pressure Vessel Head and RPV Head Penetration Nozzle Inspection Programs."

Because of this lower susceptibility, Byron Station personnel perform qualified, effective bare metal visual (BMV) inspections of the RPV head surface and VHPs. The BMV inspection for Byron Station, Unit 2 was completed in the Fall of 2002 with no evidence of VHP leakage found.

The BMV inspection for Byron Station, Unit I is scheduled for the Fall of 2003. A partial BMV was completed during the Spring 2002 on Unit 1 to verify that no degradation to the head had occurred from a previous leak. Approximately 80% of the RPV head was examined with no degradation found.

Steam Generator Drain Lines As listed in the table in the response to Question1, the steam generator primary head drain lines for Byron Station, Unit 2 are made of Alloy 600 and Alloy 82/182 materials. The bottom surface of the steam generator primary head, the 3/8" drain lines and drain line isolation valves are enclosed in the lower head insulation package. Based on a susceptibility model developed by Westinghouse, Byron Station is visually examining the four Unit 2 drain lines whenever the Page 22 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 steam generator lower head insulation package is removed to support the eddy current testing of the steam generator tubing.

All four steam generator drain lines were visually examined as described in the table in the response to Question 1. There were no recordable indications, no signs of boric acid deposits or any degradation of the carbon steel lower head surface.

8. Provide a summary of recommendationsmade by your reactorvendor on visual Inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken orplan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Vessel Head Penetrations As stated above in the response to Question 7, Byron Station personnel are following the examination recommendations of the industry effort on the Alloy 600/821182 issue.

Westinghouse, the reactor vendor, and Babcock & Wilcox, the reactor manufacturer, are part of this industry effort. Based on the lower susceptibility of the Byron Station, Unit I and Unit 2 VHP nozzles, the recommended visual examinations are being performed. Byron Station personnel have followed all MRP recommendations and will comply with the recent MRP recommendations as stated in the letter from Leslie Hartz (Chair, MRP) to the EPRI PWR Materials Management Program (PMMP) Steering committee, dated December 2, 2002.

RPV Nozzle Safe-Ends, Reactor Lower Head Nozzles, and Pressurizer Nozzle Safe-Ends The current program for the examination of these components is listed in the table in the response to Question 1. Exelon Nuclear corporate and Byron Station personnel are currently working with Westinghouse on developing a comprehensive inspection, repair and/or mitigation program for all Alloy 600/82/182 components in the RCPB.

9. Provide the basis for concluding that the inspections and evaluationsdescribed In your responses to the above questions comply with your plant Technical Specifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of MechanicalEngineers (ASME) Code by reference. Specifically, addresshow your boric acid corrosioncontrol program complies with ASME Section Xl, paragraphIWA-5250 (b) on corrective actions. Include a description of the procedures used to implement the corrective actions.

Response

Byron Station Technical Specification (TS) Limiting Condition for Operation (LCO) 3.4.13.a states that there shall be no pressure boundary leakage. Pressure boundary leakage is defined as leakage, except steam generator tube leakage, through a non-insoluble fault in a reactor coolant system component body, pipe wall, or RPV wall. If pressure boundary leakage is detected, the action statements for this LCO require that the affected unit be in Mode 3 in six hours and be in Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The resolution of leakage indications in the corrective action program requires evaluation of the impact on this TS.

Page 23 of 24

Attachment 2 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Byron Station, Units I and 2 Compliance with the zero non-isolable leakage criteria is met by performing GL 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards." In addition, the unidentified leakage limit of one gpm defined in TS LCO 3.4.13.b is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a, requires that inservice inspection and testing be performed in accordance with the requirements of ASME Section XI. ASME Section XI contains applicable rules for examination, evaluation and repair of code class components, including the RCPB.

For this, the 2 nd Inservice Inspection Interval, Byron Station personnel have implemented the 1989 edition, with no addenda, of ASME Section XI. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"If boric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, Byron Station personnel use Exelon Nuclear Procedure ER-AA-335-015, "VT-2 Visual Examination." Paragraph 4.6.1.4 of this procedure states:

"ffboric acid residues are detected on components, then LOCATE the leakage source and the areasof generalcorrosion. EVALUATE components with local areasof general corrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptablefor continued service, or whether repairorreplacement is required."

The Exelon Nuclear procedure LS-AA-125, "Corrective Action Program (CAP) Procedure" defines the requirements for condition identification, condition review, investigation, and closeout.

Page 24 of 24

ATTACHMENT 3 Response to Request for Additional Information Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I-AmerGen Energy Company, LLC (AmerGen)

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I On November 21, 2002, the NRC issued a Request for Additional Information (RAI) for NRC Bulletin 2002-01, "Reactor Pressure Vessel Head Degradation and Reactor Coolant Pressure Boundary Integrity." The below information was required within 60 days of the date of the RAI for TMI Unit I that was categorized as a Bin 2 plant in the RAI.

NRC Question

1. Provide detailed information on, and the technical basis for, the inspection techniques, scope, extent of coverage, and frequency of Inspections, personnel qualifications, and degree of insulation removal for examination of Alloy 600 pressure boundary material and dissimilar metal Alloy 821182 welds and connections in the reactor coolant pressure boundary (RCPB). Include specific discussion of inspection of locations where reactor coolant leaks have the potential to come In contact with and degrade the subject material (e.g., reactor pressure vessel (RPV) bottom head).

Response

Introduction IBackground Regulatory Requirements:

10 CFR 50.55a, "Codes and standards," identifies the codes and standards requirements for operating nuclear power plants. Section (f) identifies the in-service testing requirement and section (g) identifies the in-service inspection requirements. For facilities whose construction permit was issued prior to July 1, 1971 (the construction permit for Three Mile Island Unit 1 was issued on May 18, 1968), components are required to meet the requirements of paragraphs (g)(4) and (g)(5) to the extent practical.

Paragraph (g)(4) states, "...components (including supports) which are classified as American Society of Mechanical Engineers (ASME Code) Class 1, Class 2 and Class 3 must meet the requirements, except design and access provisions and preservice examination requirements, set forth in Section XI of editions of the ASME Boiler and Pressure Vessel Code and Addenda that become effective subsequent to editions specified in paragraphs (g)(2) and (g)(3) .... to the extent practical within the limitations of design, geometry and materials of construction...."

The ASME Section XI, "Rules for Inservice Inspection of Nuclear Power Plant Components," serves as the technical basis for the inspections, techniques, scope and extent of coverage, inspection frequency, personnel qualifications, and extent of insulation removal for those components listed in the following table. TMI Unit 1, currently in the 3rd Inservice Inspection Interval, is committed to the 1995 Edition, through the 1996 Addenda, of ASME XI. In addition, the visual examinations of the RCPB and associated systems, structures, and components are supplemented by the requirements of the TMI Unit I commitment to Generic Letter (GL) 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants."

Page 1 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Development of the Boric Acid Corrosion Control (BACC) Program at TMI Unit I (since 1982):

On June 2, 1982, the NRC issued IE Bulletin 82-02, "Degradation of Threaded Fasteners in the Reactor Coolant Pressure Boundary of PWR Plants.' The purpose of this bulletin was twofold; first, to notify licensees and construction permit holders about incidents of severe degradation of threaded fasteners (bolts and studs) in closures in the reactor coolant pressure boundary (RCPB) and secondly, to require appropriate actions.

The scope of the resulting action items included threaded fasteners (studs or bolts) in steam generator and pressurizer manway closures, valve bonnets and pump flange connections installed on lines having a nominal diameter of six inches or greater and control rod drive flange and pressurizer heater connections that do not have seal welds to provide leak-tight integrity.

The response identified bolted closures of the RCPB that had experienced leakage with the resultant inspections made and corrective measures taken to eliminate leakage. It also identified RCPB closures and connections where fastener lubricants were used and the lubricant's composition. The only instance of the use of injection sealant was on the decay heat drop line and was reported, as required. A review of maintenance procedures and training was performed to assess threaded fastener practices.

Maintenance procedures were determined to be adequate to meet the requirements specified in IE Bulletin 82-02. In addition, training on bolting procedures was added to the mechanical maintenance training program. Finally, a report of specific connections examined since the issuance of NRC Information Notice No. 82-02 was provided to the NRC in letters dated August 3, 1982 and December 5, 1985. No evidence of RCPB stud or bolt failures was noted.

In 1989, to address concerns identified in NRC Generic Letter 88-05, "Boric Acid Corrosion of Carbon Steel RCPB Components in PWR Plants," TMI Unit 1 developed Technical Data Report (TDR) No. 946, "TMI-1 Evaluation of Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components". The existing TMI Unit I boric acid corrosion inspection requirements are based on the recommendations of this report.

This report identified specific RCPB locations most vulnerable to concentrated boric acid corrosion and the carbon steel targets of this leakage. These targets include;

"* reactor vessel,

"* pressurizer,

"* steam generator upper and lower heads,

"* hot and cold leg piping,

"* reactor coolant pump casing to piping bi-metallic weld,

"* studs on all manway I handholds or nozzles or valve packing assemblies,

"* core flood and high pressure injection nozzle safe ends,

"* pressurizer spray and surge lines, and

"* carbon steel sections of instrument piping and carbon steel valve bodies.

TDR No. 946 also provides clarification of the methodology for assessing component damage. Programmatic controls were developed to provide continuing assurance of extremely low probability of significant degradation to the RCPB components due to concentrated boric acid corrosion.

Page 2 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I TDR No. 946 divided RCPB components into three groups according to the potential consequences of their leakage onto other RCPB carbon steel components. This was intended to assist in placing appropriate emphasis on leakage inspections and evaluations. Group I components are RCPB components with mechanical joints, and the RCPB targets of the leakage. Group 2 components are RCPB components with mechanical joints for which unchecked corrosion of their targets could result in a RCPB leak equivalent to a leak from a line size greater than one inch (within the plant's normal makeup capability). Group 2 components are a subset of Group I components. Group 3 components are RCPB components with mechanical joints for which unchecked corrosion of their targets could result in a RCPB failure that exceeds the plant's normal makeup capability without first alerting the operator by exceeding the unidentified leak rate limit. Group 3 components are a subset of Group 2 components.

The reactor pressure vessel incore monitoring instrument (IMI) nozzles are not addressed as a component in TDR No. 946. A detailed discussion of the IMI nozzles is provided in response to Question No. 5.

All Group 1, Group 2 and Group 3 components, as well as others identified in TDR No.

946, are identified for ASME Section XI visual inspections (VT-2) prior to startup following each refueling outage. Each item has an individual sign-off to document the inspection. If evidence of leakage is noted during these inspections, programmatic requirements are in place to ensure that an engineering evaluation of the safety consequences of identified leakage is performed, and the condition corrected via corrective maintenance or component replacement. Additional non-ASME Section XI walkdowns are performed during plant cool down conditions to identify any evidence of leakage.

TDR No. 946, dated January 10, 1989, acknowledges the importance of the boric acid corrosion control issue and concludes with:

"Borated water leakage onto the RCPB can result in severe corrosion damage. The cooling effect of a leak on a hot RCPB surface can be sufficient to keep the surface moist, allowing for development of highly corrosive boric acid solutions.

Laboratory corrosion data and documented cases of severe RCPB corrosion demonstrate the problem. Boric acid corrosion rates of up to I to 2 inches per year are expected for carbon steels at RCS operating temperatures.

Minimizing the chance of severe RCPB degradation from boric acid corrosion is crucial to safe plant operation. At TMI Unit 1, a program of leakage inspections coupled with engineering evaluations and maintenance is the primary means of minimizing the probability of corrosion damage."

Subsequently, in response to NRC Information Notice 90-10: *Primary Water Stress Corrosion Cracking (PWSCC) of Inconel 600" (February 23, 1990), TMI Unit 1 commissioned a study of the use of nickel-base alloys. B&W Nuclear Technologies completed their report, "Nickel-Base Alloy Usage at TMI-1" (Report No. 51-1179885) in June 1990. This proprietary report provides a summary listing of nickel-base alloys used in the construction of the TMI Unit I reactor coolant system (excluding fuel assemblies Page 3 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit i and their control components) to be used in assessing possible in-service inspection locations. This report serves as a basis for the component identification in the attached table. BWNT Report No. 51-1179885 also identified that the effect of temperature on the initiation time for Alloy 600 SCC is an important variable, and that Alloy 600 failures have typically occurred at operating temperatures greater than approximately 600 F.

In accordance with the recommendations of BWNT Report No. 51-1179885, TMI Unit 1 inspects all pressurizer nozzle to safe end welds and the reactor vessel internals upper core barrel bolts during each 10-year in-service inspection period. These sites were characterized as most susceptible to Alloy 600 SCC. Other locations that were identified as possibly susceptible to Alloy 600 SCC, based strictly on temperature, were the reactor vessel and head and the reactor coolant piping. This report does not identify the incore monitoring instrumentation nozzles as a priority for Alloy 600 SCC inspections because of the lower operating temperatures.

In 1998, Framatome Technologies completed a study to rank on a relative basis each of the Alloy 600 components for potential failure due to PWSCC. A ranking was performed for each of the B&W Owners Group Plants. The results of this report, uAlloy 600 PWSCC Susceptibility Model, 51-5001951-01, December 16, 1998,0 are discussed in the response to Question No. 7.

Insulation removal is discussed in detail in response to Question No. 2.

Reactor Pressure Vessel Bottom Head Construction:

The reactor vessel is constructed of low alloy steel. The design pressure is 2500 PSI and the design temperature is 650 degrees F. The sides of the vessel are constructed of SA-533B, Class 1 plate with a stainless steel clad on the inner surface. The minimum wall thickness is 8.4 inches. The lower head is a forging of A-508 material with a minimum thickness of 5 inches. This component is also clad with stainless steel. There are 52 incore instrument nozzles that penetrate the lower vessel head. These are fabricated from ASME SB-166 Alloy 600 (Inconel) barstock. This material was supplied by B&W Tubular Products Division with heat number M6378. The initial size before machining was 2.25 inches outer diameter. This material was either hot rolled or hot finished, annealed and pickled. As stated in BWNT Report No. 51-1179885, these nozzles were most likely installed with a GTAW root pass with Alloy 82 weld metal then completed using the manual metal arc technique with Alloy 182 weld metal.

The reactor vessel was constructed under the following governing specifications: 1) The American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section III "Rules for Construction of Nuclear Vessels," 1965, and all applicable Code cases and Addenda for Class A vessels as of June 20, 1967, 2) The American Society of Mechanical Engineers, Boiler and Pressure Vessel Code,Section IX,Welding Qualifications, 1965, 3) The Babcock and Wilcox Company Equipment Specification CS-3-22, dated May 26, 1970, and 4) The Babcock and Wilcox Company, Quality Control Department Specifications covering Welding, Non-Destructive Testing, Heat Treatment, Cleaning and Testing.

The area below the bottom head insulation is surrounded by concrete and is referred to as the reactor vessel cavity area. This area is located within the primary shield. The area is approximately twelve feet in diameter and approximately nine feet high. Other Page 4 of 23

Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I than the incore instrument piping, there is no equipment in this area. A personal access hatch (approximately four feet high by four feet wide) and three ventilation ports (approximately one foot diameter) are provided through the structural concrete. Access to this area is restricted (due to dose rates) when the reactor is critical or when any incore instrumentation is pulled from the fuel. This area is not normally entered when the reactor coolant system is heated.

Insulation Design:

The thermal insulation for the reactor vessel is reflective type, designed and manufactured by Diamond Power Specialty Corporation and known as SS-MIRROR or MIRROR insulation. The insulation is of 100% stainless steel construction with carbon steel support members. The insulation was provided as pre-fabricated panels with adjacent panels matched to fit (tapped screw holes in overlapping members at the joints). The insulation is designed with clearances between the reactor vessel outer diameter and the inside diameter of the insulation assemblies to allow for thermal expansion of the vessel. The insulation panels are banded together with stainless steel bands.

For the bottom head panel placement, three sections of support steel were used. These were welded together after being put in place in the cavity area. Insulation panels were then bolted through one-inch diameter cutouts and attached with three-inch square washers, lock washers and nuts. This assembly was then raised and attached to the concrete wall using self-drilling anchors.

The following table provides a listing of the requested information of the Alloy 600 pressure boundary material and Alloy 82/182 welds and locations in the TMI Unit 1 Reactor Coolant Pressure Boundary (RCPB).

Some of the Alloy 600 and Alloy 82/182 materials are not listed in this table because they are internal to RCPB components and, assuming their failure, do not have a potential to degrade the RCPB with boric acid leakage. For the reactor vessel, these items include the guide lugs, reactor internal bolting block plate, the internal jack- screw locking cup and bolt locking cup. For the pressurizer, the spray nozzle connection inside the pressurizer is not included. In the once-through steam generators, the items are the steam generator tubing and the tube sheet cladding.

Page 5 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type IT Reactor vessel nozzle to Visual Inspection Exams performed Exam is performed The VT-2 exams The insulation Is not No corrective safe-end welds (2 core flood for Leakage (VT- by Certified Level II by looking for are performed each removed for the actions required to nozzles) 2) VT-2 examiners, evidence of leakage refuel outage: VT-2 examinations, date.

around the pipe coming out of the Insulation joints and outage at normal The insulation Is a along the annulus operating stainless steel of the piping temperature and reflective (mirror) penetration. pressure with a 4 design around the hour hold time. pipe-nozzle OD.

Non-ASME Section XI walkdowns are performed during plant cool down conditions to identify any evidence of leakage.

Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation is not (ultrasonic) (UT) Level 111111 Last examined in removed for this examination of the Examiners, the Fall of 2001. exam. The exam is nozzle to safe-end Next scheduled performed from the welds. exam for TMI-1 is pipetnozzle inner Fall 2011. diameter with an automated inspection tool.

Page 6 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Techniques Qualifications Coverage Insulation Removal/

Insulation Type Reactor vessel head Previous VT-2 Exams performed Exam is performed The VT-2 exams The RV head Bare metal, UT and penetrations (VHP) 71 total exams performed by Certified Level II by looking for are performed each insulation is a PT examinations 2 1 and corrective

-69 CRDMs with the RPV VT-2 examiners, evidence of leakage refuel outage: series of mirror

- 1 RVLIS head Insulation in- around the pipe and coming out of the insulation panels. actions taken in the

- 0 Thermocouple (Plugged) place. insulation joints, outage at normal The insulation is 1R14 refueling

- I head vent operating installed in a flat outage are The reactor temperature and field across the top described in vessel head is pressure with a 4 of the RPV head. AmerGen letter to scheduled to be hour hold time. the NRC dated April replaced with a Peripheral vertical 1, 2002 (5928-02 new head in and horizontal 20091) in response October 2003. panels are to NRC Bulletin designed for 2002-01, 15 day removal. Insulation response is not removed for requirement.

VT-2 examination at normal operating temperature and pressure.

Page 7 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-I Ahloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type 3 1 RPV lower head in-core Previous VT-2 Exams performed Exam is performed The examination Is For previous After the 9R instrumentation penetrations exams performed by Certified Level II by looking for performed once exams, the refueling outage (52 total) with the RPV VT-2 examiners, evidence of leakage during each refuel Insulation has not (1991), cleaning lower head around the pipe and outage. been removed, was performed by insulation in- insulation joints, removing boron place. TMI Unit 1 The insulation at residue from six is planning to the bottom of the suspect guide tubes install a camera vessel Is a flat, and from within the above the horizontal deck of primary shield, and insulation to stainless steel performing a water visually inspect mirror panels. The flush of the area the bare metal deck stands off Including the vessel around the incore from the bottom of insulation, primary instrumentation the lower head shield walls and nozzle providing a guide tubes and penetrations clearance of about within the cooling during the 6 inches. The annulus conducted refueling outage panels are fixed from the seal plate currently around the 52 in- area.

scheduled for core guide tubes.

October 2003 (TIR15).

4 1 Pressurizer surge nozzle to Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation has No corrective safe-end weld (1 weld) (ultrasonic) (UT)/Penetrant Last examined in been, and will be, actions required to examination of the Level I/Ill the Fail of 1999. removed for the date.

nozzle to safe-end Examiners. volumetric welds. A surface Next scheduled examination.

exam is also exam for TMI-1 Is required by Fall 2009.

Section Xl Code._I Page 8 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-1 Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Component Inspection Personnel Extent of Frequency Degree of Corrective Action Item Unit Techniques Qualifications Coverage Insulation Removal/

Insulation Type VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed removed for the VT VT-2 examiners, evidence of leakage each refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is a operating series of form fitting temperature and stainless steel, pressure with a 4 mirror styled panels hour hold time. with stainless steel bands that allow for removal.

Volumetric Certified Ultrasonic 100% Once per 10 years. Insulation has No corrective Pressurizer spray nozzle to actions required to safe-end weld (1 weld) (ultrasonic) and (UT) Penetrant been, and will be, Surface Level 1ill/ Last examined in removed for the date.

examination of the Examiners. the Fall of 2001. volumetric nozzle to safe-end examination.

welds.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners. evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation Is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement (NUKON).

Surface exam, Certified Penetrant Once per 10 years. Insulation has No corrective Pressurizer relief valve actions required to nozzle to flange weld (1 weld) (Less than 4 Level liIll 100%. Last examined in been, and will be, Nominal Pipe Size examiners, the Fall of 1997. removed for the date.

(NPS) surface examination.

Page 9 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Three Mile Island Unit-1 Alloy 600 pressure boundary material and Alloy 82/182 welds and connections in the reactor coolant pressure boundary (RCPB)

Item Unit Component Inspection Personnel Extent of Frequency Degree of Corrective Action Techniques Qualifications Coverage Insulation Removal/

Insulation Type VT-2 Exams performed Exam is performed The VT-2 exams The insulation Is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners, evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement (NUKON).

7 1 Pressurizer safety valve Surface exam, Certified Penetrant 100% Once per 10 years. Insulation has been No corrective nozzle to flange weld (2 less than NPS 4. Level 11411 and will be removed actions required to welds) Examiner. The 2 welds were for the surface date.

last examined in the examination.

Fall of 1997.

VT-2 Exams performed Exam is performed The VT-2 exams The insulation is not by Certified Level II by looking for are performed each removed for the VT VT-2 examiners, evidence of leakage refuel outage: 2 examinations.

around the pipe and coming out of the insulation joints, outage at normal The insulation is operating part of the temperature and pressurizer head pressure with a 4 insulation hour hold time. arrangement II_(NUKON).

8 1 RC drain line nozzle to safe- Volumetric Certified Ultrasonic 100% Once per 10 years Insulation has been No corrective end and safe-end to nozzle (ultrasonic) and (UT) Level IlIII per ISl schedule. and will be removed actions required to welds (6 welds) surface exam for Examiners.- for the date.

> NPS 4 examinations.

RC pumps pipe to elbow and Certified Penetrant pipe to pipe welds Surface exam for Level IIll1 (9 welds) < NPS 4 ExaminersI_ I NOTE : The MIRROR Insulation on the pressurizer and once-through-steam-generator upper heads have been replaced with NUKON Insulation, manufactured by Owens-Coming Fiberglass Corporation.

Page 10 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Results of Previous Inspections of the Reactor Vessel Bottom Head Cavity Area:

Due to transfer canal water leakage past the seal plate, an inspection was performed in the cavity area during 1991 (9R refueling outage). In summary, the area was cleaned and no primary system leakage was present. The following provides a summary of the 9R Outage inspection:

During 9R, Plant Engineering performed inspections of remote areas of TMI-1. One such area was within the primary shield underneath the reactor vessel lower head. This inspection was performed when all the incores were removed from the guide tubes awaiting replacement. The initial entry into the area found boron deposition on numerous incore tubes and the interior wall of the primary shield opposite the exhaust of the AH-E-2 fans. The examination during this entry was video taped. It was noted that water was dripping down from the cooling annulus in the vicinity of the incore chase.

After review of the videotape, Plant Engineering noted the amount of boron accumulation and the arrangement of deposition under the vessel. Engineering suspected that heavy localized deposits may have been a result of a leak in one or more incore guide tubes with mixing by the reactor cavity fans. As a result, plans were made to remove boron from six suspect stainless steel guide tubes, perform a visual inspection for a leak followed up by an NDE examination, application of a freeze seal and a 1000 PSI hydro of each tube from the incore seal plate. Each of the six guide tubes was successfully tested with no leakage identified.

Boron removal work was then performed within the primary shield followed by a water flush of the area including the vessel insulation, primary shield walls and guide tubes.

After this work was completed, a water flush was also performed within the cooling annulus conducted from the seal plate area. The flush was concentrated in the area where seal plate leakage had been earlier detected. A final entry was made to remove standing water and clean the floor.

The final assessment for boron accumulation was as follows:

"* There was 3 to 4 inches of standing water being retained within the primary shield.

"* Water leakage was from the seal plate while the transfer canal was flooded.

"* The dispersion of boron was due to the air turbulence induced by the AH-E-2 fans entering the cavity near floor level to the left of the primary shield entrance.

"* The total dose for the effort was 1.8 man-rem of which 0.6 was attributed to boron removal activities.

Subsequent to the 9R refueling outage transfer canal seal plate leakage, Operations surveillance OPS-$419 was created. This task inspects the reactor vessel cavity area and the area within the reactor head support skirt. A summary of these results, based on a review of the last three refueling outage inspections, follows:

Page 11 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1

" In 1997, standing water was found in the cavity area with some minor rusting noted.

" In 1999 (13R), no abnormal conditions were noted and a video tape was made. The videotape was reviewed with no significant abnormal conditions noted. However, a thin layer of water on the floor and some minor boron streaks were noted.

" In 2001 (TI R14), only photos were taken due to dose rate that limited entry into the cavity area. These photos were reviewed with no significant abnormalities noted, except for minor rusting of the air inlet piping and minor boron streaks on shield wall.

• The 1999 and 2001 conditions noted are indicative of some minor transfer canal seal plate leakage.

In conclusion, the reactor cavity area underneath the vessel has been inspected every refueling outage since at least 1991 (9R) with no significant abnormal conditions found.

These visual inspections (VT-2) did not specifically examine the bottom of the reactor vessel where the incore instrument nozzles penetrate the vessel because insulation completely covers this area and prevents visual inspection of the actual penetration.

These inspections did assess the general condition of this area and did identify indications of boron accumulation (most probably from canal seal plate leakage). Based on previous results, we are confident that any significant indications of leakage from the incore instrument nozzles would have been identified during these visual inspections.

Locations Where RCS Leakage has the Potential to Come Into Contact with the RPV Bottom Head:

There are no components located below the reactor vessel in the cavity area except the incore monitor tubes. These provide the only potential source of leakage located below the bottom head. Leakage onto the bottom head from elevations above can only originate from components whose weld interface is contained within the primary shield enclosure. For Alloy 600182/182 welds, these components include:

"* Reactor vessel upper head control rod housing bodies (69)

"* Reactor vessel upper head thermocouple nozzles (2)

"* Reactor vessel lower head incore monitoring instrumentation nozzles (52)

"* Core flood nozzle to safe-end welds (2)

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I NRC Question

2. Provide the technicalbasis for determining whether or not insulationis removed to examine all locations where conditions exist that could cause high concentrationsof boric acidon pressureboundarysurfaces or locations that are susceptible to primarywater stress corrosioncracking (Alloy 600 base metal and dissimilarmetal Alloy 82H182 welds). Identify the type of insulationfor each component examined,as well as any limitations to removal of insulation. Also include in your response actions involving removal of insulationrequiredby your proceduresto identify the source of leakage when relevant conditions (e.g., rust stains,boric acidstains, or boric acid deposits) are found.

Response

The basis for determining whether or not insulation is removed for examinations at TMI Unit I is consistent with ASME Section XI allowances which reflect practicality, cost, and dose considerations. The degree of insulation removal and insulation design is described in the Table provided in the response to Question No. 1.

Pipingq and Bolted Connections:

The visual examination (VT-2) of borated systems (for the purpose of controlling reactivity) requires insulation to be removed from pressure retaining bolted connections.

For other components, the visual examination may be conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation.

The ASME requirements on the extent of insulation removal and the plant conditions under which the insulation is removed, have been modified by TMI Unit I Inservice Inspection Relief Requests RR-00-08 and RR-00-09. Both of these alternatives to the ASME Section XI requirements have been authorized for use at TMI Unit I by the NRC.

Relief Request RR-00-08 allows the performance of the leakage tests on bolted connections in Class 1 borated systems to be performed without the removal of insulation. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examinations (to allow for leakage propagation from the insulation). Additionally, the insulation is removed from Class 1 bolted connections and a VT-2 visual examination is conducted with the system depressurized. These inspections are performed each refueling outage (nominal 24 month frequency).

Relief Request RR-00-09 allows the insulation around the bolted connections around the electrical pressurizer heater connections to remain installed during the VT-2 examinations of this area. The approved alternative requires that a system be pressurized for a minimum of four hours at normal operating pressure prior to the VT-2 examinations (to allow for leakage propagation from the insulation). These inspections are performed each refueling outage (nominal 24 month frequency) with the plant at hot shutdown.

Page 13 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I For insulated piping and components, a four-hour hold time at nominal operating pressure or hydrostatic test pressure is required as specified in the implementing procedures. For systems borated for the purpose of controlling reactivity, insulation is removed from pressure retaining bolted connections for visual examination VT-2 (unless relief has been authorized). Where normal access methods allow, pressure-retaining nuts, studs, bolts, capscrews and washers are visually inspected for evidence or indication of boric acid corrosion. This includes inspection for wastage, missing metal, cracks, pits, boric acid accumulation, corrosion products, and damaged or missing threads. For other than pressure retaining bolted connections, visual examination (VT-2) is conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation. In accordance with ASME Section XI, essentially vertical surfaces of insulation are examined at the lowest elevation where leakage may be detectable, and essentially horizontal surfaces of insulation are examined at each insulation joint. When examining insulated components, the examination of the surrounding area (including floor areas or equipment surfaces located undemeath the components) for evidence of leakage, or other areas to which such leakage may be channeled, is required. Discoloration or residue on surfaces examined is given particular attention to detect evidence of boric acid accumulations from borated reactor coolant leakage.

During the examination, particular attention is given to the insulated areas of components constructed of ferritic steels to detect evidence of boric acid residues whose sources derive from borated reactor coolant, and which may have accumulated during the service period preceding the examination. Any recordable indications identified during these inspections are evaluated by engineering through the corrective action program. The following conditions are considered recordable:

• Leakage from other than locations where leakage is normally expected and collected

• Inoperative leakage collection system

• Areas of general corrosion

• Corrosion which appears to have reduced the wall thickness by more than 10%

of the component, or which results in a surface transition with less than a 3 to I taper. (Rust with no visible thickness (no flaking) is acceptable without further evaluation)

• Any areas of structural distress (i.e., bent hangers, etc.)

• Boric acid residues on ferritic steel (verification of leakage source shall also be recorded)

In accordance with TMI Unit I VT-2 leakage examination Procedure SP 1300-6, if leakage occurs at a bolted connection, the corrective measures and evaluations of ASME Section XI as modified by NRC approved relief (RR-00-08), are required to be performed. Leakage at a bolted connection also requires at least one bolt to be removed and be VT-3 examined, per SP 1300-6.

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Dissimilar Metal Welds:

Insulated dissimilar metal welded piping connections that contain Alloy 82/182 typically do not have insulation removed for VT-2 examinations. Welds NPS 4 and larger receive a volumetric and surface examination per ASME Section XI. A list of these nozzle to safe-end welds and the type of insulation is provided in the Table contained in the response to Question No. 1. Examinations of these areas are performed in response to Generic Letter 88-05 and are conducted at hot shutdown after a four hour hold time to allow for leakage to propagate through the insulation joints and be observed by direct VT-2 examination.

The two reactor vessel nozzle to safe-end welds (core flood nozzles) are the only components considered inaccessible to direct VT-2 examination. The welds are located in an area between the concrete reactor vessel shield wall and the concrete primary shield wall. This area enclosing the reactor vessel nozzles and connected piping is referred to as the "sand plug" area. The sand plug area is only accessible from the refuel canal floor. The normal technique for viewing potential leakage in this area is to visually inspect along the piping as it passes though the D-ring wall. The piping is insulated, so the examiner looks for evidence of boric acid at the insulation joints. The reactor vessel nozzle to safe-end weld insulation is not removed. These welds are examined internally by Ultrasonic Testing (UT) as part of the 10-year Inservice Inspection Program requirements.

Reactor Vessel Penetrations:

TMI Unit 1 reactor vessel penetrations in the lower head are scheduled for visual examination in the Fall 2003 refueling outage. A bare metal visual inspection of the TMI Unit I upper vessel head penetrations was performed in the Fall of 2001, prior to startup of the current operating cycle. The upper head is scheduled to be replaced in the Fall of 2003.

In general, TMI Unit I Class 1, 2, and 3 RCPB components containing borated water, if insulated, have removable, stainless steel, reflective style insulation. Regulatory Guide 1.82, "Water Sources for Long-Term Recirculation Cooling Following a Loss-of-Coolant Accident," guidance is utilized for review of changes to thermal insulation installed on the primary coolant system piping and components. The panels around the reactor vessel head are removable. The insulation panels around the pressurizer heaters are not easily removed. Relief Request RR-00-09 allows this insulation to remain in place due to personnel dose exposure and the potential damage to the heaters associated with the insulation removal.

TMI Unit I VT-2 leakage examination Procedure SP 1300-6 specifies that in the event boric acid residues are detected, the insulation shall be removed from the components to the extent necessary to permit visual examination of the surfaces wetted by reactor coolant leakage, in order to detect evidence of corrosion. This procedure also specifies that for a recordable indication, the specific location of the leak shall be determined by the removal of any insulation, which interferes with the determination of the leakage Page 15 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I source. The leakage source, when determined, shall be identified and its specific location defined and documented by measured distances from adjacent welds, components, etc.

NRC Question

3. Describe the technicalbasis for the extent and frequency of walkdowns and the method for evaluating the potential for leakage in inaccessibleareas. In addition, describethe degree of Inaccessibility,and Identify any leakage detection systems that are being used to detect potentialleakage from components In Inaccessible areas.

Response

For RCPB components, TMI Unit I performs inspections to identify any reactor coolant system leakage following a plant shutdown, during any refueling outage and, depending on circumstances, at-power. Typical at-power containment visual inspections of accessible areas for leakage would be initiated at the request of the operations department if unidentified leakage were trending up or if there was an unexpected increase in containment atmosphere gas or particulate levels. For at-power visual inspections, the area of interest would be limited for ALARA considerations. VT-2 certified personnel perform the visual inspections for refueling outages and in most cases for forced and at-power visual inspections. Visual inspections performed during plant shutdowns include the reactor head area, the reactor coolant system and the makeup system, both inside and outside the secondary shields inside the reactor building.

See the response to Question No. 5 for a discussion of the detection methods used for inaccessible areas. TMI Unit I does not have any plans to install additional leak detection instrumentation at this time; however, TMI continues to monitor industry activities in this area.

NRC Question

4. Describe the evaluations that would be conducted upon discovery of leakage from mechanicaljoints (e.g., bolted connections) to demonstratethat continued operationwith the observedleakage is acceptable. Also describe the acceptance criteriathat was establishedto make such a determination. Provide the technical basis used to establish the acceptance criteria. In addition,

a. If observed leakage Is determinedto be acceptable for continued operation,describe what Inspection/monitoringactionsare taken to trend/evaluatechanges in leakage, or Page 16 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I

a. If observed leakage is determined to be acceptablefor continued operation,describe what inspection/monitoringactionsare taken to trend/evaluatechanges In leakage, or

b. If observed leakage Is not determined to be acceptable,describe what corrective actions are taken to address the leakage.

Response

TMI Unit 1 utilizes Technical Specification Surveillance Procedure Nos. 1300-6, "VT-2 Leakage Exams, 1300-6Q, "Leakage Exam for Insulated Bolted Connections,n and Administrative Procedure No. ER-AA-335-015, "VT-2 Visual Examination," to control these examinations. These procedures describe the requirements and instructions for the evaluation of any indications found during visual examinations, including those of insulated bolted connections. The procedures provide instructions for the corrective actions that must be implemented in the event the structural integrity of any component or bolted connection is determined to be suspect.

For insulated piping and components, a four-hour hold time at nominal operating pressure or hydrostatic test pressure is required as specified in the implementing procedures. For systems borated for the purpose of controlling reactivity, insulation is removed from pressure retaining bolted connections for visual examination VT-2 unless prior relief has been granted. Where normal access controls allow, pressure retaining nuts, studs, bolts, capscrews and washers are visually inspected for evidence or indication of boric acid corrosion. Inspections are conducted for wastage, missing metal, cracks, pits, boric acid accumulation, corrosion products, and damaged or missing threads. For other than pressure retaining bolted connections, visual examinations are conducted without the removal of insulation by examining the accessible and exposed surfaces and joints of the insulation. Essentially vertical surfaces of insulation are examined at the lowest elevation where leakage may be detectable. Essentially horizontal surfaces of insulation are examined at each insulation joint. When examining insulated components, the examination of the surrounding area (including floor areas or equipment surfaces located underneath the components) for evidence of leakage, or other areas to which such leakage may be channeled, is required. Discoloration or residue on surfaces examined is given particular attention to detect evidence of boric acid accumulations from borated reactor coolant leakage.

During the examination, particular attention is given to the insulated areas of components constructed of ferritic steels to detect evidence of boric acid residues whose sources derive from borated reactor coolant, and which may have accumulated during the service period preceding the examination. Any recordable indications are evaluated.

The following conditions are considered recordable:

• Leakage from other than locations where leakage is normally expected and collected

• Inoperative leakage collection system Page 17 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I

• Areas of general corrosion

• Corrosion which appears to have reduced the wall thickness by more than 10%

of the component, or which results in a surface transition with less than a 3 to 1 taper. (Rust with no visible thickness (no flaking) is acceptable without further evaluation)

• Any areas of structural distress (i.e., bent hangers, etc.)

• Boric acid residues on ferritic steel (verification of leakage source shall also be recorded)

If leakage occurs at a bolted connection, the corrective measures and the evaluations of ASME Section XI (as modified by NRC approved reliefs) are performed. Components with local areas of general corrosion that reduce the wall thickness by more than 10%

are required to be evaluated by plant engineering. This evaluation will determine whether the component may be acceptable for continued service or whether repair or replacement is required.

TMI Unit 1 uses the corrective action process, specifically the condition report, to determine the acceptability for continued operation when leakage is identified. Within the condition report, operability is considered and may require a formal evaluation using procedure LS-AA-105, "Operability Determinations." Ifthe operability assessment determines that the leakage is acceptable, inspection/monitoring actions may be established and tracked using LS-AA-105-1001, "Supporting Operability Documentation." For leakage that is determined to be unacceptable repair or replacement is required.

NRC Question

5. Explain the capabilitiesof your program to detect the low levels of reactor coolantpressureboundary leakage that may result from through-wall crackingIn the bottom reactorpressure vessel head incore instrumentationnozzles. Low levels of leakage may call into question reliance on visual detection techniques or installedleakage detection instrumentation,but has the potentialfor causing boric acid corrosion. The NRC has had concern with the bottom reactorpressure vessel head incore Instrumentationnozzles because of the high consequences associatedwith loss of Integrityof the bottom head nozzles. Describe how your program would evaluate evidence of possible leakage in this Instance. In addition,explain how your program addressesleakage that may impact components that are in the leak path.

Response

As explained in the response to Question No. 1, Item 2, the insulation at the bottom of the reactor vessel lower head stands off of the head surface by approximately six inches at the very bottom of the lower head curvature. Visual examinations of the TMI Unit 1 reactor vessel lower head, scheduled for the Fall of 2003, may require removing Page 18 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I insulation to view the metal surface. Any evidence of leakage from lower head penetrations will be visible.

Reactor coolant water/condensed vapor and boric acid deposits from a lower penetration leak would collect on the inner surface of the flat, horizontal insulation panels and the supporting structural carbon steel. The incore penetration instrument tubes, which connect to the Alloy 600 nozzles, are stainless steel and have an increased resistance to boric acid corrosion/wastage. If boric acid were to leak through the seams or opening of the insulation, there are no pressure retaining components beneath the reactor vessel that could be affected.

Plant Technical Specifications require monitoring leakage (including primary-to secondary leakage) from the reactor coolant system (RCS) and the makeup and purification system. This differs from Standard Technical Specifications in that the makeup and purification system is included in the scope of monitoring for TMI Unit 1.

This monitoring is intended to assure that any reactor coolant leakage does not compromise the safe operation of the facility. When the reactor is critical and above two percent power, two reactor coolant leakage detection systems of different operating principles are required to be in operation for the reactor building in accordance with Technical Specification 3.1.6, with one of the two systems sensitive to radioactivity.

These systems include containment radiation monitors, mass balance calculations, reactor building sump level monitoring and reactor building humidity monitors. The primary method used at TMI Unit I for quantifying RCS and makeup and purification system leakage is the mass balance calculation.

During power operations, containment radiation monitors, reactor building sump level instruments and reactor building humidity monitors are generally in service continuously.

Mass balance calculations are required to be performed daily. These calculations are normally performed over a two-hour period and are calculated by the plant process computer. The accuracy of this calculation allows identification of changes in leakage rates of less than 0.1 gpm.

Plant Technical Specifications also require that if the total reactor coolant leakage rate exceeds ten gpm, the reactor is to be placed into hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. If unidentified reactor coolant leakage (excluding normal evaporative losses) from the RCS pressure boundary exceeds one gpm or if any reactor coolant leakage is evaluated as unsafe, the reactor is required to be placed into hot shutdown within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. The unidentified leakage limit of one gpm is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a matter of hours, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

Unexpected changes in the trend of the measured leak rate are identified and dispositioned in the corrective action program with subsequent investigation and operability evaluation.

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I If a reactor shutdown is required, the rate of shutdown and the conditions of shutdown are determined by a safety evaluation for each case and justified in writing as soon as practicable. Action to evaluate the safety implications of RCS leakage is initiated within four hours of detection. The nature, as well as the magnitude, of the leak is considered in this evaluation. Maintaining exposure of offsite personnel to radiation within the guidelines of 10 CFR 20, "Standards for Protection Against Radiation," is also required within this evaluation. Other factors that are recommended to be included in this evaluation are;

1. Consideration of leakage effects on operation of associated system instrumentation which is important to safety,

2. Consideration of leakage effects on associated system operation during normal and emergency operations,

3. Consideration of leakage effects on the environmental qualification of surrounding equipment which is important to safety,

4. Consideration of restriction of required personnel access to operate or maintain important to safety equipment under normal and emergency conditions,

5. The potential for identified leak to grow to unsafe magnitudes under continued operation, and

6. The effects of boric acid wastage on carbon steel components, piping, supports, etc. To the extent practical evidence of boric acid leakage is not disturbed until engineering has been notified to evaluate the possibility of carbon steel wastage. RCS leakage should be redirected to minimize carbon steel corrosion.

If reactor shutdown is required, the reactor will not be restarted until the leak is repaired or until the problem is otherwise corrected.

NRC Question

6. Explain the capabilitiesof your program to detect the low levels of reactor coolantpressure boundaryleakage that may result from through-wallcrackingIn certain components and configurationsfor othersmall diameternozzles. Low levels of leakage may call Into question reliance on visual detection techniques or Installedleakage detection Instrumentation,but has the potentialfor causing boric acidcorrosion. Describe how your program would evaluate evidence of possible leakage in this instance. In addition,explain how yourprogram addresses leakage that may Impact components that are in the leak path.

Response

See the response to Question Nos. 3 and 5. The visual examination and evaluation procedures at TMI Unit I require that components in the area of a leak be examined and, if necessary, be evaluated.

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I NRC Question

7. Explain how any aspects of your program(e.g., Insulation removal,Inaccessible areas,low levels of leakage, evaluation of relevant conditions)make use of susceptibilitymodels or consequence models.

Response

In 1998, Framatome Technologies completed a study to rank on a relative basis each of the Alloy 600 components for potential failure due to PWSCC. This ranking was performed for each of the B&W Owners Group Plants ("Alloy 600 PWSCC Susceptibility Model, 51-5001951-01, Proprietary, December 16, 1998). However, TMI Unit I currently does not make use of any susceptibility models or consequence models to identify or rank the Alloy 600 component locations. The basis for TMI Unit I inspections of dissimilar metal welds is ASME Section Xl. TMI Unit I continues to monitor the status of the susceptibility predictions through the B&W Owners Group.

NRC Question

8. Provide a summary of recommendationsmade by your reactorvendor on visual Inspections of nozzles with Alloy 600/82/182 material,actionsyou have taken or plan to take regardingvendor recommendations,and the basis for any recommendationsthat are not followed.

Response

Babcock & Wilcox (B&VV), the reactor manufacturer, issued Condition Report No.

6014542 on April 1, 2002. This document raised the concern that, while the incore instrumentation nozzles have been ranked low in susceptibility to PWSCC, additional evaluations have ranked the incore nozzles high in failure consequence. B&W recommended that effective visual inspections of the lower reactor vessel head area (OD) be conducted. They also recommended that development of new NDE techniques and repair processes be substantially accelerated. Framatome ANP also issued a Preliminary Report of Safety Concern (PSC) 4-02, related to the chemical samples taken at Davis-Besse associated with potential IMI nozzle leakage, in a letter to the B&W Owners Group Members, dated October 11, 2002. This letter reiterated the recommendation that based on the current state of qualified non-destructive examination (NDE) techniques and accessibility concerns, a bare metal visual examination of the IMI nozzle/lower reactor vessel head interface area should be performed at the earliest opportunity.

Based on this and other recommendations, TMI Unit 1 is planning to install a camera above the insulation to visually inspect the bare metal around the incore instrumentation nozzle penetrations during the refueling outage currently scheduled for October 2003 (TI R1 5). TMI Unit I is currently evaluating the development and use of new NDE Page 21 of 23

Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit I Based on this and other recommendations, TMI Unit I is planning to install a camera above the insulation to visually inspect the bare metal around the incore instrumentation nozzle penetrations during the refueling outage currently scheduled for October 2003 (TI R1 5). TMI Unit 1 is currently evaluating the development and use of new NDE techniques and repair processes to support the TIR15 outage inspection. No additional specific recommendations have been provided by the reactor vendor.

NRC Question

9. Provide the basis for concluding that the Inspections and evaluationsdescribed in your responses to the above questions comply with your plant Technical Specifications and Title 10 of the Code of FederalRegulations (10 CFR), Section 50.55(a), which incorporatesSection XI of the American Society of Mechanical Engineers(ASME) Code by reference. Specifically, addresshow your boric acid corrosioncontrol programcomplies with ASME Section Xl, paragraphIWA-5250 (b) on correctiveactions. Include a descriptionof the proceduresused to implement the corrective actions.

Response

TMI Unit I Technical Specification Limiting Condition for Operation, (LCO), 3.1.6 states that there shall be no pressure boundary leakage, except steam generator tube leakage, through a nonisolable fault in a reactor coolant system component body, pipe wall, or vessel wall. If pressure boundary leakage is detected, the action statements for this LCO requires that the reactor shall be shutdown and a cool-down to cold shutdown initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of detection. Actions to evaluate the safety implications of reactor coolant system leakage are required to be initiated within four hours of detection.

Compliance with the zero, non-isolable leakage criteria is met by performing Generic Letter 88-05 examinations, conducting inspections and repairs in accordance with ASME Section XI, and 10 CFR 50.55a, "Codes and standards" and by monitoring reactor coolant leakage trends using diverse methods (mass balance calculation, radiation monitors, reactor building sump level accumulation and reactor building humidity monitoring), as required by plant-specific technical specifications. In addition, the unidentified leakage limit of one gpm is established as a quantity that can be accurately measured while sufficiently low to ensure early detection of leakage. Leakage of this magnitude can be reasonably detected within a short time, thus providing confidence that cracks associated with such leakage will not develop into a critical size before mitigating actions can be taken.

10 CFR 50.55a requires that inservice inspection and testing be performed in accordance with the requirements of the ASME Boiler and Pressure Vessel Code,Section XI, "Inservice Inspection of Nuclear Plant Components."Section XI contains applicable rules for examination, evaluation and repair of code class components, including the reactor coolant pressure boundary.

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Attachment 3 Response to RAI Regarding NRC Bulletin 2002-01, Three Mile Island Station, Unit 1 For this, the 3 RD Inservice Inspection Interval, TMI Unit I has implemented the 1995 edition, with 1966 addenda, of ASME Section Xl. Paragraph IWA-5250 (b), "Corrective Measures," of this edition states:

"Ifboric acid residues are detected on components, the leakage source and the areas of general corrosion shall be located. Components with local areas of general corrosion that reduce wall thickness by more than 10% shall be evaluated to determine whether the component may be acceptable for continued service, or whether repair or replacement is required."

To incorporate these requirements, TMI Unit I utilizes Technical Specification Surveillance Procedure Nos. 1300-6, "VT-2 Leakage Exams," 1300-6Q, "Leakage Exam for Insulated Bolted Connections," and Administrative Procedure No. ER-AA-335-015, "VT-2 Visual Examination," to control these examinations and any subsequent corrective actions. Corporate Procedure No. ER-AA-335-015, 'V7-2 Visual Examination,"

Paragraph 4.6.1.4 states:

"iffboric acid residues are detected on components, then LOCATE the leakage source and the areasof general corrosion. EVALUATE components with local areasof generalcorrosionthat reduce the wall thickness by more than 10% to determine whether the component may be acceptable for continued service, or whether repairor replacementis required."

Corporate Procedure No. LS-AA-125, "Corrective Action Program (CAP) Procedure,"

defines the requirements for condition identification, condition review, investigation, and closeout.

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